Greenhouse Gas Control Technologies - 6th International Conference (Tribology Series, Vol 41)

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G R E E N H O U S E GAS CONTROL TECHNOLOGIES

6 th

Proceedings of the International Conference on Greenhouse Gas Control Technologies

1 - 4 October 2002, Kyoto, Japan

Volume H

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G R E E N H O U S E GAS CONTROL TECHNOLOGIES

6 th

Proceedings of the International Conference on Greenhouse Gas Control Technologies 1 - 4 October 2002, Kyoto, Japan

Edited by

J. Gale IEA Greenhouse Gas R&D Programme, Cheltenham, Gloucestershire, UK

Y. K a y a RITE, Kyoto, Japan

Volume H

2003 PERGAMON An imprint of Elsevier Science Amsterdam - Boston - H e i d e l b e r g - London - New Y o r k - Oxford P a r i s - San D i e g o - San Francisco - S i n g a p o r e - S y d n e y - Tokyo

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0080442765

Library of Congress Cataloging in Publication Data A catalog record from the Library of Congress has been applied for.

ISBN:

0-08-044276-5 (2 volume set)

The paper used in this publication meets the requirements of ANSI/NISO Z39.48-1992 (Permanence of Paper). Printed in The Netherlands.

Foreword

These proceedings contain papers presented or displayed as posters at the 6th International Conference on Greenhouse Gas Control Technologies (GHGT-6) held at Kyoto International Conference Hall, Japan, from October 1 to 4, 2002. Overall, some 240 papers were presented orally and 76 papers were displayed at poster sessions. The conference attracted 500 delegates from 32 countries, of which more than 55% were from countries other than Japan, the host country. Following the plenary session consisting of two keynote speeches on climate change policies and technical measures, six parallel sessions were held for presentation of the 240 papers. The origin of this conference series started in 1992 under the title of the International Conference on Carbon-Dioxide Removal (ICCDR 1). It dealt with studies on carbon dioxide capture and sequestration technologies and was followed by ICCDR-2 held in Kyoto, Japan, in 1994 and ICCDR-3 held at MIT, USA, in 1996. The scope of the conference was broadened in the next conference held in Interlaken, Switzerland, in 1996 so as to include all greenhouse gases and issues related to climate change such as technical, economic and policy measures to mitigate climate change. The name of the conference series was changed at that time to the International Conference on Greenhouse Gas Control Technologies (GHGT-4). GHGT-5 was held in Cairns, Australia, in 2000; both conferences were very successful with more than 200 papers presented respectively. By 1995, the IEA Greenhouse Gas R&D Programme (IEA GHG) had held a similar conference series and decided to support the GHGT series. IEA GHG then became the guardian of the GHGT series. The present conference, GHGT-6, was organized jointly by IEA GHG, the Research Institute of Innovative Technology for the Earth (RITE), Japan, and the Japan Society of Energy and Resources (JSER). Taking into account that JSER's fields of activity include energy economics and general energy technologies, the organizers decided to broaden the scope of the conference so as to accommodate their inclusion. This may be one of reasons why the total number of papers presented at this conference has been the largest in this conference series. The papers included here, therefore, cover broad areas related to climate change issues. About 55% of the papers consist of those in the field of CO2 recovery and sequestration, although the other 45% cover non-CO2 greenhouse gases, forest absorption, biomass and other energy sources, energy technologies including those for conservation, CO2 utilization technologies, and energy policy and economics. It is noticeable that the number of papers on geological sequestration increased dramatically at this conference, compared with previous conferences. A total of 98 papers were presented or displayed at poster sessions at this conference, whereas less than 40 papers were presented at GHGT-4 and GHGT-5. This may reflect the rapid rise in research spending worldwide on topics associated with the geological sequestration of carbon dioxide.

The proceedings also include a keynote speech made at the plenary session. This comprises an overview of R&D technologies for the mitigation of climate change presented by Mr. H. Mitsukawa of the New Energy and Technology Development Organization (NEDO) of Japan. An important feature of the present conference was the holding of two panel sessions, one concerned with public outreach on CO2 sequestration and the other on the role of industries in the strategy for mitigating global warming. Although this was the first such attempt in this conference series, both sessions attracted audiences who enjoyed the, sometimes heated, discussions between the panelists and audience. The conference was supported not only by main sponsors such as the IEA GHG Programme, RITE and JSER, but by many other organizations, both domestic and foreign. They were: • • • • •

• • • • • • • • • • • • • •

Battelle/Pacific Northwest National Laboratory (PNNL) U.S. Department of Energy/The National Energy Technology Laboratory (US DOE/NETL) The Commemorative Association for the Japan World Exposition (1970) ABB Corporate Research (ABB) BP Statoil TotalFinaElf NOVEM (Netherlands Agency for Energy and the Environment) Engineering Advancement Association, Japan Federation of Electric Power Companies, Japan Japan Automobile Manufacturers Association Japan Cement Association Japan Chemical Industry Association Japan Electronics and Information Technology Industry Association Japan Gas Association Japan Iron and Steel Association Japan Society of Industrial Machining Manufacturers Petroleum Association of Japan Japan Electrical Manufacturers Association

We also acknowledge the support of the Ministry of Economy, Trade and Industry of Japan (METI), New Energy and Industrial Technology Development Organization (NEDO), Kyoto Prefecture, the Japan Business Federation, and Kansai Economic Federation. In addition, we would like to acknowledge the contribution of Dr S. Mills in helping to put these proceedings together.

Yoichi Kaya Chairman, Organizing Committee, GHGT-6 Director General, RITE

vii

CONTENTS

Foreword

VOLUME

I

Address to the Opening Session Kelly Thambimuthu

OPENING SESSION

Global Warming Prevention Technologies in Japan (Keynote lecture) Hiroshi Mitsukawa

CO2 CAPTURE - OVERVIEW

Japanese R&D on CO2 Capture Takahisa Yokoyama The CO2 Capture Project: Meeting the Challenge at the Halfway Point Gardiner Hill CO2 Capture and Storage - The Essential Bridge to the Hydrogen Economy D.R. Simbeck

25

Test Results from a CO2 Extraction Pilot Plant at Boundary Dam Coal-Fired Power Station M. Wilson, P. Tontiwachwuthikul, A. Chakma, R. Idem, A. Veawab, A. Aroonwilas, D. Gelowitz, J. Barrie, C. Mariz

31

CO2 CAPTURE - E N E R G Y

A Study of Very Large Scale Post Combustion CO2 Capture at a Refining and Petrochemical Complex M. Simmonds, P. Hurst, M.B. Wilkinson, C. Watt, C.A. Roberts Application of CO2 Removal to the Fischer-Tropsch Process to Produce Transport Fuel George Marsh, Judith Bates, Heather Haydock, Nikolas Hill, Chris Clark, Paul Freund

39

45

Evaluation of CO2 Capture Technology Developments by Use of Graphical Evaluation and Review Technique Takanobu Kosugi, Ayami Hayashi, Tsuyoshi Matsumoto, Keigo Akimoto, Koji Tokimatsu, Hajime Yoshida, Toshimasa Tomoda, Yoichi Kaya Life Cycle Assessment for CO2 Capture Technology from Exhaust Gas of Coal Power Plant Eriko Muramatsu, Masaki Iijima

57

viii Environmental Analysis of Different Options of CO2 Capture in Power Generation from Natural Gas G. Clerici, E. D 'Addario, M. MusicantL G. Pulvirenti, S. Serenellini, M.G. Valdiserri CO2 Capture from Oil Refinery Process Heaters Through Oxyfuel Combustion M.B. Wilkinson, J.C. Boden, T. Gilmartin, C. Ward, D.A. Cross, R.J. Allam, N. IV. Ivens A Workbook for Screening Options to Reduce CO2 Emissions from Existing Power Stations Lindsay Juniper, John Davison

63

69

75

CO2 Control Technologies: ALSTOM Power Approach Timothy Griffin, Alain Bill, John L. Marion, Nsakala ya Nsakala Numerical Investigation of Oxy-Coal Combustion to Evaluate Burner and Combustion Design Concepts E.H. ChuL A.J. Majeski, M.A. Douglas, Y. Tan, K. V. Thambimuthu

87

Evaluation of Characteristics and Economics of CO2-Capturing NOx-Free Repowering System - In the Case of Utilizing Middle Pressure Steam in a Thermal Power Plant Pyong Sik Pak

95

CO2 C A P T U R E

- AMINE ABSORPTION

Carbon Dioxide Capture from Multiple Flue Gas Sources M. Slater, E. West, C.L. Mariz

103

Flue Gas CO2 Recovery and Compression Cost Study for CO2 Enhanced Oil Recovery Masaki Iijima, Takashi Kamijo

109

Oxidative Degradation of Aqueous Monoethanolamine in CO2 Capture Systems Under Absorber Conditions George S. Goff, Gary T. Rochelle Exergy Analysis of Amine-based CO2 Removal Technology F. Geuzebroek, L.H.J.M. Schneider, G.J.C. Kraaijveld Performance and Cost Analysis for CO2 Capture from Flue Gas Streams: Absorption and Regeneration Aspects A. Veawab, P. Tontiwachwuthikul, A. Aroonwilas, A. Chakma

CO2 C A P T U R E

115

121

127

- MEMBRANES

Integration of H2-separating Membrane Technology in Gas Turbine Processes for CO2 Sequestration K. Jordal, R. Bredesen, H.M. Kvamsdal, O. Bolland Production of Hydrogen and Electricity from Coal with CO2 Capture T.G. Kreutz, R.H. Williams, R.H. Socolow, P. Chiesa, G. Lozza

135

141

Removal and Enrichment of CO2 by Novel Facilitated Transport Membrane Using Capillary Membrane Module with Permeation of Carrier Solution M. Teramoto, N. Takeuchi, N. Ohnishi, H. Matsuyama

149

A New Method for CO2 Capture: Frosting CO2 at Atmospheric Pressure D. Clodic, M. Younes

155

Novel Concepts for CO2 Capture with SOFC J.W. Dijkstra, D. Jansen

161

CO2 C A P T U R E - C H E M I C A L R E A C T I O N •

Solid Sorbents for the Reversible Capture of Carbon Dioxide S. Contarini, M. Barbini, G. Del Piero, E. Gambarotta, G. Mazzamurro, M. Riocci, P. Zappelli Carbon Deposition Characteristics of NiO Based Oxygen Carrier Particles for ChemicalLooping Combustor H.J. Ryu, D.H. Bae, G.T. din

169

175

Novel Combustion Cycles Incorporating Capture of CO2 with CaO J.Carlos Abanades, John E. Oakey, Diego Alvarez, Jouni Hdm~ildinen

181

CO2 Capture from the Air: Technology Assessment and Implications for Climate Policy David W. Keith, Minh Ha-Duong

187

Carbon Dioxide Recovery from Flue Gases by Ammonia Scrubbing Xian-Yu Zheng, Yong-Fa Diao, Bo-Shu He, Chang-He Chen, Xu-Chang Xu, Wen Feng

193

GEOLOGICAL STORAGE - OVERVIEW CO2 Storage in the Subsurface L.G.H. van der Meer Geological Storage of CO2: What's Known, Where are the Gaps and What More Needs to be Done John Gale

201

207

Obstacles to the Storage of CO2 Through EOR Operations in the North Sea A.A. Espie, P.J. Brand, R.C. Skinner, R.A. Hubbard, H.I. Turan

213

The IEA Weyburn CO2 Monitoring and Storage Project R. Moberg, D.B. Stewart, D. Stachniak

219

GEOLOGICAL STORAGE - POLICY Fossil Fuels - Zero Emissions Notions on a Policy Strategy - The Dutch Perspective Rob Cuelenaere

227

Geological Carbon Storage: Understanding the Rules of the Underground Elizabeth J. Wilson, David W. Keith

229

A Search for Regulatory Analogs to Carbon Sequestration D.M. Reiner, H.J. Herzog Health, Safety and Environmental Risk Assessment for Geologic Storage of Carbon Dioxide: Lessons Learned from Industrial and Natural Analogues Sally M. Benson, John Apps, Robert Hepple, Marcelo Lippmann, Chin Fu Tsang, Craig Lewis Passing Gas: Policy Implications of Leakage from Geologic Carbon Storage Sites David G. Hawkins

235

243

249

The Quality of a CO2 Repository: What is the Sufficient Retention Time of CO2 Stored Underground Erik Lindeberg

255

Implications of Surface Seepage on the Effectiveness of Geologic Storage of Carbon Dioxide as a Climate Change Mitigation Strategy Robert P. Hepple, Sally M. Benson

261

Global Constraints on Reservoir Leakage Stephen W. Pacala Retention of CO2 in Geologic Sequestration Formations: Desirable Levels, Economic Considerations and the Implications for Sequestration R&D J.J. Dooley, M.A. Wise Integrated Path Towards Geological Storage: TotalFinalElfApproach R. Bouchard, A. Delaytermoz Geologic Sequestration: An Integrated Framework for Assessing Technical, Economic, Public Acceptance, and Policy Issues Natesan Mahasenan, Elizabeth M. Cook, Prasad Saripalli CO2 Capture, Storage and Reuse Potential in Finland T. Koljonen, H. Siikavirta, R. Zevenhoven, L Savolainen The U.S. Department of Energy Carbon Sequestration Research, Development and Demonstration Program David J. Beecy, Scott Klara Potential for Geological Storage of CO2 in The Netherlands Harry C.E. Schreurs

267

273

279

285

291

297 303

GEOLOGICAL STORAGE- AQUIFERS Demonstrating Storage of CO2 in Geological Reservoirs: The Sleipner and SACS Projects Tore A. Torp, John Gale

311

Japanese R&D Project for CO2 Geological Sequestration H. Koide, T. OhsumL M. Uno, S. Matsuo, T. Watanabe, S. Hongo

317

Geological Characterization of CO2 Storage Sites: Lessons from Sleipner, Northern North Sea R.A. Chadwick, P. Zweigel, U. Gregersen, G.A. Kirby, S. Holloway, P.N. Johannessen

321

Reactive Transport Modeling of Geologic CO2 Sequestration at Sleipner James W. Johnson, John J. Nitao

327

The Potential for Storing Carbon Dioxide in the Rocks Beneath the UK Southern North Sea Michelle Brook, Karen Shaw, Ceri Vincent, Sam Holloway

333

Effective CO2 Storage Capacity in Aquifers, Gas Fields, Oil Fields and Coal Fields A. Obdam, L. van der Meer, F. May, C. Kervevan, N. Bech, A. Wildenborg

339

GEOLOGICAL S T O R A G E - MONITORING Monitoring of CO2 Injected at Sleipner Using Time Lapse Seismic Data R. Arts, O. Eiken, A. Chadwick, P. Zweigel, L. van der Meer, B. Zinszner

347

Monitoring Carbon Dioxide Sequestration Using Electrical Resistance Tomography (ERT): A Minimally Invasive Method R.L. Newmark, A.L. Ramirez, W.D. Daily

353

Laboratory Measurements of Seismic Wave Velocity by CO2 Injection in Two Porous Sandstones Ziqiu Xue, Takashi Ohsumi, Hitoshi Koide

359

Geochemical Monitoring of Fluid-Rock Interaction and CO2 Storage at the Weyburn CO2-lnjection Enhanced Oil Recovery Site, Saskatchewan, Canada S. Emberley, I. Hutcheon, M. Shevalier, K. Durocher, W.D. Gunter, E.H. Perkins

365

Crossweli Seismic and Electromagnetic Monitoring of CO2 Sequestration G. Michael Hoversten, Roland Gritto, Thomas M. Daley, Ernest L. Majer, Larry R. Myer

371

Sensitivity and Cost of Monitoring Geologic Sequestration Using Geophysics Larry R. Myer, G. Michael Hoversten, Erika Gasperikova

377

GEOLOGICAL STORAGE - ENHANCED OIL RECOVERY Geologic Storage of CO2 in a Carbonate Reservoir within the Williston Basin, Canada: An Update S. G. Whittaker, B. Rostron Soil Gas as a Monitoring Tool of Deep Geological Sequestration of Carbon Dioxide: Preliminary Results from the EnCana EOR Project in Weyburn, Saskatchewan (Canada) M.H. Strutt, S.E. Beaubien, J.C. Beaubron, M. Brach, C. CardellinL R. GranierL D.G. Jones, S. Lombardi, L. Penner, F. QuattrocchL N. Voltatorni

385

391

Storage of C02 in Depleted Hydrocarbon Reservoirs on Low-permeability Chalk N. Bech, P. Frykman

397

C02 Sequestration in Depleted Oil Reservoirs D. Bossie-Codreanu, Y. Le-Gallo, J.P. Duquerroix, N. Doerler, P. Le Thiez

403

xii

GEOLOGICAL STORAGE - NATURAL ANALOGUES The French Carbogaseous Province: An Illustration of Natural Processes of CO2 Generation, Migration, Accumulation and Leakage Isabelle Czernichowski-Lauriol, H~lkne Pauwels, Philippe Vigouroux, Yves-Michel Le Nindre Natural CO2 Accumulations in Europe: Understanding Long-Term Geological Processes in CO2 Sequestration J.M. Pearce, J. Baker, S. Beaubien, S. Brune, I. Czernichowski-Lauriol, E. Faber, G. Hatziyannis, A. Hildenbrand, B.M. Krooss, S. Lombardi. A. Nador, H. Pauwels, B.M. Schroot Natural CO2 Reservoirs on the Colorado Plateau and Southern Rocky Mountains, USA. A Numerical Model S.P. White, R.G. Allis, J. Moore, T. Chidsey, C. Morgan, W. Gwynn, M. Adams Production Operations at Natural CO2 Fields: Technologies for Geologic Sequestration S.H. Stevens, C. Fox, T. White, S. Melzer, C. Byrer The Ladbroke Grove-Katnook Carbon Dioxide Natural Laboratory: A Recent CO2 Accumulation in a Lithic Sandstone Reservoir Maxwell N. Watson, Naoko Zwingmann, Nicholas M. Lemon

411

417

423

429

435

GEOLOGICAL STORAGE - CODE COMPARISONS Mixing of CO2 and CH4 in Gas Reservoirs: Code Comparison Studies C.M. Oldenburg, D.H. -S. Law, Y. Le Gallo, S.P. White

443

Numerical Investigations of Multifluid Hydrodynamics During Injection of Supercritical CO2 into Porous Media M.D. White, B.P. McGrail

449

Measurements of Feldspar Dissolution Rates Under Supercritical CO2-Water-Mineral System Based on Nanoscale Surface Observation M. Sorai, T. OhsumL M. lshikawa

457

Code Intercomparison Builds Confidence in Numerical Models for Geologic Disposal of CO2 463 Karsten Pruess, Andreas BielinskL Jonathan Ennis-King, Yann Le Gallo, Julio Garcia, Kristian Jessen, Tony Kovscek, David H.-S. Law, Peter Lichtner, Curt Oldenburg, Rajesh Pawar, Jonny Rutqvist, Carl Steefel, Bryan Travis, Chin-Fu Tsang, Stephen White, Tianfu Xu

GEOLOGICAL STORAGE - SAFETY Are Disused Hydrocarbon Reservoirs Safe for Geological Storage of CO2? J.A. Jimenez, R.J. Chalaturnyk

471

Geological Sequestration of CO2: Is Leakage Unavoidable and Acceptable? Michael A. Celia, Stefan Bachu

477

Effects of Supercritical CO2 on the Integrity of Cap Rock I. Okamoto, X. LL T. Ohsumi

483

Xlll

The Long-term Fate of CO2 Injected into an Aquifer Erik Lindeberg, Per Bergmo Building Geomechanical Models for the Safe Underground Storage of Carbon Dioxide in Porous Rock Jurgen E. Streit, Richard R. Hillis

489

495

Mechanical Stability of the Potential CO2 Sequestration Sites in Japan X. Li, H. Koide, T. Ohsumi, Q. Li, Z. Wu

501

Rate of Dissolution due to Convective Mixing in the Underground Storage of Carbon Dioxide J. Ennis-King, L. Paterson

507

Risk and Hazard Assessment for Projects Involving the Geological Sequestration of CO2 K.P. Saripalli, N.M. Mahasenan, E.M. Cook

511

Transmission of CO2- Safety and Economic Considerations John Gale, John Davison

517

Engineering and Economic Assessment of CO2 Sequestration in Saline Reservoirs Neeraj Gupta, Larry Smith, Bruce Sass, Sandip Chattopadhyay, Charles W. Byrer

523

GEOLOGICAL

STORAGE

- ECBM

Fundamental Tests on Carbon Dioxide Sequestration into Coal Seams K. Ohga, K. Sasaki, G. Deguchi, M. Fujioka Methane Displacement Desorption in Coal by CO2 Injection: Numerical Modelling of MultiComponent Gas Diffusion in Coal Matrix J.Q. Shi, S. Durucan

531

539

Economic Assessment of CO2 Sequestration in Coal Seams Sohei Shimada, Teru Matsui, Takeshi Sekiguchi, Yukari Sakuragi

545

The Injectivity of Coalbed CO2 Injection Wells P.A. Fokker, L.G.H. van der Meer

551

CoaI-Seq Project Update: Field Studies of ECBM Recovery/CO2 Sequestration in Coalseams Scott Reeves

557

Comparison of Numerical Simulators for Greenhouse Gas Storage in Coalbeds, Part II: Flue Gas Injection David H.-S. Law, L.H.G. van der Meer, W.D. Gunter Development of a Field Experiment of CO2 Storage in Coal Seams in the Upper Silesian Coal Basin of Poland (RECOPOL) F. van Bergen, H.J.M. Pagnier, L.G.H. van der Meer, F.J.G. van den Belt, P.L.A. Winthaegen, R.S. Westerhoff Surface Facilities Computer Model" An Evaluation Tool for Enhanced Coalbed Methane Recovery Doug Macdonald, Sam Wong, Bill Gunter, Rick Nelson, Bill Reynen

563

569

575

xiv

GEOLOGICAL STORAGE - E N H A N C E D O I L R E C O V E R Y A N D NEW DEMONSTRATION P R O J E C T S Frio Brine Sequestration Pilot in the Texas Gulf Coast Susan D. Hovorka, Paul R. Knox

583

CRUST: CO2 Reuse Through Underground Storage Willem Grootheest, Jan- Willem DO'k, Peter Stollwerk, Harry Schreurs

589

A Cleaner Development: The In Salah Gas Project, Algeria F.A. Riddiford, A. TourquL C.D. Bishop, B. Taylor, M. Smith

595

CO2 Underground Storage for Snohvit Gas Field Development T. Maldal, I.M. Tappel

601

GEOLOGICAL STORAGE - MATCHING SINKS AND SOURCES Defining Optimum CO2 Sequestration Sites for Power and Industrial Plants V.A. Kuuskraa, L.J. Pekot

609

CO2 Geological Storage Economics Guy Allinson, Victor Nguyen

615

Geologic Storage of CO2 from Refining and Chemical Facilities in the Midwestern United States Neerja Gupta, Bruce Sass, Sandip Chattopadhyay, Joel Sminchak, Peng Wang, Tony Espie

621

Mathematical Programming Techniques for Designing Minimum Cost Pipeline Networks for CO2 Sequestration H. Y. Benson, J.M. Ogden

627

Australia's CO2 Geological Storage Potential and Matching of Emission Sources to Potential Sinks J. Bradshaw, G. Allinson, B.E. Bradshaw, K Nguyen, A.J. Rigg, L. Spencer, P. Wilson

633

Worldwide Selection of Early Opportunities for CO2-EOR and CO2-ECBM (1) F. van Bergen, A.F.B. Wildenborg, J. Gale, K.J. Damen Worldwide Selection of Early Opportunities for CO2-EOR and CO2-ECBM (2): Selection and Analysis of Promising Cases Kay Damen, Andrd Faaij, Frank van Bergen, Erik Lysen

639

645

A Decision Support System for Underground CO2 Sequestration P.J.P. Egberts, J.F. Keppel, A.F.B. Wildenborg, M.R.H. Peersmann, C. Hendriks, A.S. van der Waart, C. Byrman

651

Saline Aquifer Storage of CO2 from Major Point Sources - A Danish Case Study Michael Larsen, Niels Peter Christensen, Torben Bidstrup

657

xv

GEOLOGICAL S T O R A G E - MINERALS A Program to Develop CO2 Sequestration via Mineral Carbonation Philip Goldberg, Richard Walters

665

Mineral Carbonation and ZECA L. Jia, E.J. Anthony

671

Carbon Dioxide Sequestration by Aqueous Mineral Carbonation of Magnesium Silicate Minerals S.J. Gerdemann, D.C. Dahlin, W.K. O'Connor Carbon Dioxide/Limestone/Water Emulsion for Ocean and Geologic Sequestration of CO2 Dan S. Golomb

677

683

GEOLOGICAL STORAGE - NEW DEVELOPMENTS Economic Feasibility of Carbon Sequestration with Enhanced Gas Recovery (CSEGR) C.M. Oldenburg, S.H. Stevens, S.M. Benson

691

Methanogenic Activity on Coal and Sequestered CO2 for Enhanced Coalbed Methane Recovery K. Budwill, A. Beaton, M. Bustin, K. Muehlenbachs, W.D. Gunter

697

Carbon Sequestration in Coal Seams in Japan and Biogeochemical Carbon Cycle in Tertiary Sedimentary Basins H. Koide, S. Nishimura, S. SatsumL Z. Xue, X. Li

703

In-situ Gasification, Enhanced Methane Recovery and CO2 Storage in Deep Coal Seams James Hetherington, Kelly Thambimuthu

OCEAN STORAGE

-

709

OVERVIEW

On the Production and Use of Scientific Knowledge about Ocean Sequestration Peter M. Haugan

719

Sensitivity of Sequestration Efficiency to Mixing Processes in the Global Ocean B.K. Mignone, J.L. Sarmiento, R.D. Slater, A. Gnanadesikan

725

The Second Phase of Japanese R&D Program for CO2 Ocean Sequestration Shigeo Murai, Takashi Ohsumi, Fumiyasu Nishibori, Masahiko Ozaki

733

In Situ Experiments of Cold CO2 Release in Mid-depth I. Aya, R. Kojima, K. Yamane, P.G. Brewer, E.T. Peltzer, IlL

739

OCEAN

STORAGE

- NEAR

FIELD

BEHAVIOUR

On the Fate of a Purposefully Disposed CO2 Lake in the Deep Ocean Iker Fer, Peter M. Haugan

747

xvi

Modeling Descending Carbon Dioxide Injections in the Ocean Eric J. Wannamaker, E. Eric Adams

753

Modelling of Biological Impact in Direct Injection of Carbon Dioxide in the Ocean Toru Sato

759

A

Sinking Plume Model for Deep CO2 Discharge G.C. Nihous, L. Tang, S.M. Masutani

765

A Hybrid Numerical Model of LCO2 and CO2 Enriched Seawater Dynamics in the Ocean Induced By Moving-ship Releasing B. Chen, Y. Song, M. Nishio, M. AkaL T. Ohsumi

771

OCEAN STORAGE - EXPERIMENT Research Results from the International Collaboration on Ocean Carbon Sequestration Ocean Engineering G. C. Nihous

779

Plume Experiments and Modelling Eric Adams, Norikazu Nakashiki, Baixin Chen, Toru Sato, Guttorm Alendal

785

International Field Experiment Nozzle and Large Tank Studies S.M. MasutanL M. Nishio, M. Ozaki

791

OCEAN STORAGE

-

IMPACTS/CORAL REEF

Ocean Carbon Sequestration: A Case Study in Public and Institutional Perceptions M.A. de Figueiredo, D.M. Reiner, H.J. Herzog

799

Influence of Ocean CO2 Sequestration on Bacterial Elemental Cycling Richard B. Coffin, Michael T. Montgomery, Thomas J. Boyd, Stephen M. Masutani

805

Evasion of CO2 Injected into the Ocean in the Context of CO2 Stabilization Haroon S. Kheshgi

811

Possibility of High CO2 Fixation Rate by Coral Reef Ecosystems K. Yamada, Y Suzuki, B.E. Casareto, H. Komiyama

817

OCEAN STORAGE - LIQUID AND HYDRATE/MESOCOSM Dual Nature of CO2 Solubility in Hydrate Forming Region R. Kojima, K. Yamane, I. Aya

825

Liquid CO2 Droplet Spectra L. Tang, T.J. Gorgas, S.M. Masutani

831

Experimental Studies on Liquid CO2 Injection with Hydrate Film and Highly Turbulent Flows Behind the Releasing Pipe S. Tsushima, S. HiraL H. Sanda, S. Terada

837

xvii

Development of a Formation Process of CO2 Hydrate Particles for Ocean Disposal of CO2 Satoko Takano, Akihiro YamasakL Keiichi Ogasawara, Fumio Kiyono, Minoru Fujii, Yukio Yanagisawa

843

Impacts of CO2 on Microbial Communities in a Mesocosm Experiment K. TakeuchL alL. SugimorL S. Furukawa, Y. Fujioka, J. Ishizaka

849

Efficiency and Effects of Carbon Sequestration Through Ocean Fertilization: Results from a Model Study Anand Gnanadesikan, Jorge L. Sarmiento, Richard D. Slater

E N E R G Y

855

MODELING

Modeling Greenhouse Gas Energy Technology Responses to Climate Change James A. Edmonds, John Clarke, James Dooley, Son H. Kim, Steven ,I. Smith

863

Prospects for the Application of Energy Models in the Design of Climate Policies J. Harnisch, M. Koch, N. HOhne, K. Blok

869

Multiple Gas Reduction Strategy A. Kurosawa

875

Exploring Implications to 2050 of Energy-Technology Options for China E.D. Larson, P. DeLaquil, Z. Wu, W. Chen, P. Gao

881

CO2 Emission Reduction Effect of Cogeneration System in Commercial and Residential Sectors Considering Long-Term Power Generation Mix in Japan Ryoichi Komiyama, Kenji YamajL Yasumasa Fujii

889

An Optimal Energy and Greenhouse Gas Mitigation Path for South Africa in the Short to Medium Term M.I. Howells, M. Solomon

895

ELSA - Energy Linkage Structure of Asia - A Middle Term Multiregional Model for the Assessments of Energy and Environmental Technology Options Shunsuke Mori, Tomohiro Furuse, Kiyoshi Dowaki

901

Modelling Impacts of New Power Generation Facilities and Renewable Technologies on Greenhouse Gas Emissions in Saskatchewan, Canada Q.C. L in, G.H. Huang, B. Bass

907

Evaluation of Carbon Sequestrations in Japan with a Mathematical Model Keigo Akimoto, Hironori Kotsubo, Takayoshi Asami, Xiaochun LL Motoo Uno, Toshimasa Tomoda, Takashi Ohsumi Assessment of CO2 Emissions Reduction Potential by Using an Optimization Model for Regional Energy Supply Systems Y. GenchL K. Saitoh, N. Arashi, H. Yagita, A. Inaba A Role for Renewables Toward Sustainable Energy Systems Hiromi Yamamoto

913

919

925

xviii

Life Cycle GHG Emissions for FCVS in Japan B. Heffelfinger Reduction Potential of CO2 Reduction by Integrated Energy Service System in Urban Area Considering the Generation Mix of Electric Utility Kazutoshi Ikeda, Kiichiro TsujL Hideharu Sugihara, Jun Komoto

931

937

Ranking of Global Energy Systems as Environmental Countermeasure Takaoshi AsamL Motoo Uno, Norifumi Matumiya, Senji Niwa

943

Environmental Evaluation of Introducing Electric Trolley Buses Yuki Kudoh, Hisashi IshitanL Ryuji Matsuhashi, Yoshikuni Yoshida

949

VOLUME II ENERGY EFFICIENCY - GENERAL Energy Efficiency and Environmental Implications in India's Household Sector B. Sudhakara Reddy Effect on CO2 Reduction of Installation of Outer Skin Surface Technologies in Houses and Office Buildings Tomohiko Ihara, Takashi Handa, Ryuji Matsuhashi, Yoshikuni Yoshida, Hisashi Ishitani Evaluation of RDF Power Generation of Large-area Waste Treatment by LCA Nagisa Komatsu, Tomoko Iwata, Sohei Shimada Contributing to Reduction of CO2 Emissions Through Development of a Heat-integrated Distillation Column M. Nakaiwa, K. Huang, T. Endo, T. OhmorL T. Akiya, T. Takamatsu, S. Beggs, C. Pritchard Effect of Fluctuation of Hot-water Demand on Actual Performance of Home Co-generation System Takeyoshi Kato, Siori Kasugai, Tetsuhisa lida, Wu Kai, Yasuo Suzuoki Literature Survey on Economics of Environmental Friendly Electricity Production Takeyoshi Kato

957

963

969

975

981

987

E N E R G Y EFFICIENCY - INDUSTRY

The Cement Industry and Global Climate Change: Current and Potential Future Cement Industry CO2 Emissions Natesan Mahasenan, Steve Smith, Kenneth Humphreys

995

Improvement in Energy Efficiency of Re-rolling Furnaces for Stainless Steel Industry at Jodhpur, Rajasthan, India UP. Singh

1001

Implementation of a Corporate-wide Process for Estimating Energy Consumption and Greenhouse Gas Emissions from Oil and Gas Industry Operations Susann Nordrum, Arthur Lee, Georgia Callahan

1007

xix

Thermoneutral Co-production of Metals and Syngas without Greenhouse Gas Emissions M. Halmann, A. SteinfeM

1013

An Analytical Method of Constructing Best-mixed Power Generation Systems Reflecting Public Preference R. Akasaka, N. Shikasho, K. Morita, K. Fukuda

1019

Application of the API Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry to Examine Potential Emission Reductions K. Ritter, S. Nordrum, T. Shires

1025

Cleaner Production Technology and Bankable Energy Efficiency Drives in Fertilizer Industry in India to Minimise Greenhouse Gas Emissions - Case Study Surendra Kumar

1031

CO2 Reduction in the Ironmaking Process by Waste Recycling and By-product Gas Conversion J. G. Kim, J. O. Choi

1037

ZERO EMISSION P O W E R PLANTS

Clean Coal-fired Power Plant Technology to Address Climate Change Concerns W.A. Campbell, W.H. Richards

1045

An 865 MW Lignite Fired CO2 Free Power Plant - A Technical Feasibility Study Klas Andersson, Henrik Birkestad, Peter Maksinen, Filip Johnsson, Lars StrOmberg, Anders Lyngfelt

1051

Recent Developments on Flue Gas CO2 Recovery Technology Tomio Mimura, Takashi Nojo, Masaki Iij'ima, Takashi Yoshiyama, Hiroshi Tanaka

1057

IGCC - The Best Choice for Producing Low-CO2 Power G. Haupt, G. Zimmermann, R. Pruschek, G. Oeljeklaus

1063

Modeling Infrastructure for a Fossil Hydrogen Energy System with CO2 Sequestration Joan M. Ogden

1069

ECONOMICS A CO2-1nfrastructure for EOR in the North Sea (CENS): Macroeconomic Implications for Host Countries P. Markussen, J.M. A ustell, C- W. Hustad

1077

Economic Modeling of the Global Adoption of Carbon Capture and Sequestration Technologies J.R. McFarland, H.J. Herzog, J. Reilly

1083

Economic Benefits of a Technology Strategy and R&D Program in Carbon Sequestration S. Klara, D. Beecy, V. Kuuskraa, P. DiPietro

1089

xx

Prospects for Carbon Capture and Sequestration Technologies Assuming Their Technological Learning Keywan Riahi, Edward S. Rubin, Leo Schrattenholzer CO2 Storage and Sink Enhancements: Developing Comparable Economics B.R. Bock, R.G. Rhudy, H.J. Herzog Carbon Management Strategies for Existing U.S. Generation Capacity: A Vintage-based Approach R.T. Dahowski, J.J. Dooley

1095

1101

1107

Examining Planned U.S. Power Plant Capacity Additions in the Context of Climate Change J.J. Dooley, R.T. Dahowski

1113

Uncertainties in C02 Capture and Sequestration Costs E.S. Rubin, A.B. Rao

1119

Costs of Renewable Energy and CO2 Capture and Storage John Davison

1125

Costs and Performance of CO2 and Energy Transmission D.J. Freeman, D.A. Findlay, M. Bamboat, J. Davison, I. Forbes

1131

POLICY - OVERVIEW Experience Curves for Environmental Technology and Their Relationship to Government Actions E.S. Rubin, M.R. Taylor, S. Yeh, D.A. Hounshell

1139

Greenhouse Gas Intensity Targets vs. Absolute Emission Targets N. HOhne, J. Harnisch

1145

Canadian Initiatives on CO2 Capture and Storage: Towards Zero Emissions from Fossil Fuels Kelly Thambimuthu, Gilles Mercier, Malcolm Wilson, Bob Mitchell, Mahmuda Ali

1151

Australia's Renewable Energy Certificate System David Rossiter, Karla Wass

1157

Financial Incentives for Climate Neutral Energy Carriers Chris Hendriks, Mirjam Harmelink, Rob Cuelenaere

1163

POLICY - KYOTO PROTOCOL Possible Imperfection of International Emissions Trading Under the Existence of Hot Air Akira Maeda The Effect of Emissions Trading and Carbon Sequestration on the Cost of CO2 Emissions Mitigation Natesan Mahasenan, Michael J. Scott, Steven J. Smith

1171

1177

xxi

CO2 Emissions Trading Market Systems as an Environmental Policy Option and Assessment of its Effect - Evaluating Intertemporal Trading in Particular Kazuya Fujime CDM Investment: Market Actors' Perceptions J. Buen Potential Evaluation of CO2 Emissions Reduction by CDM Projects - Project Design to Provide Benefit to Both Developed and Developing Countries Takanobu KosugL Weisheng Zhou, Koji Tokimatsu Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change Chris Hendriks, David de Jager, Jochen Harnisch, Judith Bates, Leonidas Mantzos, Matti Vainio New Renewable Energy Innovation Partnerships: Elements of a Constructive Carbon Strategy for Norway's Industry and Government J. Buen

1183

1189

1195

1201

1207

Optimization of Natural-gas Utilization at Lanzhou City in China Tetsuo Tezuka, Cheng Min Xin

1213

Potential for Co-utilisation of Coal with Other Fuels to Reduce Greenhouse Gas Emissions I.M. Smith, d.M. Topper

1219

Commercial Viability of Space Solar Power System as a CDM Project Iwao Matsuoka, Tetsuo Tezuka, Takamitsu Sawa

1225

Study on Effective Institutions to Make CDM Projects Viable Ryuji MatsuhashL Sei Fujisawa, Wataru Mitamura, Yutaka Momobayashi, Yoshikuni Yoshida

1231

Economic and Greenhouse Gas Emissions Assessment of Excess Biomass Extracted from Future Kraft Pulp Mills A. ,~dahl, S. Harvey, T. Berntsson Transportation, CDM, and GHG Emission Reductions Ming Yang, )(in Yu

1237

1243

NON-CO2 GASES An Assessment of the Abatement Options and Costs for Reducing the Emissions of the Engineered Chemicals J. Harnisch, J. Gale, David de Jager, Ole Stobbe

1251

Potential Reduction of Fluorocarbon Emissions Under the Enforcement of New Laws in Japan 1257 T. Hanaoka, Y. Yoshida, R. MatsuhashL H. Ishitani Direct Global Warming Emissions from Flat Panel Display Manufacturing and Reduction Opportunities Scott C. Bartos, C. Shepherd Burton

1263

xxii New Alternative Gas Process Feasibility Study for PFC Emission Reduction from Semiconductor CVD Chamber Cleaning Tatsuro Beppu, Yuki Mitsui, Katsuo SakaL Akira Sekiya

1269

RD&D Implications of Multigas Radiative Forcing Scenarios D. Beecy, I~. Kuuskraa, P. DiPietro

1275

Dynamic Model for the Methane Emission from Manure Storage M.A. Hilhorst, R.M. de Mol

1281

Coal Mine Ventilation Air Methane Catalytic Combustion Gas Turbine S. Su, A. C. Beath, C. W. Mallett

1287

The Effective Management of Methane Emissions from Natural Gas Pipelines S. Venugopal

1293

Nitrous Oxide Emission from Purification of Liquid Portion of Swine Waste Takashi Osada

1299

FUEL CELLS

High Efficiency Carbon and Hydrogen Fuel Cells for CO2 Mitigated Power M. Steinberg, J.F. Cooper, N. Cherepy

1307

Multi-criteria Optimization of On-site Heating, Cooling and Power Generation with Solid Oxide Fuel Cells - Gas Turbine Combined Cycle Units K. Tanaka, M. Buret, D. Favrat, K. Yamada

1311

Optimised CO2 Avoidance Through Integration of Enhanced Oil and Gas Recovery with Solid Oxide Fuel Cells T. Clemens, M. Haines, W. Heidug

1319

An Experimental Investigation into the Use of Molten Carbonate Fuel Cells to Capture CO2 from Gas Turbine Exhaust Gases A. AmorellL M.B. Wilkinson, P. Bedont, P. Capobianco, B. Marcenaro, F. Parodi, A. Torazza

1325

High Efficiency CO2 Separation and Concentration System by Using Molten Carbonate Kazuhiko Itou, Hidehisa TanL Yu Ono, Hidekazu Kasai, Ken-ichiro Ota

1331

RENEWABLE ENERGY

Renewable Energy: Prospects for Supplying Electricity in the Deregulated Market in the Philippines Jude Anthony N. Estiva, Ma. Aileen Leah G. Guzman

1337

Technological Options for Cost-effective and Eco-friendly Power Generation for Development of Remote and Rural Areas in India R. Prasad, D.I). Misra

1343

Greening Electricity Generation in South Africa Through Wind Energy Joe dsamoah

1349

xxiii

Greenhouse Gas Mitigation Opportunities Through the Application of Solar Power in Bangladesh Ahsan Uddin Ahmed Corporate Environmentalism in India: Social and Community Issues R.K. Khullar

1353

1359

BIOMASS

Biomass Energy with Geological Sequestration of CO2: Two for the Price of One? James S. Rhodes, David W. Keith

1371

Modelling Bio-energy with Carbon Storage (BECS) in a Multi-region Version of FLAMES P. Read, J. Lermit, P. Kathirgamanathan

1377

A Life Cycle Analysis of Biomass Energy System Taking Sustainable Forest Management into 1383 Consideration Kiyoshi Dowaki, Shunsuke Mori, Hitofumi Abe, Pauline F. Grierson, Mark A. Adams, Nalish Sam, Patrick Nimiago The Synthesis of Clean Fuels from CO2 Rich Biosyngas Kyu-Wan Lee, Jae-Sung Ryu

1389

Reduced CO2 Mitigation Costs by Multi-functional Biomass Production P. BOrjesson, G. Berndes

1395

New Fuel BCDF (Bio-Carbonized-Densified-Fuel): The Effect of Semi-carbonization T. Honjo, M. Fuchihata, T. Ida, H. Sano

1401

New Renewable Energy Innovation Partnerships: Elements of a Constructive Carbon Strategy for Norway's Industry and Government J. Buen

1407

Carbon Sequestration in Plantations and the Economics of Energy Crop Production: The Case of Salix Production in Sweden G. Berndes, P. BOrjesson, C. Azar

1413

Greenhouse Gas Emissions from Bio-ethanol and Bio-diesel Fuel Supply Systems Haroon S. Kheshgi, David J. Rickeard

1419

BIOTECHNOLOGY AND UTILISATION The Potential Role of Biotechnology in Addressing the Long-term Problem of Climate Change in the Context of Global Energy and Economic Systems James A. Edmonds, John Clark, James Dooley, Son H. Kim, R. Izaurralde, N. Rosenberg, G.M. Stokes The Controlled Eutrophication Process: Using Microaigae for CO2 Utilization and Agricultural Fertilizer Recycling J.R. Benemann, J.C. Van Olst, M.J. Massingill, J.A. Carlberg, J.C. Weissman, D.E. Brune

1427

1433

xxiv

The Improvement of Microalgal Productivity by Reducing Light-harvesting Pigment Analysis of a Phycocyanin-deficient Mutant of Synechocystis PCC 6714 Yuji Nakajima, Shoko Fujiwara, Mikio Tsuzuki

1439

Effective C02 Removal by Chlorella sp.HA-1 in Various Cultivation Methods Ji- Won Yang, Tae-Soon Kwon, Jae- Young Lee

1445

Enzymatic Synthesis of Pyruvic Acid and L-Lactic Acid from Carbon Dioxide Masaya Miyazaki, Hiroyuki Nakamura, Hideaki Maeda

1451

LAND USE AND SINKS

Analysis of Agricultural Greenhouse Gas Mitigation Options Within a Multi-sector Economic Framework R.D. Sands, B.A. McCarl, D. Gillig, G.J. Blanford

1459

CSiTE Studies on Carbon Sequestration in Soils G. Marland, C.T. Garten Jr., W.M. Post, T.O. West

1465

Microagriculture - Biofixation of CO2 Using Nitrogen-fixing Microalgae in Rice Fields Y Ikuta

1471

Possibility of CO2 Fixation on Arid Land in Western Australia K. Yamada, T. Kojima, Y. Egashira, Y Abe, M. Saito, N. Takahashi

1477

UTILISATION - ALGAE CO2 Reforming of Methane Catalyzed by Ni-loaded Zeolite-based Catalysts Satoru Murata, Nobuyuki Hatanaka, Hiroharu lnoue, Koh Kidena, Masakatsu Nomura

1485

Promotion of CO2 Hydrogenation in Fixed Bed Recycle Reactors M.J. Choi, J.S. Kim, S.B. Lee, W.Y. Lee, K.W. Lee

1491

The Use of Marine Macroalgae as Renewable Energy Source for Reducing CO2 Emissions M. Aresta, A. Dibenedetto, I. Tommasi, E. Cecere, M. NarraccL A. PetrocellL C. Perrone

1497

Design Parameters of Solar Concentrating Systems for CO2-mitigating Algal Photobioreactors 1503 Eiichi Ono, Joel L. Cuello

PANEL DISCUSSIONS

Public Outreach on CO2 Sequestration Chair: Paul Freund

1511

The Role of Industry in the Strategy for Mitigating Global Warming Chair: Baldur Eliasson

1525

xxv

POSTER PAPERS COs CAPTURE International CO2 Capture Test Network J.M. Topper

1543

The International Test Centre for Carbon Dioxide Capture (ITC) M. Wilson, P. Tontiwachwuthikul, A. Chakma, R. Idem, A. Veawab, A. Aroonwilas, D. Gelowitz

1547

Development of CO2 Separation Membranes (1) Polymer Membrane Hiroshi Mano, Shingo Kazama, Kenji Haraya

1551

Development of CO2 Separation Membranes (2) Facilitated Transport Membrane Kazuhiro Okabe, Norifumi Matsumiya, Hiroshi Mano, Masaaki Teramoto

1555

Evaluation of Membrane Separation Process of CO2 Recovery Norifumi Matsumiya, Hiroshi Mano, Kenji Haraya

1559

PSA Processes for Recovery of Carbon Dioxide Jong-Nam Kim, Jong-Ho Park, Hee-Tae Beum, Sang-Sup Han, Soon-Haeng Cho

1563

Numerical Study of Boiler Retrofitting to Use Recirculated Flue Gases with 02 Injection L. M.R. Coelho, ,I.L. T. Azevedo, M.G. Carvalho

1567

Precombustion Decarbonisation for Power Generation P. Freund, M.R. Haines

1571

Challenges of Recomissioning a CO2 Capture Pilot Plant in Saskatchewan, Canada Dave Skoropad, Don Gelowitz, Raphael Idem, Bob Stobbs, John Barrie

1575

Novel CO2 Absorbents Using Lithium-containing Oxides Masahiro Kato, Kenji EssakL Sawako Yoshikawa, Kazuaki Nakagawa, Hideo Uemoto

1579

Carbon Dioxide Absorption Contactors: Hollow Fibre Membranes and Packed Absorption Columns David deMontigny, Paitoon Tontiwachwuthikul, Amit Chakma

1583

New Column Design Concept for CO2 Absorbers Fitted with Structured Packings A. Aroonwilas, A. Chakma, A. Veawab, P. Tontiwachwuthikul

1587

Heat Stable Salts and Corrosivity in Amine Treating Units W. Tanthapanichakoon, A. Veawab

1591

Corrosion in CO2 Capture Unit for Coal-fired Power Plant Flue Gas A. Veawab

1595

New Amines for the Reversible Absorption of Carbon Dioxide from Gas Mixture Michele Aresta, Angela Dibenedetto

1599

xxvi Carbon Dioxide Absorption with Aqueous Potassium Carbonate Promoted by Piperazine J. Tim Cullinane, Gary T. Rochelle

1603

GEOLOGICAL STORAGE Effect of Pressure, Temperature, and Aqueous Carbon Dioxide Concentration on Mineral Weathering as Applied to Geologic Storage of Carbon Dioxide Robert G. Bruant Jr., Daniel E. Giammar, Satish C.B. MynenL Catherine ,4. Peters

1609

Advanced Centrifugal Compressors for CO2 Re-injection Plant ,4kinori Tasaki, Tsunenori Sato, Norihisha Wada

1613

Reactivity of Injected CO2 with the Usira Sand Reservoir at Sleipner, Northern North Sea I. Czernichowski-Lauriol, C.A. Rochelle, E. Brosse, N. Springer, K. Bateman, C. Kervevan, J.M Pearce, B. Sanjuan, H. Serra

1617

Carbon Dioxide Sequestration in Saline Brine Formations John M. ,4ndr~sen, Matthew L. Druckenmiller, M. Mercedes Maroto-Valer

1621

The GEO-SEQ Project: A Status Report Larry R. Myer, Sally M. Benson, Charles Byrer, David Cole, Christine A. Doughty, William Gunter, G. Michael Hoversten, Susan Hovorka, James W. Johnson, Kevin G. Knauss, Anthony Kovscek, David Law, Marcelo J. Lippmann, Ernest L. Majer, Bert van der Meet, Gerry Moline, Robin L. Newmark, Curtis M. Oldenburg, Franklin M. Orr, Jr., Karsten Pruess, Chin-Fu Tsang

1625

The lEA Weyburn CO2 Monitoring Project - The European Dimension J.B. Riding, I. Czernichowski-Lauriol, S. Lombardi, F. QuattrocchL C.,4. Rochelle, D. Savage, N. Springer

1629

Preliminary Characterisation of Regional Hydrogeology at the CO2 Sequestration Site of Weyburn (SK-Canada) Y.M. Le Nindre, I. Czernichowski-Lauriol, S. Bachu, T. Heck Use and Features of Basalt Formations for Geologic Sequestration B.P. McGrail, ,4.M. Ho, S.P. Reidel, H.T. Schaef

1633

1637

Evaluation of CO2 Sequestration in Saline Formations Based on Geochemical Experiments and 1641 Modeling Bruce M. Sass, Neeraj Gupta, Sandip Chattopadhyay, Jennifer Ickes, Charles ~ Byrer Capacity Investigation of Brine-bearing Sands for Geologic Sequestration of CO2 Christine Doughty, Sally M. Benson, Karsten Preuss Cost Comparison Among Concepts of Injection for CO2 Offshore Underground Sequestration Envisaged in Japan Hironori Kotsubo, Takashi Ohsumi, Hitoshi Koide, Motoo Uno, Takeshi Ito, Toshio KobayashL Kozo lshida

1645

1649

Rate of Dissolution Due to Convective Mixing in the Underground Storage of Carbon Dioxide 1653 J. Ennis-King, L. Paterson

xxvii

Potential Effect of CO2 Releases from Deep Reservoirs on the Quality of Fresh-water Aquifers 1657 P.R. Jaffe, S. Wang Economics of Acid Gas Reinjection: An Innovative CO2 Storage Opportunity Sam Wong, David Keith, Edward Wichert, Bill Gunter, Tom McCann

1661

OCEAN STORAGE Advances in Deep-ocean CO2 Sequestration Experiments P.G. Brewer, E.T. Peltzer, G. Rehder, R. Dunk

1667

Study on CO2 Hydrate Formation as Stockpiling in Marine Sediments Hironori Haneda, Yoshitaka Yamamoto, Takeshi Komai, Kazuo Aoki, Taro Kawamura, Koutaro Ohga

1671

Measurements of CO2 Solution Density Under Deep Ocean and Underground Conditions M. Nishio, Y. Song, B. Chen

1675

Estimations of Interfacial Tensions Between Liquid CO2 and Water from the Sessile-Drop Observations T. Uchida, R. Ohmura, S. Takeya, J. Nagao, H. Minagawa, T. Ebinuma, H. Narita Lethal Effect of Elevated pCO2 on Planktons Collected from Deep Sea in North Pacific Y. Watanabe, A. Yamaguchi, H. Ishida, T. Ikeda, J. Ishizaka Thermodynamic Relationship to Estimate the Effects of High CO2 Concentration on the CO2 Equilibrium and Solubility in Seawater C.S. Wong, P.Y. Tishchenko, W.K. Johnson The GOSAC Project to Predict the Efficiency of Ocean CO2 Sequestration Using 3-D Ocean Models James C. Orr, Olivier Aumont, Andrew Yool, Gian-Kasper Plattner, Fortunat Joos, Ernst Maier-Reimer, Marie-France Weirig, Reiner Schlitzer, Ken Caldeira, Michael Wickett, Richard Matear, Bryan Mignone, Jorge Sarmiento, John Davison Effects of CO2 on Marine Fish J. Kita, A. Ishimatsu, T. Kikkawa, M. Hayashi

1679

1683

1687

1691

1695

E N E R G Y EFFICIENCY

Analysis of Ways of Energy Consumption Reduction While Carbon Dioxide Recovery from Flue Gas by Absorption Methods to Solve the Greenhouse Problems losif L. Leites Making Tourism in New Zealand Energy-efficient- More Than Turning Off the Lights S. Becken Study of Highly Efficient Gas Engine Driven Heat Pump System with Cascaded Use of Exhaust Heat from Engine Kazumi Takahata, Takeshi Yokoyama

1701

1705

1709

XXVIll

Analysis of Cogeneration Network Systems Effective for Reducing Greenhouse Gases Kei Kawakami, Takemi Chikahisa, Yukio Hishinuma

1713

Logics and Logistics of Life Cycle Assessment (LCA) for Minimizing Green House Gas Emissions - An Indian Case Study of Automobile Sector Sita Anand, Surendra Kumar

1717

Energy Saving in Energy Sector of the Republic of Karelia (North-West Russia) S. Y. Kulagin

1721

Reducing Greenhouse Emissions by Inherently Safe Nuclear Reactors A.R. Kenny

1725

Integrated Carbonation: A Novel Conception to Develop a CO2 Sequestration Module for Power Plants M. Mercedes Maroto- Valer, Matthew E. Kuchta, Yinzhi Zhang, John M. Andrdsen

1729

ECONOMICS

Economics of CO2 Capture from a Coal-fired Power Plant- A Sensitivity Analysis D. Singh, E. Croiset, P.L. Douglas, M.A. Douglas

1735

ENERGY MODELLING

Modelling Climate Change and Population Growth on GHG Emissions from the Energy Sector in the Toronto-Niagra Region, Canada Q. G. Lin, B. Bass, G.H. Huang

1741

Development of D.atabase on Japanese Sectoral Energy Consumption, CO2 and Air Pollutant Emission Intensities Based on the Input-output Tables Keisuke Nansai, Yuichi Moriguchi, Susumu Tohno

1745

Analysis of Market Growth Condition for Future Type of Vehicles Based on Consumer Characteristic Model Takemi Chikahisa, Yukio Hishinuma

1749

POLICY

Transportation, CDM, and GHG Emission Reductions Ming Yang, Xin Yu

1755

Emerging Carbon Offset Markets: Prospects and Challenges Patrick Karani

1761

Planning for the Diffusion of Technologies to Capture and Dispose of Carbon Elizabeth L. Malone

1765

An Analysis on CO2 Reduction Effects of Introducing Green Taxation to Car Ownership Tax Yoshikuni Yoshida, Akira Morishita, Ryuji Matsuhashi, Hisashi Ishitani

1769

xxix A Framework for Greenhouse Gas Related Decision-making with Incomplete Evidence A.J.P. Fletcher, J.P. Davis, W.W. Shenton, B. Han, J. Pang

1773

Complex Problems with Incomplete Evidence - Modelling for Decision-making A.J.P. Fletcher, J.P. Davis, W.W. Shenton, B. Han, J. Pang

1777

The Need for Renewable Energy with Emphasis on Solar in Rural Uganda Robert Kabaseke

1781

NON COs - GASES

The Non-CO2 Greenhouse Gases Network John Gale, Francisco de La Cheshnaye, Matti Vianio Reduction of Methane Production from Dairy Cows by Decreasing Ruminal Degradability of Concentrated Ingredients M. Kurihara, T. Nishida, A. Purnomoadi

1787

1791

Dynamic Model for the Methane Emission from Manure Storage M.A. Hilhorst, R.M. de Mol

1795

Separation Process of Hydrofluorocarbons (HFCs) by Clathrate Hydrate Formation Taku Okano, Kazuhiro Shiojiri, Minoru Fujii, Akihiro Yamasaki, Fumio Kiyono, Yukio Yanagisawa

1799

Low Temperature PFC Destruction System Using Surface Discharge Plasma with Catalyst Toshiaki Kato, Tatsufumi Mori, Ryu-ichiro Ohyama, Jun Tamaki

1803

Simplified Monitoring Technique of HFC Mixed Gases in a Coolant Recycle System Yoshiya Iida, Makoto Morita

1807

RENEWABLE ENERGY

CSIRO's Advanced Power Generation Technology Using Solar Thermal- Fossil Energy Hybrid Systems R. Benito, G.J. Duffy, K.T. Do, R. McNaughton, J.H. Edwards, N. Dave, M. Chesnee, C. Walters Solar Technology in Uganda for Reducing CO2 Emissions Wilbrod Birabwa

1813

1817

BIOMASS

Fossil Fuel Consumption and Biomass Energy Sources in Sri Lanka G.K. Winston de Silva, Tissa Ranasinghe Processing of Non Purified Ethanol from a Glucose Fermentation Process for Solid Oxide Fuel Cell Application Raphael Idem, Hussam Ibrahim, Paitoon Tontiwachwuthikul, Malcolm Wilson An Experimental Study on Biomass Coal Briquetting Process Yongliang Ma, Kangfu Xu, Jiming Hao

1823

1825

1829

XXX

New Fuel BCDF (Bio-Carbonized-Densified-Fuel):The Effect of Semi-Carbonization T. Honjo, M. Fuchihata, T. Ida, H. Sano Evaluation of Technology of Generating Electricity with Woody Biomass - Estimate of Reduction in CO2 Emission T. Ogi, Y. Dote

1833

1837

Carbon Sink and Storage Capacity of Forest Ecosystems in Oze, Central Japan Atsushi Hirano, Makoto Tsuchida, Michio Ishibashi, Kazuhiko Ogino

1843

Study of Durable Catalyst for Methane Reforming Using CO2 Takumi Tanaka, Zhaoyin Hou, Osamu Yokota, Tatsuaki Yashima

1847

Mitigation Potential for Carbon Sequestration Through Forestry Activities in Russia D.G. Zamolodchikov, G.N. Korovin, A.I. Utkin

1851

Forestal Biomass: Possible Extension of the Resource of Wood from Thinning in Forests H. Sano, T. Honjou, T. Ida, M. Futihata

1855

Economic Analysis of Carbon Sequestration in Cherrybark Oak in the United States Ching-Hsun Huang, Gary D. Kronrad

1859

International Network for Biofixation of CO2 and Greenhouse Gas Abatement with Microalgae P. PedronL J. Davison, H. Beckert, P. Bergman, J. Benemann

1863

CO2 Emission Reduction and CO2 Fixation on the Ground by Using Supercritical Carbon Dioxide as an Alternative to Organic Solvents Masaaki Yoshida, Masayuki Ohsaki, Naohisa Yanagihara

1867

Utilization of Carbon Dioxide for Neutralization of Alkaline Wastewater S.K. ChoL K.S. Ko, H.D. Chun, J.G. Kim

1871

Author Index

1875

ENERGY EFFICIENCYGENERAL

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

957

E N E R G Y EFFICIENCY AND E N V I R O N M E N T A L IMPLICATIONS IN INDIA'S H O U S E H O L D SECTOR B.Sudhakara Reddy Indira Gandhi Institute of Development Research, Goregaon (E), Mumbai 400 065, India e-mail:[email protected]

ABSTRACT

This present paper provides a methodological framework for estimating the costs and benefits to the household sector through the replacement of the existing inefficient technologies with efficient ones, and suggests policy measures. Annualised Life Cycle Costs (ALCC) are calculated taking into consideration the capital cost of the device, its life, operating cost, energy carrier price, etc. using a 12% discount rate. The results show that the average discounted payback period for many of these technologies, at the current capital costs, is less than two years which usually considered warranting the investment. It is seen from the results that, on average, for every hundred rupees of capital invested on efficient lighting systems, the consumer gets an annual return of about Rs.60. This shows that the rate of return on investment is very high. The paper identifies the barriers that prevent the government from achieving its energy efficiency goals, analyzes programs that address these barriers, and explores the creation of an institutional mechanism.

INTRODUCTION

Energy efficiency improvements have multiple advantages such as the efficiency of utilisation of natural resources, reducing air pollution levels, and reduced spending by the consumer on energy related expenditure. Despite these significant benefits, the government and the utilities are not integrating efficiency programmes into their planning process. From the consumers' perspective, several barriers prevent them from investing in cost-effective energy technologies. The reasons include (1) lack of initial investment for efficient technologies and (ii) lack of sufficient perceived incentives to pursue energy efficiency investments. As a result, the country is missing out on opportunities to save both in terms of energy and the environment. In the present paper, we assess the energy efficiency technologies and their implementation based on three criteria: (i) awareness: propagating the incentives to consumers, (ii) capital constraints: How readily available is funding; and (iii) institutional mechanism: the difficulties in the process of implementation? This new paradigm, with emphasis on energy efficiency, entails the demand for energy from consumer side and switches the focus from energy supply to demand management. A 10-year planning horizon is considered here to study the impact of various technologies on the economy as well as on the environment. This is an attempt to evolve a rational basis for deciding how each stakeholder can benefit from each technology so that costs and benefits can be shared among various stakeholders.

958 INDIA'S ENERGY CONSUMPTION - IMPORTANCE OF HOUSEHOLD SECTOR

India mainly depends on coal, oil and fuel wood for most of its energy needs. In the year 2000, the total energy demand stood at 1.5 million tera joules (MTJ). Of the total, about 65% came from commercial sources and the rest from non-commercial sources such as fuel wood, agriculture wastes, etc. Households are the major consumers with nearly 44% of total energy followed by industry with around 40%. In the household sector, wood-based fuels accounted for 75% and the rest is through kerosene and LPG. The type of fuel used by a household varies with income (Anon, 2000). Low-income groups depend mainly on firewood (in rural as well as urban areas) while the middle income groups depend on fuelwood in rural areas and on kerosene in urban areas. The high income groups depend mainly on LPG in urban areas. METHODOLOGICAL

FRAMEWORK

Energy Efficiency involves the replacement of inefficient technologies with efficient ones and fuel switching from non-renewables to renewable technologies. In the residential sector, major alternatives would be fuel switching- from firewood to kerosene/LPG for cooking, and replacement of existing inefficient devices with efficient ones (for cooking, lighting, water heating, etc. particularly in rural regions where cooking/heating is done using fuelwood with efficiencies as low as 10%. Efficiencies as high as 30% can be achieved through improved stoves with negligible costs. We have developed a framework for analyzing various energy efficiency technologies available in India that are relevant for the residential sector. Various economic criteria are used here to evaluate cost effectiveness of energy efficient technologies. This criterion assesses the technologies with respect to the beneficiaries. Specifically, we assess the savings through each technological shift based on (i) annualised life costs, (ii) the rate of return on investment to the consumer and (iii) total savings that typically accrue to the government and the society. The benefits through each technology by the terminal year 2010 have been calculated as follows: Bi =

(Es * UCSs )* Iu

where Bi =

Benefits through ith technology in the terminal year

Eu = Energy savings per unit UCSs = Avoided cost per unit cost of energy saved Iu = Incremental Units by the terminal year The incremental units are the difference between the market saturation with and with out the programme.

FINANCIAL BENEFITS Here, we examine here different energy carriers (in terms of devices) used by different households and calculate the Annualised Life Cycle Cost, taking into consideration the capital cost of the device and its life, operating cost, operating efficiency, energy carrier price, etc. Since the ALCC includes capital cost, operation and maintenance costs, it is easy to compare the cost of appliances whose performance characteristics are similar. It is seen from Table 1 that on an average, every hundred rupees of capital invested on efficient fuel wood technology the household gets an annual return of about Rs. 64, whereas the shift from fuelwood to biogas produces an annual rate of return

959 of about Rs.34 In the case of lighting technologies, the average annual rate of return is about Rs.60. Thus, from a financial perspective, these technologies are attractive investments for an individual household. ENVIRONMENTAL BENEFITS

Energy efficiency creates an environmental benefit by reducing emissions of air pollutants. Environmental problems in India reflect the pattern of energy utilisation.. India's electricity is primarily generated by coal. Burning fossil fuels emits large amounts of airborne pollutants, primarily carbon dioxide, sulfur dioxide, and nitric oxides. On the basis of consumption by various types of fuels, the CO2 emissions were estimated using the emission coefficients (tC/toe): coal 1.08; oil - 0.86 and gas 0.62. Table 1 indicates the level of emission reduction the household avoids each year as a result of energy efficiency technologies. For example, each household using fuelwood emits 2,184 kg less carbon dioxide per year than would have been emitted had efficient fuelwood technologies not been implemented. Table 2 indicates the costs and benefits through various technological shifts. FACTORS T H A T A F F E C T E F F I C I E N T T E C H N O L O G Y P E N E T R A T I O N A question that such results often arouse is "if it is so economically beneficial and environmentally sound, why don't customers adopt energy efficient technologies on their own?" and "why the government doesn't take initiatives to spread awareness about energy efficiency and help in reducing the energy consumption levels"? Obviously there must be some barriers to adoption. From the consumers' perspective, the availability of capital for the installation of efficient technology, limitations of information, availability about the costs and benefits of the efficient technologies, and uncertainties about the future energy carrier prices are the major barriers. Since efficient devices are expensive, reduction in capital costs through subsidies, rebates, etc., can induce poorer households to shift to more efficient and energy conserving devices. This will also reduce the stress on natural resources. Another possibility will be for the government or electricity boards to install energy efficient equipment in households and collect the payments in monthly installments so that the generation costs could be avoided. However, the consumer's knowledge regarding the costs, benefits, etc., also plays a significant role in the faster diffusion of efficient technologies. The government should try to educate the consumers in understanding the trade-off between the capital cost of the efficient device and the future energy savings. CONCLUSIONS An energy efficiency scenario has been developed for the household sector in India with a ten-year perspective, i.e. 2010A.D according to which the energy saving of 757 PJ is possible. The equivalent cost of saved energy is Rs 10,000/GJ which is much lower than the capital investment required for supplying energy, typically ranging around ten times higher. From the consumer point of view most of the technologies are cost effective with a payback period of about two years. Also, energy efficiency programs offer the largest rewards to the society in the form of emission reductions. To achieve the goal of efficiency, an institutional mechanism should be evolved through which the existing fragmented limited scale markets should be transformed into a greater and more flexible one. Such an institution should act as a coordinator between various stakeholders such as the customer, electric utility, energy supply agencies, equipment manufacturers and other key players. For this to happen, new tools and new rules must be explored that can overcome the critical market barriers to promote energy efficiency programmes. In the light of all the changes that the energy industry is undergoing, the usefulness of integrated resource planning, and its success in meeting the goals of the customer, the government and the society will be based largely on the quantum of involvement of all players in this field --- electric utilities, oil companies, forest departments, consumers, equipment

960

manufacturers, financial institutions, researchers, planners and finally the government.

REFERENCES

1.

Anon, 2001, Results

o f the National S a m p l e

Survey

Organisation

for the Household

Sector, N S S O , G o v e r n m e n t o f I n d i a , N e w D e l h i . S e c t o r , C e n t r e f o r M o n i t o r i n g Indian E c o n o m y , N e w D e l h i .

2.

CMIE, 2001, India's Energy

3.

R e d d y A . K . N . " B a r r i e r s to i m p r o v e m e n t s in e n e r g y e f f i c i e n c y " ,

Energy Policy, 19

(10), 953-

961 ( 1 9 9 1 ) . 4.

Sudhakara

Reddy.B.

households",

"Consumer

Discount

TABLE COSTS From

rates

and

InternationalJournal of Energy Research, 2 0

AND BENEFITS

To Incremental investment (Rs.)

Savings (Rs.)

THROUGH

energy

carrier

choices

in

urban

(2) ( 1 9 9 6 ) .

1 VARIOUS

TECHNOLOGIES

Annual ROI (%) Payback Incremental Energy Unit cost of Carbon rate of period cost (Rs.) saved (G J) energy Emissions return (%) (years) saved (Tons) (Rs./GJ)

Cooking: Wood - TS Wood - TS Kerosene - KS Wood - TS Kerosene- KS Wood - TS Kerosene - KS

Wood- ES Kerosene - TS Kerosene - ES Biogas Biogas LPG stoves LPG stoves

225 100 125 9975 9875 1975 1875

937.7 279.5 543.1 - 133.1 -652.6 -357.6 -637.1

62.22 18.55 44.25 27.34 -66.09 -23.73 -51.91

416.75 279.55 434.51 6.18 -6.61 -18.10 -33.98

0.24 0.36 0.23 16.17 -15.13 -5.52 -2.94

37.3 20.5 16.9 1268.1 1247.6 248.1 227.6

16.0 17.3 3.2 23.8 5.2 20.1 2.8

2.33 1.19 5.35 53.33 240.99 12.35 80.29

Wood - TS Wood - TS Kerosene - KS Wood - TS Kerosene - KS Wood - TS

IWood - ES Kerosene - TS Kerosene - TS SWH SWH Biogas

225 1oo 125 11975 11875 9975

337.7 153.5 415.1 -1005.0 -1158.5 616.9

44.61 20.29 68.80 -132.77 -192.00 27.34

150.08 153.55 332.11 -8.39 -9.76 6.18

0.67 0.65 0.30 -11.92 -10.25 16.17

37.3 20.5 16.9 1755.0 1734.5 1268.1

8.8 9.6 2.4 12.8 3.2 23.8

4.24 2.14 6.94 137.11 535.34 53.33

Wood - TS Kerosene- KS EWH

EWH iEWH SWH

2475 2375 9500

-641.8 -795.4 -363.1

-84.79 - 131.82 -25.96

-25.93 -33.49 -3.82

-3.86 -2.99 -26.16

311.8 291.4 1443.1

11.5 1.9

27.10 149.88

1.3

-

163 217 209

241.3 404.2 253.5

68.48 70.50 44.21

0.68 0.54 0.82

21.5 33.8 42.1

0.3 0.5 0.4

68.11 64.22 118.76

Water Heating:

Lighting (at 5 Hours Usage per Day): IB (60W) IB (IOOW) IB (100 Watt)

CF (I0 Watt) ICFL(18 Watt) FL (36 Watt)

Note: TS: Traditional Stove ES: Efficient Stove EWH: Electric water heater SWH: Solar water heater IB: I n c a n d e s c e n t B u l b CFL: Compact fluorescent lamp FL: Fluorescent lamp

148.05: 186.29i 121.30!

0.58 0.63 0.06 0.86 0.10 0.63 0.05 0.00 0.32 0.18 0.05 0.46 0.06 0.86 0.42 0.04 0.02 0.00 0.005 0.009 0.006

961

TABLE 2 IMPACT OF EFFICIENT TECHNOLOGIES Energy Carrier

]Investm:nt~6~nnualCost IAnnual Rate [Incremental Rs. [Ml(l~illi°n~ [Savings (Rs. ~ofRetum ~ost (Rs. Savings [Million) I(%) [Million) Wood Kerosene Electricity (mt) ((million l) (GWh)

Cooking/heating- rural Firewood

7354

Kerosene

35940

828

3616

47414 I

28022]

57 35

1003

37.95 437.11

50

Total (PJ)

% of total

CO2 Emissions abated (mt)

607.12

80.30

63.75

15.3

2.02

1.08

41.02

5.42

12.19

36.24

4.79

3.81

19.44

2.57

1.37

37.8

4.99

11.42

Lighting - rural Electricity]

55 !

11201

3482

Cooking/heating - urban Firewood

439

Kerosene

1052

2146

60

4595

35

63

28115

50

3365

2.27 19.44

Lighting - urban Electricity rotal

51542 108629

Cost of savings

102433

8033

10493 40.22 Rs.36/t

456.55

21694

Rs.2.47/1 Rs.0.32/K Wh

756.92

89.52

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

963

EFFECT ON CO2 REDUCTION OF INSTALLATION OF OUTER SKIN SURFACE TECHNOLOGIES IN HOUSES AND OFFICE BUILDINGS Tomohiko Ihara l, Takashi Handa 2, Ryuji Matsuhashi

2, Yoshikuni

Yoshida l, Hisashi Ishitani 3

l Department of Geosystem Engineering, Graduate School of Engineering, University of Tokyo, Hongo 7-3-1, Bunkyo-ku, Tokyo, 113-8656, JAPAN 2 Institute of Environmental Studies, Graduate School of Frontier Sciences, University of Tokyo, Hongo 7-3-1, Bunkyo-ku, Tokyo, 113-8656, JAPAN 3 Department of Media and Governance, Graduate School of Media and Governance, Keio University, Hiro-o 1-11-5-801, Shibuya-ku, Tokyo, 150-0012, JAPAN

ABSTRACT In this work, we evaluated the extent of reduction in CO2 emissions brought about by introducing high lightreflective and high heat-emissive paint (A) and the low light-reflective and low heat-emissive outer skin surface (B) to houses and office buildings. First, we measured the light-reflectivity and heat-emissivity of Paint A, which was 0.90 and 0.91, respectively. Next, we calculated the extent of reduction in CO2 emissions by Paint A or Surface B, using our recently developed heat load simulation program. Finally, we evaluated the economical efficiency of Paint A. For office buildings, Paint A is a reasonable measure to reduce CO2 emissions, especially when installed in cities where the heat island phenomenon occurs, or when installed in places located in low latitudes. INTRODUCTION In recent years, CO2 emissions from the commercial and residential sectors have greatly increased in Japan. Governmental regulations for energy saving are very effective for the industrial sector, but they are found to be rather ineffective for the commercial and residential sectors. Thus, low-cost measures for CO2 reduction are really required in these two sectors. In the present work, we focus upon installation of outer skin surface technologies to buildings. These technologies, low-cost measures for CO2 reduction, are applicable to buildings, which include high lightreflective and high heat-emissive paint [ 1] and the low light-reflective and the low heat-emissive outer skin surface. We calculated air-conditioning demand in the building according to our recently developed dynamic heat load simulation program, and assessed the extent of reduction in CO2 emissions brought by high lightreflective and high heat-emissive paint or low light-reflective and low heat-emissive outer skin surface. OUTER SKIN SURFACE T E C H N O L O G I E S

High light-reflective and high heat-emissive paint "High light-reflective and high heat-emissive paint" (Paint A) is one which reflects light to a greater extent (mostly as visible light rays) and emits heat to a higher extent (most is infrared ray). This was developed to mitigate the heat island phenomenon or to reduce the cooling load of a building, and is already commercially

964 available. To learn more about light-reflectivity and heat-emissivity of Paint A, we coated plywood with Paint A and examined its properties using a long-wave and short-wave radiometer (EKO MR-40) and thermocouples on the rooftop of Faculty of Engineering Bldg. 4th, University of Tokyo (Bunkyo-ku, Tokyo). Items for measurement were as follows. •

•

Short-wave incident and emitted radiation, and long-wave emitted radiation. Temperature ofradiometer's sensor, dome and plywood.

The light-reflectivity of Paint A was calculated as 0.90 and heat-emissivity was as 0.91, using the above data based on the black body radiation theory. Low light-reflective and low heat-emissive outer skin surface Low light-reflective and low heat-emissive materials are well known as selective reflecting and absorbing surfaces for solar thermal collectors and so on. In the present work, as a low light-reflective and low heatemissive outer skin surface, we used black chrome plating (Surface B), which is a representative among them.

Light-reflectivity and heat-emissivity We used the above experimental data on Paint A. The data on other outer skin surfaces were according to bibliographies. The light-reflectivity and heat-emissivity of each outer skin surface are shown in Table 1. TABLE 1 POSTULATEDLIGHT-ABSORPTIVITYAND HEAT-EMISSIVITY Outer skin surface

Absorptivity

Emissivity

Default

0.80

0.90

Default value for dynamic heat load calculation

Paint A

0.10

0.91

The present work (experiment)

Surface B

0.95

0.066

SIMULATION

Note

FOR HOUSES

Simulation conditions Under the following conditions, we performed building dynamic heat load simulation.

•

• • • •

•

An object building follows "Standard problem for house" [3] (wooden house), which the Architectural Institute of Japan (AIJ) proposed. This house is a two-story house with the area of the second floor being equal to that of the first floor (the floor area is 62.93[m2]). Refer to "Standard problem for house" for each of the schedules. The air-conditioning setting temperature ranges from 20 to 27 [deg C]. Use AIJ's "Expanded AMeDAS Weather Data" (EA Weather Data) [4], Tokyo or Naha, typical meteorological year. Naha is the most southern city among the cities in Japan. Solar position is calculated using the equations of Yamazaki [4]. Direct and diffuse solar radiations are calculated from horizontal global radiation using an Erbs model [5]. A global radiation on tilted surfaces is calculated from direct and diffuse radiation using a Perez model [6]. Earth temperature is calculated using a Hayashi model [4].

965 Results

Air-conditioning demand (Tokyo) The cooling and heating demand (heat extraction) is shown in Figure 1. 15,000 ,.--, --)

em

eElO,O00

"ID

O) ._C ¢.e-

5,000

8 0

0 Annual

Annual

Winter

Winter

Interval

(c)

(H)

(C)

(H)

(C)

Interval Summer Summer

(H)

(C)

(H)

Figure 1: Reduction in the heat extraction (Standard problem for house, Tokyo) In the case using Paint A for the outer skin surface throughout the year, the cooling demand decreased 18.8%, but the heating demand increased 10.2%. On the other hand, when using Surface B throughout the year, the cooling demand increased 11.9% and the heating demand decreased 10.6%.

C02 emissions (Tokyo) Based on the data on CO2 emissions from fuel consumption and by postulating representative airconditioners in houses (see Table 2), we evaluated the extent of reduction in CO2 emissions brought by Paint A or Surface B (see Figure 2). TABLE 2 cop OF REPRESENTATIVEAIR-CONDITIONERSANDTHEIRCO2 EMISSIONS Building

Type

COP

Fuel

[-] House Office Building

CO2 emissions intensity [kg-CO2/MJ]

Cooling

EP

0.040

Heating

EP, city gas, LPG and kerosene

0.064

Cooling

City gas

0.050

Heating

City gas

0.063

If using Paint A throughout the year, CO2 emissions increased 6%; and Paint A could not be measured. On the other hand, Surface B reduced CO2 emissions 3.2%. This result showed that heating load was larger than cooling load in houses, and that if a measure reduces heating load, it is also a measure for reducing CO2 emissions.

Switching outer skin surface The cooling and heating demands peak in the summer season (S) and winter and interval seasons (W&I), respectively. If the outer skin surface of the building can be switched for the summer and winter seasons, Paint A becomes one measure for reducing CO2 emissions. Switching the outer skin surface is not yet a practical proposition, however, it can be accomplished. For example, it is enough to cover the outer skin surface with sheets coated with Paint A during the Summer season alone.

966 With regard to the above switching technology, we evaluated the effect of Paint A only during the Summer season on the house having the default outer skin surface. In addition, we also evaluated the effect of Paint A in the Summer season alone on the house having Surface B. These simulation results are shown in Figure 2. 1,500

6 1,000 ¢/I E .9 ._~

E

m 500

c3 ¢..)

o Cooling

Heating

Total

Figure 2: Reduction in the CO2 emissions (Standard problem for house, Tokyo) Paint A alone, which is disadvantageous, can now reduce CO2 emissions 4.5%, and becomes an effective measure, when installed solely during the Summer season. A combination of Paint A and Surface B reduced CO2 emissions 10.3%. Economical efficiency as measure to reduce C02 emissions

Because Surface B is not yet commercially available, we evaluated only Paint A. In Tokyo, using it with switching is the only measure to reduce CO2 emissions. The price of Paint A is shown in Table 3. However, the switching cost is not taken into consideration. TABLE 3 THE PRICE OF OUTER SKIN SURFACE TECHNOLOGIES

Type

Cost [yen/m2]

Year [y]

Cost per year [yen/m2y]

Note

Default paint

1,830

5

403

2

Paint A

4,000

5

880

Price of material: 1,400[yen/m 2]

times painting

TABLE 4 THE CO2 EMISSIONSREDUCINGUNIT(STANDARDPROBLEMFOR HOUSE) Type

Introductory part

COa reduction [kg-CO2]

Paint A (switching)

Paint A (throughout the year)

[Tokyo]

[Naha]

Required cost [yen]

[yen/kg-CO2]

Roofs

9.0

61,300

6,800

Walls

5.7

153,000

26,600

Roofs and walls

14.8

214,000

i4,400

Roofs

16.3

38,600

2,360

Walls

10.1

98,900

9,750

Roofs and walls

26.4

138,000

5,220

Unfortunately, Paint A in Tokyo is expensive. Even in Naha, it is not always inexpensive.

967 SIMULATION FOR OFFICE BUILDINGS Simulation conditions • An object building is "Standard problem for office" which AIJ proposed. This is a reinforced concrete building which consists of one-story basement, eight stories and a tower. Its floor and total floor areas are 826.56[m 2] and 7583.44[m2], respectively. • Refer to "Standard problem for office" for each of the schedules. The air-conditioning setting temperature ranges from 22 to 26[deg C]. Results

When Paint A is applied to office buildings, it reduces CO2 emissions throughout the year, even in Tokyo. Reduction in the CO2 emissions from the office building is shown in Figure 3, and its economical efficiency is shown in Table 5.

40

,.--, O

6~ :~30 .£ "~20 t.-

8 010

o Cooling

Heating

Total

Figure 3" Reduction in the CO2 emissions (Standard problem for office, Tokyo) TABLE 5 THE CO2 EMISSIONSREDUCINGUNIT(STANDARDPROBLEMFOR OFFICE) Introductory part

Type

CO2 reduction [kg-CO2]

Required cost [yen]

[yen/kg-CO2]

Paint A (switching)

[Tokyo]

Roofs and walls

5980

2,810,000

471

Paint A (throughout the year)

[Tokyo]

Roofs and walls

98.0

2,040,000

20800

Paint A (switching)

[Naha]

Roofs and walls

10400

2,570,000

248

Paint A (throughout the year)

[Naha]

Roofs and walls

11300

1,410,000

125

In the office building in Tokyo, when switching the outer skin surface, Paint A is not so expensive. For example, photovoltaics (PV), which is also an outer skin surface technologiy, costs 73.9-418 [yen/kg-CO2]. Installation of Paint A to the office building is a reasonable measure. First, the price of Paint A will fall in the future; second, the initial cost is very low; and third, Paint A is also effective for mitigating the heat island phenomenon. Moreover, Paint A is a more reasonable measure in Naha, as PV costs 54.7-337 [yen/kg-CO2].

968 CHARACTERISTICS OF THE MEASURES TO REDUCE CO2 EMISSIONS High light-reflectivity If some buildings in cities were coated with Paint A, the streets would become dazzling. However, high light-reflectivity and shiny brightness are different things. If there is significant mirror reflection, it will have shiny brightness. However, reflection of Paint A consists not only of mirror reflections but also of diffuse reflection. For example, brightness of silver paint is greater than that of white paint, but the former reflectivity is lower than the latter one. Moreover, solar radiation contains not only visible light, but also near-infrared, and new technologies are emerging that make a particular paint to reflect only near-infrared rays. Thus, the streets would not become dazzling. Heat insulating When the building is highly heat-insulated (by heat insulating materials, ventilation layers and so on), the extent of CO2 reduction by Paint A and Surface B is smaller than that by low heat-insulated one. However, the rate of reduction in CO2 emissions from air-conditioning does not significantly alter (see Figure 4). 2,500

25

,--2,000

20

._~

-~-1,500 ¢) ¢-

.o_ ¢) ._~

O

~ 1,ooo

c3 o

10"6

500

5= •

0

0 0

25 50 100 Thickness of glass wool (24K) [mm]

150

Figure 4: Effect of heat insulating (Standard problem for office, Tokyo) CONCLUSIONS In the present work, we evaluated the extent of reduction in CO2 emissions brought about by introducing high light-reflective and high heat-emissive paint (Paint A) and a low light-reflective and low heat-emissive outer skin surface (Surface B) to houses and office buildings. Paint A and Surface B are effective in reducing CO2 emissions, especially in the case of outer skin surface switching technologies. In terms of cost for reducing CO2 emissions, installation of Paint A to houses is expensive at present. However, the costs of installation to office building are not so high, considering the initial costs. In particular, when installing to cities, Paint A will mitigate the heat island phenomenon, and when installed at locations in low latitudes, Paint A will reduce CO2 emissions further. REFERENCES 1. Kondo, Y., Nagasawa, Y. and Irimajiri, M. (2000). In: Research Reports of Society of Heating, Air-conditioning and Sanitary Engineers of Japan." Reduction of Solar Heat Gain of Building, Urban Area and Vending Machines by High Reflective paint. No. 78, pp. 15-24. (in Japanese) 2. Takizawa,H. (1985). In: The 15th Heat Symposium: Proposal of Standard problem -standard problem for office-, pp. 35-42. The ArchitecturalInstitute of Japan. (in Japanese) 3. Udagawa,M. (1985). In: The 15th Heat Symposium: Proposal of Standard problem -standard problem for house-, pp. 23-33. The ArchitecturalInstitute of Japan. (in Japanese) 4. The ArchitecturalInstitute of Japan. (2000). Expanded AMeDAS Weather Data. Maruzen. (in Japanese) 5. Erbs, D.G., Klein, S.K. and Duffle, J.A. (1982). In: Solar Energy." Estimation of the diffuse radiation fraction for hourly, daily and monthly-average global radiation, pp. 293-302. 6. Perez, R.R., Ineichen, P., Maxwell, E.L., Seals, R.D., Zelenka,A. (1992). In: ASHRAE Transactions Research Series." Dynamic Global to Direct Conversion Models, pp. 154-168.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

969

E V A L U A T I O N OF RDF P O W E R G E N E R A T I O N OF L A R G E - A R E A W A S T E T R E A T N M E N T BY LCA

Nagisa KOMATSU, Tomoko IWATA and Sohei SHIMADA Institute of Environmental Studies, Graduate School of Frontier Sciences, The University of Tokyo, Hongo, Bunkyo-ku, Tokyo 113-0033 JAPAN

ABSTRACT In this study, the viability of RDF power generation is evaluated from the viewpoint of energy saving and the reduction of CO2 emissions by analyzing operations at the Kashima RDF power plant, which has been nmning since fiscal year 2001. The purpose of this study is to consider the thermal recycling system most suitable for a given area. RDF has the advantages of being easy to transport and store and has a high calorific value. On the other hand, it has the disadvantage of requiring extra energy for manufacturing RDF itself. Kashima City, Kamisu Town and Hasaki Town run the Kashima RDF power generation operation. Although power generation and heat supply were originally planned, the latter was abandoned because of the lack of demand in this area. In this study, Kashima City and Kamisu Town are regarded as the study area since the Hasaki RDF center has not yet started operating. LCA (Inventory Analysis) is adopted as an evaluation method in this study. In the application range of LCA, not only the operating process but also the construction and dismantling processes are included. Five cases are evaluated from the viewpoint of saving energy and the reduction of CO2 emission to find the most suitable RDF power generation system. From the result of detailed analysis of each life cycle process in the present operation, it was found that the introduction of RDF power generation did not produce much advantage under present conditions. However, it was found that it would save energy and reduce CO2 emissions if it were used to produce significant electrical output by large-area waste treatment. INTRODUCTION

Recently, many efforts have made in reducing and recycling waste. A recycling-based society and the development of new recycling technologies are current goals. For the promotion of recycling, the first option must be Material Recycling. However, it is difficult to recycle some wastes, both economically and technically. Under these circumstances, it is important to promote Thermal Recycling, ie. recovering energy from waste. One promising thermal recycling method is power generation from RDF (Refuse Derived Fuel), aiming at highly efficient energy recovery by large-area waste treatment. Some studies have been done from the viewpoint of energy saving, reduction of environmental impact materials and economy [ 1]. However, the data used for these studies were estimated or supposed values, as at the time, actual power generation using RDF had not yet started in Japan. In this study, Kashima City and Kamisu Town were selected as the study area, where RDF power generation started in 2001. This is the first such operation in Japan. Previously, general waste was incinerated without any

970 heat recovery or power generation. The feasibility of the RDF power generation is evaluated considering energy savings and reduction of environmental impact materials (CO2, NOx, SOx). The optimum thermal recycling method suitable for the area is considered through the comparative study of different cases of waste treatment RDF POWER GENERATION OPERATIONS IN KASHIMA CITY AND KAMISU TOWN

In the Kashima RDF Power Generation Operation, combustible general waste collected from one city and two towns (Kashima City, Kamisu City and Hasaki Town) and industrial waste collected from industries in the Kashima Bay Industrial Area are processed into RDF in RDF Centers. RDF is combusted at the Kashima Recycling Center. Steam is produced by the combustion and used to provide heat to industries and the local community, and to generate power. It is the first operation of its kind in Japan. Power output and in-plant consumption are 3,000kW and 1,000kW, respectively. The electric power for selling to Tokyo Electric Power Co. was planned to be 2,000kW. Two RDF Centers, in Kashima City and Hasaki Town, were planned. The RDF Center in Hasaki Town started operation in April 2002. At the time of this study, the RDF Center in Kashima City and a Recycling Center in Kamisu Town are operating. Heat supply was planned, but the steam is now used only for power generation due to lack of demand for heat. The locations of centers are shown in Fig. 1. V

~

a

~ ~ ~

g

~i U "~ ",Kashima R¢cvelimzCenter

=)

)

v

) Figure 1: Locations of RDF Centers and Recycling Center ANALYSIS OF KASHIMA RDF POWER GENERATION OPERATION

Method of ProcessAnalysis LCA application range of the study area is shown in Fig.2. The construction and dismantling processes are included in this analysis. Input energies of construction processes for power generation plant and final deposit site were calculated from the relationship between construction cost and construction input energy based on the past actual data. For the RDF manufacturing plant, it was calculated from the published construction cost data. CO2 emission was calculated from the amount of material and floor area by multiplying the unit values. For the f'mal disposal site, the forest lost due to construction of the site is considered and reduced sequestrated CO2 due to lost forest are included in the calculation. For the waste collection process, the input energy and environmental impact emissions were calculated considering the distance and fuel consumption of waste collection trucks including the manufacture and eventual disposal of the vehicles. The operating process was analyzed using data on RDF manufacturing, transportation and power generation up to December 2001. The input energy and emissions were considered against the net electric power generated. Fig.

971 3 shows the input energy and emissions at the Kashima RDF Center for 1 ton transported combustible waste. The input energy required by the drying process is about 60% of the total energy required for manufacturing RDE The lower calorific value of RDF ranged between 3,750kcal/kg (15.8MJ/kg) and 3,550kcal/kg (14.9MJ/kg). In the ash transportation process, the distance between the power generation plant and the ash disposal site, and the number of tracks were included in the calculation. In the final disposal process, operations of land filling at the final disposal site were considered and the calculation was made based on the amount of ash. Dismantling costs were calculated based on the construction costs. i .............................................. t C

onstruction

P rocess

t .......................................... i

i

, RDF

MSW

I

f......

f.......

I ]alldfill

I

•

,

ii I"

]

l i [i

•

" ........................................................................................................................................................

] +1[o per. ring Process . . . . . . . . . .

P rocess

factu re o f R D F

. . . .

~ 1

.

+ ,

rra,,+,~o,*ation I . . ~ o ' + ~ ' Industrial

~

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..... p .... [ on of RDF

i

T ransportatio

ItLll ,

io~ o+

Ii 'l

rl

. I asnes

n

of

process

~lii ~1

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--I

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I I

II'

electricity

aste

+

l+{

tl

,t

.........

] 1

i burning,

IndustrialW

I

"........................... • .................................................................................................................................. ' 1 " .......................

Collection

of

....

l burnin ......... ion o f I~I e l e c t r i c i t y p l a n t

generation

electricity

o

Process

plant

.................................................................................................................. j

Figure 2: LCA application rage C om b u s t i b l e

W astel

M o i s t u re y lathe solid A sh

II~ec*ric~*~| ~0~w~ II

~++

content

Low er cabrific

C 0 2-- 1 7 . 0 7 k g SO x-- 4 . 2 7 g N 0 x-- 6 . 4 0 g

t

42.5% 51.7% value

2072kcal/kg

I............................................................................................... t............................................................................................. Y

Ica~.-m I

~

S ack

breaking,

IC a (0 H )2 I C arry-out

3.53kg

k" ~- 7

A lur, injure N onburnable

0.4kg 20.5kg

]-~ ....................................................................i RD

A sh

content

Low er calorific

,

F471kg

M o isture V o latile s o l i d vahae

4.3% 82.2% 13.6% 3672kcal/kg

Figure 3:

II E l e c t r i c i t y 90.5kW c 0 2- 29.70kg SO x 7 . 4 2 g NO x - l l . 1 4 g

h I

I1~ . . . . . . .

52.71

II

] C 0 2-- 1 3 3 . 1 6 k g [ SO 3.16g NO x-- 3 1 0 . 1 9 g

Flow of RDF manufacturing process

RESULTS An inventory analysis was made for the Kashima RDF Power Generation Center using actual operation data. Although the present power generation level is not 3,000 kW, analysis was made based on the planned power generation level. According to the reports of NEDO [2] on RDF power generation planning and RDF power generation in Ohmuta City in Kyushu, the following correlation between output of power generation (y) and waste treatment capacity (x) is obtained: y = 0.0361

X2 +

38.863 x

(R 2 = 0.8987)

972

The analysis for an output of 9,200 kW, which is the maximum output obtainable at the Kashima Recycling Center (capacity 200t/day), was used for comparison. Fig. 4 - Fig. 7 show the results of input energy, CO2 emission, NOx emission and SOx emission for the incineration of conventional general waste and for RDF power generation (conventional incineration, present, 3,000kW, 9,200kW). These figures show that the power generated does not compensate for the input energy and emissions due to the small power generation under present operation. Addition of industrial combustible waste by 30% leads the input energy to zero, and addition of 50% leads CO2 emission to zero. For an output of 3,000kW, the input energy is reduced to almost zero but emissions are still greater than zero. In this case, power generation by conventional waste combustion is better than RDF power generation, as it avoids the energy consumption involved in the manufacture of RDE For an output of 9,200kW, both input energy and emissions are largely reduced. The gross thermal efficiency of RDF power generation is about 28%, which is much higher than that of power generation by combustion of general waste (= 15 - 16 %). In a relatively large operation, power generation using RDF has some advantages. But NOx emission in RDF power generation is greater than in power generation by buming general waste, for kerosene is used in the drying process in RDF power generation.

1 000.0 0.0 -500.0

,

,

.. ~:l,

,

._

l l

hc heratbn

~-,

,

, [] p r e s e n t

-1 ooo.o

m -1'500.0 -2'000.0 -21500.0

• conventbnal

833.8 , 1

-955 -

o

~

~,

~,==

o

~'

~,~

o~

.'

[] 3,000KW

• 9,200k~

[._,

~

[._,

Figure 4: Input energy 120.1 ~.,n

~

~

~~

~

~

118.5

m

• conventbnal hcheratDn

_t~__.~

[] pre s e n t ,

.~

g

.~

~

~

[] 3,000K W

• 9,200kW b--

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e-~

Figure 5:C02 emission 500.0 400.0 300.0 200.0 100.0 0.0 -100.0 -200.0

985.0

• conventDnal nc heratDn

n i ! I I

• pre s e n t

.,.~

o~ ~

"~

Q 3,000K~

o • 9,200kW

8

Figure 6:

NOx emission

973 r

_ b.~ O ._ ~ n

,

L _

R:-i •. i : ~

_ilIil[...........-

i • conventbnal

hcheratbn

,

•present ~ ~

•,~

....

~

~

,-.t

N ~

--27.1

"~ ~

i

o

•~

~

o

~

Figure 7: SOx emission OPTIMUM SYSTEM OF RDF POWER GENERATION IN THE KASHIMAAREA The comparative analysis was made using the following five cases. Case 1: RDF Center and Recycle Center at the same site (no transportation of RDF) Case 2: Conventional general waste incineration Case 3: Power generation and heat supply Case 4: Including Hasaki Town Case 5: Large-area RDF power generation (7 cities and towns ) For Case 1, the RDF transportation process is excluded. The energy required by RDF transportation is 0.5% of the total energy consumption. Therefore, the reduction of input energy and emissions is not significant. This leads to the conclusion that having some distance between the plants doesn't have much effect on the results. For Case 2, the input energy and emissions are reduced in the waste collection and construction processes with no RDF manufacturing or transportation, although they are very small. However, RDF power generation is advantageous in total owing to its power generation process. For Case 3, the specification of the steam transportation pipe was determined, based on the planned flow rate of 7t/h. Heat loss from the pipe was also calculated. The length of heat supply pipe was assumed to be 5km. As a result, the total input energy was -799.0 Meal/t-waste, CO2 emission was 138.2kg/t-waste. This shows the large effect on the reduction of input energy and emissions. RDF power generation is effective when used to supply heat, even in the case of a small operation. For Case 4 and Case 5, the results are shown in Figs. 8 - 11. In Case 5, four other cities and towns, Omigawa Town, Tosho Town, Itako City and Chosi City, located next to Kashima City, Kamisu Town and Hasaki Town, were included for the calculation of large-area waste treatment. In Case 4, a slight reduction is observed, but it is not so advantageous for introducing RDF power generation. In Case 5, the large-area waste treatment of 7 cities and towns, the input energy and environmental impact emissions were reduced greatly compared to Case 4. This implies that RDF power generation is effective in a large-area waste treatment.

630.0

1,000.0

-c.

500.0 o.o

"~- -500.0

._m_~

. . . .

m m i n ,

,

-~

-2,000.0

834.7

.....

.~

• conventbnal hcheratbn h 3 city and towns IRDFsystem

1,000.0

-1,500.0

350.7

,~, n

~

. ~ ~ .~

=

1

h 3

c~andtowns D conventbnal ncheratbn

h 7

cities and towns URDFsystem h 7 cities and towns

Figure 8: Input energy

974

• 300.0 200.0 100.0 -~

m

m

mm.m~_y

, ---

,

0°.6,

"

o.o

-100.0 -200.0 -300.0

conventbnal

hciaeratbn h 3 c ~ and towns mRDFsystem h 3 c ~ and towns [] conventbnal nciaeratbn h 7 cities and towns • RDFsystem in 7 cities and t o w n s ,

Figure 9:CO2 emission

365.4

400.0 300.0 200.0 ~o 100.0 0.0 -100.0

Itl

ll~p

mmm

-200.0

= •~

~

~

.q2~_5

nml • m l

mRDFsystem ia 3 city and towns

....

~

• conventimal he iaeratim ia 3 city and towns

pl conventi3nal iacheratbn h 7 cities and towns

..~

mRDFsystem ia 7 cities and towns

Figure 10:

NOx emission =A n

,Itl

,--,-'.-,

mm m

....

.

.

,q6_4

n m,r'--~,mm-'i-,~ mm

• conventbnal iaciaeratbn ia 3 city and towns IIIRDFsystem ia 3 city and towns

15-9..~

..

.

=o F

[] conventbnal i a c i a e m t b n ia 7 cities and towns mlRDFsystem in 7 cities and towns

Figure 11: SOx emission CONCLUSIONS The main results obtained by this study are summarized as follows; 1. Consumption of energy in the manufacturing of RDF must be compensated for by the power generated by the RDE In small power plants, heat supply should be incorporated. The introduction of RDF power generation is effective if heat is also supplied, even when the electrical output is small. 2. Except in the case of large-area waste treatment with large electrical output, RDF is not a suitable power generation system because of the low thermal efficiency of power generation. 3. The input energy for transportation is very small compared to that required by construction. It is better to construct a small number of RDF power generation plants that can operate on a large scale. ACKOWLEDGEMENTS The authors express their thanks to Kashima City and Kamisu Town for the supply of data for this study. REFERENCES 1. Nagata,K. and Ureshino M. :Availability ofRDF- from viewpoint of LCA-, (1996)J. WasteManagementResearch, 7, 282 2. Ishikawa Pref. :Study on RDF power generation by general waste in Noto Area, (1998), NEDO Report

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

975

CONTRIBUTING TO REDUCTION OF CO2 EMISSIONS THROUGH DEVELOPMENT OF A HEAT-INTEGRATED DISTILLATION COLUMN M. Nakaiwa I, K. Huang l, T. Endo 1, T. Ohmori l, T. Akiya I, T. Takamatsu 2, S. Beggs 3 and C. Pritchard 3 1National Institute of Advanced Industrial Science and Technology (AIST), Tsukuba 305-8565, Japan ZInstitute of Industrial Technology, Kansai University, Suita 564-8680, Japan 3School of Chemical Engineering, University of Edinburgh, EH9 3JK, UK

ABSTRACT This paper introduces the development of a heat-integrated distillation column as a means of contributing to the reduction of CO2 emissions. The process has evolved from the application of the heat-pump principle to a distillation process, leading to an internal heat integration between the whole rectifying and the whole stripping sections. Three candidate configurations have been proposed and analyzed for the practical process realization. The results from the operation of the first bench-scale plant and simulation studies demonstrate its substantial contribution to the reduction of CO2 emissions.

INTRODUCTION The imperatives of global wanning and sustainable development demand efficient energy utilization in all aspects of life. The chemical processing industry, as an intensive energy consumer, is a major contributor to CO2 emissions. It accounts for 25% of the energy consumed by industries overall, while the distillation process accounts for up to 50% of the energy consumed by this industry. To abate its impacts and achieve the targets designated by the Kyoto Protocol, the development of energy-efficient distillation processes has a potentially very important role. An energy-efficient heat-integrated distillation column (HIDiC) is developed in this work as a way to alleviate C02 emissions. Three candidate configurations have been proposed and analyzed for the practical process realization. The results of the first bench-scale plant experimentation of its kind and simulation studies are given in detail and its effectiveness in mitigating C02 emissions is discussed.

THE C O N C E P T U A L C O N F I G U R A T I O N OF THE HIDiC In Figure 1, a conceptual configuration for the HIDiC has been created. The column's stripping and rectifying sections are separated, but connected through internal heat exchangers. To accomplish internal heat transfer from the rectifying section to the stripping section, the rectifying section is operated at sufficiently higher pressure than the stripping section to give higher temperatures throughout its length. To adjust the pressures, a compressor and a throttling valve are installed between the two sections. Owing to the heat integration, a proportion of the latent heat transported in the rectifying section is transferred to the stripping section, thereby generating both the reflux flow for the rectifying section and the vapor flow for the stripping section. Thus the condenser and reboiler are, in principle, not needed; and operation at zero external reflux is theoretically

976 possible. Figure 2 elaborates the principle of the HIDiC. The heat discharged along the rectifying section has been upgraded through a compressor and reused along the stripping section. By this internal heat integration, process energy efficiency can be improved, substantially. Compressor

F, zf

Throttling valve Figure 1: A schematic representation of a HIDiC

TI

Reboiler

Reboiler duty .," ~ ~ e b c

°.°o°.°°.o°°°°°°° emperature I..] difference

m t e g r ~ l ~1,. a

thenat

~Mirror image-'] " ] ofrectifymg1 [section curve.) Condenser H Figure 2: The principle of the HIDiC in a T-H diagram

ALTERNATIVES FOR THE PRACTICAL REALIZATION OF HIDiC Although the HIDiC appears to be very attractive in energy efficiency, it poses great difficulties in realizing an effective configuration. Difficulties arise from not only the arrangement of sufficient heat transfer area between the rectifying section and the stripping section, but also from the possible degradation in mass transfer between vapor and liquid phases. Three potential configurations are introduced, below. A Concentric Configuration

A concentric configuration is very similar, in structure, to a multi-tube and multi-shell heat exchanger (cf. Figure 5). Both tube side and shell side are equipped with mass-transferring packing and are operated respectively as the rectifying and the stripping sections [ 1,2].

977

A Configuration with Heat Transfer Loops The intemal heat integration is carried out by pumping a liquid heat transfer medium around a single or multiple heat transfer loops (Figure 3 shows heat integration through a single heat-transferring loop). This method can effect internal heat integration on each plate in both sections [3].

RECTIFYING STRIPPING SECTION Tm,g~0) -- Tin(top)= Tm,s(0)

1

Tm,r( )

'(

' ~

+ Tm,s(1) 1

Tm,r(3)

~

+ Tm,s(3) Tm,s(ns-3) Tm,r(nr-2) Tm,s(ns-2)/~

Tm,r(nr-1)

+ Tm,s(ns-1) >

Tm,r(nO= Tm(bot) = Tm,s ( n s ) ~ ---] ~ Figure 3: A potential configuration with a heat transfer loop

A Configuration with Heat Pipes Internal heat integration is carried out by a series of heat pipes linking pairs of plates in the rectifying and the stripping sections (Figure 4). The high internal heat transfer coefficients and negligible temperature drop along the heat pipes permit effective heat transfer over small temperature differences [3].

STRIPPINGSECTION

RECTIFYINGSECTION

PLATE

HEATPIPEn

~l 0 oleT"piatl°n ~

o

!° ! ooo?ool, c°ndoenS~_i°n

Tm(n)

Figure 4: A potential configuration with heat pipes

PLATEn

978

I ~ I Throttling~~ I ' 'Va~e T I

I

1 I~

Top Product

~~ri--6.1C_°m

I

i

~r~o~f---~

.

.

.

.

press°r

.

.

.

.

Figure 5: Layout for the bench-scale plant E X P E R I M E N T A L EVALUATIONS CARRIED OUT ON THE BENCH-SCALE PLANT

Layout of the Bench-Scale Plant As shown in Figure 5, the plant is about 27 m in height and 0.254 m in diameter. Packing has been furnished in both sections and the internal design guarantees sufficient contact between vapor and liquid phases, effecting a major improvement in performance over that of conventional packed distillation columns.

Process Startup An inverse heat transfer (i.e., heat transfer from the stripping to the rectifying section) must be avoided during process startup. To enhance the pressure difference as quickly as possible, one needs to start the overhead trim-condenser later than the bottom trim-reboiler. It was found that no special difficulties were encountered during startup. Around 10 hours were needed for the process to reach its normal steady state, although a substantial reduction of this time period should be possible through appropriate use of the trim heat exchangers. Steady State Operation with and without External Reflux Steady state operation with external reflux was obtained directly after startup. More than 100 hrs of continuous operation have been performed and no special difficulties were encountered during the experimental tests. The results obtained show that the process can be operated very smoothly, just as conventional distillation processes. External reflux-free operation was achieved by reducing the external reflux rate whilst gradually increasing the pressure difference (Pr-Ps) between the rectifying and the stripping sections. As can be seen, the operation of the bench-scale plant could be easily shifted to the reflux-free mode after the startup period (Figure 6a). In this case the internal heat integration between the rectifying and the stripping sections functions as an efficient means of generating internal liquid and vapor flows (Figure 6b). Figure 6c illustrates the time history of the overhead and bottom temperatures in the rectifying and the stripping sections respectively, demonstrating stable operation of the bench-scale plant. Figure 7 shows the steady state heat and mass balances for the bench-scale plant. It can be readily seen that the internal heat integration between the rectifying and the stripping sections plays a very important role in the process operation. 100

4.0

80 ~"~P =060

k_

~ 3.0

Fe~l

•--, 120 ~ B ° t t (Rec.sec.) ° m ~~,Bottom (Rec.sec.)

duct

~2.0

~= ~,4°k -~_1.0 = 201 ~ottomproduct 01

13

l~l

I

14 15 16 Time [h]

(a)

'~°/

Feed

product

17

0l

13

Bottom product I

I

,

14 15 16 Time [h]

(b)

i

17

I

,,0 1°°L ..... Top,(S~.Sec.)J 80 ~ ! 13

,

J

~

.... t=

14 15 16 Time [h]

17

(c)

Figure 6: A typical reflux-free operation result of the bench-scale plant

979

I ~°°c .~15.3 kwI 890C 3.28kmol/h Benzene 59.2mo1%

'.~li~R = 0 II' | ~ 1.94kmol/h i I I Benzene 99.9mo1% ~1 I 114.7kW> 8 ~/I I Heat radiation / 73 kmol/h

I.J~l ~kwl

121.3kW1 2.34kmol/h

w--i ,~Compressor 0ower

--.. | -"117°C 2.79 kmol/h 1.34 kmol/h Toluene 99.7 mol% Figure 7: Heat and mass balances for the bench-scale plant

Energy Efficiency of the HIDiC Table 1 compares the operating costs between the experimental HIDiC and a conventional distillation column designed for the same separation task. As can be seen, the HIDiC is about 40 % more energy efficient than the conventional distillation column [4]. This saving is, however, lower than that calculated in the conceptual process design [5], mainly due to the fact that the bottom trim-reboiler is still in operation and a compressor with much low an isentropic efficiency (<25%) has been used in the bench-scale plant. Also shown in Table 1 are the simulation results for those configurations of the HIDiC with heat pipes and a single heat transfer loop under the same operating condition as shown in Figure 7. They demonstrate the theoretical potentials of energy savings of the HIDiC over conventional distillation columns. The heat pipe configuration appears a lot of better in energy efficiency than the single loop one. However, it does not necessarily mean that the former is preferable to the latter, if one has considered the difficulties in arranging heat pipes between the rectifying and the stripping sections. Which one, among the three configurations discussed, is the best realization of the HIDiC should be dependent upon the overall analysis and comparison of the detailed application at hand. TABLE 1 COMPARISONS BETWEEN THE BENCH-SCALE PLANT AND SIMULATION STUDIES (Compressor Isentropic Efficiency = 0.8, Motor Efficiency = 0.95) Description

External Reflux Ratio, R

Conventional

1.5 (= 1.4Rmin)

Total Energy Consumption (kW) (Electrical ---3xThermal) 43.1

Bench Plant Heat Pipes

0.0 0.0

25.8 18.3

60% 42.5%

Single Loop

0.0

22.0

51%

Energy Equivalence 100%

CONTRIBUTIONS TO R E D U C T I O N OF CO2 EMISSIONS In Japan, there are currently around 3,000 distillation columns operating in various industrial corporations. If 30 percent of these processes can be replaced with the HIDiC, then the energy savings per year would be: 8000 hr/yr x (5Gcal/hr x 40%) x (3000 x 30%) -- 1.440 x 107 Gcal/yr - 9250 kcal/(liter crude oil) = 1.557 x 109 (liter crude oil) Here, a distillation column has been assumed to consume 5 Gcal of heat per hour (5.8 MW) and the annual

980 operating time has been taken as 8000 hrs. The equivalent reduction in C 0 2 emissions is: 1.557 x 109(liter crude oil) x 2.674(kg CO2/litre crude oil) / 1000 (kg/ton) = 4.163 x 106 (tonnes of CO2) This would be a substantial reduction of CO2 emissions in Japan and the HIDiC would play an important part in achieving the target designated by the Kyoto Protocol. CONCLUSIONS A HIDiC has been developed through effectively applying the heat pump principle to a conventional distillation column. This process involves internal heat integration between the whole rectifying and the whole stripping sections and thus offers potentially high energy savings. Three process configurations have been proposed and analyzed for the practical realization of the HIDiC. Both bench-scale experimental evaluations and simulation studies reveal that a much higher energy efficiency than conventional distillation columns can be achieved for close-boiling binary mixture separations, and a substantial contribution to the reduction of CO2 emission can be expected if HIDiC is adopted in the industry. In practical applications, care should be taken in deciding the most appropriate configuration of the HIDiC. ACKNOWLEDGMENT The authors from the National Institute of Advanced Industrial Science and Technology (AIST) of Japan are grateful for the financial support from the Japan Science and Technology (JST) Corporation under the frame of Core Research and Evolutional Science and Technology (CREST). The authors from Edinburgh University acknowledge the support of the British Council under the Collaborative Research Program (CRP). NOMENCLATURE F H L nr ns

Pr- P~ R

T V X

y Zf

HIDiC

feed flow rate, kmol/s enthalpy, kJ/s liquid flow rate, kmol/s number of trays in the rectifying section number of trays in the stripping section pressure difference between rectifying and stripping sections, MPa extemal reflux flow, kmol/s temperature, K vapor flow rate, kmol/s mole fraction of liquid mole fraction of vapor feed composition heat-integrated distillation column

REFERENCES

Takamatsu, T., Nakaiwa, M. and Aso, K. (1998). US Patent, No. 5873047. Takamatsu, T., Nakaiwa, M. and Aso, K. (1999). Japanese Patent, No. 3184501. Beggs, S. (2002). MEng project report, University of Edinburgh, UK. Naito, K., Nakaiwa, M., Huang, K., Endo, A., Aso, K., Nakanishi, T., Nakamura, T., Noda H. and Takamatsu, T. (2000). Comput. Chem. Eng., $24, 389. Nakaiwa, M., Huang, K., Naito, K., Endo, A., Owa, M., Akiya, T., Nakane T. and Takamatsu T. (2001). Proceedings of 6th World Congress of Chemical Engineering, Melbourne, Australia.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

981

EFFECT OF FLUCTUATION OF HOT-WATER D E M A N D ON A C T U A L P E R F O R M A N C E OF HOME C O - G E N E R A T I O N SYSTEM Takeyoshi Kato, Siori Kasugai, Tetsuhisa Iida, Wu Kai, Yasuo Suzuoki Center for Integrated Research in Science and Engineering (CIRSE), Nagoya University Furo-cho, Chikusa-ku, Nagoya, 464-8603, Japan

ABSTRACT This paper discusses the efficiency of a micro co-generation system (ktCGS) for residential use based on the hot-water demand observed in three domestic households. Two structures of ~tCGS were assumed, i.e., PEFC with a large backup boiler and small hot-water tank, and PEFC with a small backup boiler and large hot-water tank. Assuming the constant output operation of a PEFC, we calculated the required output of a backup boiler in order to meet a series of hot-water demand for each month during the period between August 2000 and March 2001. We evaluated the composition of the hot-water output on the supply side and the hot-water usage on the demand side. As a result, although the backup boiler supplied the hot water, some hot-water output of PEFC was wasted because of the concentrated hot-water demand within a short period. This reduced the actual efficiency of ~tCGS by 10% or more in each month as compared to the ideal situation, where all hot-water demand was met by only the hot-water output from PEFC and no hot-water output was wasted.

INTRODUCTION A micro co-generation system (gCGS) using a Polymer Electrolyte Fuel Cell (PEFC) is expected to be one of the promising measures for improving energy efficiency in the residential sector, because the gCGS recovers waste heat from PEFC and supplies it as usable hot water in addition to its electricity supply. In the evaluation of a gCGS being installed into a single household, we should take into account a pulsating and fluctuating characteristic of hot-water demand, because this characteristic is quite different from that in a business building where a conventional, larger sized CGS is installed. To cope with a pulsating and fluctuating hot-water demand, a gCGS should be equipped with a back-up boiler and a hot-water tank of large capacity, although the frequent use of these appliances might decrease the actual efficiency of the ktCGS. If we evaluate the ~tCGS by using a set of statistically estimated hourly demand patterns, which is utilized in the evaluation of conventional CGSs[ 1,2], it might be difficult to distinguish the actual contribution of a ~tCGS for supplying the hot water. Therefore, in order to present a good evaluation of a gCGS for residential use, we need to develop a new evaluation method that takes a fluctuating characteristic of hot-water demand. As a first step for such an evaluation, we calculated the primary energy reduction of a gCGS based on a series of actual hot-water demand patterns for several months. Since July 2000, we have conducted the observation of the hot-water demand in three residential households in the same apartment building near Nagoya city, Japan. Using this observed data, we calculated the required output of a backup boiler to meet a series of hot-water demand for each month during the time period between August 2000 and March 2001. We evaluated the composition of the hot-water output on the supply side and the hot-water usage on the demand side. Then, by comparing the results with the evaluation using the hourly hot-water demand pattern, which was statistically estimated from the observed hot-water demand, we discussed the influence of the pulsating and fluctuating demand characteristic on the actual efficiency of the IaCGS.

982 OBSERVATION O F HOT-WATER DEMAND We observed the hot-water demand from June 2000. Each family consisted of two adults and a varied number of children in each household. The breakdown of total household members is as follows: 1 for family-A, 3 for family-B, and 2 for family-C. Each household is equipped with a hot-water boiler with the maximum supply capacity of 30 kW. Hot water is available in both the bathroom and kitchen. We installed a thermistor at the exhaust exit of the hot-water boiler and measured the exhaust temperature in intervals of one minute. Figure 1 shows an example of the observed exhaust temperature. We can identify an occurrence of the hot-water demand by a rapid increase of the exhaust temperature. The exhaust temperature was almost stable during the use of hot water, while it gradually decreased after the use of hot water. Therefore, we identified the existence or duration of the hot-water demand by the following criteria: 1) The exhaust temperature increases by 3 or more degrees °C than the temperature measured one minute earlier; or 2) The current temperature is 40°C or more and does not decrease by more than I°C; or 3) The existence of hot-water demand before the one-minute measurement is identified and the current temperature increases more than that of the one minute before. As the position of the thermistor was different among the three families, its sensitivity varied somewhat, resulting in lower observed temperatures in family-B. However, because the purpose of this observation is to identify the occurrence of the hot-water demand, this does not have any influence on the discussion below.

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(a) family-A (b) family-B (c) family-C Figure 1: Exhaust temperature and identification of occurrence of hot-water demand Figure 1 also shows the occurrence of the hot water with the black bars. As the exhaust temperature is measured every one minute, we assumed the minimum duration of the hot-water demand to be one min. In family-A, the continuous hot-water demand around 19:00 was for filling the bathtub and the following pulsating hot-water demands were for shower use. In family-A, it took more time for the first hot-water demand after filling the bathtub to occur, than the other two families. In addition, the variation of the hot-water demand in amount and time was also larger than the other families. In family-B, filling the bathtub started at around 17:00 immediately followed by other hot-water demands. In family-C, the hot-water demand after 21:00 was more than the other families. Because our observation of the exhaust temperature could only identify the occurrence of hot-water demand, we estimated the actual amount of hot-water demand by taking the city water temperature observed together with the exhaust temperature, the setting temperature of the hot-water supply and the hot-water flow rate (11 L/min) into account. Figure 2 shows the amount of the daily hot-water demand. As a comparison, maximum hot-water supply from PEFC (capacity: 1.0 kW, efficiency: 35% for electricity and 40% for heat recovery) is shown by the thick line. In all families, the hot-water demand varied with the day of the week as well as season. Especially, the variation was large during the winter season. Therefore, if a ~tCGS is operated with constant output, the hot water might be wasted on some days, while the hot-water supply using the backup might be required on the other days. Figure 3 shows only one example of a hot-water demand pattem (9 January 2001) and the statistically estimated hourly demand pattern for January. Although the consumption rate of actual hot-water demand is

983 very high, e.g. 27 kW (or J/sec) in January, the duration per one demand is very short, resulting in a small hourly average demand. Because the ability for supplying hot water of a gCGS with 1 kW of PEFC is very small (about 1 kW), the hot-water output of a PEFC cannot directly meet the demand and should be stored once in the hot-water tank and then supplied to the demand. Therefore, if we use the hourly average demand pattern in the evaluation of a I.tCGS, it causes the improper evaluation of ~tCGSs.

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STRUCTURE OF THE I.tCGS The ~tCGS for residential use would consist of a PEFC, a backup boiler and a hot-water storage tank. The capacity of each component varies with many factors such as operation pattern and the system structure of a ktCGS, and demand size, etc. Considering a lifetime of a reformer, which produces hydrogen from natural gas on site, we assumed a continuous operation of 24 hours with a fixed output to meet a base load, where a backup boiler meets the shortage of hot-water supply. As shown in Figure 4, we assumed two system structures of the ktCGS with a different conformation for each backup boiler. System-I is equipped with the backup boiler of 30 kW available for the demand side. Because 30 kW corresponds to the consumption rate of hot-water demand in the winter season, the backup boiler can directly meet the demand to compensate the shortage of the hot-water supply from a PEFC through the hot-water tank. Therefore, because the capacity of a hot-water tank could be reduced in System-l, we assumed 100 L as a base case. On the other hand, System-II is equipped with a small backup boiler of 5 kW as a part of the PEFC side and a large hot-water tank. In System-II, because the hot-water output of the backup boiler is much smaller than the demand, it is stored in the hot-water tank together with the hot-water output of PEFC, and then supplied on demand. We assumed that the backup boiler begins to operate when the stored hot water is lower than 20% of the capacity, refills the hot-water tank and stops when the stored hot water reaches 40% of the capacity.

984

The main assumptions regarding the performance of the gCGS are as follows: 1) A ~tCGS has an efficiency rate of 35% for electricity generation, and 40% for the recovery of hot water at 80°C. 2) The temperature of stored hot water is 70°C. 3) The loss in the hot-water storage is 0.01%/min relative to the stored hot water. 4) The reverse flow of electricity from PEFC to the grid is allowed.

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Composition of Hot WaterSupply and Usage In this paper, we discuss the actual efficiency of the gCGS in family-B where the hot-water demand was largest among the three families. Considering the hot-water demand in family-B as shown in Figure 2, we assumed that the capacity of a PEFC is 1 kW and the PEFC is operated at a rated output throughout the day. Then we calculated the hot-water output patterns of the backup boiler in order to meet a series of the hot-water demand for each month between the period of August 2000 and March 2001. Figure 5 shows the composition of the hot-water output on the supply side. Because of the constant operation at the rated output of the PEFC, the monthly cumulative hot-water output of the PEFC was almost constant. On the other hand, the hot-water output of a backup boiler, which compensates the shortage of hot-water supply, varied with the month. In System-I with a small capacity hot-water tank (100 L), the stored hot water sometimes decreased to zero and the backup boiler was operated frequently, resulting in a larger output of the backup boiler than in System-II. Figure 6 shows the composition of the supplied hot water. In every month, some amount of the supplied hot water was wasted because of the miss-match between demand and supply patterns. As shown in Figure 2, since the hot-water supply is larger than the hot-water demand during most days in the summer season, many portions of hot-water supply from the PEFC were wasted. Therefore, in order to avoid wasting the recovered hot water, the partially loaded operation or DSS operation would be required for a gCGS. Especially, during the month of August where the hot-water demand was very small, it might be preferable that a gCGS does not operate and the hot-water demand is met only by the backup boiler. In the winter season, although the backup boiler was operated as shown in Figure 5, some hot water from the PEFC was still wasted because of the different patterns between the demand and PEFC hot-water output. In System-I during January, the wasted hot-water output of the PEFC reached 42% of the monthly hot-water demand, while the backup boiler met 42% of the monthly hot-water demand. As shown in Figure 4, the hot-water demand was very large and concentrated within a short period. Therefore, especially in System-I with a small hot-water tank, the stored hot water in the tank became empty during the concentrated demand period and the backup boiler met the shortage. However, the other period with no demand, the hot-water tank was filled by the continuous hot-water output of PEFC, and the extra output was wasted. In System-II with the large capacity of the hot-water tank, the loss in the hot-water tank was larger than that in System-I. However, the wasted hot water was smaller than that in System-I, especially during January.

985

Primary Energy Consumption of the IzCGS By using the following equations, we calculated the primary energy consumption of the ~tCGS (El) and the conventional system. Note that the conventional system includes the electric power grid and the boiler (E2). gCGS: E~ = S1 / rib + $2 / rib Conv.: E2 = (Sl / rib x tie ) / rig + Q / rib Where, Sn: hot-water output of a PEFC, $2: hot-water output of a backup boiler, Q: hot-water demand, rib: hot-water output efficiency of a PEFC, tie: electricity-output efficiency of PEFC, rib: efficiency of a backup boiler, rig: efficiency of grid electricity at the receiving end. 5

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(a) System-I (b) System-II Figure 7: Reduction of primary energy consumption Figure 7 shows the reduction of primary energy consumption in a ~tCGS relative to the conventional system. In Figure 7, the results in the ideal situation are shown, which is discussed in the next section. In Figure 7(a) the results in System-I with the larger capacity of the hot-water tank are also shown. The reduction of primary energy consumption was a little larger in System-II than in System-I with the 100 L hot-water tank because of the

986 smaller contribution to the hot-water boiler and less wasted hot water. On the other hand, if System-I would have the hot-water tank with a larger capacity, the operation hour of the backup boiler cold be lowered, resulting higher energy savings but higher investment cost. Therefore, if enough space could be prepared for the ~tCGS installation in a house, the structure of System-II, PEFC with a large hot-water tank and small backup boiler might be preferable. However, the space might be very limited, especially in urban areas, where many ~tCGSs expected to be installed because of well-developed city gas infrastructures. Although many portions of hot-water output of the PEFC was wasted during the summer season as shown in Figure 5, the reduction of primary energy consumption could be derived because of the electricity output from the PEFC when it could be fully utilized in the household or grid. In order to reduce wasted hot water, a Daily Start and Stop (DSS) operation might be a possible option. However, because of fluctuating characteristics of the hot-water demand, it might be difficult to meet the demand by the DSS operation with fixed schedule. Therefore, a DSS operation with a learning function about fluctuating demand characteristics would be required in order to control the ON and OFF schedule suitably. Besides, as the DSS operation might shorten the lifetime of the components in the ~tCGS, e.g. a reformer, a fuel cell, etc., an improvement of lifetime of components would be also required in order to fully utilize the DSS operation.

Influence of Fluctuating Characteristics In order to discuss the effect of fluctuating characteristics of the hot-water demand on the evaluation of the energy saving potential of a ~tCGS, we calculated the primary energy consumption of a IaCGS in the ideal situation with the following hypothesis: 1) The recovered hot water in a PEFC is fully utilized to meet the hot-water demand. 2) PEFC operates only to meet the hot-water demand. 3) The loss in hot water is ignored for the simplicity. 4) The electricity demand is same with actual situation and met by PEFC and grid. In Figure 7, the primary energy consumption in the ideal situation is shown with the black bar on the right side for each month, which can be calculated independently of both the system structure and the demand pattern. As compared to the ideal reduction, the actual reduction of primary energy consumption was small by approximately 10% or more in each month, because the recovered hot water in PEFC is fully utilized and is not wasted in the ideal situation. The difference would be large in the winter season when large hot-water demand existed. For example, in the case of System-I with the 100 L hot-water tank, the reduction of primary energy consumption is only 56% of the ideal situation on January. Therefore, if we evaluate the demand side technologies, such as a ~tCGS for residential use, we should take into consideration the difference between the actual situation and ideal situation. CONCLUSIONS Based on a series of data taken for hot-water demand in three residential households during several months, we evaluated the actual efficiency of a ~tCGS for residential use. Main results are as follows: 1) Due to a pulsating and fluctuating characteristic of the hot-water demand in residential households, some hot-water output of PEFC would be wasted when a constant output operation occurs in the PEFC, especially during the summer season. 2) However, because of the electricity supply, primary energy consumption could be reduced even during the summer. 3) If enough space could be prepared for the ~tCGS installation in a house, a ~tCGS with a large hot-water tank and small backup boiler might be preferable for reducing primary energy consumption. 4) The actual efficiency of a ~tCGS was small approximately 10% or more as compared to the ideal situation, where all hot-water demand was met by only the hot-water output from the PEFC and no hot-water output was wasted. REFERENCES The society of heating, air-conditioning and sanitary engineers of Japan, (1998) Design and Plan Manual of Natural Gas Co-generation '98', Maruzen, pp.33-38. Japan Gas Appliances Inspection Association, (1991) Research Report on Standardization of Combustion Performance of Efficient Gas Combustion Appliances, pp.8-11.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

987

L I T E R A T U R E SURVEY ON E C O N O M I C S OF E N V I R O N M E N T A L FRIENDLY E L E C T R I C I T Y P R O D U C T I O N Takeyoshi Kato Intemational Institute for Applied Systems Analysis (ILASA) Schlossplatz 1, A-2361 Laxenburg, Austria TEL: +43-2236-807-202, FAX: +43-2236-807-488, E-mail: [email protected]

ABSTRACT This paper discusses two technologies, natural gas combined cycle power plants (NGCC) and a proton exchange membrane fuel cells (PEFC), from the perspective of greenhouse gases emission reduction costs. Based on data for capital cost and energy conversion efficiency from IIASA's carbon dioxide technology database (CO2DB), the costs of electricity and greenhouse gas emissions were calculated. Hydrogen was assumed to be produced from natural gas or biomass sources. In the future, the capital costs of PEFC could be considerably reduced as a consequence of mass production. However, the costs of electricity and the amount of emissions emitted from PEFC might be higher than in the case of NGCC, particularly if PEFC is not utilized as a co-generation system. Among all natural gas power plants, this paper concludes that NGCC without CO2 capture might be the most cost-effective option for reducing greenhouse gas emissions. INTRODUCTION

In order to cope with the global wanning problem, it is important choose a cost-effective technology for reducing greenhouse gas emissions. Due to the diversity of available electricity production technologies, such as fuel cells (FC), natural gas combined cycles (NGCC), integrated gasification combined cycles (IGCC), biomass gasification, wind turbines, etc., one needs to choose a suitable technology according to regional circumstances with regards to applicability and availability of technologies and resources. IIASA's CO2DB contains detailed data on greenhouse gas reduction technologies and assists in comparative assessments of various energy technologies. Using the recently updated CO2DB data, this report focuses on a comparison of greenhouse gas reduction costs of PEFC and NGCC. CO2DB

CO2DB is a tool for collecting and analyzing detailed data on greenhouse gas reduction technologies. This tool, available from IIASA,* assists the users in decision-making processes and comparative assessments of different energy technologies based on technical, economical and environmental criteria. In addition to these characteristics, data on innovation, commercialization and diffusion in some 3000 entries are included in the database. The calculations used in this report on electricity production technologies are taken from the recently revised CO2DB version done in 2002.

* To order a copy of the CO2DB, please send an e-mailmessage to AngelaDowds at [email protected]. The database is free of charge to all research institutions.

988 CAPITAL COST AND P E R F O R M A N C E Figure 1 shows data on capital costs and energy conversion efficiencies of FC, NGCC, IGCC, pulverized coal-fired simple cycle (PC), biomass gasification (BIO) and others. The capital costs have been standardized to 2000US$, and if the currency year was not explicitly given, the publication date of the literature was used. Users of CO2DB can make a comparative assessment of various technologies from various points of view, e.g., greenhouse gas reduction costs, technological learning, etc. Due to limited space, this report focuses on a comparison of greenhouse gas reduction costs of NGCC and PEFC. The recent data on both technologies is described first, and then the greenhouse gas reduction costs are discussed. ]

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TREND OF CAPTAL COSTS

Natural Gas Combined Cycle (NGCC) At present, NGCC is the cheapest option for electricity production, when one compares its relatively low greenhouse gas emissions in relation to other fossil fuel power plants. Due to price wars for larger NGCC plants, the capital costs of NGCC decreased rapidly in 1990's. As shown in Figure 1, the capital cost of NGCC in US$/kW decreases in line with increasing capacity, and is lower than other power plants [1-6]. Some NGCCs with higher capital costs are equipped with a CO2 capture technology. In many studies, the capital costs of NGCC including CO2 capture are estimated to be 2 to 3 times higher than ones without CO2 capture, though they might still be cheaper than IGCC or PC without CO2 capture [2-6]. A study of historical capital cost reductions of NGCC using leaming curves shows a progress ratio of 75% during the 1990's, indicating that capital costs declined by 25% for each doubling of cumulative installed capacity [7]. During this period, the increase of turbine input temperature has reached 1430°C and a more integrated steam cycle with a triple pressure system has been applied. With the exception of very small-scaled plants, the thermal efficiency is more than 50% and reached up to 60% on the latest models. Since NGCC can be considered a mature technology, it might be difficult to expect further significant improvements in the medium run (around 2030). Therefore, the progress ratio of NGCC might increase to around 90%, indicating a capital cost decline by only 10% for each doubling of cumulative installed capacity.

Proton Exchange Membrane Fuel Cells (PEFC) FC is a demand-side technology with a much smaller capacity than NGCC. A variety of fuel cells with different electrolytes, i.e., PAFC, MCFC, SOFC and PEFC, are presently in different stages of development. The capital costs of all types of FCs are generally high, and vary widely independently of the capacity [8-15].

989 Over the past few years, there have been intense efforts to develop low-cost PEFC systems. While the primary emphasis has been on automotive applications, an equally important application may be combined heat and power generation in commercial and residential buildings. In the medium run, there could be more potential for reducing the capital costs of PEFC than NGCC. In the automotive applications, the cell stack costs must achieve stringent cost goals of perhaps 50 US$/kW. A recent study regarding PEFCs for automotive application, which utilized a learning curve, concluded that the unit cost can be reduced to 38 US$/kW with the progress ratio of around 80%, assuming an increase of the cumulative number of fuel cell vehicles to 5,000,000 until 2020 [8]. In addition, the technical challenges are in many respects less severe for stationary applications than for automotives, although longer lifetime is required for the stationery application. Therefore, in a recent study, which estimates the capital costs of stationary PEFC with high volume manufacturing, 10,000 units/year, around 300 US$/kW (for a unit size of a few 10 kW) [9]. This figure is also used in the analysis presented below. CALCULATION BASIS PEFC Fueled with Hydrogen In the initial phase of a "hydrogen economy", hydrogen could be produced from currently available competitive fossil fuels. At a later stage, as the market develops, the production system could evolve towards renewable resources, such as biomass. This report assumes that PEFC is fueled with natural gas or hydrogen, where hydrogen is produced either by steam methane reforming (SMR) or biomass gasification. Based on the literature [ 10] including detailed techno-economic analysis of PEFC for residential use, this report assumes for PEFC without reformer 50% lower capital costs and 33% higher efficiencies than for PEFC with reformers. Greenhouse Gas Emissions In terms of total greenhouse gas emissions of electricity production, it is important to account the total emissions of the fuel cycle. In order to calculate the greenhouse gas emissions on a fuel-cycle basis, this paper used the value from the GREET model, which was developed for the evaluation of energy and emission impacts of vehicle technologies by Argonne National Laboratory [ 16-17]. In the GREET model, emissions of CO2, CH4 and N20 are considered at 3 stages, i.e., feedstock recovery, fuel production and final operation. The greenhouse gas emissions from biomass-based hydrogen production were assumed to be fully recovered during the biomass growing cycle. Thus, no greenhouse gas emissions from hydrogen at the final operation stage were assumed.

Cost The costs of generating electricity depend not only on the capital costs, but also on fuel costs, O&M costs, efficiency, and capacity factors, etc. In this study, the cost of electricity (COE) is based upon capital costs and efficiency taken from the literature, and constant values of the other factors. In order to discuss the influence of fuel price differences between supply side and demand side on the COE of PEFCs, the installation of PEFCs on both sides is considered. The assumptions used are described below: Fuel cost O&M cost Capacity factor Discount rate Lifetime

Natural gas: 3.0 US$/GJ (supply side), 6.0 US$/GJ (demand side) Biomass: 5.0 US$/GJ Coal: 1.5 US$/GJ NGCC: 2 mills/kWh, NGCC with COz capture: 4 mills/kWh, PEFC: 3 mills/kWh NGCC: 80%, PEFC: 80% 10% NGCC: 30 years, PEFC: 15 years

The hydrogen production cost was estimated based on the capital costs of hydrogen production systems shown in Figure 2 [18-28]. As for biomass gasification, some different designs of gasifiers are reported. In this assessment, an indirectly heated gasifier developed at the Battelle Columbus Laboratories (BCL) was selected as the representative technology. This biomass gasification technology is not commercialized yet, but it has been estimated to be the cheapest hydrogen source of all biomass gasification options. Considering

990 hydrogen transportation costs of 3 US$/GJ and a production capacity of 1 million Nm3/day (12,800 GJ/day), this report assumes hydrogen costs as follows [29]. SMR: 7 US$/GJ (supply side) BCL: 11 US$/GJ (supply side)

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E L E C T R I C I T Y GENERATION COSTS AND GREENHOUSE GAS EMISSIONS Figure 3 shows COE and greenhouse gas emissions of NGCC and PEFC. Because of the high cost of natural gas on the demand side and relatively lower efficiency, both the COE and greenhouse gas emissions of PEFC fueled with natural gas is still higher than the NGCC without CO2 capture, even if the capital cost of PEFC is reduced to 300 US$/kW by mass production. The COE and greenhouse gas emissions are much higher in the PEFC fueled with hydrogen produced by SMR. Even if the relative low fuel price on the supply side is used, the COE of PEFC is higher than the one of NGCC. Therefore, PEFC must be utilized as a co-generation system for reducing greenhouse gas emissions in comparison to NGCC. In other words, if PEFC producing only electricity is installed at a large-scale due to the lowered capital cost instead of NGCC in the future, greenhouse emissions might increase. If biomass-based hydrogen is used in PEFC, we can assume that emissions are emitted only at the biomass plantation and transportation stages, resulting in very low emissions, though the COE of PEFC fueled with biomass-based hydrogen would be quite high, more than 0.1 US$/kWh. The COE of NGCC without CO2 capture could be smaller than that of NGCC with CO2 capture unless the carbon tax of 300 US$/t-C is applied. <>NGCC w/o CO2 cap. [] FC (natural gas)

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side

991 GREENHOUSE GAS REDUCTION COST Figure 4 shows the relationship between the emissions reductions and the reduction costs (CoHo) relative to a conventional coal power plant with 0.039 US$/kWh and 850 kg-CO2/kWh. Because of the low COE, CoHo of NGCC without CO2 capture is negative. NGCC without CO2 capture might be the most cost-effective option for reducing greenhouse gases among electricity production technologies fueled with natural gas. CoHo of NGCC with CO2 capture is still lower than that ofPEFC. Ifa very high carbon tax is applied, the NGCC with CO2 capture and then the PEFC fueled with biomass-based hydrogen could also be cost-effective for reducing emissions. However, PEFC fueled with natural gas or natural gas-based hydrogen might not be a costeffective option unless it is utilized as a co-generation system to reduce the emissions from boilers for hot water supply. ! O NGCC w/o CO2 cap. [] FC (natural gas)

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(b) PEFC supply side (a) PEFC demand side Figure 4: Greenhouse gas reduction costs relative to a conventional coal power plant

CONCLUSIONS By analysing data from the updated CO2DB, this report discussed the cost-effectiveness of NGCC and PEFC technologies in reducing greenhouse gases. The emissions reduction costs of PEFC might be higher than the ones of NGCC, even if the mass production of PEFC considerably reduces its capital costs. Therefore, PEFC should be used as a co-generation system for reducing greenhouse gas emissions in a cost-effective way. In the medium run, NGCC without CO2 capture might be the most cost-effective technology among electricity production technologies fueled with natural gas. REFERENCES Gas Turbine World 2000-2001 Handbook (2000) Vol.21, Pequot Publishing David, J., and Herzog, H. (2000) The Cost of Carbon Capture. Proc. of the Fifth International Conference on Greenhouse Gas Control Technologies (GHGT-5), pp.985-990 Audus, H. (2000) Leading Options for the Capture of CO2 at Power Stations, 5th International Conference on Greenhouse Gas Control Technologies (GHGT-5), pp.91-96 Undrum, H., Bolland, O., and Aarebort, E. (2000) Economical Assessment of Natural Gas Fired Combined Cycle Power Plant with CO2 Capture and Sequestration, 5th Intemational Conference on Greenhouse Gas Control Technologies (GHGT-5), pp.167-172 Herzog, H., and Vukmirovic, N. (1999) CO2 Sequestration : Opportunities and Challenges, 7th Clean Coal Technology Conference Delallo, M., Buchanan, T., White, J., Holt, N., and Wolk, R. (2000) Evaluation of Innovative Fossil

992

10. 11. 12. 13. 14. 15.

16. 17. 18.

19. 20. 21. 22. 23. 24.

25.

26.

27. 28. 29.

Cycles Incorporating CO2 Removal, Proc. of 2000 Gasification Technologies Conference Colpier, U.C., and Comland, D. (2002) The Economics of the Combined Cycle Gas Turbine - An Experience Curve Analysis, Energy Policy 30, pp.309-316 Tsuchiya, H., and Kobayashi, O. (2002) Fuel Cell Cost Study by Learning Curve, presented at International Energy Workshop 2002. available at Kreutz, T., and Ogden, J. (2000) Assessment of Hydrogen-Fueled Proton Exchange Membrane Fuel Cells for Distributed Generation and Cogeneration. Proc. of the 2000 U.S. DOE Hydrogen Program Review, pp.785-827. Thomas, C.E., James, B.D., and Lomax, F.D. (2000) Analysis of Residential Fuel Cell System & PNGV Fuel Cell Vehicles. Proc. of the 2000 U.S. DOE Hydrogen Program Review, pp.756-784. Schaeffer, G.J. (1998) Fuel Cells for the Future. University of Twente, (ISBN 90 365 12 30 1). Brown, D. R. and Jones, R., (1999) An Overview of Stationary Fuel Cell Technology, Report PNNL12147 prepared for the U.S. Army Forces Command (FORSCOM), DE-AC06-76RLO 1830. Ernst, W.D., Law, J., Chen, J., and Acker, W. (1998) PEM Fuel Cell Power Systems for Automotive Applications: Technology and Implementation. Paper presented at the Fuel Cell Seminar 1998 Bloomfield, D., and Bloomfield, V. (1998) Residential Power Generator. Paper presented at the Fuel Cell Seminar 1998 Iannucii, J., Eyer, J., and Horgan, S. (1999) Economic Market Potential Evaluation for Hydrogen Fueled Distributed Generation and Storage, Proc. of the 1999 U.S DOE Hydrogen Program Review, NREL/CP-570-26938 Wang, M.Q. (1999) GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, Development, Use, and Results, ANL/ESD-39, Vol.1 Wang, M.Q., Saricks, C., and Santini, D. (1999) Effects of Fuel Ethanol Use on Fuel-Cycle Energy and Greenhouse Gas Emissions, ANL/ESD-38. Mann, M., K. (1995) Technical and Economic Assessment of Producing Hydrogen by Reforming Syngas from the Battelle Indirectly Heated Biomass Gasifier, Report NREL/TP-431-8143, NREL/DOE. Williams,.R.H. (1998) Fuel Decarbonization for Fuel Cell Applications and Sequestration of the separated CO2. Spath, P.L., and Mann, M.K. (1998) Technoeconomic assessment of four biomass-to hydrogen conversion technologies. Proceedings of the 12th World Hydrogen Energy Conference Amos, W., (1998) Analysis of Two Biomass Gasification/Fuel Cell Scenarios for Small-Scale Power Generation, NREL/TP-570-25106 Basye, L., and Swaminathan, S. (1997) Hydrogen Production Costs - A Survey SENTECH, Inc. Report DOE/GO/10170-778, US Department of Energy, Maryland, US. Wurster, R., and Zittel, W. (1994) Hydrogen Energy, published at the workshop on Energy technologies to reduce CO2 emissions in Europe: prospects, competition, synergy. NEDO (New Energy and Industrial Technology Development Organization) (1999) Conceptual design of the total system. World Energy Network (WE-NET) Project Annual Report, Subtask 3: Tokyo, Japan. Written in Japanese. Williams, R.H. (1998) Fuel decarbonization for fuel cell applications and sequestration of the separated CO2. In Ecorestructuring: Implications for Sustainable Development. R.U. Ayres, P.M. Weaver (eds.), United Nations University Press, Tokyo, pp. 180-222. Blok, K., Williams, R.H., Katofsky, R.E., and Hendriks, C.A. (1997) Hydrogen Production From Natural Gas Sequestration of Recovered CO2 in Depleted Gas Wells And Enhanced Natural Gas Recovery, Energy 22(2/3), pp.161-168. Berry, G. D. (1996) Hydrogen as a Transportation Fuel: Costs and Benefits, Report UCRL-ID123465, Lawrence Livermore National Laboratory, University of California, California, US. Ogden, J. (1999) Hydrogen Energy System Studies. Report NREL/TP-570-26938, National Renewable Energy Laboratory, US Department of Energy, Colorado, U.S. Makihira, A., Barreto, L., and Riahi, K. (2002) Assessment of Alternative Hydrogen Pathways: Natural Gas and Biomass, ILASA (International Institute for Applied Systems Analysis), Final Report on the TEPCO-IIASA Collaborative Study.

ENERGY E F F I C I E N C Y INDUSTRY

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

995

THE C E M E N T INDUSTRY AND GLOBAL C L I M A T E CHANGE: C U R R E N T AND POTENTIAL FUTURE C E M E N T I N D U S T R Y CO2 EMISSIONS Natesan Mahasenan l, Steve Smith 2 and Kenneth Humphreys l IPacific Northwest National Laboratory - Battelle, Richland, WA 99352, USA. 2joint Global Change Research Institute, Pacific Northwest National Laboratory- Battelle - University of Maryland, College Park, MD 20740, USA.

ABSTRACT

The cement industry is responsible for approximately 5% of global anthropogenic carbon dioxide emissions. Atmospheric concentrations of greenhouse gases cannot be stabilized without addressing this important emissions source. The industry emits nearly 900 kg of CO2 for every 1000 kg of cement produced. As a result of the significant emissions per unit of cement produced, emerging climate change policies have the potential to place the industry at significant financial risk. To create the foundation for an industry-wide climate change response strategy and manage the associated environmental and financial risk, ten of the world's largest cement companies, under the auspices of the World Business Council for Sustainable Development, sponsored a quantitative assessment of current and potential future CO2 emissions from the cement industry in 14 regions of the world [1 ]. Some key results from the assessment are reported in this paper. Quantitatively, current and potential future cement industry greenhouse gas emissions are evaluated under the new family of Intergovemmental Panel on Climate Change (IPCC) scenarios that were developed as part of the Third Assessment and documented in the Special Report on Emissions Scenarios (SRES). The results of the assessment show that if the industry does not improve its current specific emissions (i.e., kg of CO2 emitted per unit of cement produced), its relative contribution to anthropogenic CO2 emissions increases by more than one order of magnitude over the next century. The industry faces several challenges as it seeks to reduce its specific CO2 emissions, including (1) its heavy dependence on fossil fuels, and especially highcarbon fossil fuels, (2) its dependence on limestone-based clinker, and (3) the age and efficiency of its capital stock, especially in regions where future demand is expected to be high.

INTRODUCTION

The cement industry is responsible for approximately 5% of the global anthropogenic CO2 emissions (based on data from [2,3,4,5,6]). Cement-related greenhouse gas emissions come from fossil fuel combustion at cement manufacturing operations (about 40% of the industry's emissions); transport of raw materials (about 5%); and combustion of fossil fuel required to produce the electricity consumed by cement manufacturing operations (about 5%). The remaining cement-related emissions (about 50%) originate from the process that converts limestone (CaCO3) to calcium oxide (CaO), the primary precursor to cement, as shown in Eqn. 1: CaCO

3 --), C a O + C O z

(1)

996 As shown by Eqn. 1, it is chemically impossible to convert limestone (CaCO3) to CaD and then cement clinker without generating CO2, which is currently emitted to the atmosphere. Table 1, based on data from [3,4,5,6], presents the total estimated emissions, cement demand, unit emissions, energy intensity and clinker factor (kg of clinker per kg of cement) in 2000 for the global cement industry. As shown, the gross unit-based emissions for the industry were approximately 0.87 kg CO2 per kg of cement. Unit-based emissions vary globally from 0.73 to 0.99 kg CO2 per kg of cement. There is similar variation in energy intensity and clinker factor. Two of the important factors that drive unit-based CO2 emissions are the energy intensity and clinker factor. Lowering the energy intensity lowers the fossil fuel combustion during production. Lowering the clinker factor directly reduces both the process emissions and the associated fuel-related emissions, as shown in Eqn. 1. Other options for reducing unit CO2 emissions are switching to fuels with lower carbon content, or using fuels that qualify for an emissions credit. TABLE 1 CEMENT DEMAND, TOTAL AND UNIT CO2 EMISSIONS, ENERGY INTENSITY AND CLINKER FACTOR IN MAJOR WORLD REGIONS FOR THE YEAR 2000

Region

Total C02 Emissions (Mt/year)

Total Cement Demand (Mt/Year)

UnitEmissions (Mt CO2 / Mt Cement)

Energy Intensity (MJ/Kg Cement)

90

90

186 60

220 82

449 112 " 40 64

500 123 44 69 88 37 134 87 80 1571

0.99 0.91 0.84 0.73 0.79 0.90 0.92 0.90 0.93 0.81 0.89 0.82 0.85 0.85 0.87

5.50 5.20 4.04 3.10 4.08 4.71 4.65 4.05 4.71 5.52 5.20 4.48 4.75 4.92 -

1. USA 2. Canada 3. W. Europe 4. Japan 5. Aus. & NZ 6. China 7. SE. Asia 8. Rep. of Korea 9. India 10. FSU 11. Other E. Europe 12. S. & L. America 13. Africa 14. Middle East TOTAL

THE EMISSIONS REDUCTION

109 74 68 1371

Clinker Factor (Kg/Kg)

0.88 0.88 0.81 0.80 0.84 0.83 0.91 0.96 0.89 0.83 0.83 0.84 0.87 0.89

CHALLENGE

Historically, the cement industry as a whole has made only modest gains in lowering energy intensity and the clinker factor over the last decade or so, though some regions have done better [1 ]. In order to understand the magnitude of the challenge facing the cement industry, we need to understand the implications of no-action by the cement industry against future trends in worldwide emissions. Future human social, economic, and technological development cannot be predicted with a high level of certainty. Therefore, in looking at the future over long time horizons, it is helpful to examine a number of plausible future scenarios. We use the scenarios developed by the Special Report on Emissions Scenarios [7], under the auspices of the Intergovernmental Panel on Climate Change (IPCC). The IPCC SRES scenarios are grouped into 4 families, each with a set unique set of economic, demographic, technology and energy-use assumptions. These scenarios are termed A1, A2, B 1 and B2, and are described in detail in [7].

Understanding Cement Demand In order to compare future cement emissions against these baselines, it is necessary to develop a predictive equation for future cement demand. Two obvious candidates for the predictive variables are population and gross domestic product, or GDP. Historical cement demand [4,5] was compared with GDP and population data for the 14 regions shown in Table 1 for a sub-interval of at least 20 years between (1947-1997). To ensure a consistent comparison across the different regions, the GDP values were adjusted for purchasing

997

power parity (PPP). When the cement data in per capita terms are evaluated, a consistent pattern emerges. In "developed" economies (USA, Canada, Japan, Australia & New Zealand, and Western Europe), the cement demand 'flattens' out when per capita GDP is approximately US$8000 (expressed in 1990 dollars). This is consistent with the literature [8]. Representative plots for Japan and Western Europe are shown in Figure 1.

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Figure 1. Per Capita Cement Demand vs. Per Capita GDP for Western Europe and Japan In China, Korea, India, Latin and South America, and other developing regions, where per capita GDP has not yet reached US$8000, the per capita cement demand is a linearly increasing function of the per capita GDP. Representative plots for China and India are shown in Figure 2. 300

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Figure 2. Per Capita Cement Demand vs. Per Capita GDP for China and India

Based on this remarkably consistent observation across all regions, it was postulated that cement demand is proportional to the GDP at lower income levels (< US$8000, deflated to 1990), while at higher income levels, it is proportional to the population. The function form shown in Eqn. 2 can therefore represent cement demand, when GDP and population are known. A X -'r + B X r Demand

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998 From the above equation, it can be readily seen that at low incomes (X is small), the relationship reduces to simply A (=a*GDP), and at high X, it reduces to B (=[3*population). In order to test the above functional form, tx and 13were estimated for each region based on historical values for cement demand, GDP and population, ot is estimated when per capita GDP is below US$8000, and [3 is estimated once per capita income exceeds that threshold. In developing regions, where per-capita incomes are less than US$8000, [3 values are assigned based on values in developed parts of the world. After a and [3 were determined in this way, historical GDP and population data were used to predict historical cement demand and compared against the actual numbers. Excellent fit and r: values generally in excess of 0.95 were obtained for all regions for '{=3. A comparison of the actual cement demand per capita and the predicted cement demand per capita for selected regions is shown in Figure 3. 800

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Projecting Future Cement Demand Based on the GDP and population data for the four IPCC SRES scenarios [7], we can now project cement demand into the 21 st century. Projected cement demand over the next century is shown in Figure 4. The global demand projections for the four scenarios highlight the nature of the challenge for the industry: while the demand projections are closely bunched together until about 2020 or so (about 30% difference between the extreme scenarios), the gap widens to a factor of four by the end of the next century. Thus, it is imperative that whatever strategy the industry chooses to meet its 2020 goals must be sufficient to handle the longer-term growth in cement demand. The spatial distribution of the demand is also important. In all four scenarios, the highest demand and the fastest growth are in Asia, followed by Africa and the Middle East, where demand increases quite rapidly after 2020. Latin/South America and Eastern Europe show modest increases in cement demand over the next half-century, while it is relatively flat in Western Europe and North America. These trends are keeping with the historical relationship between per capita incomes, population and cement demand. The regions that have rapidly growing economies and/or populations are predicted to show proportionally large increases in the demand for cement, while relatively prosperous regions with slower population growth show much lower demand growth rates. There may also be cultural and societal factors driving the cement demand in different parts of the world-- for example, multi-family housing, which is popular in areas with high population densities (and relatively lower incomes), is much more cement and concrete intensive than single-family housing that may be found in areas with lower population densities and/or higher income levels.

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Figure 4. Projected Cement Demand under IPCC SRES Scenarios

As the cement industry makes progress on the issue of climate change, it will be necessary for the industry and individual companies to set emission mitigation goals. While there are a multitude of possible goals, it is suggested here that one plausible goal is for the industry to commit itself to participating in a global effort that includes a peak in global emissions, followed by an indefinite decline in emissions until stabilization of atmospheric concentrations of greenhouse gases is achieved. For the purposes of understanding the possible implications for the industry of adopting such a goal, this paper assumes that 1) the industry makes this commitment and 2) further commits to not allowing the industry's relative contribution to global emissions (-5%) to exceed this level. That is, in the near-term while global emissions from all sources continue to grow, they would grow at a pace equal to or less than this growth. In the medium- to long-term when global emissions are declining, cement industry emissions would decline at an equal or greater pace. This would put the cement industry in a leadership position on the long road to addressing climate change and creating a more sustainable industrial system. Under this type of mitigation regime, Table 2 provides the projected cement demand, cement-related CO2 emissions under No-Action, target CO2 emissions and the improvement in unit emissions that would be required to meet the target.

TABLE 2 PROJECTED CEMENT DEMAND, CO2 EMISSIONS AND IMPROVEMENT REQUIRED

Scenario ~ Cement Demand (Mt) No-Action Cement Emissions (Mt CO2) Share of Global CO2 Emissions Target Emissions (Mt CO2) Implied Improvement in Unit Emissions from No-Action Case Cement Demand (Mt) No-Action Cement Emissions (Mt CO2) Share of Global C O 2 Emissions Target Emissions (Mt CO2) Implied Improvement in Unit Emissions from No-Action Case

A1B 3221 2675 7% 1841

A2 2656 2190 6% 1816

BI 2483 2054 7% 1464

B2 2855 2378 7% 1560

31%

17%

29%

34%

5488 4604 8% 2848

5086 4241 7% 3017

3766 3153 8% 1881

5067 4766 9% 1949

38%

29%

40%

59%

The results suggest that if the cement industry chooses to minimize its financial risk and adopt a leadership position on this issue, a productive goal would be for the industry to commit itself to a reduction in unitbased emissions of 30% by 2020 (based on the range of possible required reductions, 17% to 34% in Table

1000 2, associated with a range of possible future scenarios). Meeting such a goal would require that the industry implement significant mitigation measures in the short-term. At the same time, the results suggest that the cement industry must work to develop new technology and new cementituous products that will enable larger reductions by 2050 (by up to an additional 30%) when global cement demand potentially increases dramatically and climate change policies also tighten. CONCLUSIONS The cement industry is faced with potentially explosive demand for its product over the next few decades. Across the four scenarios examined here, global cement demand is projected to increase 60% to 105% over current levels by 2020. By 2050, three of the four scenarios have approximately equivalent cement demand, with an approximately-225% increase from current levels. Most of the increase in demand is in developing regions of the world, where the industry's current capital stock is relatively old and inefficient. While 2050 may seem far into the future, nearly all cement plants built in the coming decade or two to meet this demand will still be operating at this point in time. Thus, the decisions the industry makes today to meet this significant emissions mitigation challenge will affect its future well beyond 2020. The cement industry therefore needs to adopt a two-pronged strategy for responding to this challenge. First, companies must progressively pursue cost-effective CO2 reductions by (1) expanding sales of cement with lower clinker content (e.g., composite cement with fly ash or blast furnace slag), (2) increasing the use of alternative fuels (bio-based, low-carbon, or waste fuels that provide a net carbon dioxide emissions reduction), and (3) initiating energy efficiency enhancements (improving equipment and phasing out inefficient plants). Second, to enable additional, long-term, cost-effective CO2 reductions, the cement industry must undertake or support R&D at a much higher level than today. This R&D must be focused on the development of highly innovative low-CO2 products and processes, as well as low-CO2 business ventures. Examples of such ventures might include capturing and sequestering CO2, co-producing electricity and cement in lowCO2 facilities, or earning royalty income from low-CO2 processes or products licensed to other companies. Without a commitment to long-term innovation, the industry will likely find itself facing growing emission liabilities as individual nations commit themselves to ever-tighter CO2 constraints in an attempt to stabilize atmospheric concentrations of greenhouse gases.

REFERENCES

1. Humphreys, K.K. and Mahasenan, N (2001). Towards a Sustainable Cement Industry: Substudy 8: Climate Change. World Business Council for Sustainable Development, Conches-Geneva, Switzerland. 2. IPCC (2001). Climate Change 2001: The Scientific Basis. Intergovernmental Panel on Climate Change, Cambridge University Press, Cambridge, UK. 3. International Energy Agency (1999). The Reduction of Greenhouse Gas Emissions From The Cement Industry, Report PH3/7, Paris, France. 4. CEMBUREAU (1996). World Cement Directory, CEMBUREAU - The European Cement Association, Brussels, Belgium. 5. CEMBUREAU (1998). Cement Production, Trade, Consumption Data: World Cement Market in Figures 1913-1995, Worm Statistical Review No. 18, CEMBUREAU - The European Cement Association, Brussels, Belgium. 6. CEMBUREAU (1999). Cement Production, Trade, Consumption Data 1994-1997, Worm Statistical Review Nos. 19 and 20, CEMBUREAU - The European Cement Association, Brussels, Belgium. 7. Nakicenovic, N. and R. Swart, eds. (2000). Special Report on Emissions Scenarios, Intergovernmental Panel on Climate Change, Cambridge University Press, Cambridge, U.K. 8. Aitcin, Pierre-Claude (2000). Cement and Concrete Research. 30:1349.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1001

I M P R O V E M E N T IN ENERGY EFFICIENCY OF RE-ROLLING FURNACES FOR STAINLESS STEEL INDUSTRY AT JODHPUR, RAJASTHAN, INDIA U.P. Singh GM (PS), Petroleum Conservation Research Association ABSTRACT In India, there are a large number of stainless steel re-rolling mills in the small and medium sectors, located in three main clusters at Jodhpur, Ahmedabad & Delhi. The majority of these mills use furnace oil as fuel in their reheating as well as annealing furnaces to heat the stainless steel billets/sheets to rolling temperature of around 1250°C for the production of stainless steel sheets of required thickness and other items such as bar and rod stock. The Petroleum Conservation Research Association (PCRA) carried out energy audit studies in about 10 mills in the Jodhpur cluster during 1998-99 and identified large potentials for improvement in energy efficiency and reduction in GHG emissions through upgrading of technology in the re-heating and annealing furnaces of these mills. Over 80% of the stainless steel re-rolling mills have already upgraded the technology in their re-heating and annealing furnaces and the specific fuel consumption has come down from 80-100 liters/M.T, to around 35-40 liters/M/T. This has also resulted in about 60% reduction in GHG emissions. BACKGROUND

Steel re-rolling is the most popular method of producing finished steel all over the world. Almost all steel products made from steel are finished in the re-rolling/annealing process. With the increasing requirement of steel in the country and limitations of the main steel producers to meet this growing demand, the secondary steel sector is an alternative and viable source to meet the country's future steel requirements. In India, there are over 1500 mild steel re-rolling mills located in four main clusters, as well as other places. There are also a large number of stainless steel re-rolling mills located in three main clusters at Jodhpur, Ahmedabad and Delhi, as well as elsewhere within the country. The stainless steel sheets are used for manufacture of utensils and for industrial applications. In the Jodhpur cluster of stainless steel re-rolling mills, there are nearly 100 units. The Ahmedabad and Delhi clusters also have a high number of stainless steel re-rolling mills apart from other stainless steel re-rolling mills located at other places in the country. Most of the stainless steel re-rolling mills use furnace oil as fuel for heating raw steel sheets / billets to temperatures of about 1250°C, followed by annealing for the production of stainless steel sheets of required thickness and size, as well as bars and rod stock. R E - H E A T I N G AND A N N E A L I N G FURNACES

The re-heating/annealing furnaces are the heart of the stainless steel re-rolling mill. The primary energy sources used in the re-rolling mills are electricity, coal or fuel oil in the form of furnace oil, R.F.O., LSHS, and LDO. Thermal energy is required for heating the stainless steel sheets / billets before the rolling operations and the electrical energy is required to run the mill and other auxiliaries of the furnace, mill and lighting. The annealing furnaces also need electricity as well as furnace oil as a source of energy. The energy cost used to constitute about 4 0 - 50% of the total cost of the mills in this

1002

industry. This has now reduced to 25 -30% after incorporating technology upgrading in the fumaces. In view of the high cost of fuel, as well as scale losses, the rolling operation becomes viable only for an industry which operates at minimum cost. In order to achieve this, it is absolutely essential to study reheating and annealing furnaces in a scientific manner, so that they can be improved or modified to achieve optimum results. Even today, this idea has not been applied to many of the rolling mills and they continue to operate in a haphazard manner, resulting in a loss to the unit and national exchequer. In a re-heating and annealing furnace, to obtain the maximum efficiency, the following points have to be considered; Minimum and maximum size of raw material used in the furnaces. Maximum capacity required i.e. in tonnes per hour. This capacity has to be about 25% more than the mill capacity. Least consumption of furnace oil. Least possible scale losses. In order to obtain the above a real scientific analysis of the following is required to be done.

a) b)

c)

Inside volume of the fumace to accommodate the products of combustion. Correct profile of the furnace - there are three types of heat transfer - conduction, convection, and radiation. Of these, radiation is the most important and about 70-75% of the heat absorbed by the material is by radiation, which comes from proper profile of the furnace and correct placement of burners. Selection of combustion equipment such as, blowers, heating, pumping unit and burners. This plays a very vital role and the selection has to be on the basis of standard calculations. These aspects are more or less lacking in most of the Indian Stainless Steel rolling mills.

ENERGY AUDIT STUDIES CARRIED OUT BY PCRA As per its mandate, PCRA carried out energy audit studies in about ten numbers of stainless steel rerolling mills in Jodhpur cluster during 1998-99. Following areas were covered during the study: i) Performance of re-heating and annealing furnaces ii) Insulation of re-heating and annealing furnaces iii) Performance of Motors iv) Performance of Transmission Drive v) Study of Illumination Salient observations made during energy audit studies in these mills were as follows: 1. Efficiencies of furnaces were in the range of 30-32% which can be improved to 55-60%. 2. Large amount of heat is wasted in flue gases. Waste heat recovery should be done. Maximum waste heat can be recovered by preheating the metal. 3. Preheating of air by installation of a recuperator leads to better combustion. However primary air and secondary air will require different pressure and flow, which needs review of burner design. Also, there will be change in the process parameters at blower end, as well as at burner end. Accordingly process needs to be reviewed and blower parameters should be selected accordingly. 4. Preheating of combustion air/oil leads to higher flame temperature, which again leads to faster heat transfer. Due to this, increase in production can be expected. 5. Motors are driven through V belt drive hence for better efficiency energy efficient fiat belts can be used. 6. Illumination was reviewed. Better fitting and improved lighting will lead to better working environment along with saving. 7. The movement of the product was manual in both re-heating and annealing furnaces.

1003 8. The length of fumaces was varying from 12 to 14' at the inception stage, which was raised to 21' in course of time. 9. Stainless steel sheets in annealing furnaces were being fed and taken out from the front side only. GENERAL R E C O M M E N D A T I O N S MADE ON THE BASIS OF ENERGY AUDIT STUDIES IN STAINLESS STEEL R E R O L L I N G MILLS AT JODHPUR 1. Recycle Waste heat to the maximum extent possible 2. Use fuel efficient equipment 3. Use fuel efficient low excess air burners 4. Clean burner nozzles and oil filters regularly 5. Maintain pre-heat temperature of oil at the optimum level 6. Reduce excess air (keep CO2 above 13% or 02 below 3.5%) 7. Check thermal insulation 8. Have regular Energy Audit Studies carried out SALIENT FEATURES OF OLD DESIGN RE-HEATING & ANNEALING FURNACES A. The salient features / specifications of old design reheating furnaces are shown in Fig. No. 1, the details of which are as follows • i) The material is fed from the gate (1) ii) Material is coming out from gate (2) iii) Loading of material is manual on rollers iv) There are two burners installed on both ends of furnaces and are in operation continuously. v) Whenever the exhaust port is open, fuel consumption increases and hence the same is kept closed. Consequently, all the flue gases come out through gate no. 1 & 2 at a temp. of approximately 850°C. B.

The salient features / specifications of old design annealing furnaces, are as follows : i) The material is fed from the gate (1) ii) The material is taken out from the same gate (1) iii) Loading of the material is manual iv) There are three nos. of blowers for comfort of operators v) The burner is installed on the side of gate no. (1) and this is in operation continuously.

PCRA IMPROVED DESIGN R E H E A T I N G FURNACE A. PCRA developed an improved design reheating furnace having the following salient features/specifications which are shown in Fig. 2: 1. Provision for material preheating by increasing length of the furnace. 2. Optimizing number of burners and their locations. 3. Provision of a recuperater to pre heat combustion air by utilizing the waste heat content in the flue gases. 4. Improvement in furnace insulation and use of ceramic fibre for minimizing heat loss from outer surface of the furnace. 5. Entry of the material into the furnace from one end by a pusher arrangement and exit from the other end. B.

PCRA also developed an improved design annealing furnace having the following salient features/specifications which are shown in Fig. 3: 1. The length of fumace was increased to about 40' 2. Only one burner was provided on the front and of the furnace, from which material comes out 3. Provision of a recuperater to pre heat combustion air by utilizing the waste heat content in the flue gases.

1004 Improvement in furnace insulation and use of ceramic fibre for minimizing heat loss from outer surface of the furnace. The material enters the furnace from one end on rollers and comes out from the other end. C.

The salient features / specifications of PCRA improved design reheating & annealing furnaces are summarized as under : S.N.

2

3

PARAMETERS

OLD DESIGN R E H E A TING/A NNEALING FURNACE

PCRA 'S I M P R 0 VE D DESIGN R E H E A TING/AN NEALING FURNACE

SAVINGS

REMARKS

Length of Furnace

21 feet

33-40 feet

Upto 10%

Waste recovery

Metal ingots preheated Installed recuperator

Specific Fuel 80-100 Lit/M.T. 35-40 Lit/M.T. Consumption

Used ceramic fibre for insulation Saving of over 60%

heat No waste heat Temperature of Upto 10% recovery combustion air raised upto 260°C Improvement in Avg. skin temp. Max.Avg. skin Upto20% Furnace Insulation 120°C & above temperature up to 60°C

P C R A ' S R E C O M M E N D A T I O N F O R F U R T H E R I M P R O V E M E N T IN P E R F O R M A N C E OF R E H E A T I N G / A N N E A L I N G FURNACES Flue Gas Temp. is still high (400 °C and above). Further waste heat can be recovered by : i) Increasing preheated combustion air temp. ii) Installing regenerative burners. Presently heavy oil is used for combustion that requires higher air / fuel ratio & greater mass of flue gases emitted per kg of oil burnt. Introduction of gaseous fuel can reduce emissions. Use of PID controllers, provision of air curtains can reduce heat loss from charging & discharging doors. This will improve overall specific fuel consumption. Accurate control of material temperature. C O M P A R I S I O N OF P E R F O R M A N C E OF R E H E A T I N G FURNACES IN 3 NOS OF INDUSTRIES B E T W E E N OLD DESIGN FURNACES AND P C R A I M P R O V E D DESIGN FURNACES PCRA carried out additional energy audit studies after replacement of old design fumaces with PCRA improved design furnaces. The salient observations in three industries are shown in Table 1. I M P R O V E M E N T IN E N E R G Y E F F I C I E N C Y OF R E - R O L L I N G M I L L S F O R STAINLESS STEEL INDUSTRY AT JODHPUR, RAJASTHAN, INDIA About 80 steel re-rolling mills in the Jodhpur cluster have replaced the old design of re-heating and annealing furnaces with PCRA improved designed furnaces. This has resulted in a reduction in specific fuel consumption from a level of 80 to 100 lit/MT to 35-40 lit/MT. In view of growing demand for rerolled stainless steel products in the country, the stainless steel re-rolling mills at Jodhpur have increased their production capacities by almost 2.5 times, maintaining the earlier level of fuel consumption at around 31000 KL/Annum. With PCRA improved designed furnaces, at a furnace oil consumption level of 31000 KL/annum and specific fuel consumption of 90 liffMT (average), the total

1005

capacity of all the stainless steel re-rolling mills at Jodhpur was nearly 344, 450 MT/annum. For rerolling of the same quantity o f stainless steel with PCRA improved design furnaces having specific fuel consumption of 36 l i ~ T (average), the fuel oil consumption would only be 12400 KL. Thus, there is a saving of nearlyl 8,600 KL/annum of furnace oil for stainless re-rolling compared with the earlier level of 344,450 MT/annum. Therefore the improvement in energy efficiency

= 18,600 / 31,000 = 60%

R E D U C T I O N IN COz E M I S S I O N Specific gravity of fumace oil at 70°C = 0.90 Carbon contents in furnace oil = 86% by weight. Due to burning of furnace oil, CO2 is formed as per the following reaction: C+ 02 Therefore, saving in emission of CO2 due to reduction in furnace oil consumption by 18600 kl/annum

~ CO2

= 18,600 x 0.86 x 0.9 x 44 12 = 52790 M.T./annum

CONCLUSIONS PCRA has successfully developed an improved design o f reheating as well as annealing furnace for stainless steel re-rolling mills at Jodhpur, which has been adopted by over 80 steel re-rolling mills at Jodhpur. The energy cost in these mills has reduced significantly from a level of 40-50% to 25-30%, of the total cost o f the mills. In addition, fuel savings of about 60% and CO2 emissions reduction of more than 50,000 MT/annum have been achieved.

TABLE 1 COMPARATIVE PERFORMANCE OF REHEATING FURNACES AS PER OLD DESIGN AND PCRA IMPROVED DESIGN IN A FEW STAINLESS STEEL RE-ROLLING MILLS AT JODHPUR Name of Industry

Heat units

Input Heat i) Heatof fuel ii) SensibleHeat of Air Out put Heat i) Material Sensible Heat ii) Flue gas losses iii) Wall Losses/Rad.Losses iv) Other Losses

Chetan With old design urnace Kcal/hr %

Metal

883200 _

100 _

Surabhi Alloys

PCRA

Tri Murti Steels With PCRA design

With PCRA design

With

urnace Kcal/hr

%

design furnace Kcal/hr %

urnace Kcal/hr

%

321408 36519

89.8 10.2

480000 37628

92.7 7.3

288000 37628

88.4 11.6

165100

18.6

164190

45.9

190271

36.80

93210

28.80

581642 24179

65.8 2.7

121049 22274

33.8 6.2

225929 44683

43.60 8.60

111054 31082

34.20 8.60

112279

12.9

50414

14.1

56745

11.00

56745

19.40

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1007

IMPLEMENTATION OF A CORPORATE-WIDE PROCESS FOR ESTIMATING ENERGY CONSUMPTION AND GREENHOUSE GAS EMISSIONS FROM OIL AND GAS INDUSTRY OPERATIONS Susann Nordrum, Arthur Lee, Georgia Callahan ChevronTexaco Corporation 6001 Bollinger Canyon Rd., San Ramon, California, USA 94583

ABSTRACT

ChevronTexaco Corporation believes that global climate change is an important issue and is taking action to address it. We are responding to the concern about climate change with a four-fold plan of action. We are: • Reducing emissions of greenhouse gases and increasing energy efficiency • Investing in research, development and improved technology • Pursuing business opportunities in promising innovative energy technologies • Supporting flexible and economically sound policies and mechanisms that protect the environment. The ChevronTexaco Energy and Greenhouse Gas Inventory System (CEGIS) was designed and implemented to establish a reliable baseline and have a verifiable inventory of greenhouse gas emissions. This will enable us to pursue our goal of reducing emissions per unit output from our operations. CEGIS is an automated, electronic data management information system that is designed to gather monthly energy and greenhouse gas emissions data from ChevronTexaco's worldwide exploration and production, refining and marketing, petrochemicals, transportation and coal mining activities. The system was implemented throughout ChevronTexaco beginning in July, 2001. ChevronTexaco Corporation and its Chevron, Texaco and Caltex subsidiary companies enter data to calculate greenhouse gas emissions and energy utilization on a monthly basis. At the end of each quarter, energy and greenhouse gas emission estimates are reported to ChevronTexaco Corporation. This paper will review system scope and boundaries, provide an overview of how the system works and highlight lessons learned during company-wide implementation of the system.

INTRODUCTION

ChevronTexaco Corporation is a global company providing energy and chemical products and services vital to the growth of the world's economies. Our core values include a commitment to protecting the safety and health of people and the environment. This commitment is a critical component of the value we deliver to our stockholders, customers, government partners and employees.

1008 The ChevronTexaco Energy and Greenhouse Gas Inventory System (CEGIS) was designed to establish a reliable baseline and have a verifiable inventory of greenhouse gas emissions. This will enable us to pursue our goal of reducing emissions per unit output from our operations.

What is CEGIS? ChevronTexaco Corporation developed CEGIS using our decision-driven project management process. Representatives from the major business units actively participated in developing the system. In addition, we hired external consultants to gain perspective on greenhouse gas inventory issues and expertise in auditing. CEGIS is an Excel-based auditable energy and greenhouse gas inventory system, with calculations driven by a Visual Basic add-in. It is a comprehensive management system that provides for data collection, data entry, computation, compilation, reporting, record keeping and data management in an Oracle data base at the corporate level. CEGIS: • Requires monthly data input • Enables facilities to submit quarterly reports to the corporation • Requires documentation of data sources so that the data is verifiable • Provides for a consistent approach across all of ChevronTexaco • Yields emissions and energy utilization information that can be reviewed and analyzed by the facilities in real-time, enabling each facility to manage its own emissions. • Is highly automated, with the ability for transfer of input data from existing accounting systems into the spreadsheet, automatic quarterly reporting from facilities to the corporation and standard reports generated for each facility by the software. Key innovations are: • Combining greenhouse gas emissions and energy utilization estimates. Because the input data used to estimate energy utilization is a subset of data used to estimate greenhouse gas emissions, combining the estimates is more efficient for the user, eliminates rework, and ensures consistent energy utilization and greenhouse gas emission data for a given facility. • Developing an enterprise-wide, complete process for data generation, calculation, analysis, reporting and management. The ability to comprehensively manage data with automatic reporting, downloading, and Oracle database loading and query at the corporate parent level were integral to the design for ChevronTexaco's system. • The emissions and energy utilization estimation system is modular and Excel-based. The modules allow facilities to customize reports for their operations (e.g., downstream versus upstream). Use of Excel avoids the need for users to load and understand a new software environment. • The system uses the latest greenhouse gas estimating methodology developed by API [ 1].

CEGIS SCOPE AND BOUNDARIES

CEGIS scope and boundaries were discussed in a previous paper [2]. The scope and boundaries were initially designed based on the principles of completeness, credibility and control.

Completeness. In deciding whether to include or exclude an operation or source, we considered whether exclusion of the source would make our inventory materially incomplete. For initial inventory efforts, we attempted to be as inclusive as possible, with an emphasis on completeness over accuracy. For example, when data was not available, we estimated emissions from our non-operated

1009 joint ventures by using a ratio of greenhouse gas emissions per barrel of oil produced. The ratio was based on similar operations. Although this does not reflect the actual emissions from a non-operated venture, it does ensure that these emissions are assessed in our overall total.

Credibility. Some sources were included because the inventory would not be credible to external reviewers if the sources were omitted For example, contract drilling operations are included because these operations can have significant emissions and are closely associated with our business in some areas. Thus, an external reviewer/user of the data would not consider it to be a complete and credible report if we did not acknowledge the existence of emissions from drilling operations. Control. In some cases, we may have a very small working interest in an operation, but some degree of influence or control of emissions from the operation. For example ChevronTexaco is the contract operator of a production field in Venezuela. As the operator, we have the opportunity to implement some best practices to minimize greenhouse gas emissions. However, in this case, since we do not control capital investments, our ability to control funding for energy efficiency and/or greenhouse gas mitigation projects is limited. CEGIS includes three of the six greenhouse gases listed in the Kyoto Protocol. Carbon dioxide and methane were included because they are expected to be emitted from our operations in significant quantities. Nitrous oxide was also included in the inventory because it can be a minor byproduct of combustion. By including an assessment of nitrous oxide emissions, we can analyze the data to determine whether these emissions are significant to our overall inventory. The other three Kyoto gases were not included in our inventory because they are not expected to be emitted in significant quantities from our operations.

CEGIS I M P L E M E N T A T I O N

CEGIS was implemented in three phases. The first phase of implementation consisted of pilot tests at worldwide upstream and U.S. downstream locations. As a result of these tests, we made changes to CEGIS to make it more user-friendly, and to improve the flow of information. The second phase of implementation took place in July 2001, before the Chevron Texaco merger. Initial deployment of the software was done during a training class that was attended by representatives of all Chevron business units. After the training session, CEGIS users were given two months to configure the software for their business units and to enter data for the first nine months of the year. The first reports were to be submitted by mid-October, 2001, and the final year-end report was due in mid-January 2002. The report was to contain full year data for 2001 for each facility. In addition to the training session, help desk services were available to CEGIS users as they configured their systems, entered data and produced reports. The majority of the users were able to use CEGIS with little difficulty, and the majority of the reports were delivered on time. Users learned that it was best to have a good understanding of greenhouse gas emission sources, equity shares of operations, and location of facilities. With this information, users could draft a configuration plan before using the software. Although configuration can be changed at any time, it is easier and more efficient to complete the configuration with a minimum of revisions. Also, a comprehensive understanding of the operation helps ensure a complete inventory. The main problems occurred at facilities that did not have ChevronTexaco's common operating environment software. Because CEGIS was designed to be used with Windows NT and Excel 97, it did not always function properly with other combinations of operating systems and versions of Excel. In particular, facilities that had non-English versions of Excel typically encountered difficulties.

1010 During the first phase of implementation, users noted a number of improvements that could be made to CEGIS. For example, since estimation of criteria pollutant emissions often relies on the same data as estimation of greenhouse gas emissions, users requested that CEGIS be upgraded to include the capability of estimating criteria pollutant emissions. Another area of improvement was composition of flared gas. In the first version of CEGIS, the default composition of flared gas was consistent with the API Compendium, which suggests that as a default, the gas can be considered to be 100 percent methane. However, most users noted that associated gas tends to be comprised of about 80 percent methane, and the methane content can vary by as much as 20 percent. They therefore requested the ability to customize the composition of flared gas. Another driver for change was that ChevronTexaco's common operating environment was to be upgraded to Windows XP and Excel 2002, and the CEGIS software needed to be made compatible with this change. Starting in October, 2001, CEGIS was revised to incorporate learnings from the first phase of implementation. CEGIS 1.1 was issued in early 2002, and used in the third phase of implementation by all ChevronTexaco business units. The new version of CEGIS was designed so that existing users could transfer configuration and input information from their existing files to the new software, with little or no rework. This was a significant benefit, because some facilities had implemented highly detailed inventory systems, listing each emissions source individually. It would have taken a great deal of effort to re-enter all of that information. Also, retaining the configuration makes it easier to compare data from year to year. The third phase of implementation took place in March 2002, after the ChevronTexaco merger. The session incorporated lessons learned from the first phase of implementation. We continue to provide help desk support, and note a high level of activity every three months when the quarterly reports are due. With roughly 70 users, we receive many suggestions for improvements, and plan to incorporate as many as possible into the next version of CEGIS, which we expect to issue at the end of this year.

WHAT W E ' V E LEARNED Successes

• • • • • • •

Implementation of a companywide data management system has enabled us to develop a consistent, high quality energy and greenhouse gas inventory. Because CEGIS includes all the calculational methodologies, we can make meaningful comparisons of data from facility to facility (comparing "apples to apples"). The existence of a common operating environment was a major factor in enabling us to deploy this type of inventory system. Involvement of current and future CEGIS users in development of the system both improves the software and promotes user acceptance. Users who had prior experience with energy management systems generally found it easier to understand and use the CEGIS system. The additional effort and planning needed to configure the CEGIS system yields significant longer-term efficiency benefits in data entry and management. Because the CEGIS system is designed to enable upgrades to be implemented without forcing users to reconfigure their systems, CEGIS will continue to be relevant as greenhouse gas emissions estimating methodologies and practices continue to evolve.

1011 •

•

• • • • • •

CEGIS includes a 'Compositions' sheet that enables users to easily convert between mass and volume data, and to get information on the heating value, density and emission factors for a gas. This sheet has proven useful both in CEGIS configuration and for other work. CEGIS allows the user to choose units of measure for data entry. This minimizes the need for users to do unit conversions and therefore reduces the chance for error. CEGIS output data can be specified by the user to be shown in metric tonnes or standard tons. Data is sent to the corporate database with common units of measure (metric tonnes of emissions). Users can add, modify or remove sources as needed in order to keep the CEGIS configuration up to date as operations change. The CEGIS software is password protected in a Visual Basic add-in, so that users cannot inadvertently change the methodologies. The CEGIS reporting process is designed so that old versions of CEGIS can be detected, enabling us to ensure that users are running the latest version. Because audit trail information is required before data submittal, the CEGIS software facilitates development of an auditable inventory. The inventory system was designed to be converted to a Web-based system in the future. CEGIS uses Excel as its basis, so emissions data is readily available to the user for analysis and reporting. Users can create charts and tables from the data using standard Excel capabilities.

Areas for Improvement •

•

•

• •

•

•

The first area for improvement will focus on quality assurance and quality control (QA/QC) procedures both at the data reporter level and at the corporate level. A plan is being implemented currently to facilitate self-check at the data reporter level. Further, the QA/QC of numbers, based on materiality of the emissions and the production is performed rigorously by corporate staff beginning with data submitted in the first and second calendar quarters of 2002. The CEGIS users guide was written more as documentation than as an aid to the user. It could be improved by using case studies to illustrate how to configure the software and how to resolve common problems. Further, a ChevronTexaco Protocol Document will be developed to establish emissions accounting principles and specific guidance on boundary issues and QA/QC procedures. Flaring and combustion are separate modules, which enables us to review flaring emissions separately from other types of combustion. However, to make the system more user-friendly, these two modules should be as similar as possible. Some users found it difficult to use the 'modify' or 'remove' functions of CEGIS. It is much easier to perform initial configuration than to make revisions. Some regulatory agencies prefer to see combustion data divided between stationary and mobile sources. Although this distinction can be made if CEGIS is properly configured, it would be easier if CEGIS was specifically designed to the separate these two types of emission sources (i.e., separate modules for stationary and mobile sources). Published emission factors for nitrous oxide are generally of low quality. Further analysis of the data is needed to determine whether better factors need to be developed, or whether nitrous oxide emissions are insignificant. The Visual Basic for Applications (VBA)--Excel interface is not always sufficiently robust to handle the calculations and data manipulation automatically. In some cases, users have to exit and re-enter the system in order for changes to be accepted. This is an inherent problem with the platform have chosen, and can be remedied by converting to Visual Basic.

1012 CONCLUSIONS Implementation of a companywide software system for consistent estimation of energy, greenhouse gas and criteria pollutant emissions yields numerous benefits. User involvement in development and ongoing improvement of the software is key to successful implementation. Ongoing, centralized support is necessary to keep the system relevant as greenhouse gas emission estimating methodologies and software environments continue to evolve.

REFERENCES

American Petroleum Institute (2001). Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Inventory; Pilot Test Version; API, Washington, D.C. 2. Nordrum, S., Lee, A. (2002). Development of a Corporate-wide Process for Estimating Energy Consumption and Greenhouse Gas Emissions from Oil and Gas lndustry Operations. ChevronTexaco Corporation, San Ramon California. 1.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1013

T H E R M O N E U T R A L CO-PRODUCTION OF METALS AND SYNGAS WITHOUT GREENHOUSE GAS EMISSIONS

M. Halmann 1 and A. Steinfeld 2 Weizmann Institute of Science, Department of Environmental Sciences and Energy Research, Rehovot 76100, Israel. 2 ETH - Swiss Federal Institute of Technology, Department of Mechanical and Process Engineering, CH-8092 Zurich, Switzerland.

ABSTRACT

The industrial production of iron and other metals, as well as the production of syngas, are energy-intensive processes that account for more than 10% of the annual anthropogenic release of CO2 to the atmosphere, derived mainly from the combustion of fossil fuels for heat and electricity generation. There exists an urgent need to provide economically viable alternatives to the above processes that are less wasteful in fossil fuel resources while avoiding the release of greenhouse gases and other pollutants. In a novel metallurgical process, the endothermic reduction of metal oxides is combined with the exothermic partial oxidation of hydrocarbons to co-produce, by thermo-neutral reactions, both metals and syngas. The conditions for thermoneutrality were established by thermochemical calculations for the reduction of ZnO, Fe203, and MgO to the metals, using CH4 as reductant, and 02 as the oxidant. Confirmation of the calculated processes was obtained by thermogravimetric experiments, measuring simultaneously both the weight loss during the reduction of ZnO or FezO3 under a flow of Ar, CH4, and 02 at 1 bar and 1273 or 1400K, as well as the formation of H2, CO, and CO2 by gas chromatography. A preliminary evaluation indicates that such a process, followed by the production of either hydrogen or methanol, should be economically competitive, while significantly decreasing the release of COz. INTRODUCTION

The iron and steel industries are highly energy-intensive processes, releasing annually about 1.2x109 tons of CO2, and contributing about 5% to the anthropogenic greenhouse gas emissions [ 1,2]. In the carbothermic production of iron, the main endothermic reactions are, Fe203 + 1.5C = 2Fe + 1.5CO2

AH°298K = 235 kJ mol l

(1)

Fe304 + 2C

AH°298K = 333 kJ mo1-1

(2)

= 3Fe + 2CO2

1014 In an effort to achieve a cleaner process, a modification of the direct reduction of iron oxides by syngas or natural gas has been proposed, in which the endothermic reduction of iron oxides by methane [3 ], Fe203 + 3CH4 = 2Fe +3CO + 6H2

AH°298K = 719 kJ mol

(3)

Fe304 + 4CH4 = 3Fe +4CO + 8H2

/~x-'I0298K- 978 kJ mol "]

(4)

is combined with the exothermal partial oxidation of methane [4], CH4+1/202 = CO+2H2

AH°298K =-38 kJ mol -I

(5)

resulting in an overall thermo-neutral process, with syngas as a valuable by-product [5]. By achieving both environmental improvement and economic advantage, such a new process may be more readily adopted by industry [6]. In the present work, the thermodynamic constraints for the above combined process are explored, using methane as the reductant of iron oxide. Thermochemical equilibrium calculations were made using computational codes [7-10]. The results of these calculations were applied to the economic evaluations described in Tables 1 and 2, as well as to the environmental assessments. Experimental tests were carried out using thermogravimetry to measure the reduction of Fe203 and Fe304 to Fe under a constant stream of Ar, CH4 and 02, while simultaneously measuring by gas chromatography the appearance of H2, CO, and CO2. The technique was as previously described [11]. A preliminary economic evaluation is for a proposed large-scale industrial plant to produce annually about 0.5 million metric tons of iron, using natural gas as the reductant, with the syngas converted either to hydrogen or methanol. E X P E R I M E N T A L RESULTS Figure 1 describes the time course of mass loss during the reduction of Fe203, the consumption of CH4 and O2, and the production of H2, CO, and CO2. Under the given conditions, the weight loss from Fe203 via Fe304 and FeO to Fe was complete within 40 min. The concentrations of H2, CO, and CO2 remained fairly constant, even after the Fe203 had been reduced to Fe, presumably because the Fe formed catalyzed the CH4 partial oxidation/CO2 reforming. 100 mg Fe2Oa / 5.1% CH413.6% 02 / 1400 K

120 ~ 100 ~ e

5 4

UMass

** 3 5

+ 02 --i--H2

20

1

"¢t:'CO

0

0

60

i i 40 0 i

"''C.L_

20

40

/

---I-- CH4

2~ -=-c02 60

80

Time I min

L Figure 1. Thermogravimetric experiment with Fe203 under Ar - CH4 - 02 (91 : 5.1 : 3.6 by volume) at 1400 K and atmospheric pressure.

1015 ECONOMIC EVALUATION The proposed plan is for a plant to produce annually 0.5 million mt (metric tons) of iron, using natural gas (NG) as the reductant, and oxygen for the partial oxidation. The co-produced syngas is converted either to hydrogen (Table 1), or to methanol (Table 2), thus substantially improving the process economics. The plant is assumed to be down 20% of the time for maintenance. The estimated capital cost is US$200/mt of iron, which is similar to that of planned plants in Australia and the U.S. [12]. The main uncertainties are the size of the capital cost, the highly variable costs of natural gas and oxygen, and the market prices of the products. The proposed plant would add about 0.1% to the world production of iron, and about 5% to the world capacity of methanol, which in 2001 amounted to 33.8 million mt [13]. No credit has been included in these calculations for the sale of the purified CO2 resulting from the PSA (pressure swing absorption) process. For the case described in Table 1, the production of CO2 would reach 0.97x106 mt/zvr. At the reported average price of US$12/mt [14], its annual sale would amount to US$11.6x 10°, thus further improving the economics of the process. GREENHOUSE GAS RELEASES The annual world production of iron from its ores amounts to about 0 . 5 x 1 0 9 tons, releasing about 1.2xl 09 tons of CO2 [2]. Thus the molar ratio of CO2 formed to Fe produced is CO2/Fe = 1.2x55.85/(0.5x44) = 3.05. For comparison, in the above proposed co-production of Fe and H2 (as in Table 1), the predicted molar ratio of CO2 formed to Fe + H2 produced (after complete water-gas-shift of CO) will be CO2/(Fe+H2) = (3.7+1.2)/(2.0+5.7+3.7) = 0.43. For the case of the co-production of Fe and methanol (as in Table 2), in which the syngas ratio will be partly shifted to reach H2/CO = 2, the molar ratio CO2/(Fe+H2) will be only 0.19. Current markets for methanol are formaldehyde (35.5%, mainly for polymers), various chemicals and solvents (30.8%), methyl-tert-butylether (the fuel additive MTBE, 27.4%), and acetic acid (6.4%) All of these, except MTBE, are long-term sinks for carbon [6]. REFERENCES

10.

Ullmann's Encyclopedia of Industrial Chemistry, 5th Ed. (1989) vol. A14, p. 516. Steinfeld, A., and Thompson G. Energy (1994) 19, 1077-1081. Barrett, D. Ind. Eng. Chem. Process Develop. (1986) 11, 415-420. Ashcroft, AT, Cheetham, AK, Green, MLH, and Vernon ODF, Nature (1991) 352, 225-226. Halmann, M., Frei, A., and Steinfeld, A., 6th Internat. Conf. On Carbon Dioxide Utilization, Breckenridge, CO., USA (Sept. 2001) Abstract PO-16. Halmann, MM., and Steinberg M., Greenhouse Gas Carbon Dioxide Mitigation: Science and Technology, Lewis Publ. (1999). Roine, A., Outokumpu HSC Chemistryfor Windows, Version 4.1: Outokumpu Research Oy, Pori, Finland (1997). Thermochemical Software & Database Package F*A *C'T, Centre for Research in Computational Thermochemistry, Ecole Polytechnique de Montreal, Canada, www.crct.polymtl.ca. Gordon, S. and McBride, J. B., NASA SP-273, NASA Lewis Research, Cleveland, OH (1976). A PC version prepared by T. Kappauf, M. Pipho, and E. Whitby for E. A. Fletcher at the University of Minnesota was used in the present study. National Institute of Standards and Technology, Standard Reference Data Program,

1016

11. 12. 13. 14.

Chemistry Webbook, http://webbook.nist.gov. Steinfeld, A. Frei, A., Kuhn, P. and Wuillemin, D., Int. J. Hydrogen Energy (1995) 20, 793-804. See www.ausmelt.com.au/comops_sase.html. Also: www.indiainfoline.corn/stee/pr08.html. See www.methanex.com/methanol. See www.ieagreen.org.uk/util4.htm.

TABLE 1 ECONOMIC EVALUATION FOR Fe AND H2 PRODUCTION FROM Fe203 AND NG. A designated reaction mixture of Fe203 - CH4 - 02 (molar ratio 1 : 4.87 : 3.5) at 1400 K and 1 bar in a thermo-neutral reaction forms an equilibrium mixture of Fe, H2, CO, H20, and CO2 (molar ratio 2.0 : 5.7 : 3.7 : 4.0 : 1.2). By water-gas shift, the CO is converted to hydrogen.

Assumptions Annual Fe203 feed (kmol/yr) Annual Fe203 feed (mt/yr) 1 Annual NG feed (kmol/yr) Annual NG feed (GJ/yr)2 Annual NG feed (mmbtu/yr) 3 Annual 02 feed (mt/yr) Fe production (mt/yr) H2 production (kg/yr) = H2 production (GJ/yr)" Capital Cost (million US$)

Equipment and facility 6 Interest during construction (10% of facility investment) Startup expenses & working capital TOTAL

4.5x106 0.72xl 06 21.9x106 19.5x106 18.5x106 0.50x 106 0.50x106 65.7x106 9.33x106 100 10 10 120

Annual Cost (million US$) Capital cost (15% of Total) Operation & Maintenance (2% of Total) Fe203 cost (US$4.60/mt) 7 NG cost (US$3.50/mmbtu) 8 02 cost (US$40/mt) 9 TOTAL

18.0 2.4 3.3 64.8 20.0 108.5

Annual Sales (m~llion US$) Iron (US$130/mt) H2 (US$0.71/kg) 1° TOTAL

65.0 46.6 111.6

1 mt = metric ton = tonne. 2 Taking 890.8 kJ/mol for the heat of combustion of CH4. 3 1 mmbtu = 1 million btu = 1.055 GJ; 1 GJ = 0.278 MWh. 4 Assuming 75% overall yield of conversion of CH4 to H2. 5 Taking HHV (Higher Heating Value) of H2 = 142 MJ/kg = 0.142 GJ/kg. 6 Including the reactor, desulfurization, heat recovery, shift reactor, PSA, and other related equipment and facility. 7 See www.ausmelt.com.au/comops_sase.html. 8 May 2002. Source: International Herald Tribune. 9 See Basye, L. and Swaminathan, S. "Hydrogen Production C o s t s - A Survey", 1997; Report by SENTECH, Inc. for DOE/GO/101-778. 10 See www.eren.doe.gov/hydrogen.

1017 TABLE 2 ECONOMIC EVALUATION FOR IRON AND METHANOL PRODUCTION FROM Fe203 AND NG A designated reaction mixture of Fe203 - CH4 - 02 (molar ratio 1 : 4.87 : 3.5) at 1400 K and 1 bar in a thermo-neutral reaction forms an equilibrium mixture of Fe, H2, CO, H20, and CO2 (molar ratio 2.0 : 5.7 : 3.7 : 4.0 : 1.2). Following partial water-gas shift, the syngas (H2 + CO) is converted to methanol.

Assumptions Annual Annual Annual Annual Annual Annual Annual Annual Annual

Fe203 feed (kmol/yr) Fe203 feed (mt/yr) 1 NG feed (kmol/yr) NG feed (GJ/yr)2 NG feed (mmbtu/yr) 3 02 feed (mt/yr) Fe production (mt/yr) methanol production (kmol/yr) 4 methanol production (mt/yr)

415xi06 0.72x10 6 21.9x106 19.5x106 18.5x106 0.50x106 0.50x106 13.1 x106 0.42x106

Capital Cost (million US$) Equipment and facility ~ Interest during construction (10% of facility investment) Startup expenses & working capital TOTAL

100 10 10 120

Annual Cost (million US$) Capital cost (15% of Total) Operation & Maintenance (2% of Total) Fe203 cost (US$4.60/mt) 6 NG cost (US$3.50/mmbtu) 7 02 cost (US$40/mt) 8 TOTAL

18.0 2.4 3.3 64.8 20.0 108.5

Annual Sales (m~llion US$) Iron (US$130/mt)' Methanol (US$206/mt) 9 TOTAL

65.0 86.5 151.5

1 mt = metric ton = tonne 2 Taking 890.8 kJ/mol for the heat of combustion of CH4 3 1 mmbtu = 1 million btu - 1.055 GJ; 1 GJ = 0.278 M W h 4 Assuming 60% overall yield of conversion of CH4 to CH3OH 5 Including the reactor, desulfurization, heat recovery, shift reactor, PSA, methanol synthesis reactor, and other related equipment and facility 6 See <www.ausmelt.com.au/comops_sase.html> 7 May 2002. Source: International Herald Tribune. 8 See Basye, L. and Swaminathan, S. "Hydrogen Production C o s t s - A Survey", 1997; Report by SENTECH, Inc. for DOE/GO/101-778. 9 U.S. Gulf spot price for methanol in barges, May 2002. See: www.methanex.corn/methanol.

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1019

AN ANALYTICAL METHOD OF CONSTRUCTING BEST-MIXED POWER GENERATION SYSTEMS REFLECTING PUBLIC PREFERENCE R. Akasakal, N. Shikasho 2, K. Morita 1 and K. Fukuda 1 1 Institute of Environmental Systems, Kyushu University, 6-10-1 Hakozaki, Higashiku, Fukuoka, Japan 2 Graduate School of Engineering, Kyushu University

ABSTRACT An investigation into consumers' preference for power generation systems was performed. It was found that most consumers preferred values that incorporated 'social acceptability' and 'environmental effect' in constructing the energy system. An analytical method to evaluate the best combination of power generation systems to meet consumers' preference was developed. It was applied in the evaluation of each of the selected combinations of systems that met each consumers' requirements. The resulting best combinations of systems were comprised mainly natural gas-fired power and hydraulic power generation system. The power systems with disadvantages in terms of the 'social acceptability' and/or 'environmental effect' were barely introduced. The duality theorem allowed us to evaluate the marginal cost of consumers' preferences. The 'social acceptability' yielded the highest marginal cost, and the 'environmental effect' was the next. INTRODUCTION

There are many controversial issues in terms of the energy problem. Energy suppliers are now forced to take into account environmental effects and safety, at the cost of less commercial profit. Although they intend to build more nuclear plants, it is sometimes difficult to meet the concerns of the opposition, people who fear the risk of a severe accident or have concerns about the waste disposal from such power plants. On the other hand, energy consumers expect alternative natural energy resources, such as the solar energy, as the main energy resources in the near future. However, at this moment, it is assumed that natural energy resources are rather expensive and their technologies are yet immature. Unfortunately, three participants of the energy society, suppliers, consumers, and the government, barely evaluate the unmeasurable values of energy resources, or the energy externalities, because of their complexity and variety. Under this situation, arguments among the participants on future energy systems are often confused. Recently, especially after 1980, in the field of nuclear engineering, many subjects about the best combination of power generation systems, or simply the 'best-mix', have been discussed, recognizing the externality of nuclear power. In Japan, Mankin et al. [1] estimated an increase in investment for small- or middle-scale nuclear reactors in the future, and predicted that it would be compatible with that for large-scale nuclear reactors. Ohkubo et al. [2] produced a new model to simulate the future energy best-mix, and using the model, were able to advise in Japanese policy on nuclear power. The authors also evaluated the role of nuclear energy in terms of energy security of the country [3]. In other countries, Afanasiev [4] revealed an economical advantage for Russian nuclear power over other types of power generation, using the concept of marginal cost. After the agreement of the Kyoto Protocol, marginal cost estimations for the reduction of greenhouse gas

1020 emissions have focused in the field of environmental engineering. Kainuma [5] reviewed several economic models to achieve the Kyoto Protocol Standard, and pointed out that Japan had higher marginal cost to reduce the CO2 emissions than other countries. Yoshida et al. [6] proposed a new energy model, minimizing power generation costs, and predicted that the marginal cost to reduce CO2 emissions would become dramatically higher when the growth of nuclear power generation approached saturation. Jackson [7] compared some technologies for the reduction of greenhouse gas emissions based on their marginal costs. However, few discussions have focused on constructing energy system reflecting consumers' preference. Thus, we developed a method to determine public preference based on responses to a questionnaire [8], and to establish the best-mix which reflected that preference [9,10]. In this study, applying this method, a survey on energy consumers' preference was conducted, and the best-mix that reflected this preference was evaluated. In the analysis, the linear programming algorithm was applied, with the duality theorem; marginal costs for various external values were also evaluated.

ANALYTICAL METHOD

Investigation of Energy Consumers' Preference The questionnaire shown in Figure 1 examined consumers' preference for the following five values: economical efficiency, convenience, energy security, environmental effect, and social acceptability, which were classified by factor analysis as the essential values regarding energy-related problems. Except for economical efficiency, all of the remaining four values could be regarded as external values. The questionnaire was composed of ten questions based on the AHP (Analytical Hierarchy Method), a multivalue decision support method designed to assess the relative importance among alternatives. Pairwise comparisons were carried out to produce an overall ranking table of preference for values, e.g., "Which do you think is more important for the power generation, economical efficiency or environmental effect?" All of the preferences for each value were normalized to be the range between 0 and 1. Please choose one suitable for your idea. (a) more important than (b) a little more important than (c) as important as (d) a little less important than (e) less important than. Q1. Economical efficiency Q2. Economical efficiency Q3. Economical efficiency Q4. Economical efficiency Q5. Convenience is Q6. Convenience is Q7. Convenience is Q8. Energy security is Q9. Energy security is QIO. Environmental effect

is is is is

is

convenience. energy security. environmental effect. social acceptability. energy security. environmental effect. social acceptability. environmental effect. social acceptability social acceptability.

Figure 1: Questionnaire to investigate a consumers' preference for values. Performance of Power Generation System In constructing the best-mixed power generation, the following eight systems are employed: oil fired (OIL), coal fired (COA), natural gas fired (LNG), hydraulic (HYD), photo-voltaic (SOL), light water reactor (LWR), high temperature gas cooling reactor (HTGR), and fast breeder reactor (FBR) power generation systems. An assessment of these systems is performed in terms of five values described above, and the performance score for each system for each value are evaluated.

1021

As shown in TABLE 1, several specifications related to each value are selected; e.g., capital cost, maintenance cost, and fuel cost are taken to assess the value 'economical efficiency'. Similarly, emissions of CO2, SOx, NOx, and radioactive waste are chosen for assessment o f the value 'environmental effect'. The quantitative specifications such as costs or amount of emissions of exhaust are available from literatures. These are carefully determined referring the latest publications. However, some qualitative specifications, such as 'technological maturity', contained in TABLE 1 are difficult to evaluate. To do this, the AHP is applied. All specifications thus evaluated are weight averaged and summarized to give the respective performance scores. The weights are also determined by AHP. The performance scores of each system are tabulated in TABLE 2. These are reduced to the standard deviation score, where zero indicates an average. If a score is positive, it is superior to the average performance, and if negative, it has less performance. TABLE 1 VALUES AND SPECIFICATIONS TO EVALUATE THE PERFORMANCE OF POWER GENERATION SYSTEMS Value Economical efficiency

Convenience

Energy security

Environmental effect

Social acceptability

Specification Capital cost Maintenance cost Fuel cost Technological maturity Energy density Easiness to handle the waste Amount of resource Distribution of resource Easiness of fuel storing or self supplying CO2 emission SOx emission NOx emission Radioactive waste Human damage System risk Local agreement Possibility of large-scale accident

TABLE 2 PERFORMANCE SCORES OF EIGHT SYSTEMS

Economical efficiency Convenience Energy security Environmental effect Social acceptability

OIL 0.388 0.241 -0.861 -0.542 -0.054

COA 0.388 -0.339 -0.729 - 1.247 -1.065

LNG 0.460 0.285 -0.843 -0.114 0.296

HYD SOL LWR HTGR FBR 0 . 1 9 1 -2.464 0 . 4 6 5 0 . 2 8 6 0.268 0 . 5 7 6 -0.501 -0.279 0 . 0 3 7 -0.020 1 . 2 5 4 1 . 2 5 4 -0.352 -0.352 0.629 0 . 6 9 3 0 . 4 7 8 0 . 2 4 2 0 . 2 4 2 0.242 0 . 0 3 5 1 . 2 7 4 -0.140 -0.140 -0.207

Linear Programming Figure 2 illustrates the process used to find the best-mix, applying the linear programming method (LP) [9,10]. The preferences of five values, which vary depending on examinees, are the input to LP. The LP searches the solution that minimizes the total cost to construct the best-mix. The problem is formulated as follows.

1022 8

Minimize z = ~ c,x,

(1)

i=l 8

subject to ~S~x, > bj (j = 1..5)

(2)

i=l 8

(3)

~-'x,-1 t=l

x, _>0 (i = 1..8)

(4)

where x, and c, are the composition and the power generation cost of a system i, respectively, bj is the preference for the value j , S~ the performance score of system i for value j . Only x, is unknown and q, bj, and Sv are fixed during minimization. The right hand side of Eqn. 1 is the total cost to be minimized. Eqn. 2 imposes a requirement that a sum of the product to the performance score Sv and the composition x, with respect to all power generation system should exceed the preference bj of the value j . To solve the LP, the simplex algorithm is adopted.

Performancescoresof systems I Input I Preference°f values

I Linearprogramming

I mmkll

Output Compositionof systems I

Figure 2: Process to find the best-mixed power generation

Dual Problem

The duality theorem belongs at the center of the underlying concept of the LP, which gives the dual problem formulated as follows: Maximize w = ~ bjyj + Y6

(5)

)=1 5

subject to ~ Suyj + Y6 -< Ci (i = 1..8)

(6)

j=l

yj _>0 (j = 1..5)

(7)

where yj, the variable in the problem, gives the marginal costs of the constraint conditions of the primal problem.

RESULTS AND DISCUSSIONS

Preference A survey was conducted from October to December 1999. Figure 3 shows the result of preference for values obtained from the survey. The abscissa and the ordinate are the percentage of examinees and their preference, respectively. A preference of 0.2 indicates an average. If an examinee regards that a certain value is more important than the others, its preference is grater than 0.2.

1023 About 90% of the examinees thought that the value 'social acceptability' was of above average importance, and the 'environmental effect' and 'energy security' were the next. Few examinees put their preference on the ' economical effect' and ' convenience'.

0.6.

•

,

,. 0 514"'. • I~ ~" 0.4~,'~,

i

,

i

",,

~t :,,_

,

....

"'- ...... ":'-

o.:3

i

,

i

, j

.... Economical efficiency ---- Convenience --Energy security .... Environmental effect - -- Social acceptability

"

.....

a. 0.2

. . . . . _".~-.

01f ,

I

0

,

I

20

,

I

40 Percentage

,

I

60

,

80

100

(%)

of examinees

Figure 3: Preference of each value

Best-mixed Power Generation System Figure 4 shows the best-mix to accord with the examinees' preference, evaluated by the procedure described above. The abscissa and the ordinate are the percentage of examinees and the composition of each power generation system in the best-mix, respectively. LNG and HYD comprised large part in most of the best-mix evaluated for all examinees' preference. This was reasonable because these power generation systems have relatively high performance scores for the social acceptability as tabulated in TABLE 2. Some best-mixes contained a small composition of SOL and LWR. Although SOL had the best score for the social acceptability in all systems, its economical score was considerably less than the others. Therefore, it was contained only in the best-mix of examinees who regarded the social acceptability as extremely important. The reason for including LWR was that it had average performance for all values. The best-mix that contained OIL, COA, HTGR, and FBR hardly appeared. OIL and COA had few advantages except for economical efficiency and convenience, which were not considered as highly important. HTGR and FBR had average performances, almost the same as LWR, but the lower economical performances were a disadvantage.

•

0.8

~

0.6

LNG

o

0.4 Q. ~ 0.2 U

_

so,

2~)

'

,,,'0

Percentage

'

_

s~)

of examinees

-'7""-,-'-, 80

100

(%)

Figure 4: Composition of each system in the best-mix

1024

Marginal Costs Figure 5(a) shows the marginal costs of values calculated individually for all examinees' preferences, while Figure 5(b) shows the marginal costs averaged. The highest marginal cost of the social acceptability meant that most examinees were willing to pay the highest expense for the social acceptability. This result was acceptable, in that marginal costs of the environmental effect and the energy security followed. As mentioned above, these values were regarded as important, next to the social acceptability. The fact that the marginal costs of the economical efficiency and the convenience were consistently zero was also remarkable. This was interpreted that all examinees were prepared to incur no expense for these values, since their requirement for these value had already been satisfied. 25

!

!

!

S o c i a l acc e p t a b ility

3:

~ 25 20

20 >'15

'~u Environmental •,-.

lO

effect

10

u .-~

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5

1

security

\

,

o

'

~)

",'0

'

6'0

'

P e r c e n t a g e of e x a m i n e e ( % )

(a)

8'o

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o

~

oo ~o

~ m o

~

~

O

~

~

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Figure 5: Marginal cost for values (a) individual (b) averaged CONCLUSIONS The prime problem in finding the best-mixed power generation system for energy consumers was discussed. The linear programming approach solved the problem, and the best-mix was evaluated individually, according to the preference of each consumer. The dual problem that the duality theorem derived from the prime problem was discussed. A solution of the dual problem gave the marginal cost values for consumers' preferences. The survey of energy consumers' preferences revealed that the examinees tended to attach the most importance to social acceptability, and in their best-mixes, the LNG and HYD were selected in greater percentages than the others. It was understood from the resultant marginal costs that most examinees approved the meeting of the highest expense for social acceptability. The marginal cost is regarded as the price representing the 'willingness to pay' for values in constructing the best-mix. REFERENCES

.

4. 5. 6. 7. 8.

9. 10.

Mankin, S., Sato, O., Yasukawa, S. and Hayashi, T. (1998) Nucl. Eng. Des., 109, 355. Ohkubo, H., Suzuki, A. and Kiyose, R. Journal of Faculty of Engineering (1982) The University of Tokyo, Series B, 36, 4, 787. Fujimoto, N. and Fukuda, K. (2000) Trans. Japan Soc. Energy Resources, 21, 5,438. Afanasiev, A. A., Boldshov, L. A. and Karkhov, A. N (1997) Nucl. Eng. Des., 173, 219. Kainuma, M., http://www-cger.nies.go.jp/cger-j/c-news/vol 10-4/vol 10-4-2.html Yoshida, Y., Ishitani, H. and Matsuhara, R. (1995) J. Jpn. Soc. Simul. Technol., 14, 1, 52. Jackson, T. (1991) Energy Policy, 19, 1, 35. Harada, Y., et. al., (1997) Eng. Sci. Rep. Kyushu Univ., 18, 4, 289. Fukuda, K., Fujimoto, N., et. al., (1998) ibid, 20, 1, 19. Fujimoto, N., et. al., (2001), Technol. Rep. Kyushu Univ., 74, 3, 221.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1025

APPLICATION OF THE API C O M P E N D I U M OF GREENHOUSE GAS EMISSIONS ESTIMATION METHODOLOGIES FOR THE OIL AND GAS INDUSTRY TO EXAMINE POTENTIAL EMISSION REDUCTIONS K. Ritter, ~ S. Nordrum, 2 and T. Shires 3 ~American Petroleum Institute (API), 1220 L Street, NW, Washington, D.C. 20005 2ChevronTexaco, 2613 Camino Ramon, San Ramon, CA 94583 3URS Corporation, 9400 Amberglen Blvd., Austin, TX 78729

ABSTRACT In response to continued interest by its member companies about consistency in greenhouse gas (GHG) emissions estimation, the American Petroleum Institute (API) developed a Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas lndustry [ 1]. Initially distributed in June 2001, the Compendium is a result of more than a year long effort by API to screen, evaluate and document a range of calculation techniques and emission factors that could be useful for developing GHG emissions inventories. In a continued effort to enhance the real-world application of the Compendium, API is examining the applicability of the Compendium methodologies to assess emission reductions from specific projects. This paper presents findings from this follow-on activity. Although the reduction activities presented may not be applicable to all locations, and the estimated emission reductions may not be achievable for all situations, the purpose of this study is to illustrate use of the Compendium and identify potential methodological issues. This paper examines technical considerations associated with estimating pre- and post-project emissions and discusses the criteria being set forth in the international community regarding requirements for reliable emission reduction projects.

INTRODUCTION

Background Greenhouse gas inventories and emission estimation methodologies have been evolving over the past decade. Inevitably, as different organizations and governing bodies develop inventories and emission estimation methodologies, the level of detail and type of emission sources will vary. This presents a logistical challenge to the oil and gas industry, whose operations span the globe and thus encounter a variety of rules, policies and guidelines. Recognizing the need for consistency in the methods used to quantify greenhouse gas emissions, API's member companies compiled recognized "best practices" for emission estimation methodologies applicable to oil and gas industry operations. The resulting Compendium can be used to guide the estimation of GHG emissions for individual projects, entire facilities, or company-wide inventories.

1026 The Compendium currently targets carbon dioxide (CO2) and methane (CH4) emissions, the two most significant GHG emissions for the oil and gas industry. Emissions from oil and gas industry operations are grouped into five categories: combustion devices, point sources, non-point sources, non-routine activities, and indirect emissions. The Compendium includes calculation and estimation techniques for determining CO2 and CH4 emissions for sources within each of these categories. •

•

•

•

•

Combustion devices include both stationary sources, such as engines, boilers, heaters, and flares; and fleet-type transportation devices, such as trucks and ships, where these sources are essential to operations (i.e., material or personnel transportation). The CO2 emissions from these sources can be calculated from the amount and type of fuel they consume. Methane emissions, resulting from incomplete fuel combustion, are also a function of the amount and type of fuel consumed, as well as the efficiency of the equipment. Point sources include vents from oil and gas industry units, such as hydrogen plants and glycol dehydrators, that emit either CO2 and/or CH4. Point sources also include other stationary devices such as storage tanks, loading racks and similar equipment. The rate of these emissions is a function of the unit throughput and can be estimated by engineering calculation or by using appropriate emission factors. Non-point sources include fugitive emissions (equipment leaks), emissions from wastewater treatment facilities, and a variety of other emissions generated by waste handling. Non-routine activities, associated with maintenance or emergency operations, also may generate GHG emissions. The emission rates from non-routine activities are not easily determined and have to be evaluated on a case-by-case basis, often using a combination of factors and engineering calculations. Indirect emissions are defined as GHG emissions associated with oil and gas company operations, but physically occurring from sites or operations owned or operated by another organization. The Compendium specifically addresses purchased steam and electricity. Estimating these emissions requires input from the energy utility company or use of published emission factors based on average GHG emissions for energy generation in a given location or region.

Examining Emission Reductions API has reached out to governmental, non-governmental, and industry associations during the development of the Compendium to ensure broad peer-review and to create an approach consistent with the global oil and gas industry. This outreach effort continues with the current Compendium, available for distribution through API publications. Comments received will be used to improve the document in its next release (scheduled for early 2003). One aspect of particular interest to API is the use of the Compendium for estimating emissions associated with reduction projects. GHG emission reductions enhance not only environmental performance, but also economic performance, where reductions stem from improved energy efficiency or reduced CH4 emissions. Further understanding of the emissions reduction potential associated with such activities is valuable in promoting industry best practices. API is conducting a study to specifically evaluate the application of the Compendium to emission reduction projects.

GENERAL GUIDELINES FOR QUANTIFYING GHG EMISSION REDUCTIONS Determining GHG reductions associated with a specific activity requires the following steps: 1. Establish a reference case as the basis for comparison with the reduction project. 2. Identify and quantify the effects of the project, including direct and indirect emission increases and decreases. 3. Estimate emission reductions as the difference between the reference case and post-project emissions. The baseline for a project activity is the scenario that reasonably represents the anthropogenic emissions by sources of GHGs that would occur in the absence of the proposed project activity [2]. Due to certain complexities in project boundaries, such as energy imports or exports, the baseline scenario will not only

1027 include the activities conducted prior to the project (i.e., pre-project activities), but may need to reflect what would likely have occurred in the absence of the project. Each reduction project requires evaluation on a case-by-case basis to determine the most likely baseline scenario. Other technical issues encountered in considering emission reduction projects include: imported and/or exported energy; direct versus indirect affects of the project; the duration over which the emission reductions apply (i.e., permanence), and changes in baseline conditions. GHG EMISSION REDUCTION P R O J E C T CASE STUDIES An initial list of case studies was compiled based on input from the API workgroup members and other reported petroleum industry initiatives [3,4,5]. Seven specific projects were investigated, representing potential reduction opportunities of CO2 and/or CH4 emissions for different sectors of the petroleum industry. These example case studies were used to examine various technical issues associated with quantifying emission reductions and to illustrate the use of the Compendium. It is important to recognize that the reduction case studies selected may not be applicable to all locations and the emission estimates may not be representative of actual applications due to simplifying assumptions. Further details and illustrative estimates on three of the selected emission reduction case studies are presented in the following subsections.

Pneumatic Device Retrofit or Replacement Pneumatic devices use compressed gas as the motive force to perform process operations, such as controlling pressure, flow rate, temperature, or liquid level. Pneumatic devices operated with natural gas have been identified as a potentially significant source of CH4 emissions [6]. Some options for reducing emissions from pneumatic devices include maintenance, retrofit or replacement of the devices, and replacement of natural gas with compressed air. Potential emission reductions may be estimated for each of these various options using site data or measured pneumatic device gas consumption rates. Table 1 presents a summary of estimates for the scenarios examined as part of this case study example, using assumptions about the type and quantity of pneumatic devices associated with a hypothetical oil and gas production facility. Refinery Heater~Boiler Combustion Tuning Reductions in CO2 and CH4 emissions can be estimated based on reduced fuel consumption for heaters and boilers that have demonstrated improved efficiency due to combustion tuning. Combustion tuning approaches may include adjusting the burner air register settings to maintain uniform combustion air draft, adjusting the stack dampers to control air-to-fuel ratio, cleaning burner tips to remove carbon deposits or other blockages restricting air flow, and maintenance/repair of combustion system components. For the case study examined, an overall emission reduction of 3% was estimated, based on combustion tuning for 13 heaters and 2 boilers firing natural gas at a hypothetical refinery. Although actual results may vary, emission reductions for this case study ranged from less than 1% to 25% for individual combustion units. The methodology used to estimate emission reductions is based on techniques presented in the API Compendium. Cogeneration Emission reductions from cogeneration may result from an improvement in overall system efficiency compared to the separate generation of electricity and steam from conventional fossil fuel-fired boilers. For oil and gas industry operations, cogeneration provides potentially attractive energy efficiency and GHG reduction opportunities. Pre- and post-project direct emissions, thermal energy and electricity demands, and indirect energy imports and exports are all key baseline issues that must be addressed to determine cogeneration project reductions. Thorough characterization of displaced direct and indirect energy sources is also required. Finally, appropriate definitions of source and project operational boundaries must be developed to ensure that the cogeneration project reductions are credible and verifiable.

1028 The magnitude of GHG emission reductions from cogeneration is dependent on the form of generation being displaced, i.e., the baseline scenario for the specific project including both efficiency and fuel impacts. In cases where electricity is purchased from a local grid that represents mostly coal-fired generation, the overall GHG emission reductions from cogeneration may be substantial, due to both fuel carbon content and overall system efficiency differences. However, in cases where electricity is purchased in a geographic region of significant hydroelectric, renewable, and/or nuclear generation, emission reductions may be significantly lower, and in some cases could potentially result in a net increase in overall emissions resulting from the conversion to cogeneration. Three example case studies were developed to examine different scenarios and associated complexities that may need to be considered for a cogeneration project: • Cogeneration Case Study 1: A hypothetical greenfield cogeneration plant, developed primarily for independent power production, exports nearly all energy produced. For this example, the baseline emissions were approximated for an assumed "most likely" scenario in the absence of the project. For illustrative purposes, locally available electricity was selected to represent the baseline conditions, and emissions were estimated using electric grid emission factors for an assumed location. • Cogeneration Case Study 2: A hypothetical facility installs a cogeneration unit to improve overall efficiency. On-site energy use is assumed to remain essentially constant pre- and post-project, with excess energy sold offsite. This example examines exported energy and the complexities associated with determining emission reductions for increased efficiency. Two methods are presented for estimating baseline emissions: i) a grid displacement approach for exported electricity based on an assumed location; and ii) a comparison to natural gas-fired turbine combined cycle (NGCC), which was chosen to represent the "most likely" technology. • Cogeneration Case Study 3: On-site energy use post-project is assumed to increase due to organic growth over the pre-project case; excess electricity from the cogeneration plant is exportedto grid. For this situation, no clear, consistent rules on the methodology to establish the project baseline have been established. This example examines both a static baseline scenario with no adjustment for organic growth, and a dynamic baseline, representing on-site consumption rates after project start-up. For the static baseline scenario, post-project on-site energy use is equivalent to pre-project consumption. For the dynamic baseline scenario, baseline emissions associated with the incremental increase in on-site energy consumption are estimated assuming electricity supplied by the grid and steam generated by a natural gas fired turbine are the alternative energy sources in the absence of the project. For illustrative purposes only, estimated emissions for the various case study scenarios examined are summarized in Table 2. Emission estimates from combustion sources and electricity usage are based on calculation methodologies provided in the API Compendium. Again, it is important to recognize that actual results will vary for real applications due to site-specific conditions.

CONCLUSIONS Reductions in energy usage can result in reduced operating costs. Similarly, reduced CH4 emissions can translate into increased natural gas production/recovery. Due to the competitive business environment and pressure to control costs, oil and gas operators are taking steps to reduce energy usage and improve the efficiency of their operations. Demonstrating GHG emission reductions associated with these activities is an added benefit. This project quantified emission reductions for several oil and gas industry example case studies and provided insight into characterizing emission baselines and examining different reduction scenarios. Conclusions from this study include the following: • •

Specific emission reduction opportunities may not be applicable to all locations, and potential emission reductions will vary for each situation. Emission reductions require examining emissions from specific sources for the purpose of quantifying emissions before and after a reduction project has been implemented.

1029 • •

•

All emission sources that are likely to be influenced, either directly or indirectly, by a reduction project should be accounted for when considering the overall impact of the project on GHG emissions. Calculating emission reductions associated with energy imports and exports requires a project-by-project evaluation. Guidance for emission reduction reporting is beginning to evolve. Ultimately the selection of an appropriate approach depends on location-specific conditions, how the emission reductions will be used, any associated reporting specifications, and requirements of the host country and the buyer of emission reductions in the carbon market. Although the API Compendium was targeted toward developing emission inventories, which focus on the most significant emission sources and provide more general emission approaches for less significant sources, many of the methodologies are applicable to quantifying emission reductions. However, there are certain emission reduction projects, such as pneumatic devices, in which the estimation techniques provided by the Compendium do not provide sufficient detail for quantifying pre- and post-project emissions.

Enhancements to the Compendium to address these findings will be considered for the next release. (To obtain a copy of the current version see: www.global.his.com.) API welcomes a continuing open exchange of information and a broad discussion of GHG emission estimation methodologies. It is hoped that this process will achieve better harmonization of emission protocols and enable improved global comparability of emission estimates.

ACKNOWLEDGEMENTS

The authors would like to acknowledge the support and contributions of the API member companies in the development of the Compendium document. Company representatives on API's Greenhouse Gas Emissions Methodology Working Group have contributed valuable time and resources throughout the development process. We are particularly indebted to the companies that shared their internal company procedures and practices, and facilitated this process moving forward.

REFERENCES

American Petroleum Institute (2001). Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry; Pilot Test Version; API, Washington, D.C. [Mail Orders: API Publications c/o Global Engineering Documents, 15 Inverness Way East, Mail Stop C303B, Englewood, CO 80112-5776] United Nations Framework Convention on Climate Change (2002). Project Activity Design Requirements: Project Activity Baselines, CDM Modalities and Procedures, Annex Decision 17/CP.7, unfccc.int/cdm/baseline.html, Bonn, Germany. American Petroleum Institute (1999). Voluntary Actions by the Oil and Gas Industry to Address Climate Change, A Conference on Industry Best Practices, Houston, TX. Energy Information Administration (1996). Sector Specific Issues and Reporting Methodologies

Supporting the General Guidelines for the Voluntary Reporting of Greenhouse Gases Under Section 1605(b) of the Energy Policy Act of 1992, Volume 1, U.S. Department of Energy, Washington, D.C. U.S. Environmental Protection Agency (2002). Natural Gas STAR Program, Technical Support Documents, www.epa.gov/gasstar/tech.htm, Washington, D.C. Shires, T.M. and M.R. Harrison (1996). Methane Emissions from the Natural Gas Industry, Volume 12: Pneumatic Devices, Final Report, GRI-94/0257.29 and EPA-600/R-96-0801. Gas Research Institute and US Environmental Protection Agency, National Risk Management Research Laboratory, Research Triangle Park, NC.

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TABLE

l

SUMMARY OF EMISSION REDUCTIONS FROM PNEUMATIC DEVICE CASE STUDIES

Hypothetical Baseline Scenario l Oil and production operations with 20 liquid level controllers and 180 pressure controllers Baseline pneumatic device emissions, tonnes CO2 Eq. 23,444 Estimated % Emission Potential Reduction Scenarios Reduction a Improved maintenance 35% Replace high-bleed devices with low-bleed devices 93% Retrofit high-bleed devices to eliminate pilot bleed rate 99% 99.5% t) Replace natural gas with compressed air D Replace high-bleed devices with self-contained devices 100% a Note: percent reductions are based on assumed conditions for the example case study scenarios and may not be representative of actual reductions for real-world applications. b For this scenario, post project emissions are indirect due to electricity consumption, while baseline emissions are direct. Results in a 100% net decrease in direct emissions, and a 0.5% net increase in indirect emissions.

TABLE

2

SUMMARY OF EMISSION REDUCTIONS FROM COGENERATION CASE STUDIES

Scenario Description New cogen, plant consumes 1.556x1016 J (14,760,000 million BTU) of natural gas. Generates 1,523,000 MW-hr electricity and 1.404x10 is J (1,332,000 million BTU) steam. Cogen. requires 38,500 MW-hr electricity. Refinery purchases 206,000 MW-hr electricity. Burns 190,786 m3 (1,200,000 barrels) diesel to generate 2.857x101~ J (2,710,000 million BTU) steam for on-site use. New cogen, plant consumes 8.572x1015 J (8,131,500 million BTU) of natural gas to produce 1,100,600 MW-hr electricity and 3.810x10 is J (3,614,000 million BTU) steam. Refinery requires 2.857x1015 J (2,710,000 million BTU) steam and 244,500 MW-hr electricity. Excess energy is sold offsite. New cogen, plant consumes 8.572x1015 J (8,131,500 million BTU) of natural gas to produce 1,100,600 MW-hr electricity and 3.810x1015 (3,614,000 million BTU) steam. Refinery requires 3.810x10 is J (3,614,000 million BTU) steam and 313,500 MW-hr electricity. Excess energy is sold offsite.

Case Study

Greenfield Cogeneration Plant

Baseline Conditions (used for the following scenarios) Cogeneration Increased Efficiency Grid Replacement Approach c Cogeneration Increased Efficiency "Most Likely" Alternative Technology Approach d Cogeneration with Organic Growth - Static Baseline Cogeneration with Organic Growth - Dynamic Baseline e

Estimated % Emission Reduction a

43% b

(Baseline) 65% 63% 58% 56%

a Note: percent reductions are based on assumed conditions for the example case study scenarios and may not be representative of actual reductions for real-world applications. b Reduction estimates for the Greenfield plant are based on comparison with electric grid emissions for an assumed location. c The grid displacement approach is based on the average carbon intensity of power generation in the region or state (or country), projected over the lifetime of the project. The location was assumed for this scenario. d The "most likely" technology approach is based on recent projects and those projected to develop in the same relative timeframe. This approach is consistent with cited Clean Development Mechanism (CDM) methodology, i.e. "the average emissions of similar project activities undertaken in the previous five years, in similar social, economic, environmental and technological circumstances, and whose performance is among the top 20% of their category" [2]. Estimates for this example are based on electricity generated from a natural gas-fired combined cycle (NGCC) turbine. e Baseline emissions associated with the incremental increase in on-site energy consumption are estimated assuming electricity supplied by the grid and steam generated by a natural gas fired turbine are the alternative energy sources in the absence of the project.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

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CLEANER PRODUCTION TECHNOLOGY AND BANKABLE E N E R G Y E F F I C I E N C Y D R I V E S IN F E R T I L I Z E R I N D U S T R Y IN I N D I A TO M I N I M I S E G R E E N H O U S E GAS E M I S S I O N S - CASE S T U D Y Surendra Kumar FIE, Chartered Engineer (India) Head, PACD, Nuchem Weir Limited 119, LSC, Pocket D&E, Sarita Vihar, New Delhi -110044

ABSTRACT

The Fertilizer Industry offers a most exciting, challenging and rewarding opportunity for adopting Bankable Energy Efficient and Cleaner Production Technologies to support minimization of greenhouse gas emissions. Cleaner production technology has cut down energy consumption from 9 G. calories/Mt to around 7 G. calories/Mt in ammonia plants where capacity utilization has also improved from 74% to 84%. In addition, the Fertilizer Industry has initiated measures on waste heat recovery, reuse of heat in the plant system, and steam network system optimization through computer programming. Pneumatic controls have largely been replaced by distributed control systems mainly operated by electrical drives and recently, naphtha-based power stations have adopted the latest DCS systems resulting in 3-5% energy savings besides realizing 2-3% raw material saving and 2-2.5% enhancement in yield. Energy efficient technologies relevant to the Fertilizer Industry include fuel switching (exchanging fossil fuel based energy generation system with those that use renewable fuels like biomass, solar energy etc). This has resulted in zero greenhouse gas emissions and very low cost/unit of generation of power and steam. Efficient electric motors have replaced old designs of sets and an overall effort has been made to reduce heat and power losses, which finally results in less use of fuel, thereby minimizing emissions. Waste incineration has also become a source of energy recovery. The paper includes case studies to demonstrate substantial reduction in fuel consumption and reduction in greenhouse gas emissions through the adoption of cleaner technologies in the Fertilizer Industry.

INTRODUCTION

Indian population has exceeded 1000 million in May 2001, which necessitated a requirement to feed the population of 240 million tons, and fertilizer requirement of around 21 million tons. The increased demand for fertilizers required increased production and thereby increased atmospheric emission of pollutants and greenhouse gases. The Fertilizer Industry took up the challenge of increasing its outputs but not at the cost of environmental pollution. It adopted Bankable Energy Efficient and Cleaner Production Technologies to support minimization of pollutants and greenhouse gas emissions. Cleaner production technology has been able to cut down energy consumption from 9 G calories/Mt to around 7 G calories/Mt in present ammonia plants where capacity utilization has also improved from 74% to 84%. Focus on automation has helped to realize

1032 these objectives substantially. In addition, the Fertilizer Industry has initiated measures on waste heat recovery, reuse of heat in the plant system and steam network system optimization through computer programming. Energy efficient technologies relevant to the Fertilizer Industry include fuel switching (exchanging fossil fuel based energy generation system with those that use renewable fuels like biomass and solar energy). This has resulted in zero greenhouse gas emissions and very low cost/unit of generation of power and steam.

RELEVANCE OF CLEANER PRODUCTION IN F E R T I L I Z E R INDUSTRY The main emphasis of cleaner production in the fertilizer industry is to achieve better performance in existing and future fertilizer plants. The process improvements with reference to nitrogenous plants, which are using Naphtha or natural gas as feedstock material, are: 1. Improving yield from feed stock material. 2. Improving energy conservation. 3. Reduction in consumption of energy (energy consumption has come down from 9 G cal/MT to around 7.0 G Cal/MT in present ammonia plants). 4. Reducing emissions of liquid and gaseous effluents. 5. Operator friendly interface and acceptability. Three main groups of cleaner production technology i.e. source reduction, recycling and product modification, are the guiding principles in the fertilizer industry. Source reduction includes 'good housekeeping' and 'process changes'. Process changes include options on change in input material, better process control, equipment modification and technology change. Recycling is the on-site recovery and reuse of material and energy which otherwise comprises a waste. Product modifications are made to increase product lifetime to make recycling easier and/or to minimize the environmental impacts from the disposal of the products.

APPROACH OF INCORPORATING PROCESS IMPROVEMENT The steps for improving process performance are well addressed by adopting process automation at different levels in a fertilizer plant. Appropriate revamp/retrofit measures are being adopted in existing plants and new plants are likely to have in-built process automation. The approach could be one or several of the following measures: i) Installation of distributed control systems. ii) Heat recovery and steam net work systems to be optimized through computer program. iii) Pneumatic control systems being replaced by distributed control systems mainly operated by electrical signals. The equipment cost increases by 5% if process automation is adopted. The recent naptha-based thermal power stations at two fertilizers units have adopted latest DCS system. The incremental additional cost has been paid off within a year due to quantified benefits: 3 to 5% energy saving, 2 to 3% raw material saving and improvement in yield by 2 to 2.5%

CLEANER PRODUCTION AND ENERGY EFFICIENT T E C H N O L O G I E S RELEVANT TO F E R T I L I Z E R INDUSTRY

Fuel Switching (if technologically, locationally and adequately meeting the demand) The fertilizer industry is mostly based on natural solid, liquid or gaseous raw materials and does not afford high technology installations in steam and power generation, but can switch to biomass combustion in the boilers for co-generation of steam and power. Biomass such as rice husk, sirkunda, jungle grass, straw and other crop refuses can be very conveniently selected and burnt. The advantages include little or zero greenhouse gases and toxic emissions and no depletion of

1033 resources, as they are renewable sources of energy. The other advantages of using biomass as a renewable source of energy is the very low cost per unit of generation of steam and power, and also the easy availability in the nearby vicinity.

Captive & Co-generation P l a n t s - The solution Integrated energy services are emerging very forcefully world wide. Co-generation and combined heat and power (CHP) are gaining currency. Co-generation plants claim efficiencies of more than 85 percent compared with 35 to 55 percent for conventional power generation techniques. It is logical to strongly encourage captive and co-generation plants in India. Captive and co-generation plants in the fertilizer industry, especially based on biomass, add to process efficiency as well as reducing atmospheric emissions. Electrical and Utilities field There is a huge consumption of electricity by electric motors in all the areas in the fertilizer industry. 70% of the energy used in the sector is in the operation of electric motors. Even if there is a 1% improvement through taking control measures, there will be substantial savings of power in each unit. Similarly, use of energy efficient products such as transformers and industrial electronics capacitors, and provision of energy efficient lighting would result in large savings in electrical energy. The increasing cost of power naturally promotes the use of larger power cables, capacitors for power-factor correction, more efficient motors, generators, transformers, rectifiers and other power equipment to reduce energy losses. In the utilities section, the following major steps have been taken for energy conservation: 1. Proper selection of fuel firing equipment namely Burners, mechanical stokers etc. 2. Maintenance of correct temperature & pressure of fuel oil at the burner tip exactly as per manufacturer's specifications. 3. Minimising radiation losses from Burner, Furnace and auxiliary equipment by thermal insulation. 4. Reusing blow down and waste process heat to preheat the boiler feed water. 5. Control on loss of steam from Relief valves and other fittings by critical scrutiny of steam and power both at generation and transmission levels. 6. Use of calibrated meters for fuel consumption, steam generation and transmission to account for and control losses, if any. 7. Regular analysis of flue gases for optimising complete combustion and minimising wastages and heat losses. Estimation of CO2 and 02 in flue gases and operations stimulated through micro processed control with these parameters results in large savings. 8. Fuel combustion to maintain correct pressure of primary and secondary drafts to control unburnt fuel and/or heat loses. 9. Use of Deaerators, preheaters, Economisers and Recuperators for efficient reuse of waste heat. 10. Maintaining heat transfer surface area clean to avoid heat losses. 11. In case of coal firing, minimising unburnt carbon content in ash. 12. Adequate removal of condensate from pipe lines and reuse in Feed Water Circuit. Variable Speed Pumps Variable speed pump in place of M.C. Pump should be used. In these pumps control valves should be replaced with variable speed drives for efficient functioning to control flow rate of high concentration slurry. This minimises power consumption by about 26%.

CASE STUDIES - CLEANER TECHNOLOGY/ENERGY EFFICIENCY

Typical Success Stories of a Fertilizer Plant:

ii)

Unit No. 1 Production of Formic Acid Conservation of Waste gases generated in liquid nitrogen waste unit of ammonia plant into value-added product. Use of tail gas as boiler fuel

1034

iii) iv)

v)

Tail gas produced in ammonia plant and flared is used a fuel to main boilers. Use of waste CO2 for calcium ammonium nitrate production. Recovery and recycle at source Hydrolyzer stripper unit in the urea plant helps to eliminate liquid pollution cause by ammonia and urea, while recovering and recycling large quantities. For the Nitrophosphate Group of the plant, scrubbers have been provided where pollutants like ammonia, nitrous gases etc. are recovered and recycled. Also, closed underground tankers are provided where all leakages and spillages are collected separately in different sections and recycled to the process. Use of non-conventional sources of energy To reduce firewood consumption, the unit is actively promoting the use of nonconventional sources of energy like biogas, solar heating, windmills etc. in nearly villages. In fact, these systems have become very popular and more and more villages are now adopting these systems.

2. Unit No. 2 a) Conservation Measures By generating steam from process condensate the following benefits have been achieved: Water saving of 0.22 Million US Gallons/day. - Energy saving of 3.5 Million K.Cal/hr. - Elimination of about 0.4 MT of NH3 per day from final effluent stream. - Improved flexibility for auxilary boilers and DM Plant. - Improved overall reliability of plant operation. -

3. Unit No. 3 a) Conservation Measures Return and payback due to reduced raw material mainly from the NH3 recovery system, a section of the main plant project. It is capable of recovering 20-30 Kg. ammonia vapour per ton of CO product i.e. amounting to Rs. 25,000 per day resulting in pay back of capital investment for pollution control.

ENERGY CONSERVATION Measures, at a cost of Rs. 110 Lakh, have been commissioned which are capable of generating 2040 KWH by steam turbines, resulting in conservation of low pressure steam which is used in the process. PLANT DESIGN - BASED ON ENERGY CONSERVATION C R I T E R I A Energy Conservation in New Plants These have been selected to illustrate the application of sound engineering to the design of projects, with a comparison of construction and energy costs. They include: • Furnace efficiency • Power-recovery systems • Hydraulic-turbine power recovery • Reflux vs operating cost • Water cooling vs Air cooling • Fluid catalytic cracking unit power-recovery systems • Ammonia plant optimization • Ethylene-plant design • Cryogenic gas processing

The new ammonia process has changed the state of the art in several major respects: • The synthesis of ammonia is now being conducted at much lower pressure, approximately 150200 atm, compared to the prior practice of ammonia synthesis at 300 atm or more. • The new process is adapted to the use of low-cost centrifugal compressors, rather than the high cost reciprocating compressors previously used. The relative inefficiency of centrifugal

1035

• • •

compression is more than compensated for by the use of an efficiency energy cycle to provide steam turbine power. Previously unused "Water heat" is now recovered efficiently, and is used to provide the energy for gas compression. A highly efficient steam system has been developed to achieve a significant reduction in ammonia plant energy requirements. The refrigeration circuit is effectively utilized to liquefy and refrigerate the ammonia product.

Energy Conservation in Existing Plants • Side-draw distillation design reduced energy requirements by 50% over the first design. • Steam generation on the column condenser provided 2.5 kg/cm 2 steam for plant use its heat content is equivalent to that of the gas required for the fired-heater reboiler. • Burning the heavy stream in plant reduced net plant fuel gas requirements by about 5%. • A high-thermal-efficiency fired heater reduced by 25-30% the fuel gas requirement over conventional plant heaters. Efficient use of Steam One area of large potential savings is better utilization of steam. Whenever low-pressure steam is condensed by cooling water or air, roughly 2500 KL/kg of steam is wasted. To utilize this energy in low pressure steam, several of plants have replaced electric-motor-driven mechanical refrigeration units with absorption refrigeration units, which use 0.75 to 1.0 kg/cm 2 steam as the driving force. Previously, this steam was condensed from a 1 to 2 kg/cm 2 system and returned to the power plant as condensate. The net effect is to use the energy in the low pressure steam, thus saving electrical power. One plant has saved the equivalent of 20 million KJ/h in this manner, and several others have saved 2 -3 million KJ/h. More Ways to Save Steam In one plant, 35 kg/cm 2 steam was being throttled to 16.5 kg/cm 2 because the existing 16.5 kg/cm 2 system was supposed to be inadequate to provide the full requirement of such steam. The steam reducing station was shut down and the full requirement of 16.5 kg/cm 2 steam was made available. The pressure was slightly lower but adequate for requirements. This action resulted in a net savings of 15 million KJ/h. Another plant has several multistage steam jets for the evacuation of noncondensables and inerts from columns. It was found that these jets could handle the noncondensable load adequately with one less stage, so that final stage steam was turned off. This action saved over a quarter million KJ/h. This same plant found that it needed only a third to a half the amount of steam used in steam-tracing pipes and thus saved another 2 million KJ/h.

Condensate Recovery A plant recently completed a condensate-recovery project that involved the replacement of two barometric condensers (using cold seawater) on the final stage of two multijet vacuum systems. Approximately 230 kg/h of steam used in each of these systems was lost with the sea water in the condenser, along with minor quantities of a hydrocarbon solvent from the process. The barometric units were replaced by surface condensers, in which the steam condensate (containing the hydrocarbon) is kept separate from the sea water coolant and is collected in a decanter drum, where both condensate and hydrocarbon are recovered. This represents a modest savings of 130,000 KG/h of energy and eliminates a source of both thermal and hydrocarbon pollution. Minimizing Combustion Losses Another important area opted for energy savings is control of combustion. For a given stack temperature, the minimum heat losses occur with zero percent excess air (theoretically). However, the range of 0 to 5% excess air requires extremely good burner-performance. Power plant boilers incorporate economizers and combustion-air preheaters to reduce flue-gas heat losses.

1036 CONCLUSIONS In a very modest and humble way, the fertilizer industry in India is contributing towards efficiency and minimization of GHG emissions which, if adopted in other industries, definitely yield substantial savings. Fertilizer movement through co-operatives in India has given it a real thrust and a boost, with most of the units excelling in performance on a day basis.

REFERENCES

1. Techno Market Survey on Process Automation in Chemical, Textile & Fertilizer Industry. 2. Technology Information, Forecasting & Assessment Council (TIFAC) 1997. Dept. Of Science & Technology, New Delhi. 3. Chemical Weekly i. May 3, 1994 ii. August 25, 1998 iii. April 27, 1999 iv. Dec. 28, 1999 4. Sustainable Development by Enterprises - FICCI 5. Indian Industry Environmental Status Series - N o . - IV (Fertilizer Sector ) FICCI 6. Fertilizer Statistics- Fertilizer Association of India 7. N. Manivasakam, Industrial Effluent 8. Manual on Fertilizer M a n u f a c t u r e - Vincent Soucheble Davisopn Chemical Corporation 9. Energy Conservation Plant Design (Both New and Old) 10. Process Energy Conservation Richarg 11. Greeve & Staff of Chemical Engineer - 1992 12. Economic Times, July 2001

energy would further by day

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1037

COz REDUCTION IN THE IRONMAKING PROCESS BY WASTE RECYCLING AND BY-PRODUCT GAS CONVERSION J. Ct Kim and J.O. Choi RIST, Pohang Research Institute of Industrial Science and Technology San 32 Hyoja Dong, Pohang, 790-330 Korea

ABSTRACT In this study, recycling of the top gas of a blast furnace to its base, as a reducing agent, was investigated theoretically and some new concepts introduced. In particular, a new method for blast furnace top gas recycling using gasification of waste hydrocarbon material is suggested, and the characteristics of the system have been analyzed by thermodynamic calculation. By using coal or coke as a carbon source and blast furnace top gas as the gasification agent, a reducing gas is produced for iron ore containing 50% CO and 16% hydrogen, in the state of thermodynamic equilibrium at a temperature of 1000°C. With the ratio of effective (CO+H2) 0.112, this gas can be injected as a reducing agent directly into the blast furnace. For confirmation of this result practically, an experimental study on the gasification of waste hydrocarbon material e.g. waste plastic, low grade coal or organic sludge, and evaluation of the effects on the blast furnace operation will follow.

INTRODUCTION The Korean steel industry has about 50 years of history; this is a very short time period compared to the other major steel production countries worldwide. The real step of the Korean steel industry to a modern and large-scale industry started when Pohang Works started steel production in 1973, having an annual production capacity of one million tons. Crude steel production in Korea exceeded 10 million tons in 1981, 20 million tons in 1989, 40 million tons in t997 and maintained more or less the same level thereafter.

1038 Based on its yearly total production of 41 million tons, the Korean steel industry has increased production by a factor of about 280 during the last 30 years and shared 5.2% of the total steel production worldwide in 1999. The contribution of the Korean steel industry to the national product increased from 0.5% in 1970 to 4.6% in 1999. Moreover, the contribution of the steel industry to the total manufacturing industries in terms of product and to total exports were 6% and 5%, respectively in 1999. Considering the reduction of CO2 from an integrated steel work, the ironmaking process (the blast furnace, coke plant and sinter plant) would be the major target as about 75% of the total energy consumption is used in this process. Besides pulverized coal injection (PCI), hot reduction gases (HRG) are becoming alternative candidates that can reduce CO2 from blast furnace. The source of gas can be either an external gasifier or recycling of blast furnace gas (BFG) from which the CO2 is removed. In the course of this concept, a novel concept awaits to prove its ability to reduce CO2 using relatively easy operations and low cost. The concept is that a gasifier is used to produce a reducing gas for the blast furnace and BFG is recycled to the gasifier. Generally, it is expected that CO2 emission from the blast furnace can be reduced either by using H2-rich reduction gas or by reusing BFG after removing or reforming CO2 present. The main advantage of this system is expected to be that the unreacted reducing gas, CO and Hz in the blast furnace top gas is fed into the blast furnace by a circulation system and carbon dioxide in the top gas is converted in CO and used as reducing gas. In this work, the BFG recycling technologies are studied and the possible usages are suggested, as concluded from the predictive calculations. RECYCLING OF BLAST FURNACE TOP GAS Among the three major by-product gases in the steel works, coke oven gas (COG), blast furnace gas (BFG) and basic oxygen furnace gas (LDG), BFG is the major contributor to greenhouse emissions with approximately 70% of the total CO2 generation in the integrated steel works, if it is burnt in the works. BFG generation is estimated to be 1,500 m 3 per ton of crude steel. For this reason, the recovery of CO2 from the blast furnace gas is assumed to be most effective, and the following technical options for the reduction of CO2 emissions are suggested: •

Separation and sequestration of CO2 from the top gas

•

Recycling of top gas with or without CO2 separation

•

Integrated system with synthesis of chemical feedstock

Recycling of top gas with C02 separation Recycling of the blast furnace top gas after the CO2 separation has been studied theoretically as well as practically and has shown a productivity increase of 25% and a fuel rate decrease of 20% for the blast furnace process (1, 2).

It is possible to combine the existing blast furnace process with a methanol

synthesis process based on steam reforming of natural gas, which is well established in the chemical industry. A feasibility study of this process combination made clear the potential of energy savings and a reduction of CO2 emissions (3).

1039 The pressure swing adsorption (PSA) method is one of the most popular methods for CO2 separation. In the PSA process, the gas mixture flows through the beds at elevated pressure until the adsorption of the target gas approaches an equilibrium condition at the end of the bed. The flow of the gas mixture is then intercepted, the pressure is reduced and the adsorbed constituent is desorbed with a gas having low adsorptivity. The bed is then regenerated and is ready for the next adsorption cycle. For the PSA, therefore, two or more columns are installed for separation of the target gas continuously in a cycle.

Recycling of top gas without COz separation Recycling BFG as it is, still has an effect in reducing CO2 from the blast furnace. The gas produced from the blast furnace presently forms a reducing gas in the form of CO, and this can be reused by recycling the BFG as it is. However, in this case, the rate of reduction would be decreased, with the increased CO2 gas content in the reducing gas stream in the blast furnace. Even if pure oxygen is used to compensate for the heat loss by the increased CO2, certain precautions should be taken and experimental approval required before full application. Theoretical caculation results based on the foundry blast furnace are summarized in Table 1. In this calculation, only the equilibrium composition after reaction was considered and the whole mass and energy was balanced between input and output streams. All other conditions besides the BFG recycling are the same as that of the conventional operation (temperature, energy consumption for ore reduction, and compositions of raw materials). The results show that less coke would be needed than that required in the conventional operation and consequently, less CO2 emissions could be achieved. Because of the decrease of the coke production, fuel shortages are expected with repect to the overall energy balance for the integrated steel works and the use of natural gas (LNG) is recommended for the reduction of CO2. When 15% of the BFG from top of the blast furnace is recycled, the consumption can be reduced by 5.37% and overall reduction of CO2 would be expected if the LNG is used to compenaste for the fuel shortage. Because the equilibrium concentration of the product is linearly dependent on reactant concentration, the calculation result showed that the CO2 reduction is linearly proportional to the BFG recycle ratio. TABLE 1 EFFECT OF BFG RECYCLING

Amount [Nm3/tpi] 263.4

Rec, Ratio Coke Redctn.

[%]

[%]

Carbon Redctn.[%] BF Whole works

15

5.37

6,10

3,32

Recycling of top gas by means of waste gasification In order to investigate the BFG recycling without CO2 separation, a gasification process was tested in which various hydrocarbon sources such as low grade coal, waste plastics, or other organic waste material were gasified with BFG and oxygen. The product gas from the gasifier has higher carbon monoxide and

1040 hydrogen contents than the top gas, and is suitable for injection into the blast fumace as a reducing agent. Figure 1 shows the basic flow sheet of this recycling process. Thermodynamic calculations for coal gasification with BFG indicates that the equivalent amount of coal and oxygen are 20kg and 10Nm 3, respectively, for the conversion of lkmol BFG at 1000°C and 1atm down to the CO2 concentration of 5% as shown in Figure 2. The product gas has a composition of 73%

(CO+H2) and a heating value of 1,800kcal/Nm 3. If this gas is

injected into the blast furnace at a rate of 500Nma/thm, about 50 kg/thm of coke can be saved according to the formula of an "effective

(CO+H2)" (4). Filter

BFG

Crude COG

Carbon source Oxygen - -

Coke oven

Gasifier

Reformer

Figure 1: Top Gas Recycling with Reformer or Gasifier

'

0.6 -

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1

'

I

'

I

'

I

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,

i

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,

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,

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~

20

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25

o

30

Coal [kg/hr]

Figure 2: Thermodynamic Calculation of Coal Gasification with Blast Fumace Top Gas at 1000°C and 1atm Although the theoretical result shows the possibilities and potential, the feasibility of the process

1041 should be confirmed through experimental work as this is the novel process and no actual testing has been carried out. The experimental project should include: 1) a charging system that could handle waste shredder dust produced from automobile scrap and household appliances and industrial and municipal wastes including plastics, rubber, paper and other organic materials, with little preconditioning 2) a furnace design that secures the steady continuous operation including steady downward movement of the entire bed and discharge of ash in molten state 3) the controlling of the furnace temperature and addition of carbonaceous material that can provide heat and prevent agglomeration in the furnace 4) the confirmation of the possibility that CO2 will react with the gasification product gas 5) a gas handling system and the composition of the product gas 6) the effect of combustion gas (oxygen or air) 7) the granulation of the slag For this study, an experimental gasifier was designed and installed. The basic concept is that the gasifier is divided into two sections. In the first section, feedstock will be dried, and in the second section, the dried feed will go into the conventional gasification. Figure 3 shows the schematic diagram of the experimental set-up. In this furnace, a small part of the product gas is split from the main stream and is used for drying of the feed; the gas from the drying stage can either be recycled to the bottom of the gasifier or be put to some alternative use. The compositions of the dry and wet gas streams needs determining and the control of both streams investigated. Waste

&

Carbonaceous Additive

IS

Wet Gas

S

Recycling

]gent

I

Oxygen or Air with BFG

~ I-

Figure 3: Schematic diagram of gasifier, showing the concept of wet and dry gas production

1042 COKE OVEN GAS I N J E C T I O N TO THE BLAST FURNACE Here, the injection of the coke oven gas (COG) to the blast furnace as a reducing agent is considered. The calculation would be similar to that for the BFG recycle and the results are summarized in the Table 2. As is the case when the BFG is recycled directly, there is a linear proportionality between COG injection rate and the CO2 reduction. The effect of COG injection on the COz reduction is, however, not so promising as the BFG recycle as the major component of COG is hydrogen; this can be used as a fuel for many other facilities, and this in turn means that the carbon balance for whole works would not be improved, even if the COz emission from the blast furnace is reduced. TABLE 2 EFFECT OF COG INJECTION TO THE BLAST FURNACE

Amount [Nm3/tpi] 100

Coke Redctn. [%] 11,97

Carbon Redctn,[%] BF Whole works 8,1

1.93

DISCUSSION AND CONCLUSIONS Short term measures are applicable for the reduction of carbon dioxide emissions, independent of the energy input for separation and sequestration of CO2 from steel works gases. Pressure swing adsorption techniques can be applied for the separation of CO2 from the flue gas of the power plant and BF top gas. Chemical conversion and recycling of CO2-containing steel works gases can be also effective methods for the intensive use of the chemical constitutions of coal for iron making and thus, reduction of CO2 emissions. Various top gas recycling technologies look promising so far, but the practicability of these concepts is still in doubt; pilot or on-site tests will need much time and the confirmation of the contingencies still more. It is considered here that the key factor would be how we can get the sufficient data for oxygen enrichment technology to control the reaction in the blast furnace. REFERENCES 1.

ER. Austin, H. Nogami and J. Yagi, ISIJ International Vol. 38, No. 3, 1998, pp. 239-245

2.

M.A. Tseitlin, S.E. Lazutkin and CtM. Stiopin, ISIJ International. Vol. 34, No. 7, 1994, pp. 570-573

3.

T. Akiyama, H. Sato and A. Muramatsu, J. Yagi, ISIJ International. Vol. 33, No. 11, 1993, pp. 1136-

4.

P.C. Rhee, Journal of Korean Institute ofMetals Vol. 16, No. 2, 1978, pp. 115

1143

ZERO EMISSION P O W E R PLANTS

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1045

CLEAN COAL-FIRED POWER PLANT T E C H N O L O G Y TO ADDRESS CLIMATE CHANGE CONCERNS W.A. Campbell, Project Manager 1 and W.H. Richards 2 ~Canadian Clean Power Coalition, Suite 2304, 650 - 10th Street SW Calgary, AB, T2P 5G4, Canada 2 Nova Scotia Power Inc., PO 1609, Bras d'Or, NS B 1Y3Y6, Canada

ABSTRACT The Canadian Clean Power Coalition (CCPC), an association of Canadian coal and coal-fired electricity producers, has started on a detailed analysis of technology options to control air emissions, including CO2, which result from coal use. The goal of the project is to demonstrate that coal-fired electric power can be generated with emission levels similar to those from natural gas combined cycle, and to show that CO2 can be captured for commercial use or ultimate sequestration at a cost which does not render coal uneconomic. Initial engineering studies are underway, scheduled for completion in 2003, to evaluate technology options for both retrofit and new plants. Following the initial study phase, it is planned to proceed with two demonstration projects: the first for retrofit to an existing plant, is planned by 2007; the second for a new green-field plant, is planned to be carried out by 2010. INTRODUCTION The Canadian Clean Power Coalition 1 was formed in 2001 after discussions among Canadian utilities and coal companies revealed a common interest in proactive action to address the environmental concerns arising from the use of coal in electric power generation. In particular, concerns with the potential impact of air emissions on human health, and the growing concern with carbon dioxide emissions and their impact on climate, are issues that need to be addressed. Members of the CCPC, representing power generators and coal suppliers of over 90% of Canada's coal-fired power generation, believe that the need has never been greater for a demonstration of clean coal technology for power generation.

Emissions of Concern A growing awareness of the relationship between human health and air quality has focused environmental agencies to examine the role of coal-fired power generation as an emitter of various air pollutants of concern. In Canada and the United States, regulatory agencies are setting new ambient standards for ozone and fine particulate. In addition to its current program to drastically reduce NOx emissions in the 22 eastern States, the US Environmental Protection Agency recently Foundingmembersin 2001 wereATCOPowerCanadaLtd., EPCORUtilities Inc.,LuscarLtd.,NovaScotiaPowerInc.,Ontario PowerGenerationInc., SaskatchewanPowerCorporationand TransAltaUtilitiesCorporation.

1046 decided to regulate emissions of mercury from power plants. Canada has already introduced Canada-Wide Standards for mercury for incinerators and base metal smelting. A Canada-Wide Standard for Mercury emissions from coal-fired power plants is also under development. In 20012002 Canadian regulators began a review of the National Emission Guidelines for Thermal Electric Power Generation with an interest in controlling a diverse suite of emissions from the thermal electric power generation sector. Carbon Dioxide and Kyoto Protocol In addition to these issues, there is the as yet unresolved issue of CO2 emissions and how the goals of the Kyoto agreement, which the Canadian government recently expressed their intent to ratify, will be realized. Regulatory requirements for CO2 emission reductions by the thermal electric power generating sector appear inevitable. The principal concern raised by industry is with the potential for a series of separate, poorly coordinated emission control directives, each implemented to reduce a particular emission of concern, so that the cumulative impact is to render existing and future coal-fired power plants uneconomic. The CCPC believes that by addressing these issues in a proactive and comprehensive manner, the viability of coal utilization can be assured and that the economic benefits of doing so are significant for Canada. The goal of the project is to demonstrate technologies, for retrofit to existing plants or for use in new coal fired power plants, which will allow the full suite of emissions, including CO2, to be controlled to meet foreseeable regulatory requirements. The goal is to accomplish this while maintaining overall efficiency at or above current levels, maintaining costs competitive with other generation technologies, and enabling CO2 to be captured. This project will be completed by 2010 in several phases consisting of: • • •

Phase I - Conceptual Engineering & Feasibility Studies Phase I I - Retrofit Demonstration Project Construction & Operation Phase I I I - New Green-field Demonstration Project Construction & Operation

Coal Use for Power Generation in Canada Although hydro electricity provides the majority (61%) of electrical power in Canada (mainly in Quebec, Manitoba, B.C. and Ontario), coal-fired power generation provides 18% of Canada's power generation needs. Alberta, Saskatchewan and Nova Scotia all depend on coal for over 70% of their needs, with coal supplying 25% of Ontario's needs. It is expected that technology developed by the demonstration project could be applied to most coal-fired plants in Canada. It would be particularly of interest to coal-fired power producers in western Canada, where uses for captured CO2 are being demonstrated. The technology would also be of interest to coal users in the United States and overseas. The subjects of the Phase I studies are the coal-fired power plants in Alberta, Saskatchewan, Ontario, and Nova Scotia. Lignite, sub-bituminous and bituminous coals are being evaluated as feed stocks. The demonstration plants projected for the later phases of the project will most likely be located in westem Canada, where the CO2 produced can be sold for use in enhanced oil recovery projects. DEVELOPMENT PLAN Objectives The CCPC intends to construct two demonstration projects should the results of the preliminary research studies be positive. These demonstration projects would consist of:

1047 The retrofit of an existing plant with new technology to meet the environmental and economic goals outlined above, to be completed by 2007. The implementation schedule calls for project commitment in 2004, detailed engineering in 2005, construction from 2005 into 2007, and commissioning in 2007. 2. The design and construction of a new green-field plant to meet the environmental and economic goals outlined above, by 2010. The schedule for this is for project commitment by the end of 2004, engineering 2005 through 2006, construction from 2006 through 2008, and commissioning in 2009. 1.

Study Organization The overall project will be executed in a series of successive phases, with the initiation of each dependent on the successful completion of the preceding phase. Phase 1, conceptual engineering and economic feasibility, was initiated in August 2001. This project component is evaluating the range of developing technologies and will develop the conceptual engineering for application to power plants. The Management Committee of the CCPC has appointed a project manager to manage the activities of the CCPC and to carry out the overall work plan. A number of major subcontracts have been awarded, coveting the retrofit and new plant technology cases. The project manager is responsible for the overall co-ordination of all these activities and the preparation of the final reports. A Technical committee has also been formed to oversee the project and to ensure the work meets the goals of the CCPC and other stakeholders. The committee's management function is to review the overall progress of the work with regard to schedule and costs. In addition, this committee provides a general steering function in regard to the conduct of the work. PHASE I PROJECT W O R K PLAN

This phase is planned to be carried out over 2 years at a total cost of $5M CDN. The overall plan is shown below: Month Task

03

I o e l 09 I 12 I is I 18 121 I 24

2r

30

33

3e

Coordination Retrofit Em ission Control.Assessm ent Retrofit CO2 Control Options Assessment New Plant Technology Assessment New Plant Technology Selection CO2

Utilization

Assessment Final Report

IIl/u. •" m m , R I I r

w

~

Total

Cost:

$5,000,000

1048

Retrofit Case Study The main task in the retrofit case is to carry out process feasibility studies of technologies such as amine scrubbing, CO2/O2 combustion, and gasification. Evaluation of the latest R&D in process developments for scrubbing processes are being carried out, leading to the selection of the process to be used, and the conceptual design. A major issue is to determine the fate of all air emissions, as well as to assess other environmental impacts. Results from research carried out by the Natural Resources Canada CO2/O2 project at the CANMET Energy Technology Centre and at the International CO2 Extraction Test Centre project in Regina and at the Boundary Dam power plant of Saskatchewan Power are included in the studies. The design goals for the retrofit study are: a) no net loss of power output from the plant after retrofit; b) control and safe disposal of all emissions from the plant; c) capture of the CO2 from the plant and from any auxiliary power generation required; and d) evaluation of plant integration options and benefits.

Emissions Study In addition to this work, a separate study is being carried out to examine how all the emissions of concern, except CO2, can be controlled from an existing power plant. This component will evaluate the costs to control all air emissions except CO2 for a commercial scale retrofit. The design goals are: a) control ofNOx & SO2; b) control of particulates, including PM10 & PM2.5; and c) control of mercury and other air toxics. This knowledge then enables the net cost of CO2 removal to be determined by comparison with the process feasibility research studies that include all air emissions and CO2. This will provide a sounder basis for estimating the true additional costs for CO2 extraction in a regime where all other emissions must be controlled. Following completion of these studies, a decision will be made to select the technology to be used for the retrofit demonstration project as well as the site for the project. A proposal for the design and construction of a project to convert an existing power plant to demonstrate the retrofitting of the selected technology will be prepared.

New Plant Case With continuing high natural gas prices anticipated over the next few years, it is essential to develop and demonstrate new plant, advanced coal technologies that can meet all existing and anticipated environmental constraints. This part of the Phase I scope reviews available new plant technologies, selecting the most appropriate for use in a demonstration project. Technology options for new plant concepts have been reviewed in a pre-screening study in 2001. Technologies including supercritical pulverized coal, ultra-supercritical pulverized coal, pressurized fluidized bed combustion, integrated gasification combined cycles, and advanced gasification options were reviewed together with options to control all emissions, including CO2, down to low levels. Developing technologies, such as the Los Alamos National Laboratory's hydro-gasification with CO2 sequestration in serpentine mineral (being developed by the Zero Emission Coal Alliance, ZECA) were included, as well as other advanced gasification options. Based on the results of the technology review, detailed evaluations are being carried out to determine performance and costs allowing the best option to be selected for the new technology demonstration. Alternative sites for the demonstration are also being investigated and a preliminary assessment of the environmental issues is being carried out. The results of the studies will be summarized in a report that will recommend the technology and site to be used for the

1049 demonstration project. Candidate sites for a full-scale demonstration project will be evaluated and an implementation concept for the demonstration project developed.

C02 ManagementStudy Finally, altemative options for handling the CO2 extracted from the commercial scale and demonstration plants are being evaluated. Options include Enhanced Oil Recovery (EOR), Enhanced Coal-Bed Methane (ECBM) and sequestration in saline aquifers. This work is coordinated with other activities in western Canada on EOR and ECBM, with work in Nova Scotia on ECBM, and in Ontario on depleted oil reservoirs and aquifers. Measurement and monitoring requirements will be evaluated to ensure that amounts sequestered can be quantified. CO2 infrastructure requirements to make these options viable are being evaluated with regard to transportation, temporary storage, and recycling from EOR or ECBM projects. A final report will be prepared summarizing the work carried out. Candidate sites for a full-scale demonstration project will be evaluated and an implementation concept for the demonstration project developed, taking into account the plant's operational status and the need to minimize plant outages. PROJECT STATUS

As in most public-privately funded projects of this nature, considerable effort is required at the start to get the funding in place. This project is no exception, and much of the effort over the first year was in working with our federal and provincial energy departments in preparing proposals, discussing plans, and coordinating work plans. The project now has confirmed funding from the provinces of Alberta and Saskatchewan, and has confirmed federal support. All our private sector partners have confirmed their participation. Since project and organization inception many parties, national and international, have expressed interest in participating. CCPC has welcomed this interest and these additions. Both EPRI and IEA (through the Greenhouse Gas R&D programme and the Clean Coal Centre) have joined the CCPC in 2002 as full industrial participants. The initial study, to screen technology options for both retrofit and new technology cases, was completed in 2001 and terms of reference for detailed assessments of emission control technologies and evaluation of CO2 disposal options have been prepared and contracts awarded. It is expected that the detailed assessment of retrofit technologies will be completed by early 2003.

CONCLUSIONS Power generators using coal-fired generation see an array of new emissions regulations approaching in the next few years. There is an urgent need to understand and evaluate the ability for advanced combustion and emissions control technologies to mitigate the environmental impact of coalderived power generation before committing the significant capital investment necessary to construct the necessary plant. The Canadian Clean Power Coalition is one such response. The participants anticipate that the results of the studies just now being carried out will make a significant contribution to the understanding of the control of air emissions, including CO2, from the generation of power from coal.

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1051

AN 865 M W LIGNITE FIRED CO2 FREE P O W E R P L A N T - A T E C H N I C A L FEASIBILITY STUDY

Klas Andersson 1, Henrik Birkestad 1, Peter Maksinen l, Filip Johnsson Lyngfelt 1

1, Lars Str6mberg l, 2, Anders

~Department of Energy Conversion, Chalmers University of Technology, SE-412 96 G6teborg, Sweden 2 Vattenfall AB, SE-162 87 Stockholm

ABSTRACT This work applies an O2/COa concept to commercial data from an 865 MWe lignite fired reference power plant and large air separation units (ASU). The aim of the study is to identify essential components and energy streams of the two processes and investigate the possibilities for process integration. A detailed design of the flue gas treatment before transportation of the separated carbon dioxide is also proposed. The sulphur dioxide can be sequestered together with the carbon dioxide, provided that the gas is dry, and, consequently, there is no need for a desulphurising unit. Since the investment cost of an ASU is slightly lower than for the desulphurising unit, the investment cost of the O2/CO2 plant will be slightly lower than for the reference plant. With all identified integration possibilities the net electrical efficiency becomes 34.3%, which is a reduction by 8.3 percent units compared to the reference plant.

INTRODUCTION Previous studies have shown that the O2/CO2 process is a competitive alternative for CO2 capture in power plants, e.g. [ 1]. O2/CO2 combustion involves burning the fuel in an atmosphere of oxygen and recycled flue gas instead of in air. The mixed flow of oxygen and recycled flue gas is fed to the boiler together with the fuel, which is burnt as in a conventional plant. Typically 70-80% of the flue gas is recycled from down stream the economizer and mixed with new oxygen. The remaining part of the flue gas is cleaned, compressed and later transported to storage or to another application. Studies on O2/CO2 combustion have mainly concerned emissions and combustion behaviour (e.g. [2], [3]) together with overall process studies (e.g. [4], [1]). Instead, this work combines a comprehensive study of the flue gas treatment together with integration possibilities of the O2/CO2 process, resulting in a proposal for an overall process layout (Figure 1). Thus, this work applies a lignite fired O2/CO2 combustion process to commercial process data in order to identify possible problems and to obtain design requirements under conditions as real as possible. Although an existing reference power plant forms the basis of the work, the purpose of this study is not primarily directed towards re-powering of existing power plants, but to identify limitations and possibilities for new O2/CO2 power plants. This paper gives a brief outline of the process obtained with details given elsewhere ([5], [6]).

METHOD The 2x865 MW lignite-fired Lippendorf power plant is used as reference in this study. This is a state of the art plant with a plant net (electrical) efficiency of 42.6% and with a district heating capacity of 2x115 MW. To minimize the need of redesign of burners, convection surfaces etc, an air like mixture of 20 vol.% oxygen and 80 vol.% recycled flue gas is chosen. This facilitates a direct comparison with the reference

1052

plant with respect to equipment and mass flows. Thus, for the O2/CO2 concept studied, the plant design and flue gas mass flow before recirculation are assumed identical with the reference plant, if not otherwise stated. Process data and schemes were obtained directly from the plant owner (VEAG). Based on these data, a process evaluation was carried out in order to identify new components needed as well as components that can be excluded for the O2/CO2 scheme. The process data of the ASU is taken from a plant, producing 50 000 mn 3 o x y g e n per hour, which was then scaled up with respect to investment costs and process data. Different compressor configurations for the ASU, as well as for the flue gas compression, were analyzed with Refcalc (Refrigerant Calculator) [7]. ChemCad (v5.0) [8], which uses electrolyte reactions together with a thermodynamic model, has been used to simulate the flue gas condensation. As a comparison to the latter calculations, and to determine the condensation energy, Hysys (v4.2) [9] was used. In the proposed scheme, NOx is separated in a liquid/gas separator since it assumed not to be soluble in CO2. RESULTS OF PROCESS EVALUATION Figure 1 gives a principal process scheme and component list of the lignite fired O2/CO2 plant as obtained from the process evaluation, using the Lippendorf reference plant. Thus, the three main parts of the plant are the ASU (A), the power plant (B) and the flue gas treatment pass (C) with the essential features and components described below following the numbering of Figure 1. :.............................................................................................................................................

I-1-3-1

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unit

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" 21. Subcooler '..-.~.'.'.'...~--.~---'.--.-'_.-..-'_'..-.'.ZZZZZZ33Z~Z~.~22. High pressure pump ~Oz [ ~ N

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.....

24. IP Steam turbine 25. LP Steam turbine 26. Condenser

r ~ ~

27. Cooling tower

02 :

r4]

% ~

.

(~

--

~

28. District heating 29. Feed water preheater 30. Feed water preheater 31. Optional heater, district heat 32. Nitrogen heater

Air inlet , ................................................................................................

l ~ ............................... J

Figure 1. Overall process layout for the O2/CO2 plant proposed in this work. The plant scheme is made with the Lippendorf plant as reference. A. Air separation unit, B. Power plant, C. Flue gas treatment pass.

1053

Air Separation Unit (A) The ASU is based on cryogenic air separation, which is the only separation technique which can provide the oxygen flows required in the present application [ 10]. The oxygen production rate in the plant is 451 100 mn3/h corresponding to an air flow through the compressor of 2 155 050 m,3/h. With an isentropic efficiency of 83% and with cooling provided from the plant cooling tower the power consumption of the compressor is 149 MW (tin=16°C, tout=22°C, year average). An oxygen purity of 95% is selected as the most favorable, since it gives an exchange rate (oxygen to oxygen) of 1.0 without nitrogen in the product gas. Thus, for oxygen purities lower than 95%, the oxygen contains nitrogen in addition to the impurity of argon. The compressor (1) in the ASU, with intercooling in four steps, operates between ambient temperature and about 60°C. Without intercooling an air temperature of about 210°C is obtained, giving a heat surplus of 140 MW, which could be used for feed water preheating or district heating. However, this would result in a significant decrease in compressor efficiency, corresponding to around 30 MW loss of power. Thus, this alternative is not chosen. The cooling of both the CO2 compressors (15) and (17) and the air compressor is carried out with cooling water from the plant cooling tower (27). The CO2 condensation also requires cooling water from the cooling tower, which means that the cooling capacity of these must increase with 25% compared to the reference plant. To minimize losses in power transmission to the air and CO2 compressors, these can be powered directly with steam turbines on a joint shaft. However, the main steam turbine shaft cannot be used for this purpose, since it would cause problems both in the compressor units, such as surge at the start up, and in the shaft itself because of too large thermal motions in axial direction. The extra investment cost of the separate powering of the compressors is to be compared with the power saving corresponding to about 6 MW. The heat required in the molecular sieves (5) are provided by the nitrogen heater (32), which exchanges heat from the flue gas with a minimum temperature of 200°C. Cooling, 20 MW of about 8°C, can be generated in the evaporative cooler (4) that can be used in the flue gas treatment for sub cooling of the carbon dioxide (21). Power Plant (B) Table 1 shows the mass and volume flows for the 865 MW O2/CO2 power plant. The flue gas temperature after the economizer (11) in the O2/CO2 power plant is assumed to be the same as for the reference plant; 340°C. The flame temperature in the O2/CO2 power plant will be lower than for conventional combustion with the given concentration of oxygen, 20 vol.%, because of the higher specific heating value of the flue gases compared to conventional combustion, [2]. On the other hand, the temperature decrease of the flue gas in the super heater and economizer will be lower than in the reference boiler, comparing the same steam flow as in the reference boiler. In addition to this, the radiative properties of the flue gas will change, which makes an accurate estimation of the flue gas temperature difficult. Still, the above assumption should be reasonable. Heat from the flue gas cooling and condensation, between 340°C and 20°C, can be used for feed water preheating and district heating, producing an extra power output of almost 16 MW and a heat surplus of 82 MW. TABLE 1. DESIGN COMPOSITIONOF FLUE GAS DURINGO2/CO2COMBUSTION Components

kg/s

wt%

H20 CO2 SO2 02

142.7 205.4 5.4 5.2 0.5 11.8 371.1

38.4 55.3 1.5 1.4 0.2 3.2 100

m3./s

vol%

179.8 105.3 1.9 3.7 0.4 6.7 297.8

60.4 35.4 0.6 1.2 0.2 2.2 100

_ .

N2 Ar Total

1054 Flue Gas Treatment Pass ( 0

The flue gas treatment basically involves the removal of water and non-condensable gases. Figure 2 shows the flue gas composition and emissions to air and sewer throughout the treatment steps. Each box displays the different gas emissions as weight percent of the total emission from each component. A complete dehydration of the flue gas is important since it will reduce the mass flow, inhibit corrosion and hydrate precipitation. If the flue gas is dehydrated to a dew point five degrees below the temperature required for transport conditions, the sulphur dioxide will behave almost as carbon dioxide and the two gases will not cause any corrosion problems. The gas must be dehydrated before reaching the high-pressure steps in the compression to make the compression of the gas mixture possible [11]. Carbon dioxide alone can be corrosive in the presence of water and cause sweet corrosion. What happens is that water vapour in the gas can form solid ice-like crystals called gas hydrates. The hydrates are formed when water "encages" gas molecules smaller than 1.0 nm (which is the case for both carbon dioxide and sulphur dioxide) at low temperatures and elevated pressures (below 25°C and above 15 bar). Various mechanisms for the carbon dioxide corrosion process have been proposed, which all involve either carbonic acid or bicarbonate ion formed when carbon dioxide is dissolved in water. Also in this case dehydration to a dew point five degrees below the transport temperature is sufficient to avoid the problem [12], since dry carbon dioxide is not corrosive at temperatures below 400°C [ 13]. The maximum water content in the gas prior to compression should therefore not exceed 60 to 100 mg/m3, [ 14]. A general rule for pipeline transportation in presence of water is that serious corrosion can be expected if the partial pressure of carbon dioxide exceeds 2 bar [ 15]. In the process chosen the gas is dehydrated in two steps. The first is in a traditional flue gas condenser (13) where most of the water is removed, together with remaining particles (sulphur trioxide etc). The second dehydration step is the Tri Ethylene Glycol (TEG) unit (16), which will remove the remaining water down to a value of 60 mg/m3n, corresponding to a dew point of-5°C at 100 bar in the transmission gas.

Jkg/h

io,~

kg/h

Iwt% I

1739578 1~,61

wt%

kg/h

wW,

kwh

kg/h

wt%

wt%

~

735,,, 00,~,

~

7~,12,133

~

7~195,135

~

7~5,770

ISO= 119513 11.471

iso 2

16967 2.07

so 2

16593 2.05

so I

16588 2.65

so 2

16586 2.21

i.,0

=,20

8787 10,

.,0

2~

oo3

.20

24

~0

24

0.26

N=+NO 2083 ~1

151~, p.,31

IN2+NOI2083

......... 102

I"

1~2

10.18 ]

141'~' 1°,71 I

Irot~ 11~59521

!

N2+NO12083 0,25

13.15 ~...... 02

1~2

Ni+NO 2083

5.11 ................... 02

~1

,,

~417~, 1.15

,,

Tot~

817817

TOt= 8 0 ~ 5

i

i

'

°

. . . . ."

0.~

5,17 ............ o,

41,8, 118

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~,

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Tot=

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' I

.. . . . . . . . . . . . . . . . . . . . .. . .. . .. . ... ... . .. . .. . ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

.."

".. . . . . t .

~2~ '~---~

Removed from Flue Gas Stream:

kg/h wt% C~ 782 0,15 SOz 2546 0.50 H20 504807 99,35 Nz'H~C)0 10,00 02 0 ,0,00 A.," 0 0,00 Total 508135

kg~l CO~ 382 SOz 374 H=O 8535 N2+NO10 Oz l0 A,," I0 Total 9291

To Sewer

To Sewer

wt% 4,11 4,03 91,86 0,00 0,00 0.00

o~

N2+NO 0 0.00 0 0.00 ...... ,"'- ht 0 0,00 "" " ' Total 751195

02

kg/h C.~ 217 SOz 5 I"~O 228 N2+NO 0 02 0 Ar 0 Total 450 To Atmosphere

wW, 48,22 1,11 50,67i 0,00 0,00 0,00

..

. .........

kg/h CO~ 3610 SO= 2 HzO 0 Nz,H~IO2083 Oz 9401 Ar 41784 Total 56880

wt% 6.35 0,00 0,00 3,66 16,53 73,46

To Atmosphere

Figure 2. Mass flows [kg/h] and concentrations (weight percent of the total emission from each component) through the flue gas treatment steps.

1055 Since the TEG requires a pressure of 30 bar to be efficient, a compressor step with intercooling is installed before the TEG. Some water is separated in the cooling steps in the compressor. To reduce the power consumption of the flue gas compressors, compression up to the transport pressure is carried out by a high pressure pump (22). This, since the pressure should only be increased sufficiently to transfer the flue gas (mostly carbon dioxide) into a liquid state at a reasonable cost. The first compressor step raises the pressure from 1 bar to 30 bar, which is the inlet pressure of the TEG. The flue gas is then compressed in the second step from 30 bar to 58 bar. At a pressure of 58 bar, the carbon dioxide and sulphur dioxide will, if cooled to 20°C, liquefy and 20°C is the temperature of the main cooling system. When the carbon dioxide is liquefied it is possible to use a high pressure pump for the last pressure raise up to 100 bar before transportation to the injection site.

PLANT E F F I C I E N C Y AND

EMISSIONS

Figure 3 shows a sankey diagram illustrating the energy losses in the O2/CO2 plant based on one of the blocks (865 MW) of the reference plant. The net electrical efficiency of the plant becomes 34.3%. An extra heat production of 82 MW per block, not included in the sankey, is a product from the flue gas condensation, which could be used in the existing district heating system of 115 MW per block.

- -

B;il026Power MW

~ ~"~'~

Internalelectricity dmd

\\ ~ . . ~ C02 compression \ """'ASU 71 MW-3.5% [ 137MW - 6.7%

~1 ~z

Figure 3.

-~--~

]~ Powerproduction \ 696 MW - 34.3% / without losses - 933MW /extra power output - 16 MW ] / e x t r a heat production - 82 MW

j'/

Condenser 1093MW - 54.0%

Sankey diagram of the O2/CO2power process.

Table 2 summarizes emissions to air from the O2/CO2-fired plant obtained in the present study and compares these with those of the reference plant. The combustion conditions are considered to be stoichiometric with an oxygen excess of 1.5% on a dry basis. The SOx and CO2 emissions are leakage flows from (13), (16) and (20) in the flue gas treatment as shown in Figure 2. Estimation on NOx formation is based on the results in [2]. NOx is emitted in the gas/liquid separator (20) since it is not soluble in the CO2/SO2 mixture. It should be noted that the emitted NOx has a considerably high concentration. To attain even lower NOx emissions this component arrangement could therefore be well suited for a NOx catalyst. Total emissions [kg/h] are calculated for 2x865 MW, corresponding to both blocks of the reference plant. TABLE 2. COMPARISON OF ESTIMATED EMISSIONSTO THE ATMOSPHERE BETWEEN THE REFERENCE PLANT AND THE O2/CO2 POWER PLANT Emissions to air

SOx NOx CO2 Dust

Reference plant < 350 mg/mn 3 < 145 mg/mr, 3 < 235 g / m , 3 < 2 m g / m . :~

< 2,230 kg/h < 920 kg/h < 1,480 tonnes/h < 12 kg/h

[

O2/CO2-plant < 6 mg/mn 3 < 141 mg/mn 3 < 4 g/m, 3 < 1 mg/mn 3

< 20 kg/h < 310 kg/h < 8 tonnes/h < 1 kg/h

1056 CONCLUSIONS This study proposes an overall process scheme of an 02/C02 plant (Figure 1) based on commercial data from existing plants. With all integration possibilities considered the net electrical efficiency becomes 34.3% which corresponds to a decrease by 8.3 percent units compared to the reference plant. The O2/CO2 plant can be considered as a more or less zero emission concept (Table 2). An almost complete dehydration of the flue gas is of great importance to avoid problems in the final flue gas treatment and in the transportation of the carbon dioxide. The investment costs of the flue gas treatment are lower than in the conventional case, mainly because there is no need for a desulphurising unit. Summing up the extra cost for the ASU and the extra cooling capacity needed (25% larger) the investment cost becomes approximately the same for the O2/CO~ plant as for the reference plant. In conclusion, by using commercial data from existing plants and components this study shows that 02/C02 combustion is a realistic and a near future option for CO2 reductions in the power sector with an avoidance cost of approximately $8 per tonne CO2 excluding transportation and injection costs. Cost data are taken from [5] and [6] with the lignite price set to $0.0040/kWh.

ACKNOWLEDGEMENT

This work was financed by the Swedish National Board for Energy Administration and Vattenfall AB. The supply of data by AGA and VEAG is greatly acknowledged.

REFERENCES

1.

2. 3. 4.

5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15.

Singh, D.J. et al. (2001) C02 Capture Options for an Existing Coal Fired Power Plant: Oe/COe recycle Combustion vs. Amine scrubbing. Presented at the first national conference on carbon sequestration. Washington, USA. Croiset, E., Tambimuthu K. and Palmer, A. (2000) Coal Combustion in O2/CO2 Mixtures Comparison with Air. Canadian Journal of Chemical Engineering. Vol.78, p 402-407. Kimura et al. (1995) The Characteristics of Pulverized Coal Combustion in 02/C02 Mixtures for CO2 Recovery. Energy Conversion Mgmt Vol. 36 No 6-9, p.805-808. Bolland, O. and Undrum, H. (1998) Removal of COefrom Gas Turbine Power Plants: Evaluation of Pre- and Postcombustion Methods, presented at the Fourth international Conference on Greenhouse Gas Control Technologies, Interlaken, Switzerland. Andersson, K. and Maksinen, P. (2002) Process Evaluation of C02 free Combustion in an Oe/C02 Power Plant, MSc Thesis, Chalmers University of Technology. Birkestad, H. (2002) Separation and Compression of C02 in an Oe/COe-fired Power Plant, MSc Thesis, Chalmers University of Technology. Refrigeration Utilities, Technical University of Denmark, 2000. ChemCad (v5.0), Chemstations Inc., Texas, USA. Hysys plant (v4.2), Hyprotech Ltd., Alberta, Canada. K~llstr6m, M. AGA, Private communication on cryogenic air separation process. Lindeberg, E. IKU Petroleum Research, Private communication on behavior of CO2 and SO2 mixtures. Fayed, A. (1983) COe Injection for Enhanced Oil Recovery Benefits from Improved Technology. Oil&Gas Journal p. 92-96. Kermani, M.B. and Smith, L.M. (1997) COE Corrosion Control in Oil and Gas Production. European federation of corrosion publication No. 23. London: The institution of materials. Sloan, E.D. (1998) Clathrate Hydrates of Natural Gases. Marcel Drekker Inc. New York, USA. Berry, W. (1983) How Carbon Dioxide Affects Corrosion of Pipeline. Oil&Gas Journal. March 21, p. 160-163.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1057

RECENT DEVELOPMENTS ON FLUE GAS CO2 RECOVERY TECHNOLOGY Tomio Mimura 1), Takashi Nojo 1), Masaki Iijima z), Takashi Yoshiyama 3), Hiroshi Tanaka 3) 1) Technical Research Center, The Kansai Electric Power Co., Inc. 11-20 Nakoji 3-chome, Amagasaki, Hyogo 661-0974, Japan 2) Mitsubishi Heavy Industries, Ltd. 3-1, Minatomirai 3-chome, Nishi-ku, Yokohama, Kanagawa 220-8401, Japan 3) Hiroshima Research & Development Center, Mitsubishi Heavy Industries, Ltd. 6-22, Kan-non-shinmachi 4-chome, Nishi-ku, Hiroshima 733-8553, Japan

ABSTRACT The Kansai Electric Power Co. Inc., and Mitsubishi Heavy Industries, Ltd. have been making continuous efforts to improve flue gas CO2 recovery technology. The recent improvements have been focused on the reduction of the initial costs and operation costs. The following are the recent main research and development items: • • •

Increase of flue gas velocity in the CO2 Absorber Reduction of the KP-1 packing weight Reduction of amine consumption

These items have been put to the test in the Nanko Power Station pilot plant and their performances have been confirmed. In addition to the above, development on new energy efficient solvents has been carried out. A new bench scale testing facility enabled very accurate measurement of the CO2 recovery energy consumption to be made; this was the same as that of the pilot plant and was used for the evaluation of new solvents. INTRODUCTION The Kansai Electric Power Co. (KEPCO) and Mitsubishi Heavy Industries, Ltd. (MHI) have been carrying out joint work on research and development of new technology for CO2 recovery from power plant boiler flue gas and gas turbine exhaust gas. From the results of this research and development work, an energy efficient solvent was developed and commercialized. The first commercial plant using this solvent has been operated since October 1999 in Malaysia. The performances of the commercial plant was disclosed in GHGT-5 in Australia. l) The recent research and development activities since the GHGT-5 disclosure are described in this paper.

1058

High Flue Gas Velocity Tests in the C02 Absorber KEPCO and MHI have jointly developed the KP-1 packing which has very low pressure loss under atmospheric flue gas conditions and very high gas and liquid contact efficiency. The Nanko power plant flue gas CO2 recovery pilot plant is designed to operate with 555 Nm3/H flue gas flow rate at the inlet of CO2 absorber. KP-1 is designed with a packing diameter of 320 mm and has under the normal operating conditions a flue gas velocity of 1.92 Nm/s and a pressure loss of 40 mm H20 through the CO2 absorption part (KP-1 packing part). KEPCO and MHI carried out higher flue gas velocity tests with the maximum allowable flue gas velocity of the existing pilot plant. A maximum flow rate of 950 Nm3/H was obtained at the inlet of the CO2 absorber and under this condition, the flue gas velocity at the inlet of CO2 absorber packing (KP-1) was 3.29 Nm/s. Stable operation with stable performance was confirmed under the 950 Nm3/H flue gas flow rate and no flooding was observed. Therefore, it is considered that for KP-1 packing, the flue gas velocity can be increased to more than 3.3 Nrn/s. The plant for this year is to replace the flue gas blower with a larger one and conduct higher flue gas velocity tests up to 4.0 Nm/s at the KP-1 packing inlet. Figure 1 shows the pressure loss through the CO2 absorber, under various flue gas velocities.

1000

< E r~ O

.1

• 100

10 ~ 100

I

/~ CO2 Absorption Part Pressure Loss

|

1000 Flue Gas Velocity (Nm3/H)

CO2 Absorber Total Pressure Loss

10000

Figure 1:CO2 Absorber Pressure Loss

1059 Figure 2 shows C02 recovery energy dependent upon flue gas velocity at a C02 content in flue gas of 6.0 vol.%. Using this pilot plant operational data, C02 recovery energy or C02 absorption efficiency was not affected by flue gas velocity in the C02 absorber. ©

1000 900 800 | | I

i

700

! | |

g d

600

d

500

. . . . . . . .

t. . . . . . . . !

,~ . . . . . . . . ! | !

2

1

3

4

CO2Absorber Outlet Flue Gas Velocity(m/s) Figure 2:CO2 Recovery Energy New KP-1 Packing The KP-1 packing is ideally shaped for contact with flue gas under atmospheric conditions and liquid (solvent) flow in parallel. Due to this shape, flue gas pressure loss through KP-1 is very low and therefore the flue gas velocity can be increased with a reduction of CO2 absorber tower diameter at the same time. The test results of KP-1 packing were disclosed in ICCDR-2 held in Kyoto 1994. However, as the price of tower packings, such as random packing and structure packing, have been reduced recently, the KP-1 packing has to compete with these conventional packing on a cost base. Therefore, efforts to reduce the weight and number of parts of the packing in order to compete with conventional packing have been made, and as a result, the new KP-1 packing has been developed, composed of an uneven surface lattice plate structure, similar to KP- 1 packing. The new KP-1 was manufactured and installed in the Nanko pilot plant and subjected to the performance tests. The test results of the new KP-1 packing was similar to the previous KP-1 packing in terms of C02 absorption efficiency and pressure loss through the packing. Please refer to Figure-3. • : PreviousKP-1 Packing O : NewKP-1 Packing 00 ~-~ .o

80 60 40

8

20 0 0

50

100

150

200

Steam Flow Rate [kg/h]

Figure 3"

CO2 Absorption Efficiency of previous KP-1 Packing and New KP-1 Packing

1060 A study is now being made for the mass manufacturing of the new KP-1 packing in order to compete with the cost of the conventional packing.

Reduction in Amine Consumption For CO2 recovery from atmospheric flue gas with the chemical absorption method, amine loss is relatively large. In the case of monoethanol amine (MEA), amine consumption is usually as much as 2kg/Ton CO2 recovered. The reasons for high amine consumption by the MEA process are high degradation of MEA by itself and high outflow of MEA from CO2 absorber. KEPCO and MHI have developed the KS-1 solvent which is already applied for commercial use and its amine consumption is around 0.35 kg/Ton CO2 recovered. This consumption is about 1/6 of the MEA solvent, however, it is still high compared with the high-pressure natural gas or synthesis gas CO2 removal processes. From detailed investigations into the causes of amine losses, it was understood that a combination of decomposition, vapor loss and mist loss were responsible. Therefore, various mechanical devices and operational conditions were tested that resulted in reduced amine consumption of about 0.1--0.2 kg/Ton CO2 recovered.

TABLE 1 AMINE LOSS DEPEND UPON FLUE GAS TEMPERATURE WITH SPECIAL MECHANICAL DEVICES Absorber Inlet Temperature

Average Amine Loss

35 (°C)

0.06 (kg/Ton CO2)

40 (°C)

0.16 (kg/Ton CO2)

46 (°C)

0.20 (kg/Ton CO2)

New Bench Scale Test Facility In order to evaluate new solvents quickly and accurately for flue gas CO2 recovery, a new bench scale test facility was designed and constructed in KEPCO Technical Research Center. The main specifications are indicated in Table 2. TABLE 2 SPECIFICATION OF BENCH SCALE TEST FACILITY Gas flow rate

Max. 7 m3/h

Liquid flow rate

Max. 30x10 -3 m3/h

Absorber height

2.3 m x 2 Tower (series)

Absorber I.D.

100 mm

Stripper height

1.8 m

Stripper I.D.

100 mm

Washing water tower height

0.5 m

Washing water tower I.D.

100 mm

Unit Size

4.7 m L x 1.4mw x 2.5mH

1061 Although the capacity of this bench scale test facility is small, the C02 absorption and stripping efficiencies are designed to be the same as that of the Nanko Power station pilot plant; this was accomplished through the installation of special heat traces to minimize the heat loss. Details are shown in Figure-4. Insulation

Stripper Shell

Copper Plate ~ _ .

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

Heat Trace/ / V / / , Q / / / / ~ Insulation/

/

Iron Cover P l a i ! /

Figure 4: Stripping Tower Heat Trace Due to the installation of the above-shown heat trace, CO2 recovery energy requirements of the bench scale test facility is the same as that of the pilot plant test results. By using this bench scale test facility, evaluation tests of the new solvents can be made accurately and speedily. REFERENCES 1)

Mimura T., et al. 2000 Greenhouse Gas Control Technologies, Caims Australia P. 138--142.

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1063

I G C C - THE BEST CHOICE FOR PRODUCING LOW-COz POWER G. Haupt ~, G. Zimmermann ~, R. Pruschek 2 and G. Oeljeklaus3 Siemens AG Power Generation, 91050 Erlangen, Germany 2 Independent Consultant, 70839 Gerlingen, Germany 3 University of Essen, 45141 Essen, Germany

ABSTRACT This paper reports the results of two comprehensive studies on CO2 reduction measures using integrated gasification combined cycle (IGCC) technology. The first part deals with reduced CO2 production by efficient use of energy resulting in an advanced coal-based IGCC concept with 51.5 % net efficiency (LHV). The second part provides IGCC solutions to reduce the CO2 emission to the atmosphere via CO shift and CO2 separation followed by coproduction of methanol/synthetic gasoline as an interim disposal option. An economic analysis ends up with acceptable 6 %age points efficiency loss due to CO2 removal and production costs for the liquid transportation fuels around present gasoline market prices including tax.

INTRODUCTION

: : : :: ~:i'¸::i~.... ~: .... ~ l t t t l l l l n m ~ l L ~ t ~ ~ ~

:

: :

]

~

~~oital~Of Oi|Fields: ~ :'C~mi~llndustryI ::

Figure 1: Potential steps for C02 reduction In view of recent and future developments in the field of IGCC power plants expressed by increasing overall efficiencies, a significant CO2 emissions reduction becomes possible solely by replacing old and low-efficient pulverized-coal-fired (PCF) power stations with advanced IGCC plants. If CO2 emission has to be reduced by 60 or even 80 % and coal has to be used under such circumstances, an extensive separation

1064 of CO2 from the power plant process could be of increasing importance as an option. However, any CO2 removal measure will unavoidably and significantly reduce the station efficiency and power output. Figure 1 provides some kind of systematic overview of measures, methods to verify them and disposal strategies. STATUS OF THE ADVANCED IGCC POWER PLANT IGCC technology must be measured against the most advanced PCF power stations. A plant of this type with a design efficiency of 47 % has been commissioned by ELSAMPROJEKT in Aalborg/Denmark (Nordjyllandsvaerket), on which the ambient conditions for this study are based. The coal selected is Pittsburgh No. 8, a typical imported hard coal which can be readily gasified. With a target efficiency of considerably more than 50 %, it is assumed that the power plant will be operated primarily at base load. The plant is designed in a single train and has a capacity of roughly 450 MW, corresponding to the gas turbine-generator used. The primary design objective is efficient operation with coal. Operation with natural gas as a secondary fuel, especially for start-up, plays only a secondary role with regard to efficiency. Figure 2 shows a simplified flowsheet of the advanced IGCC concept as a result of plant optimization:

co~

' ~

i~ P , ~ . o .

Ii Ii

T ........ ' ~ - ~-~ ~ i ~ Turbine I I

III

Ill "-" "r,.,

w

Saturato HP _ ~ Reheat. \

Gasifier

\ ,

I Slag

- i 1 ~ , ~ ~ - [ , , o ,•

" I~Cl~n~'~

QuenChWas~e~ w.... Gas Treatment

r~

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,,

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Saturationl J

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r S,oa~ I r

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J

I~°'n"P-~

(~ (~ Cond22s I (~ (~I (~BFT'WlTank~t~ O2 N2 HeatR..... ryl Z~ / ~ ' ate

I

Figure 2: Advanced IGCC plant based on a Siemens Model V94.3A gas turbine-generator Table 1 gives an overview of significant plant data including overall efficiency. Nearly two thirds of auxiliary electric power requirement is accounted for by gas generation. Primary loads are the compressors for the main products from air separation unit (ASU), particularly for the Nz fraction. Further significant auxiliary loads are the main feedwater pumps. The performance of the advanced IGCC concept includes a significant reduction of gaseous emissions and solid byproducts compared with today's most advanced PCF power plants, in particular compared with a standard PC boiler, based on the same coal. The emission of CO2, for instance, is reduced by approx. 10 %, and even by approx. 25 % for standard PC boilers showing efficiencies in the range of 38-40 %. A specific capital investment ofUS$1,100/kW results for the advanced IGCC power station from bidding information prepared by involved manufacturers. This reasonable price level could be achieved through the tremendous increase in net power output with nearly the same absolute capital investment as for IGCC plants designed previously. Based on the advanced IGCC plant efficiency of 51.5 % determined in this development potential study, levelised electricity generating costs of 46 mills/kWh as a typical value result, which are approx. 10 % less than with today's most advanced PCF steam power plants, if a fuel price of

1065

US$1.5/GJ (LHV) and 6,500 full-load hours/yr are assumed. In the future, the specific capital investment of IGCC plants optimised further could break the US$1,000/kW barrier [ 1]. TABLE 1 SALIENT DATA RESULTING FROM OVERALL CYCLE CALCULATIONS Heat input (LHV): Coal (2545 tpd) Natural gas (for coal preparation) Total Gross power output: Gas turboset Steam turboset Total Gross efficiency (LHV) Power consumption: Gas island Combined cycle General facilities Total Net power output Net efficiency (LHV)

874.8 MJ/s 0.9 MJ/s 875.7 MJ/s 302.3 MW 177.3 MW 479.6 MW 54.8 % 19.9 MW

7.9 MW 1.0 MW 28.8 MW 450.8 MW 51.5 %

I G C C S T A T I O N S W I T H CO2 R E M O V A L If CO2 reductions solely based on efficiency improvement measures as mentioned above are not sufficient, CO2 can be removed to a great extent and very effectively from IGCC stations. A pre-basic design was prepared in a preceding study including a water gas shift reactor system which is able to convert CO and H20 into CO2 and H2. Sulfur compounds as well as CO2 can then be removed simultaneously, for instance by Rectisol wash. With regard to economic aspects, around 90 % of CO2 are removed and extracted as a gas slightly beyond atmospheric pressure which results in 6 %age points lower net efficiency and 10 % higher investment. Table 2 compares salient data of the IGCC station with CO2 removal and a conventional IGCC plant as reference case: TABLE 2 SALIENT DATA OF THE REFERENCE CASE AND THE IGCC STATION WITH

CO2 emission (stack) absolute specific Coal heat input Gross power output gas turbine steam turbine Auxiliary power requirement Share of gas treatment Net power output Net efficiency

Reference case 72.9 kg/s 0.69 kg/kWh 811.2 MJ/s 238.8 MW 177.7 MW 37.8 MW 3 % 378.6 MW 46.7 %

C02 REMOVAL

With CO2 removal 8.4 kg/s 0.09 kg/kWh 876.1 MJ/s 234.1 MW 170.2 MW 49.1 MW 24 % 355.2 MW 40.5 %

IGCC WITH COPRODUCTION OF ELECTRICITY AND METHANOL The recovered C02 fraction from the IGCC station described above has to be either disposed of or utilized further. One of the possibilities to use CO2 removed from power plants is the substitution of other feedstocks which could contribute to the reduction of global CO2 emissions. However, to achieve considerable emissions reduction, large quantities of chemical products would have to be required by the market. Annual world-wide CO2 emissions from energetic use of fossil fuels amount to some 20 Gt,

1066 corresponding to a carbon inventory of some 6 Gt. About 20 % result from electric power generation in coal-fired stations representing 1.2 Gt C in the fuel. In contrast, carbon used world-wide for raw materials of the chemical industry such as ethylene, propylene, methanol amounts to only 0.09 Gt C. These figures show that only a small fraction of the CO2 emitted by power plants would be necessary for the production of chemicals, which would not justify demonstration of CO2 reuse technology on technical scale. The only potential worth analyzing more in detail is replacing mineral-oil-based fuels in the transportation sector with methanol, as the major part of the carbon requirement of 1.2 Gt could be provided by CO2 from power plants. For this purpose, CO2 and H2 are converted into the liquid energy carrier methanol which can be stored more easily and which is therefore more suitable for today's transportation sector infrastructure. Bound carbon would then be ultimately released into atmosphere by subsequent combustion. Required H2 has of course to be produced from carbon-free energy sources, for instance by hydropower-driven water electrolysis, to reduce CO2 emissions of the overall system. However, production of methanol using CO2 from power plants can only be justified as long as the problem of storage and transport of hydrogen is not satisfactorily solved on a large scale and for everyone's daily use. Figure 3 shows how a CO2-based methanol synthesis plant, which is not the conventional case, can be integrated into an IGCC station. Hydrogen as a reactant to be imported is assumed to be available at plant limits at 100 % purity and 66 bar. Methanol can be converted further to synthetic gasoline via MTG (methanol to gasoline) process of Mobil Oil.

Figure 3: IGCC plant with CO shift, CO2 removal and utilization for methanol synthesis Salient data of the coproduction system: • • • • •

Coal input 2300 Hydrogen input 780 CO2 (intermediate product) 5500 Methanol product (>99.85 % wt) 3800 Total gross power output 354 Gas turbine 234 Steam turbine 120 • Total net power output 310 • Relative overall energy yield 67

tonnes/d tonnes/d tonnes/d tonnes/d MW MW MW MW %

1067 ECONOMICAL CONSIDERATIONS The specific investment of the IGCC power plant with CO shift and removal of CO2 as a slightly compressed gas was calculated to be 20 % higher than that of the reference IGCC station. Including CO2 liquefaction would cause around 40 % higher specific investment. Electricity generating costs would rise by around 20 % and 50 %, respectively. Total plant investment costs for coproduction of power and methanol/gasoline comprise costs of IGCC station with CO2 removal and of methanol synthesis/MTG plant. Specific costs of coproduced methanol/gasoline strongly depend on hydrogen price. CO2 from IGCC power plants could be considered as for free in case extra costs caused by CO2 removal are allocated to generating costs. In the present case, a simplified cost calculation model has been used which is solely based on investment costs for the additional equipment of the methanol system and hydrogen production costs depending on the different sources. Taking into account that the CO2 stream has been provided by adding a removal plant to a conventional IGCC station, the specific methanol production costs estimated as described above are penalized by the resulting higher generating costs depending on the ratio of electricity and coproduced methanol/gasoline. 0.200 0.175 0.150 0.125 0.100 ~,,,,,,~-

Gasoline Market Price (incl. tax)

~"

b

0.075 0.050 0.025 0.000 0.03

0.04

0.05

0.06

0.07

Hydrogen

0.08

Price

[$/kW

0.09

0.10

0.11

0.12

h]

Figure 4: Methanol/gasoline generation costs vs. hydrogen price In Figure 4, methanol/gasoline production costs are plotted against hydrogen price. General target should be that methanol costs are below market price and gasoline costs are below market price including tax. The diagram shows that even when using very cheap hydrogen sources down to 0.02 US$/kWh, methanol from this coproduction is not competitive. Synthetic gasoline as secondary product is only "profitable" if based on hydrogen sources below 0.05 US$/kWh and not charged with tax. It should be pointed out, however, that all these market prices are subject to permanent changes on the world market. Conditions can become inverted very fast and such an economic analysis should be understood as some kind of snapshot [2]. COMPARATIVE CO2 EMISSIONS Finally, the described coproduction process and separate generation of electric power and methanol, which should be used for transportation in correspondingly modified gasoline engines, have to be compared regarding the total CO2 output. Primary energy sources are then coal and a CO2-free energy source such as hydropower also supplying hydrogen via water electrolysis. In Figure 5, primary energy requirements and accompanying CO2 emissions for different selected cases of interest, which are shortly described below, are compared. It turns out that only power generation in'a conventional IGCC station and parallel use of cars fuelled with hydrogen from a CO2-free source ("Case 2") show a slightly lower CO/output than the IGCC plant under consideration with coproduction of electric power and methanol as substitute for oil-based gasoline ("Base Case").

1068

~ eOi~s IGCX346.7 % H~m R:~er P~nt ~',~

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Otto O~de Engim Gasciin~ 2 ~

t,/, //

M k ~ l h a r d 30o,,,1

Ot to G a ~ i n e

"// ,/z //,

( R ~ n e ~ ) ~0%

Coal to MeUlar'~153% (Cor~. ~

•/ /

0.3~ kg O::~g Gmoine

I~dro P o ~ r 1746IMkN

~ 1751i~lys

17.'51

OO ....

i

x/xz ..v,. xzxz /\/x

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o

~

i

~

k-,,,-,r/A ~., Cutl~t::~0i~en t~E~C~lGCX:;Oesign

-tGCX3 -t-k~F~ ( ~

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~

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"-. -tGCX2 - t - t y ~ t : : ~ l : : ~ -F:~ef~ -~.r,,,~ ( ~

-tG0C -Cw~.t~ (C~

(Case I --- Bla~e CeBe)

Figure 5: Primary energy demand and CO2 emission for combined electrical and automotive power Case 1: Coal-based IGCC station with coproduction of electric power and methanol Case 2: Coal-based IGCC station & hydropower-based hydrogen plant Case 3: Hydropower station & oil-refinery-based gasoline plant Case 4: Coal-based IGCC station & oil-refinery-based gasoline plant Case 5: Hydropower station & coal-based conventional methanol synthesis plant Case 6: Coal-based IGCC station & coal-based conventional methanol synthesis plant

CONCLUSIONS IGCC stations represent the best choice for producing low-CO2 power [3]: either by their outstanding efficiency, which is the second highest after future coal-based solid oxide fuel cell power plants, or by the unique option to separate CO2 from shifted synthesis gas with present technology. The CO2 removed can then, for instance, be dumped in the deep sea or pressed into underground aquifers. Alternatively, CO2 from fossil fired power stations can be used as a feedstock for chemical syntheses reusing the C atom of COl. In case of producing methanol/synthetic gasoline from this C O 2 and H2 from a CO2-free source, significant quantities of CO2 can be utilized. In this way, the overall CO2 emission can be reduced by substituting oilbased fuels for the traffic sector today by using the CO2 captured in the IGCC power station. Depending on the particular hydrogen sources, coproduction of electricity and methanol/gasoline in combination with IGCC stations ends up with production costs around present gasoline market prices including tax. ACKNOWLEDGEMENT These studies were supported in part by the European Commission within the framework of the JOULE II and JOULE III programmes. REFERENCES 1. Pruschek, R. et al. (2000). Improvement of Integrated Gasification Combined Cycles Starting from State of the Art (Puertollano). In: Clean Technologies for Solid Fuels, Vol. III, pp. 3-136 (Contract JOF3-CT95-0004). European Commission EUR 19285/IIIEN, Brussels/B. 2. Pruschek, R. et al. (1997). Coal-fired multicycle power generation systems for minimum noxious gas emission, CO2 control and CO2 disposal. In: Combined Cycle Project- Final Reports, Vol. III (3.1.1), pp. 1-56 (Contract JOU2-CT92-0185). European Commission EUR 17524 EN, Brussels/B. 3. Trevifio, M.(2002). The Puertollano Demonstration Plant and IGCC Prospects in Spain. VGB PowerTech 1/2002, pp. 43-46.

Greenhouse Gas Control Technologies, Volume 1I J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1069

MODELING INFRASTRUCTURE FOR A FOSSIL HYDROGEN ENERGY SYSTEM WITH CO2 SEQUESTRATION Joan M. Ogden Research Scientist, Princeton Environmental Institute, Princeton University Princeton, NJ 08544

ABSTRACT Production of hydrogen (H2) from fossil fuels with capture and sequestration of CO2 offers a route toward near zero emissions in production and use of fuels. Implementing such an energy system on a large scale would require building two new pipeline infrastructures: one for distributing H2 to end-users and one for transmitting CO2 to disposal sites and securely sequestering it. In this paper we develop a simple technical/economic model of a single fossil energy complex linked by pipelines to a geological CO2 sequestration site and a H2 demand center. The goals of the study are to better understand design issues and costs for the total system and to identify the most important factors influencing the sequestration cost of CO2 and the delivered cost of H2. For our base case (large flows of H2 and CO2; nearby CO2 storage reservoirs with good characteristics), the most important factors contributing to the delivered cost of Hz transportation fuel are H2 production, pipeline distribution and refueling stations. The costs of CO2 capture and compression at the H2 plant are significant, but the costs of CO2 pipeline transmission and storage are relatively small. INTRODUCTION

Production of H2 from fossil fuels with capture and sequestration of CO2 would enable continued widespread use of fossil-derived fuels for applications such as transportation, with near-zero full fuel cycle emissions of both air pollutants and greenhouse gases [ 1]. A large-scale fossil H2 system with CO2 sequestration consists of one or more fossil energy complexes plus two pipeline networks--one for distributing H2 to end-users (e.g. H2 vehicles) and one for transmitting CO2 to storage sites and securely sequestering it. The performance and economics of the system depend on: •

• • •

the design of the central fossil energy conversion plant [scale, feedstock (e.g., coal vs. natural gas), process design, electricity co-production, separation technology, pressures and purity of H2 and CO2 products, sulfur removal options including co-sequestration of sulfur compounds and CO2, location (distance from demand centers and sequestration sites)]; the requirements of H2 end-users (scale, geographic density of H2 demand, H2 purity, H2 pressure); the characteristics of the CO2 sequestration site (storage capacity, permeability, reservoir thickness, location); pipeline constraints (e.g., for CO2 pipelines; moisture content must be low; for H2 pipelines, materials must be selected to resist embrittlement; for both, availability of rights of way).

Several detailed technical and economic studies have been carried out for various parts of the system, including CO2 capture from electric power plants [2-4], or H2 plants [5-8], CO2 transmission [9] and storage [10], and H2 infrastructure [11, 12]. However, relatively little work has been done assessing the entire system in an integrated way. This study seeks to understand better the total system design and economics, for the special case of a single large fossil energy complex connected to a geological CO2 sequestration site and a

1070 H2 demand center (such as a city with a large concentration of H2 vehicles) [13]. We estimate the delivered cost of H2 with CO2 sequestration as a function of fossil energy complex design, pipeline parameters, distance to sequestration site, and CO2 injection site reservoir parameters. The model developed here can be extended to fossil H2 energy systems that include multiple fossil energy complexes, H2 demand centers and CO2 sequestration sites. M O D E L OF A FOSSIL H Y D R O G E N ENERGY SYSTEM W I T H COz SEQUESTRATION

Overview of the System We consider energy systems producing H2 and electricity from fossil feedstocks (natural gas or coal), with capture of CO2, compression to 15 MPa for pipeline transmission as a supercritical fluid, and injection into an underground reservoir. H2 is compressed to 6.8 MPa (1000 psi) for on-site storage, pipeline transmission and local distribution to H2 vehicles. We consider H2 plants with an output capacity of 1000 MW of H2, higher heating value basis (25.4 tonnes H2/hr).. At an assumed 80% capacity factor, annual H2 production is 25.2 million GJ (178,000 tonnes)---enough to fuel 1.4 million H2 fuel cell cars having a fuel economy of 2.9 liters gasoline per 100 km (82 miles per gallon) and driven 17,700 km (11,000 miles) per year (the US average). To find levelized costs, we assume a 15% annual capital charge rate and an annual non-fuel O&M charge of 4% of the installed capital cost. Feedstock costs are USDOE projections for 2020 costs to electric utilities: $3.75/GJ for natural gas and $0.95/GJ for coal [ 14]. Costs are in constant 2001 US dollars. Fossil Energy Complexes Producing Hydrogen and Electricity The assumed performance and cost characteristics of 1000 MW H2 plants are summarized in Table 1. The coal-based and natural-gas-based energy complexes are taken from the "Conventional Technology" case in [8] and from [5] respectively. H2 compression to 6.0 MPa and CO2 compression to 15 MPa are included in all H2 plant designs. From Table 1, we see that coal to H2 plants have larger capital costs but lower feedstock costs, so that the levelized H2 production cost is somewhat lower than for natural gas. The coal to H2 plant produces about twice as much CO2 as the natural gas to H2 plant. TABLE 1 1000 MW FOSSIL HE PRODUCTION PLANTS W/CO2 CAPTURE AND COMPRESSION H2 from Natural Gas [4] Hz from Coal [81 Electricity net production Mwe 0 31 First law efficiency, HHV =(H2 + elecout)/Feedstocki, 78% 68.7% CO/emitted (tonne/h) at full capacity 36 34 CO2 captured (tonne/h) at full capacit), 204 406 429 731 Installed Capital Cost of H2 Plant (million $) Levelized Cost of Hz Production ($/GJ HI-IV) Plant capital (=15% of capital cost) 2.56 4.35 Non-fuel O&M 0.39 1.00 -0.26 Byproduct electricity credit 4.71 1.41 Feedstock 7.66 Total 6.50 These results can be extended to smaller complexes, using appropriate scaling factors [ 13]. At 250 MW the H2 production cost is about $2/GJ higher than at 1000 MW [13].

Hydrogen Pipeline Distribution Costs for H2 distribution and refueling systems are shown in Table 2. We assume that coal-derived H2 is transmitted 100 km to the "city gate", where it is recompressed and enters a local network bringing H2 to refueling stations. Natural gas-derived H2 is produced at the city gate. Based on the flow equations in [15,16], the optimal 100 km H2 transmission pipeline diameter is 0.29 m, and the associated cost is $0.35/GJ, for a 1000 MW plant and pipeline inlet and outlet pressures of 6.8 MPa and 1.4 MPa, respectively. (For long distance pipelines, capital costs are taken from [15] and recent industry estimates [ 17].) For an alternative H2 energy flow rate Q and pipeline length L, the cost can be estimated as 05 1.25 ($0.35/GJ) x (O/1000 M W ) - x (L/100 k m ) .

1071 For local H2 distribution within a city via small (0.1-0.2 m diameter) high pressure pipelines, we assume the installed cost of the H2 pipelines is $622/m ($1,000,000 per mile), independent of pipeline diameter [ 11 ]. We assume that H2 is distributed radially outward from a central hub through "spokes," along which the pressure drops from 6.8 MPa to no less than 1.4 MPa at the outermost refueling stations. For our base case, each of 10 spokes has 25 refueling stations, each dispensing 2.4 tonnes (1 million standard cubic feet) of H2 per day. Assuming an 80% capacity, factor, this is matched to 5600 cars per station. For a geographically dense demand of 750 H2 cars/km~(about half the average density of cars in the Los Angeles area), each "spoke" is 28 km long. The levelized cost for pipeline capital for this local H2 distribution system is $1.29/GJ. An important component of the distribution system is above-ground H2 storage at the central H2 plant, with capacity equivalent to one half day's production. This storage is needed to assure supply in case of outages and to account for time variations in H2 demand. We assume a capital cost of $5000 per GJ of H2 storage capacity for storage cylinders, or $216 million, based on current industrial bulk compressed H2 gas container technology. The levelized cost contribution of central H2 storage is significant, $1.63/GJ(H2). Lower cost bulk storage is clearly desirable, where possible; underground storage in aquifers or salt caverns is likely to be less costly [11]. (For comparison, at high levels of mass production (300,000/y) the capital cost of onboard high pressure H2 cylinders for cars is projected to be about $1500 per GJ of storage capacity [12].) At lower H2 demand density, the cost contribution of local pipeline distribution increases as (1/vehicle density) °5, while the central storage cost is insensitive to scale. Below a certain demand density, non-pipeline H2 distribution or onsite H2 production will provide a lower delivered cost. TABLE 2 H2 DELIVERY SYSTEM FOR 1000 MW H2 PLANT SERVING 1.4 MILLION H2 CARS ] H2 from natural gas

[ H2 from coal

Hz Distribution and Refueling System Capital Cost (million $)

Central Ha Plant Buffer Storage(I/2 day's output of H2 Plant) H2 Pipeline from HE Plant to City Gate 100 km(coal only) Citygate H2 Booster compressor (24 MWe) H2 Local Distribution Pipelines (750 cars/km~) Sub-total H2 Distribution (excluding refueling stations) H2 Refueling Stations (252 stations) Total

216

216 47

171 387 375 762

171 452 375 827

Levelized Cost of H2 Distribution and Refueling ($/GJ Hz)

Central H2 Plant Buffer Storage H2 Pipeline from H2 Plant to City Gate 100 km (coal only) Citygate H2 Booster compressor (coal only) H2 Local Distribution Pipelines Sub-total 1-12Distribution (excuding.refueling station). H2 Refueling Station Total

1.63

1.63

0.35 0.55 1.29 2.92 6.06 8.98

1.29 3.27 6.06 9.88

Hydrogen Refueling Stations H2 is dispensed to vehicles at refueling stations as a high-pressure gas (at 34 MPa) for storage in onboard cylinders. It is estimated that a refueling station dispensing 2.4 tonnes (1 million standard cubic feet) of H2 per day costs $1.5 million, adding $6.1/GJ to the delivered cost of H2 (see Table 2) [ 11 ] About 80% of the capital cost and 50% of the levelized cost is due to H2 compression at the station and storage cylinders. The remainder is due to capital for dispensers and controls, and labor costs. The cost of on-board H2 storage is not included. Development of a new H2 storage technology that requires less capital and energy input than compressed gas could reduce refueling station costs. C02 Pipeline To model supercritical CO2 pipelines, we use pipeline flow equations developed in [ 16] and [18]. Published estimates of capital costs for CO2 pipelines vary over more than a factor of two above and below the midrange value used here [6, 9, 10, 13, 20]. Local terrain, construction costs and rights of way are all important variables in determining the actual installed pipeline cost. Using a cost function fit to published pipeline data, and inlet and outlet pressure of 15 MPa and 10 MPa, respectively, we find a pipeline capital cost per unit length (S/m), in terms of the flow rate Q and the pipeline length L [13]:

Cost (Q,L) = $700/m x (Q/Qo) 0"48x (L/Lo) 0"24

[i]

1072 Here Qo = 16,000 tonnes/day and Lo = 100 km. The levelized cost of CO2 pipeline transmission is $3.45/t CO2 for the coal H2 plant and $5.26/tCO2 for the natural gas H2 plant. It is assumed that booster compressors are not needed for this 100 km pipeline. For transmission of more than 100 km, boosters might be needed. C02 Sequestration The injection rate of CO2 into an underground reservoir depends on the permeability and thickness of the reservoir, the injection pressure, the reservoir pressure, the well depth, and the viscosity of CO2 at the injection pressure. A practical upper limit on the injection rate per well is taken to be 2500 tonnes per day, limited by pressure drop due to friction in the well at higher flow rates, assuming practical well diameters [2]. Using a standard equation for flow into an injection well [2], this upper limit implies that for a layer thickness above 50 m and permeabilities above 40 milliDarcy, the flow rate is limited not by the reservoir characteristics, but by the pipe friction flow constraints. For the 1000 MW natural gas (coal) to H2 plant, producing about 5,000 (10,000) tonnes CO2 per day, 2 (4) wells are needed. The installed capital cost of each well is [2]: Capital (S/well) = $1.56 million x well depth (km) + $1.25 million. We assume a well depth of 2 km. CO2 is distributed by surface piping at the injection site from well to well. We require each reservoir to store 20 years of CO2 production from the H2 plant. For our base case (reservoir thickness of 50 m), the length of surface piping required at the injection site is found to be 12 (37) km for the natural gas (coal) based H2 plant. This implies a cost of $3.2 (9.2) million, based on a piping cost from Equation TABLE 3 CO2 PIPELINE TRANSMISSION AND STORAGE SYSTEM ] H2 from natural I~as I H2 from coal CO2 Disposal System (100 km pipeline~ 2 km well depth~ injection rate = 2500 t CO~/day/weil) 0.34 CO2 100 km Pipeline Diameter (m) 0.25 Number of CO2 Injection Wells 2 37 Iniection Site Pipin~ length (km) 12.2 System Capital Cost (million $) 55.7 CO2 100 km Pipeline 40.5 17.5 8.8 CO2 Injection Wells 3.2 CO2 Injection Site Piping 9.2 Total C02 Pipeline Transmission and Storage System 82.4 52.5 Levelized Cost of CO2 Disposal ($/tCOz) 5.26 3.45 CO2 100 km Pipeline 1.17 1.16 CO2 Injection Wells 0.44 0.61 CO2 Injection Site Piping Total C02 Pipeline Transmission and Storage System 6. 87 5.23 Total CO2 Pipeline Transmission and Storage System ($/GJ H2) 0.39 0.59 [1], but assuming that the minimum cost is $155,000/km ($250,000/mile) [11]. As long as the aquifer characteristics allow such a relatively high injection rate, the cost of injection wells and associated piping is less than $2/tonne CO2 [$0.10(0.26)/GJ(H2) for H2 from natural gas(coal).] The total levelized cost of CO2 pipeline transmission and storage is shown in Table 3. Per tonne of CO2, the cost of CO2 disposal is higher for natural gas, but because the coal plant produces about twice as much CO2 as the natural gas H2 plant, the contribution to the levelized cost of H2 ($/GJ) is higher for coal. However, the sum of the costs for CO2 capture ($1.33/GJ H2 for natural gas [19] and $0.95/GJ H2 for coal [8]) and disposal ($0.39/GJ H2 for natural gas and $0.59/GJ H2 for coal) is about same for natural gas and coal.

1073 S U M M A R Y OF R E S U L T S FOR SYSTEM CAPITAL COST AND D E L I V E R E D H Y D R O G E N

COST In Figure 1, we summarize our results for 1000 MW H2 plants based on natural gas and coal, with CO2 capture.

System Capital Cost For the "fully developed" H2 economy described here, serving a geographically concentrated market of 1.4 million HE cars, the total system capital cost varies from about $1200-1600 million or $900-1200/car. H2 pipeline distribution systems and refueling stations, together, contribute about 1/2 to 2/3 of the total capital cost. These costs are dominated by H2 compression and storage cylinders. This highlights the importance of developing better H2 storage methods that require lower energy inputs and costs than high pressure compressed gas. H2 production systems are also major contributors to the system capital cost, with coal plants about 1.7 times as capital intensive as natural gas plants. For our assumptions (100 km pipeline, and desirable reservoir characteristics), CO2 pipelines and wells contribute only about 5% to the system capital cost. The incremental total system capital cost of sequestration for the 1 GW H2 system considered here, relative to the same system without sequestration, is about 20% (3%) for natural gas (coal) H2 energy systems [5, 8, 13].

Delivered Cost of Hydrogen For our base case, the delivered cost of H2 is about $17.0 (16.9)/GJ for H2 from natural gas (coal) (Figure 1). HE production, distribution and refueling contribute 45% (38%), 17% (22)% and 35% (36)%, respectively. CO2 capture compression, pipeline transmission and storage add about $1.7 (1.5)/GJ (-~10%) to the delivered cost of H2 transportation fuel compared to cases where CO2 is vented. Of this, only about $0.39(0.59)/GJ or 2% (3%) is due to the CO2 pipeline and storage. Delivered H2 costs are sensitive to scale economies in both H2 production and pipeline transmission. Geographic density of demand is key to the economic viability of widespread gaseous H2 distribution. In the early stages, when demand is relatively low and geographically diffuse, trucked-in H2 or distributed H2 production (e.g., via small scale natural gas reforming at refueling sites) would be preferred from a cost perspective [ 11].

Capital Cost(million $)

Delivered H2 Cost $1GJ ding

1800 1600 1400 1200 1000 8O0 600 4O0 2O0

Distrib

• H2 Refuel Sta O&M • H2 Refueling Sta Capital • H2 Local Pipeline

ne (100 km)

• H2 Pipeline (100 km) • H2 Storage at Plant

ge at H2 Plant Is+lnj Piping

• CO2 Injection Piping • CO2 Wells ICO2 Pipeline (100 km)

.=line (100 km)

[] H2 Plant O&M • Feedstock • H2 Plant Capital

H2 from NG

H2 from Coal

Figure 1: The system capital cost and the delivered cost of H2 are shown for H2 produced from natural gas and coal with CO2 capture, transmission and storage, and H2 pipeline distribution and refueling. The H2 plant capacity is 1000 MW, which is large enough to support 1.4 million H2 fuel cell cars. CONCLUSIONS Using a technical/economic model of large-scale fossil H2 energy systems with CO2 sequestration, we have identified the major factors contributing to the delivered cost of H2, and their most important sensitivities. For our base case assumptions (large CO2 and H2 flows; a relatively nearby reservoir for CO2 sequestration with good injection characteristics; a large, geographically dense H2 demand), H2 production, distribution and refueling were found to be the major costs contributing to the delivered H2 cost. CO2 capture and sequestration added only -~10%. Better methods of H2 storage would reduce both refueling station and

1074 distribution system costs, as well as costs on-board vehicles. The models developed here will be used in a future regionally specific case study of H2 infrastructure development with CO2 sequestration, involving multiple sources and sinks for CO2 and multiple H2 demand sites. REFERENCES

Williams, R.H. (1998). "Fuel Decarbonization for Fuel Cell Applications and Sequestration of the Separated CO2," in Eco-restructuring: Implications for Sustainable Development, Ayres (ed.), United Nations Univ. Press, 180-222. 2. Hendriks, C.A. (1994). "Carbon Dioxide Removal from Coal-Fired Power Plants", Ph.D. thesis, Department of Science, Technology, and Society, Utrecht University, Utrecht, The Netherlands. 3. Foster Wheeler (1998), "Precombustion Decarbonization," Report Number PH2/19, prepared for the IEA Greenhouse Gas R&D Programme. 4. Simbeck, D., 1(999), "A Portfolio Selection Approach for Power Plant CO2 Capture, Separation, and R&D Options", Proceedings of the Fourth International conference on Carbon Dioxide Removal, Pergamon Press, pp. 119-124. 5. Foster Wheeler (1996)" Decarbonization of Fossil Fuels, Report No. PH2/2, prepared for the Executive Committee of the IEA Greenhouse Gas R&D Programme of the International Energy Agency, March. 6. Doctor, R. et al. (1999). "H2 Production and CO2 Recovery, Transport and Use from a KRW Oxygen Blown Gasification Combined Cycle System," Argonne National Laboratory Report. 7. Spath, P.L. and W.A. Amos (1999), "Technoeconomic Analysis of Hydrogen Production from Low BTU Western Coal with CO2 Sequestration and Coalbed Methane Recovery Including Delivered H2 Costs," Milestone Report to the US DOE H2 Program.. 8. Kreutz, T., R. Williams, R. Socolow, P. Chiesa and G. Lozza (2002), "Analysis of Hydrogen and Electricity Production from Fossil Fuels with CO2 Capture," Proceedings of the 6th International Conference on Greenhouse gas Control technologies, 30 Sept-4 October 2002, Kyoto, Japan. 9. Skovholt, O. (1993), "CO2 Transportation System," Energy Conservation and Management, 34(91I):1095-1103. 10. Holloway, S. (1996) An overview of the Joule II Project. Energy Conversion and Management 37(1-2): 1149-1154. 11. Ogden, J. (1999), "Prospects for Building a Hydrogen Energy Infrastructure," Annual Review of Energy and the Environment, 24, 227-279. 12. Thomas, C.E., B.D.James, F.D. Lomax, and I.F. Kuhn, (1998). Draft Final Report, Integrated Analysis of Hydrogen Passenger Vehicle Transportation Pathways, report to the National Renewable Energy Laboratory, U.S. Department of Energy, Golden, CO, Under Subcontract No. AXE-6-16685-01, March. 13. Ogden, J. and H.Y.Benson (2002). "Modeling a Fossil Hydrogen Energy System with CO2 Disposal," Princeton University, Carbon Mitigation Initiative, Technical report, forthcoming. 14. U.S. Energy Information Administration (2001). "Energy Outlook 2002, with Projections Through 2020," DOE/EIA0383(2002), U.S. Department of Energy, Washington, DC. 15. Christodoulou, D. (1984)."The Technology and Economics of the Transmission of Gaseous Fuels," Master's Thesis, Department of Mechanical and Aerospace Engineering, Princeton University. 16. Mohitpour, M., H. Golshan, and A, Murray (2000), Pipeline Design and Construction, A Practical Approach, American Society of Mechanical Engineers, New York. 17. Jandrain, C.(2001, 2002), BP Pipelines, private communications. 18. Farris, C.B. (1983). "Unusual Design Factors for Supercritical CO2 Pipelines," Energy Progress, 3, 150158. 19. Williams, R.H. (2002) "Toward Zero Emissions for Transportation Using Fossil Fuels," in VII Biennial Conference on Transportation, Energy and Environmental Policy: Managing Transitions in the Transportation Sector." How Fast and How Far, K.S. Kurani and D. Sperling, ed.s, Transportation Research Board, Washington, DC, forthcoming. 20. Fisher, L., T. Sloan, P. Mortensen (2002). "Costs for Capture and Sequestration of Carbon Dioxide in Western Canadian Geologic Media," Canadian Energy Research Institute, Study No. ISBN 1-896091-784, June. 1.

ECONOMICS

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1077

A CO2-1NFRASTRUCTURE FOR EOR IN THE NORTH SEA (CENS)" MACROECONOMIC IMPLICATIONS FOR HOST COUNTRIES P. Markussen l, j. M. Austell 2 and C-W. Hustad 3 z Elsam AS, DK-7000 Fredericia, Denmark, ([email protected]). 2 INCO2 ApS, Box 39, DK-9370 Hals, Denmark, ([email protected]). 3 CO2-Norway AS, Box 592, N-3605 Kongsberg, Norway, ([email protected]).

ABSTRACT

The CO2" for EOR in the North Sea (CENS) Project offers the host nations a unique opportunity for securing future energy supplies while developing sustainable solutions in ......................................................................................................................................................................... response to the challenge of climate change and compliance with their Kyoto commitments. The Project comprises a CO2-pipeline infrastructure in the North Sea capable of transporting more than 30 million tonnes CO2 per year (mtCO2/yr). The CO2 will initially be captured from on-shore coal-fired power plants in the UK and Denmark, and used commercially for Enhanced Oil Recovery (EOR) in the maturing oil reservoirs in the North Sea. The scope of the CENS Project entails not only collaboration between the CO2-producers, transporters and users, but also the host countries. Only when these are active participants does the project reveal a 'winwin-win' situation for all stakeholders, including host governments.

............ Figure 1: Sketch of the CENS concept super-posed on a relief map of the North The CENS Economic Models (CEM) shows that during a 25-year q~ h~i, "economic" lifetime, the project could produce 2,1 billion barrels of incremental oil obtained while sequestering 680 mt CO2 in recognised secure depositories. Assuming price of oil at $20 /bbl then the net cost for CO2capture and sequestration is less than $1,50 per tonne--this represents one of the cheapest options available to the host nations for CO2-emission reductions. We do not for the time being attribute any value to the CO2-credits that may also be generated within the project.

In this paper we briefly elaborate on some of the macroeconomic benefits that the project can produce, including increased tax income, energy security, improved oil recovery, technology development, reduced CO2-emissions, capital investment and jobs. We also indirectly infer some longer-term benefits of a CO2-infrastructure whereby Northern Europe may be in a position to decarbonise existing CO2-emissions during the next half century using ageing oil and gas reservoirs. Furthermore we perceive an accelerated commercial route towards a "hydrogen economy"minitially based on decarbonisation of fossil fuels [1] that can be supplemented by new-renewable hydrogen production, as these become commercially developed.

* We consistently use C02 as opposed to C02 for denoting carbon dioxide.

1078 INTRODUCTION The CENS Project is essentially a 25-year project for enhanced oil recovery (EOR). It is made possible by the maturing state of the oil reservoirs on the UK and Norwegian sectors of the North Sea Continental Shelf (NSCS). In Fig. 2 comparison is made with the similar situation that occurred in the US in the early 1980's. This stimulated the introduction of CO2 for EOR, particularly in West Texas where there now exists a 1500 km CO2pipeline infrastructure transporting 22 IWl~l~na~ mtCO2/yr--the majority of which is I~ ~ obtained from naturally occurring geologic 4,0 formations. The Houston-based Kinder Morgan C02 Company (KMCO2) is the major operator of the Texas-pipeline infrastructure. In addition KMCO2 owns and operates the SACROC oilfield, West Texas, which is currently the world's largest CO2-flood.

3,0 2,0

0,0 o o o o o o o ,.,. _ ~ ~D t... O0 ¢lr) 0 s~. The potential use of CO2 for EOR in the G) q~) 0') G) 0 0 0 North Sea region is also made possible by 'e~e~ ~-' ~I ~ ¢~1 O Z a growing concern regarding CO2emissions from coal-fired power plants in Figure 2: Comparison between US and North Sea oil production (1%0 Denmark and the UK. These plants have a 2020). The NSCS is currently moving into decline in a similar manner that occurred in the US in the early 1980's. relative close proximity to the NSCS and represent the cheapest 'end-of-pipe' CO2 available to the oil field operators in a sufficient volume to warrant fullscale use of CO2 for tertiary oil recovery. It is also recognised that there are many additional sources around the North Sea rim that can in the future supplement this initial 'base volume' of CO2-supply [2].

Furthermore the commercial use of CO2 captured from coal combustion is appealing due to the recognised dominance that coal has within energy production. Inevitably, on the global arena, this will probably remain the case despite the move towards lower carbon content fuels (i.e. natural gas) in many of the industrialised economies. It is the detrimental impact of coal on the environment that is of major concern [3]. The potential for removing CO2-emissions commercially from existing coal plants using post-combustion decarbonisation should possibly strengthen the perceived global role for coal in a 'carbon constrained' global economy during the next half-century. The longer-term implications of CENS suggests that the project may also be seen as an opportunity to straddle the gap between an existing high carbon fossil-based economy through to a sustainable renewable energy economy via decarbonisation, hydrogen-rich syngas and carbon sequestration. Within this perspective CENS could be a fundamental building block for commercially developing the necessary technology for economic and sustainable energy in the future.

O V E R V I E W OF THE CENS E C O N O M I C M O D E L The CENS Project primarily comprises four projects that cover: (i) power plant CO2-capture, (ii) CO2transportation, (iii) CO2-injection for EOR, and (iv) CO2-stripping and recycling. Within the CENS Economic Model (CEM) each one of these are subsequently broken into sub-projects having specific capital investments, operational costs, revenue streams, capital charges, etc. The CEM contains nearly 50 inter-linked data sheets covering all the economic components of the project, together with summary sheets for specific sectors and host nations. Many of these sheets also incorporate macroeconomic aspects such as jobs created, technology development, taxation revenue, and other societal benefits that are not directly relevant to the project microeconomics. We can also make comparison with the 'No-CENS' case based on forecast production profiles and decommissioning costs for specific fields if the project does not occur.

1079

The essence of CENS is as a multi-discipline project with stakeholders from several separate sectors--all must see a satisfactory internal rate of return in order to individually move forward and invest capital. Our fiscal and macroeconomic modelling shows that a 'win.... ......: t:~: ,I win-win' situation occurs for all stakeholders i!~,i~!U~~'...... ~ rlmli : : , ,' ,.............~1 only when the host governments also become I~i~:i~::~i::!!~:' ~ !...... ~ , . ~:~:,:~:~-~ B t ~ t , - ~ ! l : ....~ :o~:ili~i~'~ active stakeholders and project facilitators. /1 : :~i,::.... ~ Nt~w*~'//~~~~l'~+~;~ An overview of the project concept is shown in Fig.3. The designated fields are chosen as suitable candidates for CO2-flooding based on their existing production profiles and original oil in place (OOIP). They should be viewed as representative of a general portfolio of potential fields for the period 2006 - 2012 J'. The main components of the project, as currently envisaged, comprises an onshore pipeline infrastructure in Denmark (sketched) and UK (not shown), together with two main (24-inch diameter) feeder lines joining a southern hub near Fulmar and Ekofisk. The main 'backbone' is a 30-inch diameter pipe transporting the CO2 north to the fields in the Tampen area off the West Coast of Norway. There

is also some scope

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,~,Figure 3: Overview of possible CO2-pipeline infrastructure together with a portfolio of mature oil reservoirs that are representative candidatesfor CO2-flooding. Note that Sleipner and Brae are additional sources of CO2 having a comparatively high percentage as associatedgas(equivalenttol-2mtCO2/yrrespectively).

industrial and power complexes in Scotland with an additional feed line from St. Fergus via possibly fields like Forties or Claymore. These are representative of reservoirs in the more mature part of the North Sea requiring CO2 at the earliest possible opportunity starting 2006 - 8. The feed line from the west of Norway to Tampen is primarily motivated by Norway's unique position as a major oil and natural gas (NG) exporter 1:. By 2005 it is anticipated that total production of NG from the Norwegian sector of the North Sea will be around 140 bcm. However, the annual domestic consumption is presently less than 4 bcm. For this reason there is a strong desire to use gas onshore, combined with a need for decarbonisation in order to comply with Norway's Kyoto commitment. It is already well recognised that Norway is currently a major promoter for developing "zero-emission" Capturing 90% of the C02 emitted from Elsam's coal4ired power power plant technology[4]. plants is commercially competitive because:

C02-Capture

• Ultra clean flue,gas with FGD and SCR are already Installed.

The Danish company Elsam A/S own and operate five major coal-fired power plants in Denmark with total installed capacity of 2,5 GW producing a maximum of 15 mtCO2/yr. During the past year they have conducted extensive investigations with major technology suppliers for installation of standalone post-combustion CO2-capture in conjunction with these power plants. The on-going work has provided detailed cost breakdown and identified

• The flue-gas concentration is 12 - 14% CO2, which is three limes the concentration for Natural Gas power plants. , Steam at 290 bar / 580 °C minimises efficiency drop in conjunction with integration of amine capture technology. • Integration with district heating also helps reduce loss in overall plant efficiency. • Close proximity to NoRh Sea CO2-1nfrastructure. • Potential production of between 10,15 million tonnes CO2 per year from 5 plants.

t More recent work has also revealed clusters of smaller 'non-commercial' fields that also may be favourably disposed to CO2flooding. The optimal economics of these fields is currently being investigated. In 2001 Norway was responsible for exporting 4.2% of global oil consumed. At the same time it is also developing natural gas reserves equivalent to one-quarter of total European reserves. Annual export of natural gas to the European market was in 2001 around 57 billion cubic metres (bcm)--about 12% of total European gas consumption--but this is expected to reach 80 bcm by 2005. An additional 50 bcm of hydrocarbon (HC) gas is currently used for enhanced oil recovery (EOR), and it is uncertain regarding how much of this gas will be economically retrievable towards the end of the oil fields operational life.

1080 improvements for better energy efficiency and cost reductions compared with earlier published studies. The CAPEX for a standalone capture plant varies from US$140 - 195 million with size range 400 - 800 MW. Power plant load factor depends on the local co-generation configuration but will typically vary from 70 - 90%. The CEM also includes 18 potential coal-fired power units in the UK, but currently only four of these (yielding 16 mtCO2/yr) are part of the present economic analysis. The UK plants have been chosen because of their location near the coast, and that they have a similar cost potential as their Danish counterparts. However, overall the exact cost of capture will depend upon final project configuration, volume of CO2 demand, and the rate at which the CO2-offtakers come on-line in the period 2 0 0 6 - 12.

C02- Transportation KMCO2 have with INTEC Engineering B V conducted extensive studies regarding pipeline routing, size and power requirements. The scenario shown in Fig.3 comprises 1500 km of CO2-pipelines offshore together with 900 km onshore in Denmark and the UK. The total transportation investment cost is estimated to be $1,69 billion. However again, the detailed extent of the pipeline economics can only be determined once the suppliers and offtakers have confirmed volumes to be transported, and dates for delivery of initial gas. Despite this uncertainty the CEM does provide a capability to analyse different scenarios for a North Sea infrastructure, thereby yielding an envelope of values for capture and transportation costs. To date our scenario analysis suggests that the 'end-of-pipe' cost for delivered CO2 will be in the range of $32 - $35 per tonne. Elsam and KMCO2 are currently comfortable with confirming that $35/tCO2 is sufficient for both of them to make a commercial investment decision for first delivery of CO2 to the oil field operators in 2006.

C02-Injection for Enhanced Oil Recovery CO2 for EOR will require major investments to the oil platforms and oil reservoirs. However there already exists considerable onshore experience from the Permian Basin, West Texas regarding reservoir response and corrosion mitigation. Furthermore the handling and injection of CO2 offshore is well established practice (see Figs. 4 and 5). Offshore CAPEX will be platform and field dependent, thus difficult to predict with any certainty before focusing on specific installations together with the operator. In this area the CEM is conservative in its assumptions. We model a total offshore investment of nearly $5 billion spread over 12 fields. We believe this is a substantial

k

Figure 4: The Sleipner-T (CO2 amine-treatment) and Sleipner-A(production)platforms, where 1 mtCO2/yr are currently treated and injected by Statoil as part of a pilot studyon saline aquifer storage in the North Sea.

investment covering what will be needed for topside modifications and 'down hole' corrosion protection before a platform may initiate a CO2-flood. We also note that the project economics is reasonably robust to allow for an offshore investment of $6 billion if necessary. Furthermore we assume that only 6% of the original oil in place (OOIP) will be recovered. Experience has shown that the actual value will often vary in the range from 6 - 15%. Although the true value of the CO2 in the reservoir can only be estimated with detailed compositional modeling, experience shows that it is optimized through careful monitoring of reservoir response during the CO2-fiood process. We assume that 6,000 cubic feet of CO2 is necessary to produce one barrel, this being equivalent to 3,1 bbl/tCO2-injected. This is also recognized as being a conservative estimate. Decommissioning costs ($150 million per platform) are deferred to allow for extended field operations. In both the UK and Norwegian sectors much of these costs are to be carried by the respective governments. The model also includes possibility for variation in the taxation regimes by each host government, including royalty, petroleum revenue tax (PRT) and corporation tax. Furthermore the rules governing depreciation of invested capital can be modified in the model.

1081

C02-Stripping and Recycling A main feature of existing onshore CO2-floods is that following initial CO2 injection there is typically a 9 - 18 month response time before increased oil production. For offshore fields, with sparser injector and producer well spacing, this response may be 18 - 36 months. The model assumes two years (and tests sensitivity of field IRR using one and three years). Subsequently as the EOR phase evolves there is a need for stripping CO2 from the produced crude and re-injection. As illustrated in Fig. 5 such technology is already adapted for offshore applications. The incremental cost of handling CO2enriched crude, stripping, drying and re-injection into the reservoir is estimated in the model as $1,5/bbl. PROJECT E C O N O M I C S Figure 5: A CO2-membrane stripping unit (highThe CENS Project requires integration of sub-projects within lighted) attached to an offshore platform operated three main industry sectors: (i) power plant CO2-capture, (ii) by Unocal in the Gulf of Thailand. The unit shown CO2-transportation, and (iii) CO2-injection for EOR (with here is handling 1,8 mtCO2/yr. CO2-recycling). For comparison purposes we average the IRR and NPV of each sub-projects so as to provide an initial indication regarding how the three sectors will perform. We weight the averaging with respect to the capital investment of each sub-project. All net present values (NPV's) used are assuming an 18% discount rate for oil field operators, 15% for the pipeline operators, 12% for power plant owners, and 7% for the governments. These differences respectuto a certain extent--the real expectation for the return on capital invested in the different sectors.

In the CEM we can also look at modifications in the tax structures while comparing pre- and post-tax project economics, as well as IRR between a full equity and a loan-financed project (assuming 6% interest rate). We maintain that the price of coal is $1,50 /GJ, the cost of electricity is $25 /MWh, and oil is at $20 /bbl. Comparisons presented in this paper are assuming a 40% debt-financed project. Using the above we find that an 'end-of-pipe' delivery sale price for CO2 of $35 per tonne will satisfy investment hurdle-rates that are typical in sectors (i) and (ii). However the economic model also shows that the offshore EOR projects will need an oil price of $29,37/bbl to satisfy typical investment requirements in sector (iii). Alternatively with oil at $20/bbl then the necessary CO2 sale price to the oil field operators would be $12,07 /tCO2. This is a level that is not sustainable for projects in sector (i) and (ii). We have currently attributed no value to the potential CO2-credits that may eventually be generated and distributed among the project stakeholders. However it is also evident that the shortfall in price of $22,93 is not a realistic credit value that the emerging emission-trading market would currently support, and therefore does not provide any basis for making an investment decision for a project in the 2 0 0 6 - 2012 time frame.

MAKING CENS FOR THE HOST NATIONS Ultimately it is the host nations that perceive a net benefit through participating in the CENS project. The economic model indicates that with the current tax structure these governments will obtain an incremental $5,79 billion in fiscal revenue by way of direct petroleum-, corporation- and income taxation. At the same time a CO2support price of $22,93/tCO2 is equivalent to an expenditure of $6,77 billion. The net deficit of $0,98 billion is the (discounted) cost these governments need to pay in order to remove 680 mtCO2-emissions from the atmosphere at a price equivalent to $1,44/tCO2 over the 25-year duration of the project. The CEM also shows that if the oil price rises above $21,18/bbl then the host nations become net beneficiaries of the project. (If the offshore capital investment increases from $5 to $6 billion then the price of oil would need to rise above $22,21/bbl before host nations became net beneficiaries.)

1082 Altematively if we maintain oil at $20/bbl, but assume that a credit trading value of $5/tCO2 is available to the project participants, (with this being distributed internally one-third to each sector). Then the credit value will reduce the required CO2-sales price from $35 to $33,24/tCO2, and ensure a net government surplus of $0,71 billion. This is equivalent to a positive income of $1,04/tCO2-captured. Increasing the CO2-credit to $10/tCO2 leads to a government surplus of $2,41 billion and a positive income of $3,53/tCO2-captured. The preliminary calculations using the economic model also indicates that there is little incentive for host governments to reduce their Special Tax (in Norway at 50%) and PRT (in UK at 50%), as this decreases their petroleum income and net benefit. However on the Norwegian side we observe that modifying the linear depreciation for capital investment from six to three years does have a marked favourable influence on IRR of the Norwegian EOR projects.

CONCLUSIONS The CENS Economic Model (CEM) is still at an early stage of development, and we have in this paper simply wanted to indicate a few examples of approximate costs, benefits and sensitivities. To date we have made every effort to remain conservative in our assumptions by including the reality of our different business environments. The most crucial part of the model that still needs to be better elaborated upon concerns the offshore capital investment, and the final 'value' of the CO2 in the reservoir. This work is in progress with the oil field operators. Furthermore there are numerous 'what-if' scenarios that can be considered using the CEM. We believe that the model may also become a useful tool to help host governments assess possible strategies for CO2-emission reductions and identifying incentives to further the use of CO2 for EOR in the North Sea.

ACKNOWLEDGMENTS The CENS Project has evolved in close dialogue between the project developers (Elsam / KMCO2), technology providers, oil companies, and power plant operators. Furthermore there has been considerable dialogue with governmental departments in the UK, Norway and Denmark. The Project would therefore like to thank all those that have provided valuable information and support, including specifically the Norwegian Petroleum Directorate (NPD), Danish Energy Agency (ENS), UK-TradePartners, Department of Trade and Industry (DTI), and many individuals who have helped promote the project in a constructive manner--thank you! The authors thank the management of Elsam A/S and Kinder Morgan C02 Company for their permission to publish the material contained in this paper, and acknowledge our colleagues who have contributed within the CENS Project Management Team. These are: Marius Noer, Benny Hansen Mai and Claus Straegaard Graversen, Elsam; Charles Fox, Russel Martin and David L. Coleman, KMC02; Hugh Sharman, INC02.

REFERENCES Blok, K., Williams, R., Katofsky, R. and Hendriks, C. (1997). "Hydrogen Production from Natural Gas, Sequestration of Recovered CO2 in Depleted Gas Wells and Enhanced Natural Gas Recovery", International Journal of Hydrogen Energy, Vol. 22, No.2/3, pp.161-168. Holt, T. and Lindeberg, E., (1993). "CO2 from Industrial Sources as Injection Gas in Oil Reservoirs", Energy Conversion Management, Vol. 34, No.9-11, pp.1189-1196. The Economist Magazine, (2002), p.11 & p.81-82, 6 - 12 July. Hustad, C-W., (2001). "Review over Recent Norwegian Studies Regarding Cost of Low CO2-Emission Power Plant Technology", in Proc. of Fifth Intl. Conference on GHG-Control Technologies, pp.12951300. Eds. Williams, D., et al., ISBN 064306672, CSIRO Publishing, Australia.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1083

ECONOMIC MODELING OF THE GLOBAL ADOPTION OF CARBON CAPTURE AND SEQUESTRATION TECHNOLOGIES J. R. McFarland 1, H. J. Herzog 2, and J. Reilly3 1Technology and Policy Program, M.I.T., Cambridge, MA. 02139, USA aLaboratory for Energy and the Environment, M.I.T., Cambridge, MA. 02139, USA 3joint Program on the Science and Policy of Global Change, M.I.T., Cambridge, MA. 02139, USA

ABSTRACT

As policy makers consider strategies to reduce greenhouse gas emissions, they need to understand the available options and the conditions under which these options become economically attractive. This paper explores the economics of carbon capture and sequestration technologies as applied to electric generating plants. The MIT Emissions Prediction and Policy Analysis (EPPA) model, a computable general equilibrium model of the world economy, is used to model carbon capture and sequestration (CCS) technologies based on a natural gas combined cycle (NGCC) plant and an integrated coal gasification combined cycle (IGCC) plant. These technologies have been fully specified within the EPPA model for all regions of the world by production functions. We simulate the adoption of these technologies under scenarios with and without carbon taxes. The results illustrate how changing input prices and general equilibrium effects influence the global adoption of carbon sequestration technologies and other technologies for electricity production. Rising carbon prices lead first to the adoption of NGCC plants without carbon capture and sequestration followed by IGCC plants with capture and sequestration as natural gas prices rise.

INTRODUCTION

Heightened concerns about global climate change have aroused interest in carbon capture and sequestration technologies as a means of decreasing the growth rate of atmospheric carbon dioxide concentrations. Projects are already underway to research and implement such technologies in countries like the United States, Japan, Norway, and the United Kingdom. In the United States, the Department of Energy (DOE) is investigating the economic, technological, and social issues of carbon capture and sequestration technologies. Past research has focused on identifying research needs and assessing technical feasibility and engineering cost data [1,2]. More recently, economic modelers have sought to integrate knowledge about the economics of carbon capture and sequestration technologies into economic models [3,4,5]. This paper summarizes our analysis of two electricity generation technologies with carbon capture and sequestration as well as a generation technology without carbon capture and sequestration. David and Herzog [ 1] identified natural gas combined cycle generation with capture via amine scrubbing of the flue gas and integrated coal gasification combined cycle generation with pre-combustion capture of the carbon dioxide (CO2) as two of the most promising technological options for producing electricity with low CO2 emissions. The term carbon capture and sequestration (CCS) as used herein refers only to these two fossil power technologies and the subsequent capture and sequestration of the CO2. Many other energy sources and capture processes are often considered under the umbrella of carbon capture and sequestration

1084 technologies, but these options are not evaluated here. A third technology, natural gas combined cycle (NGCC) without sequestration, is modeled to represent advanced conventional generating technologies. This paper gives a brief overview of the method of analysis and the results obtained from introducing these technologies into multiple regions of a general equilibrium, global economic model. This analysis expands upon previous work [3] by introducing CCS technologies into multiple regions.

M E T H O D OF ANALYSIS

The M I T EPPA Model This analysis utilizes the MIT Emissions Prediction and Policy Analysis (EPPA) model described by Babiker, et al [6]. The EPPA model is a recursive dynamic multi-regional general equilibrium model of the world economy developed for the analysis of climate change policy. The current version of the model is built on a comprehensive energy-economy data set, GTAP-E [7], that accommodates a consistent representation of energy markets in physical units as well as detailed accounts of regional production and bilateral trade flows. The base year for the model is 1995, and it is solved recursively at 5-year intervals through 2100 to capture the long-term dynamics of resource scarcity and capital stock turnover. EPPA consists of twelve regions, which are linked by international trade, nine production sectors, and a representative consumer for each region (see Table 1). TABLE 1 EPPA REGIONSAND SECTORS Regions

Sectors

Annex B (United States, Japan, European Community, Other OECD, Eastern European Associates,Former SovietUnion) and Non-Annex B (Brazil, China, India, Energy Exporting Countries, Dynamic Asian Economies,and Rest of World). Coal, Oil, Refined Oil, Gas, Electricity, Energy Intensive Industries, Agriculture, Investment,and Other Industries.

Constant elasticity of substitution functions are used to describe production and consumption within each region and sector. In each time period the model solves these functions for a set of prices that clear supply and demand across all regions and sectors. The functions mathematically describe how the factors of production can be combined to produce output and how consumers trade-off among goods to maximize utility. Technologies are represented by production functions that use inputs in different combinations to produce their respective goods. In EPPA's conventional electricity sector, all fossil fuel-based generation technologies are represented by an aggregate production function. Specific technologies such as coal-fired plants or gas-fired turbines are not explicitly represented. Instead, these technologies are represented by conventional electricity's ability to switch among inputs of capital, labor, and fuels. Technologies for electricity produced from nuclear, hydro, biomass, wind and solar are explicitly represented.

Implementation of Carbon Capture and Sequestration Technologies For this analysis, separate production functions were added to EPPA for 1) coal power generation with CCS, 2) natural gas combined cycle power generation with CCS, and 3) natural gas combined cycle power generation without CCS. The NGCC without carbon capture and sequestration technology represents a technology that was not widespread at the time of preparation of the 1995 base year data, but is widely seen as the most likely technology to be installed where new capacity was needed. The electricity produced by each generation technology (conventional fossil fuel, nuclear, wind, gas without CCS, gas with CCS, and coal with CCS) is assumed to be a homogenous good and readily tradable within a region. Specification of the production functions consists of determining the cost of electricity from the technology, the factor shares of capital, labor, and energy required for electricity production, and the ability to substitute between the various factors of production. Costs CCS technologies are based on the bottom-up engineering cost analysis performed by David and Herzog [2] which assume small technical improvements prior to

1085 commercial availability in 2020. We view the full cost of electricity as composed of the components identified in Eqn. 1, which includes the unit costs of generation, transmission and distribution (T&D), sequestration, and value of carbon emitted to the atmosphere. Equation 1 can be used to see how, from a partial equilibrium perspective, different generation technologies compare as the price of carbon changes. (1)

CElectricity "- CG ..... tion + CT&D + Csequestration + IdgCarbon

Transmission and distribution costs and shares were derived from U.S. data [8]. Sequestration costs are assumed to be constant at $10 per tonne CO2, while emission costs are determined by a technology-specific emissions constant, K, and the price of carbon ($ per tonne carbon). The first column of Table 2 presents the total cost of electricity net emission costs based on these data. Comparing the electricity costs of these new technologies to the cost of conventional power in the U.S. at 66 mills per kilowatt-hour, we see that advanced gas generation without CCS is 16% less expensive. Gas and coal generation with CCS are respectively 8% and 25% more expensive. When introducing these technologies into other regions, we assume the ratio of the cost of electricity from the new technologies to conventional technologies remains constant across regions as do the shares of capital, labor, and fuel. The carbon price at which the capture technology and the NGCC technology, the lowest cost alternative, have the same total cost in the base year is shown in the last column of Table 2. At current natural gas prices, the natural gas technology with CCS becomes competitive at $190/tonne C, half that of the coal with capture technology. TABLE 2 TECHNOLOGYCOSTS Cost o f : Generation, Electricity Cost Ratio T&D, Sequestration of New Tech. to (mills/kWh) Conventional Tech. (66 mills/kWh) 0.84 Advanced Gas (NGCC) 55.3 71.0 1.08 Gas + Capture, Seq. 82.3 1.25 Coal + Capture, Seq. Technology

Emissions Constant, K (kg CO2/kWh) 0.337 0.037 0.073

Partial Equilibrium Carbon Entry Price vs. NGCC Technology ($/tonne C) $190 $380

In addition to the three inputs to production mentioned above, each technology is modeled to require a small share (1%) of a technology-specific fixed factor. The fixed factor represents various technology-specific inputs that limit the rate of penetration of a technology, but not the ultimate level of demand. The amount of fixed-factor is initially limited but grows as output expands. In the context of large-scale electricity generating technologies, this may be thought of an initially limited amount of engineering capacity to build and install new plants or a regulatory process that slows installation. We specify a technology's fixed factor supply grow endogenously with the level of output and posit a functional form with S-shaped growth. Without a fixed factor, technologies would immediately capture very high share of electricity production, an unrealistic proposition.

Capabilities The EPPA model allows us to evaluate the economic competitiveness of the CCS technologies as prices, output levels, and other conditions change in the general economy. The partial equilibrium cost comparisons in Table 2, while valid for considering a single plant for a set of reference prices, are not valid for considering the economy-wide potential for CCS technologies. When a carbon constraint is implemented, the prices of production inputs such as fuels and electricity change. Conversely, changes in prices, production activity, and general welfare due to CCS technology introduction can be investigated. The introduction of a competitive conventional technology such as natural gas combined cycle without capture yields similar information. EPPA also accounts for the stock nature of capital through an explicit vintaging of capital investments within the electric power sector. Vintaged capital retains the input shares it had when installed until it has depreciated; that is there is no ability to substitute among inputs once the capital is in place. Capital investments in EPPA are tracked by vintage and depreciate over a twenty year period. For this version, we

1086 further assumed that capital could not be reallocated out of a sector. While normally not an issue for other EPPA sectors [9], given the rapidly changing conditions in the electric sector with carbon policies we found a tendency for the solution to unrealistically allocate vintaged capital out of the CCS technology. By fixing capital to the technology, we more accurately capture the exit and entry dynamics of technologies [3]. Without fixed capital, a technology's output drops to zero when it becomes uneconomic since capital is not stranded in an utilized asset. Limitations

The representation of the electricity sector and the carbon sequestration technologies in the EPPA model has some limitations. First, since EPPA does not explicitly represent each power plant, it cannot represent the cost of retrofitting particular plants. Instead, the CCS technologies are modeled as new plant constructions. In reality, the distinction between a new plant and a retrofit is somewhat blurred. Extensive modifications to plants and structures at a particular site are not uncommon in the economy and could have advantages over trying to site a completely new plant, and it may be largely semantics as to whether a completely rebuilt plant at an existing site is a retrofit or a new plant (although the semantics have regulatory repercussions as US environmental regulations distinguish new sources from existing power plants emissions). Given the resolution within EPPA and the extent to which it affects the main results of concern, the distinction between a retrofit and a new plant primarily involves the difference in cost. In fact, only a fraction, ~, of each years investment is vintaged. The remaining stock (l-d?) remains malleable, reflecting the fact that there is an ability, albeit limited, to retrofit capital. Second, this same aggregation prohibits consideration of electricity market effects such as plant dispatch and transmission constraints. In ongoing work we are studying the implications of retrofitting on sequestration technology adoption.

SCENARIOS AND RESULTS The adoption of CCS technologies i n t h e United States is analyzed under a reference scenario without constraints on greenhouse gas emissions and under a scenario where a tax is placed upon carbon. Carbon taxation begins in 2010 at $50/tonne C and increases by $25/tonne C every five years reaching a maximum of $200/tonne C by 2040. The model results are compared to the reference scenario and to scenarios without CCS technologies. In the reference scenario, electricity production increases five fold over the modeling time frame from 24 trillion kilowatt-hours (TkWh) in 1995 to 120 TkWh in 2100 as shown in Figure 1. Conventional generation, primarily from coal, accounts for over 70% the electricity generation in each period. The share of advanced natural gas reaches 11% of total generation by 2100 equaling that ofhydropower. 140 120

• Conventional

[

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too

• Nuclear

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• Gas Capture

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• Coal Capture o 1995

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2055

2070

2085

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Figure 1" Global Electricity Production- Reference Scenario

1087 Under the tax scenario, the contributions from the production technologies change substantially while the total electricity production in 2100 is reduced by only 6%. The advanced gas technology without capture expands rapidly from 2005 to 2040 as Figure 2 illustrates. With a lower initial cost of generation and less carbon production, this technology displaces conventional coal as the dominant electricity production technology by 2020. The advanced coal with capture technology enters the market in 2035 even though the carbon tax is only half of the partial equilibrium carbon entry price presented in Table 2. Rising natural gas prices drive this behavior as they make the gas technology much more expensive than that represented in Table 2. The higher gas prices also explain the lack of penetration by the gas with capture technology as it cannot compete with coal with sequestration. The rise in gas prices depends on specifics of the resource model in EPPA--if there were unlimited, low cost sources of gas then prices need not rise. EPPA bases its estimates of gas resources on USGS estimates of gas and includes a technology to produce synthetic gas from coal. 140 • Conventional 120

[] Adv. Gas

100

• Nuclear

~

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60

• Wind & Solar

40

•

I--

• Hydro

Biomass

,

• Gas Capture

20

• Coal Capture{ 0 1995 2010

2025 2040

2055

2070

2085

2100

Figure 2: Global Electricity Production- Tax Scenario The trends and timing of adopting the advanced gas technology without capture followed by advanced coal with capture are exhibited across all regions except for Japan, the European Community and India. Baseyear electricity prices in Japan and the European Community are at least 43% higher than the average prices of the other regions. High electricity prices inflate the effect of the electricity cost ratio parameter (see Table 2) and make the sequestration technologies economically unattractive. The advanced gas technology accounts for the majority of Japan's electricity after 2025. The European Community gradually replaces conventional coal technology with advanced gas until 2045 when the region reverts to conventional coal. At carbon prices of $300/tonne C, the European Community switches to advanced coal with capture after 2045. India, lacking substantial gas reserves, adopts the advanced coal with capture technology in 2035 and bypasses investments in advanced gas technologies.

CONCLUSIONS We derive some broad implications for the potential of CCS technologies from the modeling results. •

CCS technologies could play a substantial role in reducing carbon emissions, but would only be economically viable with policy constraints on carbon dioxide emissions.

•

Gas technology without carbon capture would be a cost effective near-term solution for electricity as it has relatively low carbon emissions, but given the representation of gas resources in the EPPA model, it is not competitive with coal with sequestration in the longer term.

•

Coal technology with carbon capture offers a cost effective long-term source of low carbon emitting electricity.

1088 •

Benefits of using the CCS technologies are seen through increased electricity production and lower electricity prices.

•

The availability of CCS technologies in the policy scenario leads to a smaller reduction in the demand for gas and coal than from the reference demands.

•

The primary uncertainties in these projections include the potential for technological improvements in CCS technologies, fuel prices, the level of economic growth and reference emissions, the carbon dioxide emission constraints, and economic viability of other low-carbon technologies such as nuclear and solar electric power technologies, and the details of policy implementation such as taxation and permit trading.

ACKNOWLEDGEMENTS

This work was conducted with support from both the U.S. Department of Energy's Integrated Assessment program within Biological and Environmental Research (BER) and the Office of Fossil Energy (DE-FG0299ER62748). The model underlying this analysis was supported by the U.S. Department of Energy's Integrated Assessment program within Biological and Environmental Research (DE-FG02-94ER61937), the U.S. Environmental Protection Agency (X-827703-01-0), the Electric Power Research Institute, and by a consortium of industry and foundation sponsors.

REFERENCES

David, J. and Herzog, H.(2000). In: Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies, pp. 973-978. David, J. (2000). S.M. Thesis, M.I.T., United States. McFarland, J., Herzog, H., Reilly, J. and Jacoby, H.D. (2001). In: Proceedings of the First National Conference on Carbon Sequestration, netl.doe.gov/publications/proceedings/01/carbon seq/2c3.pdf. Eckaus R., Jacoby, H., Ellerman, D., Leung, W. and Yang Z. (1996) Report No. 15, Joint Program on the Science and Policy of Global Change, MIT, Cambridge, MA. Kim, S. and Edmonds, J., (2000) Pacific Northwest National Lab report 13095. Babiker, M.H., Reilly, J.M., Mayer, M., Eckaus, R.S., Sue Wing, I. and Hyman, R.C. (2001) Report No. 71, Joint Program on the Science and Policy of Global Change, MIT, Cambridge, MA. Hertel T., (1997) Global Trade Analysis: Modeling and Applications. Cambridge University Press, Cambridge. U.S. Department of Energy (1999). Supporting Analysis for the Comprehensive Electricity Competition Act. Jacoby, H.D. and Sue Wing, I. (1999). The Energy Journal 20, 73.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1089

ECONOMIC BENEFITS OF A T E C H N O L O G Y STRATEGY AND R&D PROGRAM IN CARBON SEQUESTRATION S. Klara 1, D. Beecy2, V. Kuuskraa 3 and P. DiPietro4 United States Department of Energy, National Energy Technology Laboratory, 626 Cochrans Mill Road, P.O. Box 10940 Pittsburgh, PA 15236 USA z United States Department of Energy, Office of Fossil Energy, 19901 Germantown Road Germantown, MD 20874-1290 USA 3Advanced Resources International, 1110 N. Glebe Rd Suite 600 Arlington VA 22201 USA 4Energetics Incorporated, 901 D Street SW Suite 100, Washington D.C. 20024 USA

ABSTRACT

A modeling framework developed over the past several years for the U.S. Department of Energy's Carbon Sequestration Program examines future greenhouse gas (GHG) emissions scenarios and quantifies the economic benefits that result from an investment in carbon sequestration technology development. The CarBen (Carbon Sequestration Benefits) model combines results from a general equilibrium model with non-energy data and extrapolations through 2040 to provide a robust, transparent representation of the United States GHG emissions issue. The model estimates needed reductions in GHG emissions by calculating the difference between emissions under reference case and lower GHG emissions scenarios. The reduced emissions scenario is consistent with the Administration's Global Climate Change Initiative (GCCI), an 18% reduction in the GHG intensity by 2012 with steady progress toward stabilization thereafter. Under this scenario, U.S. GHG emissions are reduced by 107 million metric tons of carbon equivalent per year (MMTCE/yr) by 2012, and 1,100 MMTCE/yr in 2040. These emissions reductions are below a reference case that assumes significant technology progress. Further emission reductions from improved energy efficiency, from renewables and from non-CO2 mitigation are determined to be insufficient to meet the target reductions. The residual emissions reduction need is 31 MMTCE/yr in 2012 increasing to 800 MMTCE/yr in 2040. Sequestration options that can meet this need are identified and their domestic capacity and cost assessed. In the reduced emissions scenario for the United States, development and deployment of sequestration technology lowers the cumulative cost of GHG emissions reduction by $4 Billion through 2012 and $250 Billion through 2040.

INTRODUCTION

This paper is part of an ongoing effort by the U.S. Department of Energy's Carbon Sequestration Program to assess the economic benefits that may result from investments in carbon sequestration technology development. Earlier versions of this analysis were presented at GHGT-V and the First National Conference on Carbon Sequestration [ 1, 2]. The objective of DOE's sequestration technology development is to create lower cost options for GHG emissions reduction through voluntary challenges and market-based incentives. The benefits

1090 derive from cost altematives for GHG emissions abatement compared to existing altematives. The analysis is forward-looking and relies on assumed future scenarios regarding GHG emissions. As such, there exists an important feedback between the benefits analysis and DOE's Sequestration R&D portfolio. The Benefits analyses process seeks to identify lower cost options for meeting the Administration's current and longer term goals for reducing greenhouse gas emissions. For this, the process uses the CarBen (Carben Sequestration Benefits) model that has the capacity to project CO2 and non-CO2 GHG emissions to year 2040, under a variety of user-selected scenarios. The CarBen model can be run to: • • •

Identify costs and quantities of sequestration options under different GHG emission scenarios Provide information to evaluate the effects of potential incentives, promoting voluntary, market based participation in carbon mitigation, and Demonstrate the economic benefits of sequestration R&D.

The model is linked to a general equilibrium model of the U.S. economy and energy-sector (the National Energy Modeling System (NEMS), operated by the U.S. Energy Information Administration (EIA). In addition, the overall model draws on a series of mini-models and studies, such as the "Value-Added Geologic Sequestration" mini-model and EPA's surveys, projections and marginal abatement cost curves for non-CO2 greenhouse gases. The model incorporates technology progress, equivalent to "learning" in some models, consistent with EIA's NEMS methodology. Finally, the model incorporates a set of emissions reduction "backstop technologies" that are combined into a broad category called Advanced Sequestration. Rather than attempt to build that detail into the general equilibrium model, a "mini-model" of backstops using general equilibrium model data-- and other economic activity d a t a - runs the backstops models offiine. The solution is then tested to be sure it does not violate the general equilibrium model solution.

BENEFITS ANALYSIS

For the benefits analyses in this paper, the CarBen model is calibrated to EIA's 2002 Reference Case, which already incorporates significant advances in technology and reduced carbon intensity. The GHG emission reduction actions and their economic benefits in the Benefit Analysis are those beyond and above the Reference Case. Combined with the EIA data and forecasts are non-energy CO2 and non-CO2 GHGs from EPA and other sources [3,4]. Beyond 2020 we extrapolate emission trends and assume that GDP grows by 3% average per year. Carbon intensity decreases, but not as fast as the GDP grows, giving a net growth in GHG emissions of 1.5% per year. Under the reduced Emissions Scenario, the rate of growth in U.S. GHG emissions is slowed and then stopped according to the following schedule: • • •

2 0 0 2 - 2012: GHG intensity reduced to 152 mtC/$GDP, 18% below AEO 2002 reference case 2013 - 2020: Emissions growth reduced 50% below AEO 2002 reference case 2021 - 2040: GHG emissions stabilized at the 2020 emissions level.

This is consistent with significantly reducing GHG intensity by 2012 and making steady progress on the path to first slow and then stop the growth of our greenhouse gas emissions as set forth in the GCCI. Figure 1 illustrates the emissions gap between the reference case and Reduced Emissions Scenario. In 2012, the reduced emissions scenario will require a reduction of 107 MMTCE below the reference case. By 2040, the delta increases to 1,100 MMTCE. (As a point of reference, a new 400

1091 MW pulverized coal plant emits about 0.6 MMTCE/yr.) The Reduced Emissions Scenario represents significant reductions and a balance between economic and environmental objectives.

o000

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2020

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Figure 1: Reference Case and Reduced Emissions Scenarios

P O R T F O L I O OF T E C H N O L O G Y A portfolio of technologies are employed to meet the needed GHG emissions reduction. The likely contribution of each of the options is assessed by CarBen results presented in Figure 2. Note that the reference case scenario contains significant advancements in energy efficiency, renewable energy, and non-CO2 GHG mitigation. All further impacts contained in the reduced emissions scenario result from accelerated R&D and market incentives.

Efficiency & Renewables: Emission reduction benefits derive from DOE R&D in renewables, enduse efficiency, and supply-side technology efficiency improvements. Incremental emissions reductions are estimated from the EIA High Technology case [3], assuming approximately one-half the EIA High Technology gains scenario could be achieved economically with aggressive R&D.

Non-C02 GHG Mitigation:

Reduced emissions are included for GHGs other than CO2, e.g., methane, nitrous oxide, HGWPs. The emission reduction quantity was estimated based on EPA's "best available current technology" marginal abatement curves [5], and assuming that collaborative activities between DOE and EPA will lower the marginal costs of methane reductions from gas and oil production, coal mining, landfills, and other sources.

Forestry and Agriculture: Forests, grasslands, and other natural ecosystems offer potential for reducing net GHG emissions by their increasing carbon uptake using state-of-the-art technologies. Marginal cost curves developed by McCarl [6] were used to estimate the amount of these emission reductions. The quantity available at a given market price is assumed to be an ultimate value that will be achieved by 2040, with one quarter of this amount is deployed by 2012 and half by 2020. Additional emission reductions are assumed to occur from collaborative R&D between DOE and Agriculture.

1092 1,200 gl " 1,000 .o o n,,

.9

Sequestration

800

600

E tu 1.1.1 0 1-

e-Added Sequestration

400

, Agriculture ;PIG Mitigation 200 & Renew ables 0 2000

2010

2020

2030

2040

Figure 2: Contribution of Technologies to the GHG Emissions Reduction Need

Early Value-Added Geologic Sequestration: Technology options for this category include enhanced oil recovery and enhanced coalbed methane production. The ultimate CO2 storage capacity for these two types of formations in the contiguous United Sates is on the order of 20,000 MMTCE. Estimates of the amount of net COz sequestered per year at a given market price is derived from two studies prepared for the International Energy Agency's GHG Programme [7,8], and subsequent work conducted by one of the authors. At a shadow price of $25/tonC, EOR sequesters 10 MMTCE/yr and ECBM 2 MMTCE/yr in 2012. These results are reliant on R&D aimed at expanding the number of reservoirs that are economic at a given shadow price. Geologic sequestration relies on a supply of inexpensive captured CO2. It is well documented that capturing CO2 from low-purity streams, such as flue gas, is prohibitively expensive with current technology. However, a diverse set of industrial conversion processes exhaust a highly pure stream of CO2 as a natural consequence of operation. Studies conducted by the authors show that roughly 44 MMTCE/yr of easily captured CO2 is currently available from varied sources in the contiguous United States and that many of the CO2 vents are geographically co-located with opportunities for valueadded geologic sequestration. CO2 vents include cement manufacture, ammonia production, aluminum production, ethanol production, oxygen blown gasification, natural gas processing, petroleum refining, and helium production. The amount of high-purity CO2 that is vented is expected to grow due to over 100 MMTCE/yr by 2020 as existing capital stock is replaced with advanced fossil fuel conversion technologies.

Advanced Sequestration:

This area includes C02 storage in novel geologic formations, CO2 conversion, inexpensive capture from advanced fossil fuel conversion processes, reductions in emissions of non-CO2 gases beyond what is achieved with existing technology, and other advanced concepts. Novel geologic formations include different types of saline formations with the potential for in-situ chemical conversion of CO2. salt formations, salt domes, and depleted CO2 domes. It also includes hydrocarbon bearing shales and depleting gas reservoirs, both of which have the potential for value added by-products. Figure 2 shows a large amount of emissions reduction being supplied by advanced concepts beyond 2030, which justifies and motivates its robust R&D initiatives.

1093 MONETARY BENEFITS

The CarBen model estimates the monetary benefits of sequestration deployment in terms of a reduced cost of GHG emissions abatement. Benefits equal the difference between the cost of carbon sequestration technologies and displaced non-sequestration options, multiplied by the quantity of emissions reduction. In the reduced emissions scenario, application of value-added geologic and advanced sequestration technology reduce the cumulative cost of GHG emissions reduction by roughly $4 Billion through 2012 and $250 Billion cumulatively through 2040. In addition, the program works collaboratively with the U.S. Environmental Protection Agency and the U.S. Department of Agriculture to develop advanced options for non-CO2 emissions abatement and terrestrial sequestration, providing a shared monetary benefit on the order of $3 Billion cumulatively through 2020.

CONCLUSIONS An eventual transformation of the U.S. energy systems toward lower GHG emissions needs to be motivated by prices and markets, guided and paced by science, facilitated by new technology, and underpinned by supporting and coordinated domestic and international policies. Sequestration technology can facilitate and reduce the costs of this transition, creating innovative options for climate change mitigation. •

The President's Global Climate Change Initiatives will require reduction in GHG emissions of 107 MMTCE/yr below the reference case scenario in 2012.

•

The required GHG emissions reduction exceeds that which can be supplied by aggressive investments in advanced technologies to increase energy efficiency and renewable energy.

•

Finding cost-effective means of achieving the GCCI's goals will require a strategy of focused public/private R&D partnerships and performance-based market incentives.

•

Sufficient capacity in both geologic formations amenable to C O 2 storage and high-purity CO2 vents exists to meet the near-term residual GHG emissions reduction needs, assuming sequestration R&D is robust and successful.

•

Novel sequestration technologies and approaches are needed to meet mid- and long-term goals for carbon sequestration in the United States.

•

Cumulative benefits of near- and longer-term sequestration technologies are estimated to be roughly $4 Billion by 2012 and $250 Billion by 2040.

REFERENCES

1. Beecy, Kuuskraa, DiPietro. (2000) "The Economics Benefits of Carbon Capture and Sequestration R&D Under Uncertainty" Conference Proceedings of the 5 th International Conference on Greenhouse Gas Control Technologies. 2. Beecy, Kuuskraa, DiPietro. (2001) "U.S. Economic Benefits of Carbon Capture and Sequestration Given Various Future Energy Scenarios" Conference Proceedings of the First National Conference on Carbon Sequestration 3. U.S. DOE, Energy Information Administration. (2001) Annual Energy Outlook 2002 4. U.S. EPA (2002) U.S. Climate Action Report - 2002. 5. U.S. EPA (2001) Addendum to the U.S. Methane Emissions 1990-2020:2001 Update for Inventories, Projections, and Opportunities for Reductions, www.epa.gov/~h~info/reports/index.htm.

1094 6. McCarl, B., Schneider, U., et. al. (2001) "Economic Potential of Greenhouse Gas Emissions Reductions: Comparative Role for Soil Sequestration in Agriculture and Forestry" Conference Proceedings of the First National Conference on Carbon Sequestration 7. International Energy Agency Greenhouse Gas R&D Programme (2000) "Barriers to Overcome in Implementation of CO2 Capture and Storage (1) Storage in Disused Oil and Gas Fields." IEA Report Number PH3/22 8. International Energy Agency Greenhouse Gas R&D Programme (1998) Enhanced Recovery of Coal bed Methane." IEA/CON/97/27

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1095

PROSPECTS FOR CARBON CAPTURE AND SEQUESTRATION T E C H N O L O G I E S ASSUMING THEIR T E C H N O L O G I C A L LEARNING*" Keywan Riahi l'*, Edward S. Rubin 2, Leo Schrattenholzer l i International Institute for Applied Systems Analysis (IIASA), Schlossplatz 1,2361 Laxenburg, Austria 2 Carnegie Mellon University, Baker Hall 128A, 5000 Forbes Avenue, Pittsburgh, PA 15213, U.S.A

ABSTRACT This paper analyzes potentials of carbon capture and sequestration technologies (CCT) in a set of long-term energy-economic-environmental scenarios based on alternative assumptions for technological progress of CCT. In order to get a reasonable guide to future technological progress in managing CO2 emissions, we review past experience in controlling sulfur dioxide emissions (SOa) from power plants. By doing so, we quantify a "learning curve" for CCT, which describes the relationship between the improvement of costs due to accumulation of experience in CCT construction. We incorporate the learning curve into the energy modeling framework MESSAGE-MACRO and develop greenhouse gas emissions scenarios of economic, demographic, and energy demand development, where alternative policy cases lead to the stabilization of atmospheric CO2 concentrations at 5 50 parts per million by volume (ppmv) by the end of the 21 st century. Due to the assumed technological learning, costs of the emissions reduction for CCT drop rapidly and in parallel with the massive introduction of CCT on the global scale. Compared to scenarios based on static cost assumptions for CCT, the contribution of carbon sequestration is about 50 percent higher in the case of learning resulting in cumulative sequestration of CO2 ranging from 150 to 250 billion (109) tons carbon during the 21 st century. The results illustrate that assumptions on technological change are a critical determinant of future characteristics of the energy system, hence indicating the importance of long-term technology policies in reducing greenhouse gas emissions and climate change. INTRODUCTION The mitigation of adverse environmental impacts due to climate change requires the reduction of carbon dioxide emissions from the energy sector, the dominant source of global greenhouse-gas emissions. There are a variety of possibilities to reduce carbon emissions, ranging from the enhancement of energy efficiency to the replacement of fossil-based energy production by zero-carbon technologies. Most of the currently available mitigation technologies, however, are more costly and technologically inferior in some ways compared to the older and more "mature" fossil alternatives. Thus, there is an increasing interest among experts and policy makers in "add-on" environmental strategies to combine state-of-the-art fossil technologies with advanced technologies that capture carbon for subsequent sequestration. Such strategies, if successfully implemented, could enable the continuous use of fossil energy carries at low (or almost zero) emissions. Present costs for carbon capture technologies (CCT) to reduce emissions are between 35 and 264 $/tC (DOE, 1999), corresponding to a prohibitive cost increase for electricity of at least 25 $/MWh. Given the current costs, it is unlikely that CCT successfully enter the energy market, even if international

" This article is based on a more extensive study conductedjointly by IIASA and the Carnegie Mellon University. An earlier version of the paper was submitted to the Journal of Energy Economics in June 2002 (Riahi et al., 2002). This research was funded by the Integrated Assessment program, Biological and Environmental Research (BER), U.S. Department of Energy under Award Number DE-FG02-00ER63037.Any opinions, findings, conclusions or recommendation expressed herein are those of the authors and do not reflect the views of DOE, IIASA, or Carnegie Mellon University. " Corresponding author: KeywanRiahi is a Research Scholar at the International Institute for Applied SystemsAnalysis (IIASA), Schlossplatz 1, 2361 Laxenburg,Austria, Tel: +43-2236-807-491, Fax: +43-2236-807-488, Email: [email protected].

1096 agreements and efficient institutions for CO2 abatement would exist. Their pervasive diffusion will require substantial efforts to induce "technological learning", which could accomplish considerable cost reductions in the long run. Thus, in this paper we quantify the potential and achievable pace of technological learning for CCTs. We incorporate the learning into the energy modeling framework MESSAGE-MACRO (Messner and Schrattenholzer, 2000) and develop a set of global greenhouse gas emissions scenarios. Within this frame, we analyze the potential of CCTs in the context of other main mitigation options, such as fuel switching and enhanced energy conservation. ESTIMATION OF LEARNING CURVES F O R CARBON CAPTURE T E C H N O L O G I E S Generally, costs - and other indicators of technology performance - improve as experience is gained by producers (learning-by-doing) and consumers (learning-by-using). In order to get a reasonable guide to future technological progress of carbon capture technologies, past experience in controlling sulfur dioxide emissions (SO2) from power plants was reviewed (Taylor 2001). In particular, we have estimated learning rates of capital and operating cost reduction for the most common flue gas desulfurization (FGD) technology used at coal-fired power plants for SO2 capture. This technology (commonly known as SO2 "scrubbers") employs similar principles of operation as currently commercial CO2 capture systems that use chemical sorbents to remove CO2 from gas mixtures such as combustion products. For FGD systems, investment costs declined by 13% for each doubling of capacity worldwide, and this is therefore also the value we used to quantify the "learning curve" for CCTs. l SCENARIO D E V E L O P M E N T In order to obtain a plausible range of estimates for the deployment of CCT, we analyze two alternative baseline scenarios, depicting future worlds of increasing carbon emissions with presumably high impacts due to climate change. For each we develop two carbon mitigation scenarios (one with and one without CCT learning) aiming at the stabilization of atmospheric carbon concentrations at about 550 ppmv. The sequel of this section first presents the main characteristics of the respective baseline and carbon mitigation scenarios, proceeding later to the implications for CCT.

Baseline reference scenarios: Both baseline scenarios are selected from the set of 40 IPCC-SRES reference scenarios (IPCC-SRES, 2000). The B2-MESSAGE scenario (Riahi and Roehrl, 2000a) was selected because it is a kind of"middle of the road" (dynamics-as-usual) scenario. In addition, we selected the A2-MESSAGE scenario (Riahi and Roehrl, 2000b), since A2 portrays a fossil-intensive future characterized by heavy reliance on coal-based energy production. A2 and B2 are based on different assumptions of socioeconomic development, technological progress, and political change. They result in widely differing world energy systems, which are cost-optimal strategies under the given assumptions, and lead to a wide range of emissions levels (Figure 1). Assumptions for the main scenario drivers and results are presented in TABLE 1. Carbon mitigation scenarios: Two stabilization scenarios for each baseline were developed - one assuming constant costs for CCTs (A2550s, B2-550s), and one including learning for CCTs (A2-550t, B2-550t). The resulting CO2 emissions trajectories of the mitigation scenarios are shown in Figure 1. They are characterized by a peak of about 9 to 12 GtC around the middle of the 21 st century. Subsequently, emissions decline to slightly less than the 1990 emissions level (6 GtC) by 2100. The emissions in the baseline and the stabilization scenarios is quite similar through 2020, and only after 2020 do emissions reductions become pronounced. This is partly because power plants have lifetimes on the order of 30-40 years, which makes for slow turnover in the energy capital stock, and partly because of the temporal flexibility built into the concentration constraint.

i The "learning curve" equation is found to describe the decline in production costs for a wide range of manufacturing activities remarkably well (e.g., Dutton and Thomas, 1984; Naki6enovi6 et al., 1998; McDonald and Schrattenholzer, 2001). The relationship is given by an equation of the form: cost = a* (cumulative number of units produced) -b, where -b gives the slope for the improvement in costs (hours) in producing the units. On a log-log scale this equation plots as a straight line with slope -b. Generally, the "progress ratio" (2b) describes the ratio of current cost to initial cost after a doubling of production. Thus, a progress ratio of 0.80 meant that costs decreased by 20 percent for each doubling. Some authors therefore prefer the term "learning rate" for the latter quantity.

1097 The model is free to choose when and where to reduce carbon emissions, and later reductions coinciding with turnover in capital plant are usually cheaper, because of both technological progress and discounting 2. 30 ...............................

~ 20

IA 2

-

g,o~: 0 1900

t ," 1950

,

,

2000

2050

2100

Figure 1: Global carbon dioxide emissions in the A2 and B2 baseline scenarios, and in the respective stabilization scenarios with and without learning for CCT. TABLE 1 OVERVIEW OF SCENARIO DRIVERS AND RESULTS COMPARE WITH 1990 VALUES FOR POPULATION (5.3 BILLION), GDP (20.9 TRILLION (1990)US$), PRIMARY ENERGY (352 EJ), TOTAL CO2 EMISSIONS (6.2 GTC), CO2 CONCENTRATION (354 PPMV). Year Scenario

Baseline scenarios

Stabilization scenarios Static CCTs

Learning CCTs

A2

B2

A2-550s

B2-550s

A2-550t

B2-550t

Population (billion)

2050 2100

11.3 15.1

9.4 10.4

11.3 15.1

9.4 10.4

11.3 15.1

9.4 10.4

Global gross domestic product (trillion 1990US$)

2050 2100

82 243

110

235

81 236

109 231

81 237

109 231

Primary energy (E J) Cumulative carbon emissions (GtC) Cum ulative ca rbon sequestration (GtC) Carbon concentrations (ppmv)

2050 2100

1014 1921

869 1357

959 1571

881 1227

960 1636

1257

1990-2100 1990-21 O0

1527

1212

992

948

990

950

167

90

243

137

2100

783

550

550

550

550

-

603

883

Although the resulting emissions trajectories of the four stabilization scenarios are similar, we shall show below that the contributions of individual mitigation measures to bring down emissions differ significantly. T H R E E KINDS OF M I T I G A T I O N M E A S U R E S Applying the carbon concentration constraint to the baseline scenarios results in significant changes of energy demand and technology mix. Compared to the respective baseline scenarios, three principal contributors were identified by MESSAGE and MACRO as the most cost-effective route to meet the required stabilization target: •

Fuel switching away from carbon-intensive fuels such as coal.

•

Scrubbing and removing CO2 in power plants and during the production of synthetic fuels, mainly methanol and hydrogen.

•

Lower energy demand (enhanced energy conservation) of the stabilization case compared to the baseline counterpart, due to higher energy costs in the stabilization cases compared to their baseline scenario counterparts. The carbon reductions of each of the mitigation measures in the stabilization scenarios are summarized in TABLE 2. In all stabilization scenarios the largest reductions comes from structural changes in the energy system. To satisfy the carbon constraint, all mitigation scenarios make pronounced shifts to less carbonintensive primary-energy resources, and coal's share of primary energy decreases considerably. The second most important contribution is due to carbon capture and sequestration, where the emissions reductions are

2 For the scenarios presented in this paper, a discount rate of 5% was applied.

1098

particularly high in the case of learning CCT technologies. Cost improvements in the case of technological learning for CCT result in additional markets for carbon capture and enable comparatively higher shares of fossil energy production, compared to the cases with constant CCT costs (TABLE 2). As illustrated by the results, each of the three main mitigation measures is important, and none of the suggested mitigation options alone is sufficient to meet a 550 ppmv stabilization target. Hence, we conclude that effective mitigation strategies have to take into account the whole portfolio of technological possibilities, which includes also carbon capture with subsequent sequestration. TABLE 2 EMISSIONS REDUCTIONS (IN GTC) OF THE MAIN MITIGATIONMEASURES IN THE STABILIZATIONSCENARIOS FOR THE YEARS 2050 AND 2100. Demand reduction 2050 2100 Static CCTs A2-550s B2-550s Learning CCTs A2-550t B2-550t

Fuel switching 2050 2100

CO2 capture and sequestration 2050 2100

Total 2050

2100

0.3 0.3

3.6 1.3

2.2 1.4

12.5 3.9

0.5 0.3

5.8 3.0

3.0 2.0

21.9 8.2

0.3 0.3

3.7 1.5

2.1 1.1

9.5 4.0

0.4 0.3

8.9 4.0

2.9 1.7

22.0 9.5

COSTS OF CARBON CAPTURE AND SEQUESTRATION The capturing of CO2 accounts for about three-fourths of the total cost of a carbon capture, storage, transport, and sequestration system. The cost assumptions in the scenarios are based upon estimates from several recent studies (Rubin, et al., 2001; EPRI & USDOE, 2000; Simbeck,1999; Herzog,1999) assuming that CO2 is captured from flue gases by currently available chemical absorption systems. Generally, the capturing of CO2 is associated with efficiency losses of the power generation process, and additional costs for the carbon capture facilities. The (aggregated) carbon abatement costs for coal technologies resulting from our assumptions are 196 US$/tC, compared to 137 US$/tC for natural-gas (both figures including transportation and disposal). 3 In the stabilization scenarios with constant costs (A2-550s, B2-550s), we assumed that the capital costs for CCTs remain constant over time. In contrast, in the case of learning CCTs (A2-550t, B2-550t), we assumed that their costs decrease with accumulated experience in CCT construction. The development of carbon reduction costs as a function of cumulative installed CCT capacities in the scenarios is illustrated in Figure 2a. Due to technological learning, CCT costs drop rapidly in the stabilization scenarios, leading to cost reductions by a factor of four until the end of the century. In line with the development of costs, CCT technologies diffuse pervasively into the energy markets, accomplishing the continuous use of fossil fuels at relatively modest costs and low carbon emissions. Total reduction costs for natural gas technologies drop to 34-38 US$/tC, and those of coal technologies to 41-61 US$/tC (Figure 2a). 4 CCT M A R K E T SHARES IN T H E E L E C T R I C I T Y S E C T O R The scenario's market shares of CCT technologies are the result of complex interactions between demandpull to supply-push activities. On the demand side, the carbon concentration limit enforces the introduction of new and advanced technologies with low carbon intensities. On the supply side, increasing returns from induced technological leaming of CCTs, pushes their market penetration (in the t-scenarios) from the supply side. Together, this results in very successful penetration of CCT technologies in the scenarios with technological learning, compared to scenarios with static cost assumptions (Figure 2b). Initially, CCTs are expensive and limited in their application. They have to first prove themselves during the demonstration phase where performance rather than costs is the overriding criterion. Then subsequent improvements and

3 Costs of carbon removal in synthetic fuels production (and from IGCC) were assumed to be 46 US$/tC (inclusive transportation and disposal). For transportation and disposal we assumed that captured CO2 is transported in liquid state, through 250 km of pipeline and disposed of in geological formations. The cost for CO2 transportation is based on estimates from the lEA (1999), assuming originally a distance of 500 km at 45 $/tC. Here, half the distance and an economy of scale factor of 2/3, which results in 28 $/tC of transport plus disposal cost is assumed. 4 The development of the carbon reduction costs for CCTs depend also on the regional resource availability and the development of fuel costs. In addition, assumptions on technological change for the power plants themselves influence the carbon reduction costs of CCTs. A sensitivity analysis using different initial costs for CCTs suggests that the learning rate might be the most decisive factor, not only for the costs, but also for the successful diffusion and dissemination of CCTs (given a specific carbon constraint).

1099

cost reductions lead to a wider application. Finally, growth rates slow down as markets become saturated. The diffusion of CCTs proceeds along a typical S-shaped pattern: slow at the beginning, followed by accelerating growth that ultimately slows down as markets become saturated. Comparing the diffusion of CCTs in scenarios with learning (A2-550t, B2-550t) with those assuming constant costs of these technologies (A2-550s, B2-550s) shows that the market penetration of CCTs is accelerated due to technological learning. Particularly, the carbon capture from coal technologies benefits considerably from the learning effect, leading to global market shares of more than 90 percent in 2100 (compared to 60-70 percent in the case of static costs). At the end of the century, almost all fossil power plants are equipped with carbon capture technologies in the case of learning (Figure 2b). The resulting CO2 emissions from coal and natural gas-based power generation are also shown in Figure 2b. The CO2 emissions path in the scenarios follows an inverse U-shaped pattern similar to environmental Kuznets curves, observed for other pollutant emissions in the past, such as sulfur (Grtibler, 1998). After initial growth, CO2 emissions peak around the middle of the century and decline later, when the carbon capture and sequestration technologies gain considerable market shares. Most notably, until the end of the century, global CO2 emissions from coal and gas power generation decreases by more than a factor of three, while power generation from these technologies grow three to five times their present production (about 27 EJ). --i

1000

• -

-

-:.

.

.

.

.

.

.

.

b)

.

100%

4000

,,c-~ . . . . . . . . . .

I C O 2 ernissions~

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.............................................

) cZ~I . . . . .

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~

3500

,000

N

F lOO

25o()

.........................

g,

i_

.

.........

lOOO0

lO

1

10

100

1000

Cumulative Installed capacities with carbon scrubbing In GW(e), 2000.2100

10000

0*/. ' 2000

~ 2020

2040

o 2060

2080

2100

Figure 2: (a) Technological learning of carbon capture technologies in the A2-550t and B2-550t scenarios, illustrated as decreasing specific carbon reduction costs over accumulated experience (cumulative installed power generation capacities). (b) Market penetration of "learning" CCT technologies for natural-gas and coal power plants in the A2550t and B2-550t scenarios (left-hand axis). Dashed lines depict the development in the A2-550t scenario, and uninterrupted lines in B2-550t. Also shown are the aggregated CO2 emissions from coal and natural-gas power generation in the respective scenarios (right-hand axis). The cumulative carbon sequestration in the scenarios - from 1990 to the 2100 - are shown above in TABLE 1. Generally, the amounts scrubbed depend strongly on (1) the socio-economic and technological assumptions in the baseline scenarios; and (2) the assumptions with respect to technological learning for CCT technologies. Cumulative carbon sequestration is higher in the case of the A2 scenarios compared to B2, and higher in scenarios with learning CCTs than in those with static cost assumptions. 5 In the case of learning CCT's cumulative carbon emissions from 1990 to 2100 range between 137 and 243 GtC. This corresponds to a 50 percent increase of sequestration due to learning effect for CCTs, compared to the scenarios with static costs (90 to 167 GtC). 6

5 Since the A2 baseline depicts a future of heavy reliance on coal technologies, cumulative carbon sequestration is particularly high in A2, calling for environmentally compatible solutions that permit the continuous use of coal at low carbon emissions. In contrast, fossil-based power generation plays a less prominent role in the B2 baseline scenario, and is mainly dominated by advanced natural gas technologies, in particular gas-combined-cycle. Hence, in A2 coal scrubbers dominate, while in B2 natural~ as scrubbers account for the bulk of the reductions. The amount of carbon emissions that has been captured in the scenarios is well below the maximum potential of storage capacity of depleted oil and gas fields alone (Herzog 2001, Riahi et al., 2002). Nevertheless, it still has to be proved, whether all reservoirs proposed for carbon sequestration are effective, safe and environmentally sound.

1100

S U M M A R Y AND CONCLUSIONS Our analysis shows that the timing, costs, and contribution of carbon mitigation measures strongly depend on (1) the socio-economic and technological assumptions in the baseline scenario, and (2) the assumed learning potential of carbon capture and sequestration technologies. Assuming that CCT technologies learn at a similar pace as SO2 abatement technologies in the past, the long-term reduction potential for CCT is vast; in our scenarios ranging between 140 and 250 GtC of cumulative CO2 sequestration (from 1990 to 2100, assuming a stabilization target of 550 ppmv). This is particularly due to large-scale investments into CCT and the accumulation of experience, which leads to rapid cost decreases of these technologies. Even though their widespread deployment requires decades to come, we conclude that carbon capture and sequestration is one of the obvious priority candidates for long-term technology policies and enhanced R&D efforts to hedge against the risk associated with high environmental impacts of climate change. Our scenario analysis also showed that the capturing of carbon with subsequent sequestration might not be sufficient to meet a 550 ppmv stabilization constraint (in the year 2100), even in the case of a very successful market penetration for CCTs. In addition to carbon sequestration, reaching this goal must also include better energy efficiency and the increased use of low-carbon emitting energy sources, in particular fuel switching, primarily away from carbon-intensive coal to low or zero-carbon fuels. Acknowledging the major differences between scenarios with learning CCTs and those with static cost assumptions leads us to two important conclusions. First, improved future models should be capable of characterizing future changes in cost and performance resulting from technology innovation (learning). Second, climate policies need to be extended to include technology policies, in order to make the diffusion of environmentally sound technologies operational in the long run. This calls particularly for early action to accomplish the required cost and performance improvements in the long term, including the creation of niche markets, the development of small-scale demonstration plants, and targeted R&D. REFERENCES 1. Dutton, J.M., and Thomas, A. 1984. Treating progress ratios as a marginal opportunity. Academy of Management Review, 9(2):235-247 2. EPRI& USDOE, 2000. Evaluation of Innovative Fossil Fuel Power Plants with CO2 Removal, EPRI, Palo Alto, CA 3. Grtibler, A., 1998, A review of global and regional sulfur emissions scenarios. Mitigation and Adaptation Strategies for Global Change, 3(2-4), 383-418. 4. Herzog,H.J., 2001. What Future for Carbon Capture and Sequestration. Environmental Science and Technology, Volume 35(7), 148A-153A. 5. IPCC(Intergovernmentai Panel on Climate Change), 2000. Naki~enovi~N., J. Alcamo, Davis, G., de Vries, B., Fenhann, J., et al. (2000), Special Report on Emissions Scenarios (SRES), A Special Report of Working Group III of the Intergovernmentai Panel on Climate Change, Cambridge UniversityPress, Cambridge, UK. 6. McDonald, A. and Schrattenholzer, L., 2001. Learning curves and technology assessment, Special Issue of the International Journal of Technology Management, Vol. 8, No. 23. 7. Messner, S., and L. Schrattenholzer. 2000. MESSAGE-MACRO: Linking an energy supply model with a macroeconomic module and solving it iteratively, Energy 25:267-282. 8. Nakicenovic N, Grt~bler A, and McDonald A (eds.). 1998. Global Energy Perspectives. Cambridge University Press, Cambridge, UK, ISBN 0521642000. 9. Riahi, K., Roehrl, R.A., 2000a. Greenhouse Gas Emissions in a Dynamics-as-usual Scenario of Economic and Energy Development. Technological Forecasting and Social Change, Vol. 63(3). 10. Riahi, K., Roehrl, R.A., 2000b. Energy technology strategies for carbon dioxide mitigation and sustainable, Environmental Economics and Policy Studies, Springer, Tokyo, 3(2), pp. 89-123. 11. Riahi, K., Rubin, E.S., Taylor, M.R., Schrattenholzer, L., Hounshell, D., 2002, Technological learning for carbon capture and sequestration technologies, Energy Economics (forthcoming). 12. Rubin, E.S., A.B. Rao and M.B. Berkenpas, 2001. A multi-pollutant framework for evaluating CO2 control options for fossil fuel power plants. Proceedings of First National Conference on Carbon Sequestration, US Department of Energy, Washington, DC. 13. Simbeck, D., 1999. A portfolio selection approach for power plant co2 capture, separation and r&d options, Proc. of 4th Int'l. Greenhouse Gas Control Technologies, Elsevier Science Ltd. 14. Taylor, M., 2001. The Influence of Government Actions on Innovative Activities in the Development of Environmental Technologies to Control Sulfur Dioxide Emissions from Stationary Sources. Ph.D. Thesis, Carnegie Mellon University, Pittsburgh, PA, Jan 2001. 15. U.S. DOE (Department of Energy), 1999. Carbon Sequestration - Research and Development. U.S. Department of Energy, Washington DC 20585, (www.doe.gov/bridge).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1101

CO2 STORAGE AND SINK ENHANCEMENTS: DEVELOPING COMPARABLE ECONOMICS B.R. Bockl, R.G. Rhudy2, and H.J. Herzog 3 ~Public Power Institute, Tennessee Valley Authority, Muscle Shoals, AL, USA 2Electric Power Research Institute, Palo Alto, CA, USA 3Laboratory for Energy and the Environment, Massachusetts Institute of Technology, Cambridge, MA, USA

ABSTRACT This paper reports on a project that compared the economics of major technologies and practices under development for CO2 storage and sink enhancement, including options for storing captured CO2, such as active oil reservoirs, depleted oil and gas reservoirs, deep aquifers, coal beds, and oceans, as well as the enhancement of biological sinks such as forests and croplands. For the geologic and ocean storage options, CO2 capture costs from another project were added to the costs of CO2 storage estimated in this project to provide combined costs of CO2 capture and storage. Combined costs of CO2 capture and storage were compared with CO2 sink enhancement costs on a life-cycle greenhouse gas (GHG) avoided basis. The CO2 storage and sink enhancement options compared in this project differ greatly in the timing and permanence of CO2 sequestration. In addressing the timing and permanence issue, a 100-year planning horizon was assumed and the net present value of both costs and revenues was considered. The methods for comparing the economics of diverse CO2 storage and sink enhancement options are overviewed and representative base-case costs of storage and sink enhancement options are compared.

INTRODUCTION In order to plan for potential CO2 mitigation mandates, utilities need better cost information on CO2 mitigation options, especially storage and sink enhancement options that involve non-utility operations. One of the major difficulties in evaluating CO2 storage and sink enhancement options is obtaining consistent, transparent, accurate, and comparable economics. This paper reports on a project that compares the economics of major technologies and practices under development for CO2 storage and sink enhancement, including options for storing captured COz, such as active oil reservoirs, depleted oil and gas reservoirs, deep aquifers, coal beds, and oceans, as well as the enhancement of biological sinks such as forests and croplands.

CO2 CAPTURE AND STORAGE

Methodology Capture costs were obtained from a DOE/EPRI [1] project that evaluated several CO2 capture technologies. Integrated gasification combined cycle (IGCC) cases were used as the basis for the

1102 capture component of this project. Costs of CO2 capture were based on differences between reference and capture IGCC plants. Revenue requirement (RR) methodology which is applicable to regulated utilities was used by DOE/EPRI [1] to estimate costs of CO2 capture. Revenue requirement methodology was also used in this project to estimate CO2 storage costs so that capture and storage costs could be combined on an equal basis. Storage options were sized to accommodate the CO2 captured (2.158 Gg CO2/year) from the IGCC CO2 capture plant noted above, 404 MW (net), operating at 80 percent capacity factor; 90 percent of the CO2 produced was captured.

Revenue Requirement Methodology In the DOE/EPRI [1] project, a levelized RR ($/yr) was calculated for each year of the 20-year book life of the plant as follows: Levelized RR = Levelized Carrying Charge (LCC) + Expenses = Levelized annual cost of

electricity

(1) where LCC = Total Plant Cost (or TPC) x Levelized Carrying Charge Factor (or LCCF), and Expenses include O&M and fuel costs. The TPC includes process facilities capital, general facilities capital, engineering and home office overhead, project and process contingencies, and miscellaneous expenses generally included under owners costs. Assumptions in the DOE/EPRI [ 1] project resulted in a LCCF of 0.15 and an after-tax discount rate of 6.09%. In calculating the costs of storing captured CO2, the RR methodology for CO2 capture was generalized to accommodate options for enhanced revenues from CO2 storage such as enhanced oil recovery (EOR) and enhanced coal bed methane recovery (ECBMR): Levelized RR = LCC + O&M costs - Enhanced revenues = Levelized annual net cost of storing CO2 (2)

GHG Bases for Calculating Costs Costs ($/Mg C equivalent) were estimated on CO2 captured, CO2 avoided, and life-cycle (LC) GHG avoided bases. The LC GHG avoided basis included all significant GHG avoided from cradle to grave, but did not include externalities (i.e., damage assessments). Carbon dioxide avoided and LC GHG avoided via CO2 capture were estimated based on the difference in CO2 and LC GHG emissions from reference and capture plants. Carbon dioxide and LC GHG emissions were also estimated for each of the CO2 storage options evaluated, and CO2 and LC GHG emissions avoided were estimated for CO2 capture and storage combined. Combined costs of CO2 capture and storage were compared with costs of sink enhancement options, forestry and cropland, on a LC GHG avoided basis.

Accounting for Timing Differences: C02 Storage vs. Sink Enhancement The timing and permanence of GHG abatement and the timing of costs differ greatly between CO2 capture/storage options and CO2 sink enhancement options. In addressing the timing and permanence issue, a 100-year planning horizon was assumed and CO2 removals and emissions/leaks were treated as separate events. The idea is that when one removes a ton of CO2, one receives the current price of CO2. When a ton of CO2 is released, the owner of this CO2 must then purchase a credit from elsewhere at the current price. This approach assumes that CO/prices will be set as a result of government policy either through market mechanisms (e.g., a cap and trade system) or in the form of a tax (e.g., a carbon tax). With these assumptions, the cost of CO2 storage and sink enhancement ($/Mg C equivalent) was calculated as a breakeven C price ($/Mg C equivalent). A breakeven C price was calculated for each CO2 storage and sink enhancement scenario by setting the sum of discounted C revenues (C price times the amount of C removed)

1103 equal to the sum of discounted C storage or sink enhancement costs for the 100-year planning horizon and solving for a breakeven C price.

Base Case Assumptions Base cases for the geologic storage options assumed a pipeline C02 transportation distance of 100 km from the power plant to the storage operation and a well depth of 1220 m for all geologic options except enhanced coalbed methane recovery in which case a well depth of 610 m was assumed. In calculating enhanced oil and gas revenues, wellhead oil and gas prices of $15 per bbl and $2.00 per MBtu, respectively, were assumed. The ocean pipeline and ocean tanker options assumed a pipeline CO2 transportation distance of 100 km from the power plant to the ocean shore and a pipeline or tanker CO2 transportation distance of 100 km from the shore to the ocean injection point. An injection depth of 2000 m was assumed for both ocean options. The ocean options were designed on a scale to accommodate CO2 from three base-case IGCC power plants. Results

GHG Bases for Calculating Costs The IGCC capture plant captured 2.158 Gg (million tonnes) CO2 per year. Compared with the IGCC reference plant, the IGCC capture plant avoided 1.824 Gg direct CO2 emissions per year, and avoided 1.807 Gg LC GHG CO2 equivalents per year. Carbon dioxide and LC GHG emissions from the CO2 storage operations were relatively small (not presented) and were subtracted from CO2 avoided during capture and LC GHG emissions avoided during capture, respectively, to get CO2 avoided via capture and storage combined and LC GHG emissions avoided via capture and storage combined. Costs Carbon dioxide capture costs were $54/Mg C eq. CO2 captured, $63/Mg C eq. C02 avoided via capture, and $64/Mg C eq. LC GHG avoided via capture. Carbon dioxide capture + net storage costs are presented in Table 1 for base cases on C equivalent stored, C equivalent CO2 avoided via capture and storage, and C equivalent LC GHG avoided via capture and storage bases. These costs were calculated on an NPV basis for years 1-100. Costs are very similar on CO2 and LC GHG avoided bases and are significantly higher on these two bases than on the stored basis. The two lowest-cost storage processes are enhanced oil recovery and enhanced coalbed methane recovery, both of which provide enhanced revenues that partially offset costs of COa storage.

Storage Process

TABLE 1 co2 CAPTURE+ NET STORAGECOSTS FOR BASECASES $/Mg C eq. $/Mg C eq. C02 stored C02 avoided

$/Mg C eq. LC GHG avoided

Depleted Gas Reservoir Depleted Oil Reservoir Deep Saline Aquifer Enhanced Oil Recovery Enhanced Coalbed Methane Recovery

72 68 65 12

85 80 77 15

86 81 77 15

34

41

41

Ocean Pipeline Ocean Tanker

74 118

86 141

89 143

1104 FOREST MANAGEMENT Case Studies Additional C can be sequestered in forests by establishing new plantations, restoring existing forests, or by avoiding deforestation.

Cases studies representing a wide range of management types, trees, and geographic locations were included (Table 2). TABLE 2 FORESTRYCASE STUDIES

Type of Management

Type of Trees

Country/region

Plantation Plantation Plantation Restoration Restoration Agro-forestry Avoidance of deforestation

Loblolly pine Douglas Fir Spanish Cedar Pine-oak Miombo Mango-Tamarind Various

USA (South) USA (Pacific NW) Mexico Mexico Southern Africa India (South) Mexico

Costs Base-case costs ($/Mg C eq.) are presented in Figure 1 on an aboveground basis (costs/aboveground C) and a life-cycle GHG avoided basis with product revenues net costs after product revenues/aboveground C + below ground C + product C + non-CO2 GHG C eq.). These two accounting bases bracket the costs ($/Mg C eq.) for each of the cases. Costs are on an NPV basis, 100-year planning horizon. The Mango-Tamarind costs are relatively high on an aboveground basis because costs for the ago-forestry system are high and no credit is taken for the relatively high value agricultural products. The Mango-Tamarind costs are relatively low on the aboveground C + below ground C + product C + non-CO2 GHG C eq. basis because credit is taken for both more C and products that more than offset costs.

200 m,m

o=

150

"=

100

E

5o o

~ @

-50 -lOO

-150 -200

! Aboveground

i

• Aboveground+ Below ground + products - non CO2 GHGs i

Figure 1: Base-case costs for forestry cases

1105 CROPLAND VIA REDUCING T I L L A G E Reducing tillage on cropland slows the rate of organic matter decomposition and increases soil organic matter levels until a new equilibrium level is attained (typically about 20 to 30 years after shifting from intensive tillage to no tillage). Carbon is sequestered in the added soil organic matter. Reducing tillage reduces equipment and fuel use, increases herbicide use, and can affect the amount of nitrogen fertilizer required and N 2 0 emissions from the soil. Costs to a utility are an adoption incentive to get farmers to switch from intensive tillage to no-tillage, transaction costs for aggregating and brokering GHG credits, and monitoring costs for assuring that contractual obligations are fulfilled. Case Studies Case studies for converting from intensive-tillage to no-tillage agriculture were conducted for the following United States agricultural regions and cropping systems: • Central Corn Belt (corn/soybean rotation* and continuous corn*) • Central Great Plains (grain sorghum/soybean rotation and continuous grain sorghum) • Western Great Plains (wheat/fallow* and wheat fallow to wheat/sorghum/fallow) • Mississippi Corridor (corn/soybean rotation and continuous cotton*) These cases represent the range of costs for CO2 sink enhancement expected due to converting from intensive-tillage to no-tillage on U.S. cropland. Costs ($/Mg C equivalent life-cycle GHG avoided) are a function of the adoption incentive a utility would have to pay farmers to get them to switch from intensive tillage to no tillage system, transaction costs, monitoring costs, and changes in C sequestered in soil organic matter, N20 emissions from soil, and GHG emissions from crop production inputs. Cases noted with an asterisk represent the range of costs expected from converting from intensive tillage to no tillage on U.S. cropland.

Costs Base-case costs are presented in Table 3 for cases that represent the range of base-case costs expected from converting from intensive tillage to no tillage on U.S. cropland. These results are presented for cases in which an annual adoption incentive is paid for 5, 10, 15, or 20 years. These costs are based on the assumption that, due to soil quality and crop yield benefits that develop over time, a farmer would continue the no-till practice after the adoption incentive stops.

TABLE 3 BASE-CASE COSTS OF CO2 SINK ENHANCEMENT--INTENSIVE TILL TO NO TILL

Corn/soybean Incentive period, years 5 10 15 20

30 48 62 72

Continuous corn Wheat/fallow Continuous cotton Cost (NPV basis, 100-year planning horizon) $/Mg C equivalent life-cycle avoided 30 32 54 51 49 88 66 61 113 77 71 132

CONCLUSIONS

For CO2 storage options, costs are very similar on a CO2 avoided basis and a LC GHG avoided basis and costs on both of these bases are significantly higher than on a CO2 stored basis. Base-case cost ranges on a life-cycle GHG avoided basis are as follows: • CO2 capture + net storage costs ($15 to 145/Mg C equivalent avoided)

1106 •

•

Forest management --Aboveground basis ($10 to 175/Mg C equivalent avoided) --Aboveground + below ground + products basis ($-160 to 55/Mg C equivalent avoided) Cropland via reducing tillage --Mid-range, 10-year adoption incentive period ($50 to 90/Mg C equivalent avoided)

These base-case cost ranges are non site specific, mid-range estimates to be used as a general indication of costs for CO2 storage and sink enhancement options. Costs of capturing and storing CO2 will vary from the base-case estimates in this paper depending on the capture technology used, distance between the capture plant and storage operation, and characteristics of the storage reservoir. Costs of improved forest management for the types of cases presented will vary with forest productivity, land and labor costs inherent in a location, and other local factors. Costs of reducing tillage on US cropland will also vary with local factors. Sensitivities to key variables were included in the final report. Avoidance of deforestation and enhanced oil recovery are the least cost options in situations where they are practical.

ACKNOWLEDGEMENTS The authors wish to acknowledge US DOE National Energy Technology Laboratory for primary funding of the project on which this paper is based and the other team members on the subject project team who were instrumental in assessing the economics of the CO2 storage and sink enhancement options reported in this paper: Mike Klett, Parsons Infrastructure & Technology Group; Gemma Heddle, Massachusetts Institute of Technology; John Davison, IEA Greenhouse Gas R&D Programme, Daniel De La T0rre Ugarte and Chad Helwinckel, Univeristy of Tennessee; Dale Simbek, SFA Pacific; and George Booras, Electric Power Research Institute.

REFERENCES 1. DOE/EPRI. 2000. Evaluation of innovative fossil fuel power plants with CO2 removal. EPRI., Palo Alto, Califomia; U.S. Department of Energy-Office of Fossil Energy, Germantown, Maryland, and U.S. Department of Energy/NETL, Pittsburgh, Pennsylvania: 1000316.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1107

CARBON M A N A G E M E N T STRATEGIES FOR EXISTING U.S. GENERATION CAPACITY: A VINTAGE-BASED APPROACH RT Dahowski I and JJ Dooley2 1 Battelle- Pacific Northwest National Laboratory P.O. Box 999 / Mail Stop K6-10, Richland, WA 99352 z Battelle- Pacific Northwest National Laboratory 8400 Baltimore Avenue, Suite 201 College Park, Maryland, 20740

ABSTRACT

This paper examines the existing stock of fossil-fired power generation capacity in the United States within the context of climate change. At present, there are over 1,337 fossil-fired power generating units of at least 100 MW in capacity, that began operating between the early 1940's and today. Together these units provide some 453 GW of electric power, and simply retiring this stock early or repowering with advanced technology as a means of addressing their greenhouse gas emissions will not be a sensible option for them all. Considering a conservative 40-year operating life, there are over 667 fossil-fired power plants, representing a capacity of over 291 GW, that have a minimum of a decade's worth of productive life remaining. This paper draws upon specialized tools developed by Battelle to analyze the characteristics of this subset of U.S. power generation assets and explore the relationships between plant type, location, emissions, and vintage. It examines the economics of retrofit capture technologies and the proximity of these existing power plants to geologic reservoirs with promise for long-term storage of CO2. The average costs for retrofitting these plants and disposing of their CO2 into nearby geologic reservoirs are presented.

INTRODUCTION The ultimate objective of current intemational efforts to address climate change, stated succinctly by the United Nations Framework Convention on Climate Change (UNFCCC) [1], is the "stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system." Wigley et al. [2] have shown that in order to achieve this goal, carbon emissions must be substantially reduced over the course of this century, and must be virtually eliminated going further into the future. Fulfilling the objective of the UNFCCC will require a long-term and fundamental transformation of the global energy system. Progressing towards this long-range goal of a net zero-emitting global energy sector requires that some actions be taken in the near term to slow the increase in global CO2 emissions. It is not unreasonable to believe that a significant fraction of this early mitigation effort can be achieved through aggressive deployment of existing renewable energy technologies and continued advancements in energy efficiency. Yet a growing body of research suggests that these steps alone will not be enough to move the global energy system onto a pathway towards stabilizing atmospheric greenhouse gas concentrations (see [3], for

1108 example). Particularly in the U.S., where over 40% of total CO2 emissions are attributable to the electric power sector [4], it can be expected that some attention will need to be paid to reducing the CO2 emissions from existing power plants. Geologic disposal of CO2 is one such method that holds significant potential for addressing these emissions [5].

U.S. FOSSIL-FUELED P O W E R GENERATION STOCK According to the most recent data contained within the Battelle CO2-GIS [6], there are currently more than 1,337 large fossil-fired generating units operating in the U.S. with a total capacity of 453 GW. Total annual CO2 emissions from these plants exceed 2.27 billion tons. The range of vintages for these plants spans the period from 1941 to 19991. Figure 1 shows the breakout of fossil-fueled power generation capacity by unit vintage and fuel type. The number in parentheses above each bar indicates the total number of operating units within each vintage category. This figure illustrates the dominant role that coal plays in U.S. fossil-fired power generation. The majority of new plants that came on-line from the 1950's through the 1980's were coal fired, with average plant sizes increasing over that time period. However, beginning in the 1990's a trend towards the increasing use of smaller natural gas fired technology developed and has continued through today. Projections of planned capacity additions through the end of this decade, using data compiled for a separate analysis [9], indicate that this trend is likely to continue. Although it remains to be seen how many of these plants will actually be built, the data indicate a possible resurgence in power plant construction over the coming decade, with most units being natural gas fired. 350 -

(471) ] I

300

----I

i! 250 -

t I

,oot.I 50

1940's

(')

II

o~

I,,.I

II

1950's

1960's

1970's

(,,~)

(,~)

: 1980's

1990's

I--IJ 2000's Planned Through 2 0 1 0

Figure 1: Installed U.S. Fossil-Fired Capacity by Fuel Type & Vintage (Number of Units in Parentheses) While it may be quite realistic to assume that many of the older power plants will be shut down, replaced, or repowered with new advanced technology (such as IGCC) in the face of climate and other environmental concerns, it is naYve (and would prove terribly disruptive to the U.S. economy) to believe that the entire stock of existing fossil-fired plants will be replaced or upgraded in this fashion. A large portion of the i The last complete update of the BattelleCO2-GIS power plant database occurred in July 2000, covering fossil-firedgenerating units with a capacityof at least 100 MW, operating within the United States as of early 1999. EIA data [7,8] suggests that over 152 additionalunits have been built and begun operating since, and plans are underwayto update the Battelle CO2-GIS to reflect these more recent data.

1109

existing stock is less than 30 years old and will be around for many years to come; therefore the owners of these existing power plants will most likely need to explore other options for reducing their emissions. Assuming a conservative 40-year useful power plant life, and looking only at the plants built through the 1990's, 667 of these units, representing more than 290 GW of capacity, will be operating into the next decade and beyond. Most (379) of these are coal-fired units; 243 are natural gas-fired, and 45 are oil-fired. The CO2 emissions contribution from these units alone is currently about 1.6 billion tons per year (roughly 62% of total U.S. electric utility sector emissions). A projection of future emissions from just these units over the next 40 years is shown by fuel type in Figure 2. The projection here assumes that each unit will be retired after operating for 40 years. If this projection were to hold true, these existing 667 power plants would collectively be responsible for emitting 30.2 billion tons of CO2 to the atmosphere over the remainder of their hypothetical lifetimes (26.7 billion tons from the coal units alone). 2,000

~

1,500

C

1,000 C

.2 500

0 2000

2005

2010

2015

2020

2025

2030

2035

2040

Figure 2:CO2 Emissions Projection for Units Built Between 1970 and 1999 (Assuming a Fixed 40-Year Operating Life)

This simplified analysis however does not tell the whole story. It does not include the emissions from units built prior to 1970, nor additional or replacement units that have already come on-line or will through 2040 (most of which will likely continue to employ conventional technology, rather than advanced power generation cycles that might be more amenable to CO2 emissions control). It also does not consider that many of these units will likely be able to produce economical power years beyond age 40. Assuming that a societal aspiration exists to begin addressing climate change within this decade, a strategy must be conceived to help these existing plants continue to produce affordable power while meeting their CO2 reduction requirements. Solutions beyond retiring this still valuable and productive stock or attempting to purchase increasingly expensive offsets must be developed to address these plants' large carbon liability, while maintaining their economic viability.

OPPORTUNITY FOR G E O L O G I C A L SEQUESTRATION The Battelle CO2-GIS currently contains information and spatial extents for some 117 geologic formations that could be amenable to CO2 disposal. These include current and prospective CO2 enhanced oil recovery operations, coal basins, and deep saline formations. Figure 3 is a map of the continental U.S. showing locations of the set of existing power generating units built since 1970 superimposed against these disposal reservoirs. Visual inspection reveals that many of these units lie directly above or in close proximity to possible disposal sites. However, it can also be seen that there are many generating units that are far from known CO2 disposal targets. Using the built-in analysis capability of the Battelle CO2-GIS, we are able to

1110 evaluate more thoroughly the opportunity that retrofit carbon capture and geologic sequestration offers this stock of plants.

Figure 3: U.S. Fossil-Fired Power Generating Units Built after 1970 and Major CO2 Geologic Disposal Reservoirs 2 Utilizing the basic spatial analysis capability of the system, we find that of the 379 coal plants built within this time frame, 244 lie directly above either a deep saline formation or a coal basin. Of the 216 such units that began operating in the 1970's, 146 sit atop a deep saline formation or coal seam and 5 are within 50 miles of an existing or prospective EOR field, representing over 70% of the annual emissions from this group of coal plants. In all, 66% of the total emissions from all 1970's vintage plants are within close proximity to potential disposal sites. For the 1980's plants, 61% of their emissions occur within a short distance to a disposal pathway, dropping to 47% for the 1990's plants' emissions. Deep saline formations are the reservoirs that underlie the most plants (44% of the total stock) across all vintage categories, reaching as high as 70% of all the 1980's natural gas fired plants. Coal seams are the next most prominent formation type located close to existing power plants, occurring beneath some 40% of 1970's vintage coal-fired plants. EOR fields offer the fewest options in close proximity to existing power plants, with only 18 of the 667 plants sitting within 50 miles of an existing or prospective EOR site. Overall, roughly 63% of the total emissions from these 667 units occur within close range of a possible disposal site, offering a promising opportunity for carbon capture and disposal. The CO2-GIS also contains an economic screening capability that seeks to optimize the matching of CO2 source and sink by assessing the costs of CO2 capture, transport, and disposal for each plant and reservoir combination. A previous paper [10] describes this functionality in greater detail. Expanding the assumed maximum search radius to 100-miles around each unit, we examine the available disposal pathways and identify those that appear most economical. Results of this analysis indicate that of the 667 units, 568 are located within 100 miles of at least one potential disposal reservoir. The results for each class of reservoir, 2Additional Legend for Figure 3: Dark solid areas represent major coal basins. Lightertextured areas represent deep saline formations. Blackdots indicate locationswhere CO2 injection for enhanced oil recoveryis on-going. The oil derrick symbol highlights areas with near-termprospects for CO2 enhanced oil recoveryprojects.

1111 including the number of plants selecting them for CO2 disposal and the average levelized cost per ton of CO2 captured, transported, and injected, are presented in Table 1. The majority of generating units elect to sell their C02 to "value added formations" which include enhanced oil recovery fields and deep coal seams, for which there would likely be an offsetting revenue stream from hydrocarbon recovery. Nevertheless, significant portions of the stock dispose of their CO2 in nearby deep saline formations. There is no direct revenue associated with this type of disposal, so the costs are much greater per ton of CO2 than for the "value added formations". Recalling that 294 of the total stock of plants sit directly over a deep saline formation, this results in many of these plants electing to build a much longer pipeline to sell their CO2 instead to a revenue-producing formation. This also suggests that many of the 176 plants that do opt to inject into a deep saline formation have no "value added" disposal options within the 100-mile radius. However, both the geographic distribution and storage capacity of deep saline formations is far greater than for enhanced oil recovery fields in particular, which could ultimately reduce the cost differences as the CO2 demand for EOR becomes saturated. While the value of methane produced from coal seams under CO2 injection is not as great as the oil produced from EOR operations, it does help to offset some of the capture and disposal costs. This, along with the broad geographic extent of the coal seams make this also a promising disposal option, accepting the majority of emissions from these units.

TABLE 1 RESULTSOF GENERATINGUNITCO2 DISPOSALECONOMICSELECTIONANALYSIS

# Units CO2, million tons/yr Req'd Pipeline, miles Av~. Cost S/ton 3

Enhanced Oil Recovery 62 120 4,500 1.50

Deep Coal Seams 330 950 19,800 18

Deep Saline Formations 176 250 11,600 61

In order to transport the C02 from source to sink, a network of pipelines will be required. Table 1 indicates the total pipeline length needed to deliver CO2 from each generating unit to its reservoir of choice. This figure assumes an average 15% adder to the straight-line distance to account for anticipated routing allowances. It also factors an additional 25 miles from the edge of a chosen coal basin or saline formation to locate an acceptable injection site. That said, these figures also assume that each generating unit builds a separate pipeline to its chosen disposal site. However, if capture and disposal of CO2 were developed on a scale such as envisioned here, a national network of interconnected CO2 pipelines would likely emerge with time. To illustrate the level of savings possible by evolving towards an interconnected national pipeline system, we note that many of the existing power plants in the U.S. have multiple generating units at the same site. By simply allowing a single pipeline to be shared by all the units at a particular location, the total required pipeline length needed to transport the emissions from existing power plants falls from over 35,000 miles to just over 18,000 miles. A more thoroughly coordinated system would reduce this further.

CONCLUSIONS

Is IGCC paired with carbon capture and disposal the power generation technology bridge to a transformed energy system? Perhaps, although it will likely be years before it is deployed at a wide scale. In the meantime, there are presently over 1,337 large conventional fossil-fired generating units across the United States that together emit some 2.3 billion tons of CO2 into the atmosphere each year. A large number of these plants are quite old and will likely be shut down and replaced with cleaner, more efficient plants (some 3The authors believe that the cost numbers presented in this table should be interpreted as relative indicators of the cost of capture and disposalrather than precise engineeringestimates.

1112 no doubt with IGCC), rather than be extensively upgraded or overhauled in the face of climate change and other environmental challenges. However, there are a significant number of units that have been built in the past few decades that have plenty of generating life remaining and will continue to operate into a future where carbon emissions are increasingly constrained. As far as U.S. electricity demand and climate change mitigation efforts are concerned, one cannot simply write off these plants' power production or resulting emissions; as we move forward and begin to define a sensible strategy for the level of emissions reduction required to help stabilize atmospheric concentrations of greenhouse gases, the continued operation and emissions from these units must be considered. Retrofitting these units with carbon capture systems and disposing of the CO2 in nearby geologic formations is an option that could help mitigate the large volumes of CO2 produced by these plants. Yet, this will not be an option for every unit. The 99 units producing 132 million tons of CO2 per year that cannot easily take advantage of geologic disposal would need to consider other options (including, but not limited to the purchase of CO2 offsets, repowering with advanced technology, or early retirement). For others, while geologic disposal options may exist, the cost of capture may prove prohibitively high (for small peaking natural gas turbines in particular). In such cases, other options will undoubtedly prove more economical and should be examined. Nevertheless, if we are serious about addressing our climate change mitigation obligations, carbon capture and geologic disposal should be considered in the portfolio of options.

REFERENCES

1. The United Nations Framework Convention on Climate Change. Article 2. http ://unfccc.int/resource/conv/conv_004.html (1992). 2. Wigley, T.M.L., Richels, R., & Edmonds, J. (1996) Economic and environmental choices in the stabilization of atmospheric CO2 concentrations. Nature, 379, 240-243. 3. Edmonds, J., J. Clarke, J. Dooley, S. H. Kim, S. J. Smith. 2002. "Stabilization of CO2 in a B2 World: Insights on The Roles of Carbon Capture and Disposal, Hydrogen, and Transportation Technologies," submitted to Energy Policy, Special Issue, J. Weyant and R. Tol (eds.). 4. Energy Information Administration. 2001. Emissions of Greenhouse Gases in the United States 2000. U.S. Department of Energy. DOE/EIA-0573(2000). 5. JJ Dooley, SH Kim and PJ Runci. "The Role of Carbon Capture, Sequestration and Emissions Trading in Achieving Short-Term Carbon Emissions Reductions." Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies. Sponsored by the IEA Greenhouse Gas R&D Programme. August 2000. 6. Dahowski, R., Dooley, J., Brown, D., Mizoguchi, A., and Shiozaki, M. "Understanding Carbon Sequestration Options in the United States: Capabilities of a Carbon Management Geographic Information System," Proceedings of the First National Conference on Carbon Sequestration. Washington, DC, May 2001. 7. Energy Information Administration. Annual Electric Generator Report -- Utility (2000). EIA-860A2000. April 8, 2002. 8. Energy Information Administration. Annual Electric Generator Report -- Nonutility (2000). EIA-860B2000. May 21, 2002. 9. JJ Dooley and RT Dahowski. ,"Examining Planned U.S. Power Plant Capacity Additions In The Context Of Climate Change" to be published in the proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies Sponsored by the IEA Greenhouse Gas R&D Programme (Kyoto, Japan October 2002). Pacific Northwest National Laboratory. PNNL-SA-36829. July 2002. 10. Dahowski, R., Dooley, J., Brown, D., and Stephan, A. "Economic Screening of Geologic Sequestration Options in the United States with a Carbon Management Geographic Information System," Proceedings of the Eighteenth Annual International Pittsburgh Coal Conference. Newcastle, NSW, Australia, December 2001.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1113

E X A M I N I N G P L A N N E D U.S. P O W E R PLANT C A P A C I T Y A D D I T I O N S IN THE C O N T E X T OF C L I M A T E C H A N G E JJ Dooley I and RT Dahowski 2 1 Battelle- Pacific Northwest National Laboratory 8400 Baltimore Avenue, Suite 201 College Park, Maryland 20740 z Battelle- Pacific Northwest National Laboratory P.O. Box 999 / Mail Stop K6-10, Richland, WA 99352

ABSTRACT This paper seeks to assess the degree to which the 471 planned fossil fueled power plants announced to be built within the next decade in the continental U.S. are amenable to significant carbon dioxide emissions mitigation via carbon dioxide capture and disposal in geologic reservoirs. In particular, we seek to assess the looming "carbon liability" (i.e., the potential 1 billion tons of annual CO2 emissions) that these power plants represent for their owners and for the nation as the U.S. begins to address climate change. The combined generating capacity of these 471 planned plants is 320 GW. Less than half of these plants are located in the immediate vicinity of potentially suitable geologic carbon dioxide disposal reservoirs. The authors examine two hypothetical scenarios for how these plants will access known CO2 disposal reservoirs.

INTRODUCTION The United States Senate ratified the United Nations Framework Convention on Climate Change (UNFCCC) on October 15, 1992 [ 1]. Since then there have been numerous legislative proposals introduced in the United States Congress suggesting various mechanisms for controlling U.S. emissions of greenhouse gases, with most of these proposals focusing on reducing greenhouse gas emissions from large point sources such as fossil fired power plants. The current U.S. Presidential Administration has reaffirmed the U.S. commitment to achieving the stated goal of the UNFCCC, which calls for the "stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system"[2]. Numerous modeling efforts strongly suggest that fulfilling this stabilization goal will require a profound transformation of the global energy system, and of particular relevance for the present analysis, will require the very large scale deployment of advanced emission mitigation technologies such as carbon capture and disposal before the middle of this century (see for example [3]). Therefore, given average power plant lifetimes that are likely more than 40 years for new plants, new additions to a nation's power plant infrastructure represent early opportunities for the introduction of new emissions mitigation technologies such as carbon capture and disposal. However, if these new power

1114 plants are unable to use carbon capture and disposal options, they instead likely represent a growing financial liability for their owners and operators as the U.S. begins to reduce its emissions of greenhouse gases. This paper seeks to assess the degree to which the 471 planned 1 fossil fired power plants announced to be built within the next decade in the continental U.S. are amenable to significant carbon dioxide emissions mitigation via carbon dioxide capture and disposal in geologic reservoirs.

B A T T E L L E CO2-GIS The Battelle CO2-GIS is a geographic information system (GIS) based model for CO2 source and sink data. At this time, it contains data (e.g., fuel type, location, vintage, ownership, rated capacity) on all fossil-fired generation capacity in the United States and Canada with a rated capacity of at least 100 MW. This represents 1,337 units with a rated capacity of 453 GW and annual CO2 emissions in excess of 2.27 billion tons. The Battelle CO2-GIS also contains key data on potential geologic reservoirs that could possibly be used for CO2 disposal. This includes data on current and prospective CO2 enhanced oil recovery (EOR) projects as well as on priority deep saline formations and coal basins with potential for CO2 disposal. In all, there are some 117 possible reservoirs currently represented in the model. The most recent version of the Battelle CO2-GIS is described elsewhere [4].

PLANNED FOSSIL P O W E R PLANT ADDITIONS F O R THE C O N T I N E N T A L U.S. For the present analysis, we have augmented the data already contained in the Battelle CO2GIS model with information on 471 power plants announced to become operational between June 2002 and the end of calendar year 2010. Each of these plants has a planned rated capacity of at least 100MW. Data for these planned power plants come from a number of different data sources [5, 6, 7, 8]. Figure 1 shows the geographic location of these planned power plants and the major CO2 disposal reservoirs identified to date and contained within the Battelle CO2-GIS. Natural gas fired turbines dominate these 471 power plants. More than 80% (396 out of 471) of these fossil fired plants are natural gas fired, thus continuing a decades' old trend in the U.S. of increasing reliance on natural gas as the fuel of choice for new power plants. The remaining plants are coal fired. Nine of these coal plants are designed to make use of integrated gasification combined cycle (IGCC) power plant concepts. The remaining 67 coal fired plants will make use of more conventional coal-fired power cycles. There are no oil-fired plants scheduled to come on line that exceed the 100MW capacity threshold being used in this analysis.

t It is important to acknowledge that these power plants represent announced plans to build a power plant at a given site. There is no guarantee that all of these plants will actuallybe built.

1115

•

i ¸

,

Ranned Capacity #r

Coal Ga

@ 200"2.Ba,~el!eMemorial in~Hut~

Figure 1: Planned Fossil-Fired Power Plant Additions in the U.S. and Major CO2 Geologic Disposal Reservoirs 2 These 471 power plants represent a planned addition of 320 G W over the coming decade. This would represent a nearly 50% increase with respect to the total fossil fired capacity already installed in the continental U.S. These planned plants themselves have the potential to release 1.01 billion tons of CO2 to the atmosphere annually 3. Moreover if one conservatively assumes that these power plants will have operating lifetimes of 40 years, then this set of new power plants alone is theoretically capable of generating 40.1 billion tons o f CO2 (or 11.0 billion tons of carbon) to the atmosphere over their hypothetical lifetimes. That is almost twice the current global annual emissions of carbon from all sources.

P R O X I M I T Y T O G E O L O G I C A L CO2 D I S P O S A L R E S E R V O I R S Given the potential "CO2 emissions shadow" cast by these plants over the course of their lifetimes, we wanted to explore the potential for reducing emissions by these plants through the use of carbon capture and disposal technology. The first level of analysis would be to assess the extent to which these plants happen to lie near reservoirs with promise for CO2 disposal.

2 Legend for Figure 1. Light stars represent planned natural gas fired power plant additions. Black stars represent planned coal fired capacity additions. Textured gray areas are deep saline formations believed to be suitable for CO2 disposal. Solid dark gray areas represent deep coal seams believed to be suitable for CO2 disposal. Black dots represent locations that are currently using CO2 for enhanced oil recovery while the oil derrick symbols represent prospective areas for near term CO2 driven enhanced oil recovery. 3 This paper's calculations of these yet-to-be-built power plants' generating capacity and resulting CO2 emissions are based upon a number of key assumptions. Foremost, is an assumed average capacity factor of 65% for all of these plants whether they be coal fired, IGCC plants or natural gas turbines. According to data contained in the Battelle CO2-GIS, the installed power plants in the U.S. have an aggregate average capacity factor of 51.5%, so the assumption of 65% capacity factor would be a substantial improvement in terms of reliability with respect to the current installed capacity.

1116 Table 1 describes how these planned power plants line up with potential CO2 disposal reservoirs. TABLE 1 PLANNEDU.S. POWERPLANTS& THEIRPROXIMITYTO POTENTIALCO2 DISPOSALRESERVOIRS

NGCC Conventional Coal IGCC

Total Number of Units By Fuel Type 396 66

Units Directly Above Deep Saline Formations 127 36

Units Directly Above ValueAdded Formations 58 24

Units within 25 miles of any reservoir 232 58

Units not within 50 miles of any reservoir 122 6

9

3

0

7

2

The 130 planned power plants that do not lie within 50 miles of any known geologic CO2 disposal reservoirs account for 29% of these power plants' annual emissions. This represents 296 million tons of CO2 that cannot be stored in these geologic reservoirs without building extensive pipeline networks. Assuming that at some point in the future plant operators will be charged for carbon emissions, this amount of uncaptured emissions is a fairly large financial liability for the owners of this long-lived capital stock. Table 1 also suggests that there are 82 planned power plants that lie directly above "value added formations. ''4 For the purposes of the present analysis, "value added formations" are defined as areas currently using CO2 for enhanced oil recovery (EOR), prospective near-term CO2-driven EOR formations, and deep coal seams believed to be suitable for CO2 disposal. These 82 power plants that sit adjacentto these potential "value added formations" are capable of generating 217 million tons of CO2 per year. This is nearly an order of magnitude greater than current U.S. use of CO2 for EOR [9]. Furthermore given that most EOR field operations typically last only 5-30 years [ 10], can these long-lived power plants count on selling their CO2 to these "value-added" applications year-after-year? There could well me too much CO2 trying to find a productive use even from this small subset of plants. If supply does indeed exceed demand by a significant fraction, then the price buyers would be willing to pay for CO2 for these value added applications should decline rapidly, perhaps even approaching zero. Note also that there are no IGCC plants in close proximity to any known EOR or ECBM prospects. Lastly, before leaving this basic spatial analysis of CO2 sources (planned power plants) and sinks (these potential geologic reservoirs for CO2), we wish to examine the role potentially played by deep saline formations. Fully 35% of all of these announced power plants (166) sit directly above identified deep saline formations. Moreover 53% of all of these planned plants (250), accounting for 51% of all of their emissions, sit within 25 miles of a potential deep saline formation CO2 disposal pathway. No other class of geologic reservoirs has the potential to meaningfully address these planned power plants' emissions over the course of their lifetimes without building lengthy CO2 pipelines.

4 For the purposes of this analysis, "directly above value added formations" connotes different things for the different classes of geologic reservoirs. Because of the spatial resolutionof the data within the Battelle CO2-GIS,a plant is determined to be above an EOR field if within 25 miles of the point representing the field. For coal beds, where we have better spatial coveragea plant must sit directlyabove them.

1117

DEPLOYMENT SCENARIOS We next turn our attention to a more sophisticated analysis where we attempt to examine how the various CO2 disposal reservoirs in the U.S. might be used under differing economic and regulatory environments. In order to perform this analysis, we will employ the economic screening function built into the Battelle CO2-GIS which seeks to optimize the matching of CO2 source and sink by assessing costs for CO2 capture, transport and disposal, s The first case we examine here is a hypothetical scenario in which each power plant is allowed to build up to a 100 mile pipeline in an attempt to find the most productive use for its CO2. That is, each plant is asked to minimize its cost subject to only one constraint; it cannot build a pipeline longer than 100 miles. This case results in 36 of these power plants attempting to sell 77.3 million tons o f CO2 annually to EOR markets while an additional 215 plants attempt to sell their annual production of 480.2 million tons of CO2 for ECBM production. Lastly, 157 plants annually seek to dispose of their 287.5 million tons of CO2 into deep saline formations. This supposedly economic efficient case comes at the potential cost o f creating a massive U.S. CO2 pipeline network stretching some 13,000 miles of straight-line pipe. If instead of assuming that each source and sink combination can be effortlessly sited along straight line pipes, one assumes less optimal pipeline routes and the need for additional pipeline to locate suitable injection points into large reservoirs, the total national CO2 infrastructure from these new plants climbs to 25,700 miles. 6 The second case revolves around a purely hypothetical regulation that limits CO2 disposal to the nearest formation with no power plant allowed to build a pipeline o f more than 25 miles. This case results in only 8 of these new power plants attempting to sell 16.0 million tons of CO2 to EOR markets annually while an additional 99 plants attempt to sell their annual production of 260.1 million tons of CO2 for ECBM production. Lastly, 182 plants seek to use deep saline formations as the ultimate disposal point for their annual 347.8 million tons of CO2. This "regulatory-oriented" scenario creates a national pipeline infrastructure of only 1200 miles o f straight-line pipeline or 9500 miles of pipeline under the more realistic assumptions noted above.

CONCLUSIONS While it is unclear exactly how many of the 471 fossil fired power plants examined here will actually end up being brought on line, it is clear that many of these plants are not ideally situated to avail themselves of carbon capture and disposal technologies. This implies that the owners of many of these power plants will need to either invest in massive COz pipeline networks, consider paying others for increasingly costly emissions offsets, or prematurely s The cost function computes a total levelized cost for any source/sink combination by applying a series of cost factors for the three major aspects of CO2 capture and disposal: (1) CO2 capture (e.g., post combustion capture from a dilute flue gas stream is more expensive than COz derived from a high purity CO2 stream such as an IGCC), (2) CO2 transport (i.e., a cost per mile of pipeline constructed is assessed) and (3) CO2 disposal (i.e., net cost for CO2 disposal in a deep saline formation is more expensive than CO2 disposed of in a coal seam for enhanced coal bed methane production while CO2 used in EOR is the cheapest disposal route). 6 In this perhaps more realistic pipeline scenario we assume, that all straight line pipeline distances have to carry a 15% adder to account for pipeline siting around obstacles and all deep saline and ECBM applications require an average 25 miles of additional pipeline to penetrate the perimeter of the large reservoirs and locate a suitable injection site.

1118 retire these new plants. None of these offer a particularly attractive option. A failure to take into account emissions mitigation options raises the cost of complying with the U.S.'s obligations under the UNFCCC and likely passes a heavy burden on to future generations. A failure to do so also increases potential out year liabilities for the owners of these plants and their shareholders. Under any scenario, the U.S. will need a portfolio of proven geologic CO2 disposal reservoirs. Placing too much emphasis on "value added formations" will needlessly strand a tremendous amount of fossil fired power plants. Consideration should also be given now to what kind of a regulatory framework will guide the evolution of a national CO2 pipeline infrastructure. If this pipeline infrastructure issue is not considered proactively, the U.S. might end up with a massive and publicly unacceptable CO2 pipeline network that will itself hamper the successful wide scale adoption of capture and disposal technologies that it is meant to support.

REFERENCES

1. United Nations Framework Convention on Climate Change: Status of Ratification. 2001. Updated: December 11, 2001. http://unfccc.int/resource/conv/ratlist.pdf 2. The United Nations Framework Convention on Climate Change. Article 2. http ://unfccc.int/resource/conv/conv_004.html (1992). 3. Dooley, JJ, Kim, SH, and Runci, PJ. "The Role of Carbon Capture, Sequestration and Emissions Trading in Achieving Short-Term Carbon Emissions Reductions." Proceedings of the Fitth International Conference on Greenhouse Gas Control Technologies. Sponsored by the IEA Greenhouse Gas R&D Programme. August 2000. 4. Dahowski, R., Dooley, J., Brown, D., Mizoguchi, A., and Shiozaki, M. "Understanding Carbon Sequestration Options in the United States: Capabilities of a Carbon Management Geographic Information System," Proceedings of the First National Conference on Carbon Sequestration. Washington, DC, May 2001. 5. Electric Power Supply Association. 2002. Announced Merchant Plants. Prepared July 1, 2002. Online database of additions to merchant power plants, http://www.epsa.org/ 6. Energy Information Administration 2000. Existing Capacity and Planned Capacity Additions at U.S. Electric Utilities by Energy Source, Table 1. U.S. Department of Energy. http ://www. eia.doe, gov/cneaf/electricity/ipp/html 1/t 1p01 .html 7. Energy Info Source. 2002. New Plant Construction. Last updated July 9, 2002. http ://www.energyinfosource.com 8. Klara, Scott and Shuster, Erik. 2002. "Tracking New Coal-Fired Plants: Coal's Resurgence in Electric Power Generation." (http://www.netl.doe.gov/coalpower/oces/pubs/ncp5-2802.PDF). U.S. Department of Energy, National Energy Technology Laboratory. May 28, 2002. 9. Stevens, SH, Kuuskraa, VA, and Gale, J. "Sequestration of CO2 in Depleted Oil and Gas Fields: Global Capacity, Costs, and Barriers." Proceedings of the FitCh International Conference on Greenhouse Gas Control Technologies. Sponsored by the IEA Greenhouse Gas R&D Programme. August 2000. 10. Stevens, SH, Kuuskraa, VA, and Taber, JJ. "Sequestration of CO2 in Depleted Oil and Gas Fields: Barriers to Overcome in the Implementation of CO2 Capture and Storage (Dissued Oil and Gas Fields." lEA Greenhouse Gas R&D Programme Report No. PH3/22. February 2000.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1119

UNCERTAINTIES IN CO2 CAPTURE AND SEQUESTRATION COSTS E.S. Rubin and A.B. Rao Department of Engineering and Public Policy Carnegie Mellon University Pittsburgh, PA 15213 ABSTRACT The cost of CO2 avoidance depends on a wide variety of factors and assumptions whose impacts have not been fully considered in past assessments of carbon capture and sequestration technologies. As part of the USDOE's Carbon Sequestration Program, we have developed an integrated modeling framework to evaluate the performance and costs of alternative CO2 capture and sequestration technologies for fossil-fueled power plants, in the context of multi-pollutant control requirements. This model (called the IECM-CS) allows for explicit characterization of the uncertainty or variability in any or all model input parameters. This paper reviews the major sources of uncertainty or variability in CO2 cost estimates, then uses the IECM-CS to analyze uncertainties in CO2 mitigation costs for currently available (amine-based) COR capture technologies applicable to coal-fired power plants. INTRODUCTION Development of improved technology to capture and sequester the CO2 emitted by power plants using fossil fuels m especially coal m is the subject of major research efforts worldwide. The attraction of this option is that it would allow abundant world resources of fossil fuels to be used for power generation and other applications without contributing significantly to atmospheric emissions of greenhouse gases. The two key barriers to carbon capture and sequestration (CCS), however, are the high cost of current CO2 capture technologies, and uncertainties regarding the technical, economic and political feasibility of CO2 storage options. Assuming geological storage of CO2 indeed proves to be viable, how much would it likely cost to capture and store the CO2 from a new coal-fired power plant? Various studies have addressed this question [ 1-7], but each study typically employs different assumptions that produce different results. Herzog (1999) and others have summarized recent cost studies and sought to adjust their results to a more consistent basis [8, 9]. Nonetheless there still remains substantial confusion and lack of understanding in both the technical and policy communities about the magnitude of CCS costs and the factors that affect it. FACTORS AFFECTING CCS COST In this paper we attempt to peel back some of the cobwebs that continue to obfuscate answers to what many believe is the simple question of how much it costs to capture and sequester CO2 emissions from power plants. We use the term "uncertainties" very loosely in this paper to describe the many different factors that contribute to differences in reported cost results for CCS systems. We begin with a brief review of the key determinants of CO2 control cost.

Defining the System Boundary: The first requirement is to clearly define the "system" whose CO2 emissions and cost are being characterized. The most common assumption in economic studies is a single power plant that captures CO2 and transports it to an off-site storage area such as a geologic formation. The CO2 emissions not captured are released at the power plant stack along with other pollutants. Other system boundaries that are sometimes used (or implied) in reporting CO2 abatement costs may include CO2 emissions over the complete fuel cycle that includes the extraction, refining and transportation of coal or other fuels used for power generation, as well as any emissions from byproduct use or disposal. Emissions of other greenhouse gases (expressed as equivalent CO2) also

1120

are included in some analyses. Still larger systems might include all power plants in a utility company's system; all plants in a regional or national grid; or a national economy where power plant emissions are but one element of the overall energy system being modeled. In each of these cases it is possible to derive a mitigation cost for CO2 but the results are not directly comparable because they reflect different system boundaries and considerations.

Defining the Technology and Time Frame: Costs will vary with the choice of CCS technology and the power system that generates CO2 in the first place. What is often less clear in economic evaluations is the nature and basis of assumptions about the future cost of a technology, particularly "advanced" technologies that are still under development or not yet commercial. Such cost estimates frequently reflect assumptions about the "n th plant" to be built sometime in the future when the technology is mature. Other estimates may reflect the expected benefits of technological learning. The choice of time frame and assumed rate of cost improvements can make a big difference in CCS cost estimates.

Different Measures of Cost: Several different measures of cost are used to characterize CCS systems, but because many of these have the same units (e.g., dollars per tonne of CO2) there is great potential for misuse or misunderstanding. Perhaps the most widely used measure is the "cost of CO/ avoided," defined as: Cost of COz Avoided = [(COE)camre - (COE)ref] / [(CO2/kWh)ref - (CO2/kWh)capture] This value reflects the average cost (S/ton) of reducing atmospheric CO2 emissions by one unit of mass (nominally one ton), while still providing one unit of electricity to consumers (nominally one kWh). The choice of both the capture plant and the reference plant without CO2 capture and storage thus plays a key role in determining the CO2 avoidance cost. Usually (but not always) the reference plant is assumed to be a single unit the same type and size as the plant with CO2 capture. If there are significant economies of scale in power plant construction costs, differences in power plant size also can affect the cost of CO2 avoided. A measure having the same units as avoided cost can be defined as the difference in net present value of projects with and without CCS, divided by the difference in their CO2 mass emissions. However, unless the two projects produce the same net electrical output, the resulting cost per tonne is not the cost of CO/avoided; rather, we call it the "cost of CO2 abated." Numerically, this value can be quite different from the cost of CO2 avoided for the same two facilities. Arguably, it is the cost of electricity (COE) for plants with CO2 capture that is most relevant for economic, technical and policy analyses. It can be calculated as: COE = [(TCR)(FCF) + (FOM)]/[(CF)(8760)(kW)] + VOM + (HR)(FC) where, COE = cost of electricity (S/kWh), TCR = total capital requirement ($), FCF = fixed charge factor (fraction/yr), FOM = fixed operating costs ($/yr), VOM = variable operating costs (S/kWh), HR = net plant heat rate (kJ/kWh), FC = fuel cost ($/kJ), CF = capacity factor (fraction), 8760 = hrs/yr, and kW = net plant power (kW). Thus, many factors affect the COE, and hence the cost of CO2 avoided.

Unreported Assumptions: For a variety of reasons, cost studies do not always report all of the key assumptions that affect the cost of CO2 control. For example, the total capital requirement (TCR) includes the cost of purchasing and installing all plant equipment, plus a number of "indirect" costs that typically are estimated as percentages of total plant cost (TPC) [10]. Assumptions about such factors (such as contingency costs) can have a pronounced effect on cost results. Further, some CO2 cost studies exclude certain items (like interest during construction and other "owner's costs") when reporting total capital cost and COE. The term "total plant cost" doesn't always mean what it seems! The addition of a carbon capture and storage (CCS) system increases a plant's capital and operating costs, while lowering the net power output because of auxiliary energy requirements. The result is a higher COE relative to the identical plant without CO2 capture. The capacity factor of the capture plant is typically assumed to be the same as the reference plant, although some studies suggest that CCS plants may be utilized more extensively than an equivalent plant without COz capture [11]. Thus, the COE and the cost of CO2 avoided are both influenced by many factors that are not directly related to the design or cost of a CO2 capture and storage system (see Table 1). Unless such assumptions are transparent, results can be easily misunderstood.

1121

TABLE 1 TEN WAYS TO REDUCE CO2 CONTROL COSTS WITHOUT EVEN CONSIDERING THE COST OF CO2 CAPTURE 10. 9. 8. 7. 6. 5. 4. 3. 2. 1.

Assume high power plant efficiency Assume high-quality coal properties Assume low fuel costs Assume EOR credits for CO2 disposal Omit certain capital costs State results in short tons Assume a long plant lifetime Assume a low interest rate (discount rate) Assume high plant utilization (capacity factor) Assume all of the above!

QUANTIFYING COST UNCERTAINTIES

As noted earlier, we use the term "uncertainty" loosely to reflect the combination o f imprecise knowledge o f a parameter value, as well as the variability in parameter assumptions used for cost estimates. To quantify the impact of these factors, we use a computer model (called IECM-CS) developed for the U.S. Department o f Energy [ 12, 13]. The I E C M - C S estimates the performance and cost of a user-specified power plant configuration that may include a variety o f emission control technologies for regulated air pollutants (SO2, NOx, particulates and mercury) in addition to CO2 capture. The model also includes an amine scrubber system for CO2 capture at a pulverized coal plant. Models o f a natural gas combined cycle (NGCC) system and an integrated coal gasification combined cycle (IGCC) system with and without CO2 capture will soon be added. In each case the CCS system includes the costs of CO2 pipeline transport plus storage in a geologic reservoir (including options for enhanced oil recovery or enhanced coalbed methane recovery), or ocean disposal. A unique feature o f the IECM-CS is its ability to represent any or all input parameters as probability distribution functions rather than discrete (deterministic) values. The probabilistic results then reflect the interactions among all uncertain input variables. TABLE 2 DESIGN PARAMETERS FOR CASE STUDY OF NEW PULVERIZED COAL PLANT

Parameter Gross plant size (MW) Gross plant heat rate (U/kWh) Plant capacity factor (%) Coal characteristics Coal HHV (kJ/kg) %S %C Mine-mouth cost ($/tonne) Delivered cost ($/tonne)

]Value 500 9600 a 75 b Low-S 19,346 0.48 47.85 13.73 23.19 c

High-S 25,300 3.25 61.2 32.24 41.3¢

I

Parameter Emission standards NOx controls Particulate control SO2 control CO2 control CO2 capture efficiency (%) CO2 product pressure (kPa) Distance to storage (km) Cost year basis (constant $) Fixed charge factor

]

Value 2000 NSPS a LNB e +SCR t ESP g FGD h MEAi 90 13,790 i 165 2000 0.15 k

aNominal case is a sub-critical unit. Uncertaintycase includes supercritical unit. The uncertaintydistributions used are: Unc = Chance distribution (8968(p=0.5), 9600(p-0.5)); bUnc = Triangular(65,75,85); CUnc-- Triangular(l5.94,23.19,26.81); dNOx= 65 ng/J, PM = 13 ng/J, SO2 = 70% removal (upgraded to 99% with MEA systems); ~LNB= Low- NOx Burner; 'SCR = Selective Catalytic Reduction; gESP = Electrostatic Precipitator; hFGD= Flue Gas Desulfurization; iMEA= Monoethanolamine system;JSee Table 3 for uncertainty. kCorresponds to a 30-year plant lifetime with a 14.8% real interest rate (or, a 20-year life with 13.9% interest); Unc = Uniform(0.10,0.20) 1Unc= Triangular (35.31,41.97, 51.96)

Case Study of a New PC Plant: To illustrate the effect of uncertainties on CO2 control cost for one technology we present a case study o f a new pulverized coal (PC) power plant with an amine (MEAbased) CO2 capture system representing current commercial technology.

1122 TABLE 3 AMINE SYSTEM PERFORMANCEMODEL PARAMETERS

Performance Parameter

I

Units

CO2 removal efficiency % SO2 removal efficiency % NO2 removal efficiency % HC1 removal efficiency % Particulate removal eff. % MEA concentration wt% Lean solvent CO2 loading mol CO2/mol MEA Nominal MEA make-up . kg MEA/tonne CO2 MEA loss (802) mol MEA/mol SO2 MEA loss (NO2) mol MEA/mol NO2 MEA loss (HC1) mol MEA/mol HC1 MEA loss (exhaust gas) ppm NH 3 generation molNH3/molMEA ox Caustic for MEA reclaimer kg NaOH/tonneCO2 Cooling water makeup M3/tonne CO2 Solvent pumping head kPa Pump efficiency % Gas-phase pressure drop kPa Fan efficiency % Equiv. elec. requirement % regeneration heat CO2 product purity wt% CO2 product pressure MPa Compressor efficiency %

Data INominal (Range) ] Value Mostly 90 Almost 100 20-30 90-95 50 15-50 0.15-0.30 0.5-3.1 2 2 1 1-4 1 0.13 0.5-1.8 35-250 70-80 14-30 70-80 9-19 99-99.8 6.9-15.16 75-85

90 99.5 25 95 50 30 0.22 1.5 2 2 1 2 1 0.13 0.8 207 75 26 75 14a 99.5 13.79 80

i

Unc. Representation (Distribution Function) Uniform (85, 95) Uniform (99,100) Uniform (20,30) Uniform (90,95) Uniform (40,60) Uniform (20,30) Triangular (0.17,0.22,0.25) Triangular (0.5,1.5,3.1)

Uniform ( 1,4)

Triangular (0.5,0.8,1.8) Triangular (150,207,250) Uniform (70,80) Triangular (14,26,30) Uniform (70,80) Uniform (9,19) Uniform (99,99.8) Triangular (6.9,13.79,15.16) Uniform (75,85)

TABLE 4 M E A COST MODEL PARAMETERS

Capital Cost Elements

~om. Value*

Process area cosis (9 areas) a Total process facilities cost PFC b Engineering and home office 7 % PFC c General facilities 10 % PFC d Project contingency 15 % PFC e Process contingency 5 % PFC f Total plant cost (TPC) = sum of above Interest during construction calculated Royalty fees 0.5 % PFC g 1 month h Pre-production costs VOM & FOM Inventory (startup) cost 0.5 % TPC ~ Total capital reqmt (TCR) = sum of above

O&M Cost Elements ]

Nom. Value*

Fixed O&M Costs 0FOM) Total maintenance cost 2.5 % TPCj Maintenance cost 40 % of total maint. allocated to labor cost Admin. & support labor 30 % of total labor Operating labor 2 jobs/shiR k

Variable O&M Costs (VOM) Reagent (MEA) cost Water cost CO2 transport cost CO2 storage/disposal cost Solid waste disposal cost

$1250/tonne MEA I $0.2/m 3 $0.02/tonne CO2/K1TI

TM

$5/tonne CO2" $175/tonne waste b

*Uncertainty distributions are given below, aTheindividual process areas modeled are: flue gas blower, absorber, regenerator, solvent processing area, MEA reclaimer, steam extractor, heat exchanger, pumps, CO2 compressor. The sum of these is the total process facilities cost (PFC). The uncertainty distributions used are: bNormal(1.0,0.1), CTriangular(5,7,15), dTriangular(5,10,15) CTriangular(10 15 20) f, Triangular (2,5,10), g Triangular (0,0.5,0.5), hTriangular (0.5,1,1), q'riangular (0.4,0.5,0.6), jTriangular' (1 2.5 5) k Tri'a~gular (1,2,3))Uniform (1100,1300), "Triangular (0.004,0.02,0.06), "Chance distribution (-10(p-0.25), -5(p=0.25), 3(p=0'.05), 5(p=0.35), 8(p=0.l)) Table 2 lists the key power plant parameters and assumed uncertainty distributions, while Tables 3 and 4 show the performance and cost parameters, respectively, for the CO2 capture and storage system. The nominal case assumes geologic storage of CO2 at a net cost to the plant owner, while the uncertainty (variability) case includes the sale o f CO2 for enhanced oil recovery (EOR).

1123 TABLE 5 PROBABILISTICCOSTRESULTSFORCO2 CAPTUREPLANTS Case Low-S coal Reference plant C02 capture plant: unc. in both ref & capture plant unc. in capture plant only Hi2h-S coal Reference plant capture plant: unc. in both ref &.capture plant unc. in capture plant only C O

Mean

COE ($/MWh) Median Range

Avoidance Cost ($/tonne CO2 av.) Mean Median Range . . . . . . . . . . . . . . . . . . . . . . . . . . .

. ....

,:

:

.

.

.

.

48.0

48.0

36-63

: :i:: :1 :~: : :i

iii :

89.5 89.5

98.1 98.1

54-132 54-132

53.0 49.5

21-91 6-102

55.3

55.0

43-69

96.3 96.3

95.9 95.9

63-138 63-138

:,,:

53.3 48.8 :

.

.

:I

:....

2

55.8 52.2

56.3 51.7

23-90 9-106

Figure 1 shows the cumulative distribution function (cdf) for the cost of CO2 avoided. One curve reflects only the uncertainty and variability in the parameters of the CO2 capture and storage system. A second curve adds uncertainty and variability in four key power plant parameters that also influence the COE and avoided cost. We consider cases where these parameter values are identical for the reference and capture plants, and another case where they differ. Table 5 summarizes the mean, median, and range of the overall distributions for COE and cost of CO2 avoided for several cases. The mean and median values of the cost of COz avoided lie in the range of roughly $49 to $56/tonne CO2. When uncertainty and variability assumptions are taken into account the range widens considerably. With uncertainties only in the CCS system, the 95% probability interval varies by approximately a factor of three, from $32 to $75/tonne COz. The most significant variables here were the CO2 capture efficiency, lean solvent CO2 loading of the amine system (which determines the regeneration heat requirements), the efficiency of heat integration (in terms of net power loss), and the CO2 storage/disposal cost. Adding variability in plant parameters has a measurable effect on COE, but a small impact on avoidance cost if the reference plant and capture plant employ the same assumptions. Otherwise the impact on avoidance cost can be large, as illustrated in Table 5. Results for the two different coal types show that fuel choice assumptions also can have a large effect on COE but a much smaller effect on avoided cost relative to the same plant without CCS. CONCLUSIONS

The analysis method used in this paper can be readily applied to other types of power generation and CCS systems, which will be part of our on-going work. While this study did not attempt to quantify the effects of technology innovation and learning on future cost reductions, this is nonetheless an important factor that is being considered in other research [ 14]. In the context of long-term scenarios or projections, assumptions about rates of technical are critical to cost estimates for CO2 capture and storage. ACKNOWLEDGEMENTS This research was supported by the U.S. Department of Energy's National Energy Technology Laboratory (Contract No. DE-FC26-00NT40935), and by the Center for Integrated Study of the Human Dimensions of Global Change through a cooperative agreement between the National Science Foundation (SBR-9521914) and Carnegie Mellon University. The authors alone, however, are responsible for the content of this paper.

1124 1.o .......................................................................................~

...........

0.8

--~ 0.7

0

10

20

30

40

51)

60

70

80

90

q00

Avoidance Cost ($/tonne C02 avoldod)

Figure 1: Effects of parameter uncertainty and variability on the cost of CO2 avoided. The dotted lines at the top and bottom of the graph encompass the 95% probability interval.

REFERENCES

1. Smelser, S.C., Stock, R.M. and G.J. McCleary (1991). "Engineering and economic evaluation of CO2 removal from fossil-fuel-fired power plants", EPRI IE-7365, Vol. 2, Palo Alto, CA. 2. Riemer, P., Audus, H. and A. Smith (1993). "Carbon dioxide capture from power stations", IEA Greenhouse Gas R&D Programme, Cheltenham, United Kingdom. 3. Hendriks, C. (1994). Carbon Dioxide Removal from Coal-fired Power Plants, 14-223, Kluwer Academic Publishers, The Netherlands. 4. Leci, C.L. (1996). "Financial implications on power generation costs resulting from the parasitic effect of CO2 capture using liquid scrubbing technology from power station flue gases", Energy Convers. Mgmnt, 37(6-8), 915-921. 5. Chapel, D., Ernst, J. and C. Mariz (1999). "Recovery of CO2 from flue gases: Commercial trends", Proc. of Canadian Society of Chemical Engineers Annual Meeting, 4-6 October, 1999, Saskatoon, Saskatchewan, Canada. 6. Simbeck, D. (1999). "A portfolio selection approach for power plant CO2 capture, separation and R&D options", Proc. of 4 th International Conference on Greenhouse Gas Control Technologies, Elsevier Science Ltd. 7. Rao, A.B. and Rubin, E.S. (2002). "A Technical, Economic and Environmental Assessment of Amine-based Carbon Capture Technology for Power Plant Greenhouse Gas Control," Environ. Sci. Technol. 36(20), 4467-4475. 8. Herzog, H.J. (1999). "The economics of CO2 capture", Proc. of 4 th International Conference on Greenhouse Gas Control Technologies, Elsevier Science Ltd. 9. Jeremy D. (2000). Economic Evaluation of Leading Technology Options for Sequestration of Carbon Dioxide, M.S. Thesis, MIT, Cambridge, MA. 10. TAG (1993). Technical Assessment Guide, EPRI TR 102276, EPRI, Palo Alto, CA. 11. Johnson, T.L. (2002). Electricity Without Carbon Dioxide: Assessing the Role of Carbon Capture and Sequestration in U.S. Electric Markets, Ph.D. Thesis, Carnegie Mellon University, Pittsburgh, PA. 12. Rubin, E.S., Kalagnanam, J.R., Frey, H.C. and M.B. Berkenpas (1997). "Integrated Environmental Control Modeling of Coal-Fired Power Systems", J. Air & Waste Mgmt. Assoc., 47, 1180-1188. 13. IECM (2001). Integrated Environmental Control Model User Documentation, www.iecmonline.com Center for Energy and Environmental Studies, Carnegie Mellon University, Pittsburgh, PA. 14. Rubin, E.S., Taylor M.R., Yeh S. and D.A. Hounshell (2002). "Experience Curves for Environmental Technology and Their Relationship to Government Actions," Proc. of GHGT-6 Sixth International Conference on Greenhouse Gas Control Technologies, October 1-4, 2002, Kyoto, Japan.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1125

COSTS OF RENEWABLE ENERGY AND CO2 CAPTURE AND STORAGE John Davison IEA Greenhouse Gas R&D Programme, Cheltenham, GL52 7RZ, UK

ABSTRACT This paper compares the costs and emissions of renewable energy technologies (wind, solar and biomass) and electricity generation from fossil fuels with capture and storage of CO2. Where natural gas is available at low costs, gas-fired combined cycle plants with capture and storage of CO2 have the lowest electricity generating costs. If the cost of gas is high, wind turbines at favourable sites are cheaper. The cost of wind energy depends strongly on the load factor and costs at low wind speed sites are high. Biomass fired power generation could be competitive if the biomass is available at very low costs but purpose grown biomass in developed countries is expected to be relatively expensive. Coal fired power generation with CO2 capture and storage could be cost competitive if coal costs are low. Solar thermal energy is more expensive than the other options for stand-alone plants but it may be competitive when used in combination with fossil fuel fired plants. Solar photovoltaics are currently more expensive than the other technologies for large scale power generation but they can be attractive for small niche applications. Costs of all of these technologies are expected to decrease in future.

INTRODUCTION Large reductions in CO/emissions will be needed to achieve the UNFCC goal of stabilisation of atmospheric greenhouse gas concentrations. Over a third of the emissions of CO2 to the atmosphere from use of fossil fuels are from electricity generation so this is a priority area for emission reductions. In 1999, 64% of electricity was generated from fossil fuels (coal, oil and natural gas), hydro and nuclear each generated 17% and the remaining 2% was generated from renewables and waste [1]. The future of nuclear power is uncertain. It may be difficult to significantly increase nuclear power output because of public concerns about radioactive waste disposal, proliferation of nuclear materials and safety. Although some new nuclear plants will be built, this is expected to be countered by closure of existing plants. There will be some increase in hydro electricity production but the increase will be constrained by availability of sites and environmental concerns. If large reductions in CO2 emissions from electricity generation are to be achieved there will need to be a large increase in renewable energy production and/or large reductions in emissions per kWh from fossil fuel power stations. Specific emissions fi'om fossil fuel power stations will reduce as a result of improvements in thermal efficiencies but to achieve large reductions, CO2 will have to be captured and stored for long periods of time, several hundred years or more. This paper discusses the costs, emissions and constraints on renewable energy technologies and capture and storage of CO2.

1126

WIND ENERGY

Wind turbines have the advantage of producing no CO2, apart from a small amount produced during manufacture of the turbines. Their main disadvantages are that they can have a major visual impact on the landscape, they only generate electricity when the wind is blowing and the best sites with high wind speeds are ot~en remote from centres of electricity consumption. At the end of 2001, there was about 25 GW of installed wind turbine capacity worldwide [2]. Over the previous 5 years, the global capacity has grown at an average rate of more than 30% per year. The potential amount of electricity that could be generated from wind energy is many times greater than the current or projected future demand. For example, the total amount of electricity that could be generated from wind energy in the EU-15 is predicted to be 40,000 TWh/y, which can be compared to a demand of about 2,300 TWh/y. Environmental and technical constraints (exclusion of ground with steep slopes, urban areas, forests, conservation areas etc) reduce the potential to 30,000 TWh/y. Social constraints, such as proximity to dwellings and limits on the maximum number of wind turbines in a given area, are predicted to reduce the potential to 1,300 TWh/y, based on the current turbine density of high wind power regions of Denmark [3]. Even in the relatively densely populated region of the EU, with a high per capita electricity consumption, it is apparent that wind energy could provide a large proportion of the electricity demand. The social constraint may change in future depending on public perception of wind turbines. Costs of wind turbines have decreased substantially in recent years and are continuing to do so. The cost of a wind turbine is currently about $700/kW of peak power output and the total cost of a large onshore windfarm, including grid connection, is typically about $1,000/kW [3,4]. The annual load factor of a wind turbine depends strongly on the wind speed. The annual average load factor would be about 20% at an annual mean wind speed of 6 m/s and nearly 40% at an annual mean wind speed of 8 m/s. Wind is an intermittent energy source; typical electricity grids can easily accommodate small amounts of wind energy but as the amount of wind energy increases, the overall system effects increase. To cope with times when wind energy availability is low, extra fossil fuel-fired back-up generating capacity would have to be installed and the fossil fuel-fired plants on the grid would have to spend more time operating as peaking plants, at lower efficiencies. At high wind energy penetrations, some of the potential wind generation may have to be curtailed or energy storage systems may have to be used. The costs of these system effects are predicted to be less than 0.5 USc/kWh of wind energy at 45% wind penetration [5].

SOLAR ENERGY Two types of technology can be used to generate electricity from solar energy: solar thermal and photovoltaics (PV). PV cells convert solar energy directly to electricity. Solar thermal processes either produce steam, which is expanded in a conventional steam turbine, or they heat air in a gas turbine. The potential amount of electricity that could be produced by PV is very much greater than electricity demand, even if only 1% of the suitable land was used [6]. The potential of solar thermal generation is less because it can only use direct sunlight at sites with high solar irradiation, whereas PV can also utilise diffuse sunlight. The global potential electricity generation would still be many times greater than demand but it would be concentrated in Africa, Australia and the Middle East. The installed capacities of photovoltaic and solar thermal generating plants are currently about 1,000 MW and 350 MW respectively. The price of large scale photovoltaic modules is about $3,500-4,000/kW of peak power. The overall average price of modules, including small modules at retail prices, is about $6000/kW and total system prices range from 6,000 to 12,000 $/kW of peak power [6]. Costs of projected new solar thermal plants range from about $2,000/kW to $4,700/kW for stand-alone steam cycle plants and from $700/kW to $1,900/kW for Integrated Solar Combined Cycle Systems, where solar energy is used to supplement the steam cycle of a gas fired combined cycle plant [6]. In common with wind energy, solar energy is an intermittent energy source and a typical load factor for solar power generator without storage would be 25% [6]. Solar thermal energy

1127 systems can include some energy storage but this increases the capital cost per kW. For the comparison of options later in this paper, a capital cost of $2,000/kW and a load factor of 35% were assumed.

BIOMASS E N E R G Y

Biomass by-products such as sawdust, bark, straw and bagasse are already widely used for heat and power generation. Fast growing biomass such as poplar, eucalyptus, acacia, and miscanthus can also be grown specifically for use as fuel. The amount of CO2 emitted from biomass fired power stations is high, usually more per kWh than from coal fired power stations, but the CO2 is absorbed during growth of the biomass. Biomass from sustainable harvesting systems can therefore be regarded as an almost CO2-neutral fuel. The potential to generate electricity from biomass would be constrained by the available resource in many parts of the world. The amount of additional biomass fuel that could be produced in 2050 is projected to be 396 EJ/y [7]. If this were all used for power generation at an efficiency of 30%, it would generate 33,000 TWh/y of electricity, which can be compared to the global consumption of 14,800 TWh in 1999 and the projected consumption of 27,300 in 2020 [1,7]. However, only 13% of the potential generation from biomass (4,300 TWh/y) would be in the developed countries, economies in transition and the rest of Asia, which account for most of the world population and about 90% of its electricity demand. This quantity of biomass would require 1.28 Gha of land, which is large compared to the projected requirement of 1.7 Gha for agriculture in 2100 [7]. In most of the world, production of substantial amounts of biomass fuel would involve land use conflicts which could have serious implications for the supply and price of food, as well as the price of biomass. A study by IEA GHG [8] showed that in Spain only 5% of the current electricity demand could be satisfied using short rotation biomass without having to use good quality agricultural land. Current biomass power stations are normally based on stoker or fluidised bed combustion steam cycles. Biomass power stations tend to be relatively small, e.g. 25-60 MWe, because the amount of biomass that can be produced within a given radius of a power station is limited and biomass is bulky and expensive to transport compared to fossil fuels. The small size results in relatively low thermal efficiencies. Biomass can be co-used in large coal fired power stations, which results in better economies of scale and higher efficiencies, provided such plants are available. Integrated gasification combined cycles are being developed to increase the efficiency of power generation from biomass. Costs are currently higher than for conventional combustion plants but they may decrease in future when the technology is fully proven. The comparison of options later in this paper is based on a 60 MW stand-alone combustion plant with a capital cost of $1,650/kW and an efficiency of 30%, LHV basis [9].

CAPTURE AND S T O R A G E OF CO2 CO2 can be captured in fossil fuel fired power stations and stored for hundreds or thousands of years, for example in depleted oil and gas fields, deep saline aquifers or unminable coal seams. The main techniques that have been proposed for capturing CO2 in power stations are: • • •

Scrub the flue gas with a regenerable chemical solvent, such as monoethanolamine (MEA). Burn fossil fuels using oxygen, to produce a flue gas containing more than 90% CO2. Partially oxidise the fossil fuel to a fuel gas, and react this gas with steam to give hydrogen and CO2. After separating the CO2, the hydrogen can be used in a gas turbine or fuel cell.

These CO2 capture techniques use mainly proven technologies, although there is a need to integrate them and demonstrate their use at a large scale. CO2 can be transported to storage sites by pipeline or ship; over 3000 km of CO2 pipelines are already operating successfully, mainly in the USA. CO2 is already being stored underground, for example nearly 1 million tonnes per year is being stored at the Sleipner field in the Norwegian sector of the North Sea. Further work is needed to develop and test monitoring and verification techniques to give confidence that CO2 can be safely stored underground for long periods of time.

1128 The main technical constraint on the use of C O 2 capture and storage is the capacity to store CO2. About 900 Gt of CO/could be stored in depleted oil and gas reservoirs, equivalent to over 100 years of current global emissions from power generation [ 10]. The capacities of other potential CO2 storage reservoirs are less well know, for example it is estimated that 400-10,000 Gt of CO2 could be stored in saline aquifers [ 10]. The capital cost and efficiency of a coal fired power station with CO2 capture using MEA are estimated to be $1,860/kW and 33% (LHV basis). The capital cost and efficiency of a natural gas combined cycle plant with MEA scrubbing are estimated to be $790&W and 47% [ 11 ]. Overall costs of generation for plants involving partial oxidation/gasification are at present broadly similar to costs of plants using MEA scrubbing [11]. These costs include CO2 compression but do not include the costs of CO2 transport and storage. If the CO2 is used for enhanced oil recovery or enhanced coal bed methane production, the net cost of CO2 transport and storage could be zero, or even negative if there is revenue from the sale of oil or gas. If CO2 is transported 300km from a single power plant, and is stored in an onshore reservoir that does not produce any economic revenue, the cost may be around $8/t of CO2 stored. If CO2 is transported a long distance or is stored in a distant offshore reservoir the costs may be higher, say $20/t of CO2 stored.

COMPARISON OF COSTS Figure 1 shows the current costs of each of the electricity generation technologies. Solar photovoltaics is not included because its costs are several times higher than those of the other technologies. Costs of wind energy are shown for 3 load factors: 40%, which can be achieved at good sites, 30% which is typical of a moderate/good site and 20%, typical of a moderate/poor site. Coal, gas and biomass fired power stations are not constrained by the timing of energy resource availability and are assumed to operate at base load with load factors of 85%, 90% and 85% respectively. Figure 1 is based on a 10% discount rate in constant money values, a life of 20 years for wind turbines and 25 years for other technologies.

12 10 .... ....... - --~---m---#--

[- . . . . . . . . . . . . . . . . . . . . . . . . .

.. 8 r~ 0

..~

6

°1,1 "

4

~

2

0

1

2

3

4

Coal+CO2 storage Gas+CO2 storage Biomass Solar thermal Wind (20% load) Wind (30% load) Wind (40% load)

5

Fuel cost, $/GJ

Figure 1- Comparison of electricity generation costs based on current technologies At fuel costs of less than $3/GJ, natural gas fired combined cycle plants with CO2 capture and storage have the lowest electricity generating cost. If the cost of gas is higher, wind turbines at favourable sites with high load factors are cheaper. However, the cost of wind energy depends strongly on the load factor, and costs at low wind speed sites are high. Biomass may be an attractive fuel for power generation if it is available at very low costs but purpose grown biomass in developed countries is expected to be relatively expensive, around $3/GJ [8], resulting in high electricity costs. Coal fired power generation with CO2 capture and storage may be cost competitive if coal costs are low. Solar thermal energy is more expensive than the other options for stand-alone plants but it may be competitive when used in combination with fossil fuel fired plants, in which case the costs may be around half of those shown in figure 1. Local factors determine fuel costs and the availability of renewable energy resources and COz storage reservoirs. The optimum combination of technologies will be different for different countries.

1129 The costs shown in figure 1 for coal and gas fired plants are based on a CO2 transport and storage cost of $8/t CO2 stored. If the cost was $20/t, the cost of generation would be 1.0 c/kWh higher for a coal fired plant and 0.5 c/kWh higher for a gas fired plant. If CO2 could be transported and stored at no net cost, the generating cost would be 0.7 c/kWh lower for a coal fired plant and 0.3 c/kWh lower for a gas fired plant. The costs of wind and solar energy exclude penalties for intermittent generation. As discussed earlier, the penalty for wind energy is predicted to be less than 0.5 c/kWh at 45% wind energy penetration.

FUTURE COST P R O J E C T I O N S The costs of all of the technologies considered in this paper are expected to decrease in future because of technological improvements and larger markets. Projections of possible costs in 2020 are shown in figure 2. However, it must be emphasised that any projections of costs 20 years into the future involve speculation and cost improvements will depend on the extents to which the technologies are applied. The cost of wind turbines may fall by around 20-40% by 2020 [3,12]; figure 2 is based on a 30% cost reduction. Efficiencies of plants with CO2 capture will improve because of improvements in capture technologies and general improvements in power station efficiencies. In the case of coal plants, a move towards IGCC would also contribute to improved efficiencies. It is difficult to quantify potential reductions in the costs of capture technologies but in the analogous technology of flue gas desulphurisation, capital costs decreased by 75% between 1970 and 2000 [13]. For the cost projections in figure 2 it was assumed that the specific capital costs of power stations without CO2 capture would remain constant, the incremental capital cost of capture would decrease by 50%, efficiencies would increase by 10 percentage points and the costs of CO2 transport and storage would remain constant. For biomass, it was assumed that the state of the art would become biomass IGCC, with an efficiency of 45%, allowing for improvements in gas turbines. The capital cost of biomass IGCC is currently significantly greater than the cost of combustion plants but it was assumed that by 2020 the capital cost of biomass IGCC would be the same as the current cost of combustion plants. Costs of solar thermal energy are subject to more uncertainty than the costs of the other technologies. The overall potential for cost reduction is estimated to be in the range of 40-55% in the long term, based on a number of technical and economic improvements [6]. For figure 2 it was assumed that costs could reduce by 40% by 2020.

.= 8

!

I

Coal+CO2 storage 6

....

r~

o 5

¢,J

Gas+CO2 stoarge

. . . . . . . Biomass

~4 •~. 3 .~

2

.....

Solar thermal

.....

Wind (30% load)

1

0

1

2

3

4

5

Fuel cost, $/GJ

Figure 2: Comparison of electricity generation costs, 2020 The 2020 costs in figure 2 are lower than current costs for all of the technologies. The main differences compared to current costs are that solar thermal and to a lesser extent wind energy are more competitive.

1130 EMISSIONS

In plants with capture and storage of CO2 about 15% of the CO2 would still be emitted to the atmosphere, although this could be reduced if required. All of the power generation technologies emit some CO2 and other greenhouse gases indirectly, during fuel production and transportation and power plant construction. These direct and indirect emissions are summarised in table 1 [6, 8, 11, 14, 15].

TABLE 1 CO2 EMISSIONSFROMELECTRICITYGENERATION

Direct emissions, g/kWh Indirect emissions, g/kWh

Coal with CO2 capture 150 60

Gas with CO2 capture 60 10

Biomass

Solar thermal

Wind

10

30

10

CONCLUSIONS

The lowest cost methods of generating electricity with low emissions of CO2 are natural gas fired combined cycle plants with capture and storage of CO2 or wind turbines at sites with high wind speeds. Biomass-fired power stations and coal fired power stations with capture and storage of CO2 can be competitive at low fuel costs. Solar thermal energy is currently not cost competitive, except possibly in combination with fossil fuel plants. The costs of all of these technologies are expected to decrease in future.

ACKNOWLEDGEMENT

The views expressed in this paper are those of the author and do not necessarily represent those of the International Energy Agency, the lEA Greenhouse Gas R&D Programme or its Members.

REFERENCES

1. IEA (2201). Key Worm Energy Statistics 2001, International Energy Agency, Paris, www.iea.org 2. BTM Consult (2002). International wind Energy development: World Market Update 2001, BTM Consult, Denmark, April 2002, www.btm.dk 3. Fellows, A., Gow, G., Ellis, A. and Davison, J., (2001). The Potential of Wind Energy to Reduce CO: Emissions, European Wind Energy Conference, Copenhagen, 2-7 July 2001. 4. European Wind Energy Association (2002), www.ewea.org/src/economics.htm 5. Milborrow, D., (2002), www.piu.gov.uk/2002/energy/report/working%20papers/Milborrow.pdf 6. IEA Greenhouse Gas R&D Programme (2002), The Potential of Solar Energy to Reduce C02 Emissions, forthcoming study, Cheltenham UK. 7. Intergovemmental Panel on Climate Change (2001), Climate Change 2001: Mitigation, Cambridge University Press, UK 8. Varela, M,, Sfiez, R. and Audus, H. (2001), Solar Energy 70(2), 95-107. 9. IEA Greenhouse Gas R&D Programme (1999), Report no. PH3/11, Nov. 1999, Cheltenham, UK. 10. IEA Greenhouse Gas R&D Programme (2001), ISBN 1898373 07 8, www.ieagreen.org.uk 11. Audus, H., (2000). Leading options for capture of C02 at power stations, GHGT-5 Conference, Cairns, Australia, 13-16 August 2000, CSIRO Publishing, Australia. 12. European Wind Energy Association and Greenpeace (2002), Wind Force 12, EWEA, Brussels 13. Soud, H.M. (2000), IEA Coal Research report CCC/29, ISBN 92-9029-339-X. 14. IEA Greenhouse Gas R&D Programme (1995), ISBN 1 898373 03 5, www.ieagreen.org.uk 15. European Commission DG XII, (1995), ExternE: Externalities of Energy, Luxembourg

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1131

COST AND PERFORMANCE OF CO2 AND ENERGY TRANSMISSION D.J. Freeman 1, D.A. Findlay l, M. Bamboat 1, J. Davison 2 and I. Forbes 3 1Woodhill Engineering Consultants, St. Andrew's House, West Street, Woking, GU21 1EB, UK 2IEA Greenhouse Gas R&D Programme, Stoke Orchard, Cheltenham, GL52 7RZ, UK 3Mort MacDonald, Victory House, Trafalgar Place, Brighton BN 1 4FY, UK

ABSTRACT The need to reduce emissions of greenhouse gases could have major effects on energy transmission. CO2 from fossil fuels may need to be captured and transported to long term stores, for example deep saline aquifers or depleted oil and gas fields. This may affect the optimum location of energy conversion plants such as power stations. Also, novel energy carriers such as hydrogen may become more attractive. On behalf of the IEA Greenhouse Gas R&D Programme, Woodhill Engineering Consultants, in collaboration with Mott MacDonald, have developed a model for initial assessment of the costs and performance of energy transmission and CO2 capture. The model covers the distribution of energy in various forms such as natural gas, hydrogen, methanol, distillate oil, and electricity, and the capture and gathering of CO2 using onshore and offshore pipeline transmission. Sensitivities can be assessed for a wide range of factors, such as the output of power stations, fuel supply flowrate, pipeline diameter, operating pressure, terrain and country. Cost estimation is based on industry standard techniques. The model also includes simple algorithms for the costs and performances of energy conversion plants, such as power stations and hydrogen plants, and for underground injection of CO2. This paper contains a description of the model and includes several examples of predicted costs and performance of energy distribution and CO2 capture and transmission. INTRODUCTION

Future strategies for fuel transmission and CO2 sequestration have always and will continue to be influenced by capital and operating costs (capex and opex). In addition to the costs of energy conversion (e.g. hydrocarbon fuel to electricity), other costs to be considered include fuel transportation, electricity distribution and CO2 sequestration. All these costs can vary considerably with relatively small changes in the strategy selected. On behalf of the IEA Greenhouse Gas R&D Programme (lEA GHG), Woodhill Engineering Consultants, in collaboration with Mott MacDonald, have developed a model for the initial assessment of the costs and performance of energy transmission and CO2 capture. This paper includes details of the model, a discussion of the key factors that affect costs, and examples of predicted costs. The model addresses capex and opex for energy distribution and CO2 sequestration. These cost estimates can be used in economic modelling which may include other factors not addressed in this paper, such as emissions trading, carbon tax, local logistics and planning.

1132 CO2 TRANSMISSION The use of pipelines for transportation of gaseous and liquid hydrocarbon fuels has long been established. Pipelines for transmission of CO2 are also in operation, and factors to be addressed include:

C02 Quality In the presence of liquid water, CO2 forms carbonic acid which can cause corrosion of carbon and low alloy steels. CO2 corrosion has been studied extensively, and the precautions needed to satisfactorily transport CO2 in carbon steel lines are well documented [ 1]. CO2 should not cause corrosion of carbon and low-alloy steel lines, provided the gas is dry. Operating below 60% relative humidity normally provides a margin to avoid water condensation or dropout from the gaseous phase. Without free water in the system, carbon steel is an acceptable material for CO2 pipelines. C02 Phase Behaviour The phase behaviour of CO2 can cause considerable process concerns, particularly with respect to possible phase changes. The Model described in this paper assumes that following capture, CO2 is dried and its pressure boosted to achieve a dense phase fluid for efficient pipeline transport to a storage site [2]. At pressures and temperatures above the critical point, CO2 will exist as in the dense phase region. ENERGY DISTRIBUTION SYSTEMS An Energy Distribution System (EDS), for the purposes of this paper, is considered to supply electrical power to consumers using a fossil fuel source. An EDS typically comprises the following elements: Fuel sources, e.g. natural gas, oil or coal. Systems to transport the fuel from the source. Fuel synthesis plants, for the manufacture of e.g. methanol or hydrogen from natural gas. Power stations, using natural gas, oil, methanol, hydrogen or coal to generate electricity. Electrical transmission system. Systems for sequestration of CO2 from fuel synthesis plants or power plants for disposal. CO2 storage facilities. There may be many options available to supply energy from any given source, as shown in Figure 1. In this example, natural gas is used as the fuel source to generate electrical power for three separate 400 MW consumers. Four possible options to supply this power are shown: A centralised 1200 MW natural gas-fired power station, with centralised CO2 sequestration facility. Electricity is supplied to the consumers via relatively long transmission lines. Local 400 MW power stations for each consumer. The transmission lines will be shorter, but longer pipelines will be needed for fuel and CO2 transmission. A centralized power station, fuelled by hydrogen which is manufactured from natural gas at a synthesis plant close to the fuel source. No CO2 is produced at the power station, and CO2 captured at the synthesis plant can be stored using relatively short pipelines. Local hydrogen-fuelled power stations. These illustrate that the options for supplying energy to consumers from a given fuel source may be extremely varied, and when selecting the most appropriate option there are many considerations to be made, including: capex and opex; safety; environmental impact; logistics of construction; etc. The use of smaller, local power stations reduces losses in transmission lines, but means that pipelines for fuel and CO2 may be longer, with higher compression requirements. The costs associated with three small power stations compared with a single large one will also be different. The optimum location for a single facility may also be difficult to determine, with a balance required between long transmission lines and long pipelines.

1133 Figure 1: Example Energy Distribution System la: Centralised fossil fuel power station Consumers Power station (1200 MW)

Fuel Source Fuel pipeline (200 km)

V A "'~ - - - . a ~ o 0 Electrical Transmission /I

km

COz pipeline (200 km) 50 km !

/~

C02 recovery and compression

CO2 injection facility

lb: Distributed fossil fuel power stations Power stations (400 MW)

:i"

|. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . |

1¢: Centralised, hydrogen fuel power station Power station (1200 MW) ~

10 km d H2 synthesis [ H2 Pipeline (190 km) "1 plant !

~"

A

COz pi~elin_e_(IOkm_)__ |

ld: Distributed hydrogen fuel power stations Power stations (400 MW)

"-i'll Hz syntheSiSplant] i |

r- . . . . . . . . . . |

r

ps~

1134 Using hydrogen as a fuel is an attractive alternative from an environmental point of view, because no CO2 will be produced at the power stations. The hydrogen synthesis plant will produce CO2, but if the CO2 is stored close to the fuel source then the CO2 pipelines are likely to be shorter than from a power station. Transmission of hydrogen in pipelines presents several difficulties, particularly in terms of pipeline design and hydrogen compression. Several significant metallurgical considerations (such as hydrogen induced cracking) need to be taken into account when designing pipelines for hydrogen service. However, carbon steels with a low sulphur content and alloyed with other metals are commonly used for hydrogen service. Similarly, centrifugal compressors are not generally suitable for hydrogen compression as the pressure rise per stage is very small due to the low molecular weight of the gas: reciprocating compressors are often used. When considering the viability of hydrogen as an alternative fuel, these considerations may mean that costs change significantly, and these must be taken into account, along with other factors such as potential environmental benefits. COST ESTIMATION

Estimation of capex and opex is essential for the comparison of options for COz and energy transmission. A model has been developed that allows an initial assessment of the costs and performance of energy transmission and COl capture, by allowing the user the overall flexibility to build each option by defining the following assets: • • • •

Power station (including a CO2 export pipeline and power transmission) Fuel synthesis plant (with associated export pipeline) CO2 storage facility (with pipeline and storage wells) Pipeline system

By defining the necessary assets, the costs for any complete EDS can be estimated. The model takes into account global factors such as the location and fuel costs, and determines capex and opex for each asset and for the EDS as a whole. P o w e r station

The power station has been designated as using either Combined Cycle Gas Turbine (CCGT) or Pulverised Coal Steam Cycle technology. As an intrinsic element of the model, all power stations incorporate recovery of COz from the exhaust gases of the plant. The CO2 recovery process is assumed to use amine absorption. Capex and opex estimates are based on IEA GHG data for natural gas and coal fired electrical power stations, with factors applied for power stations of other fuels, i.e. methanol, distillate oil, and hydrogen.

Fuel synthesis A fuel synthesis plant within the model can manufacture either methanol or hydrogen. Both these products are synthesised from a natural gas feedstock. The process assumes that natural gas feedstock is converted to synthesised fuel at fixed conversion efficiencies on an energy basis [3]. Methanol synthesis plant costs are based on the conventional technology of Steam Methane Reforming (SMR) [4]. The H2 synthesis plant cost estimates are based on IEA GHG data for a plant producing H2 from natural gas, including separation of CO2.

COz sequestration

CO2 injection is assumed to take place into retaining aquifers. In general these are considered to be saline aquifers with sufficient integrity and retention such that seepage of CO2 back to the atmosphere is negligible. A second option is the use of redundant hydrocarbon reservoirs that have ceased production. The choice of a suitable aquifer is influenced by many factors such as well performance, location, etc., and is beyond the scope of this paper. Aquifers defined in the model can be located either onshore or offshore and are assumed to be approximately 1000m in depth.

1135 Injection wells can be onshore or offshore. The costs for offshore injection include the costs of a wellhead platform or subsea wells and a subsea pipeline. Offshore well costs are greater than onshore well costs.

Pipelines Pipelines may be offshore or onshore, and may include compression facilities along their length, for pipeline cost optimisation. The pipeline size and the number of booster stations are calculated using standard sizing routines or by setting them manually. The variables used to determine the size and cost of the pipeline and booster stations include the fluid (fuel, CO2 etc), length, mass flowrate through the pipeline, the terrain through which it will be laid and the required outlet pressure. Example costs for the four options shown in Figure 1 are presented in Tables 1 and 2: TABLE 1 CAPEX COST ESTIMATESFOR FOURALTERNATIVEENERGYDISTRIBUTIONSYSTEMS

Option (see Figure 1)

la

lb

lc

ld

Power Stations (inc. CO2 capture)

856

1020

450

536

Hydrogen Synthesis Plant

N/A

N/A

787

787

95

75

95

75

Electrical Transmission Natural Gas Pipelines (inc. booster compression) Hydrogen Pipelines (inc. booster compression) CO2 Storage (Pipelines, compression and wells)

70

109

14

14

N/A

N/A

135

146

127

168

73

74

Total

1148

1372

1554

1632

TABLE 2 OPEX COSTESTIMATESFOR FOURALTERNATIVEENERGYDISTRIBUTIONSYSTEMS

Option (see Figure 1)

la

lb

lc

ld

Power Stations (inc. CO~ capture)

188

207

26

35

Hydrogen Synthesis Plant

N/A

N/A

309

309

Electrical Transmission

0.3

0.0

0.3

0.0

Natural Gas Pipelines (inc. booster compression) Hydrogen Pipelines (inc. booster compression) CO2 Storage (Pipelines, compression and wells)

N/A

N/A 12

13

13

Total

196

222

354

364

1136 Comparing options l a and l b in the above example, the reduced capex for electrical transmission is significantly outweighed by the greater capex for three smaller power stations compared with a larger centralised station and the greater capex for fuel and CO2 pipelines. The model can take the terrain through which pipelines are laid into account, and can therefore be used as a tool for determining optimum (from a cost point of view) locations and routes for power stations and pipelines. The costs shown in Table 1 for options l c and l d show that in this example the total capex and opex are greater if hydrogen is used to generate electricity. The cost of the synthesis plant is a major factor, and pipelines suitable for transportation of hydrogen have a higher cost than natural gas pipelines. However, a decision to use hydrogen will not be determined by facilities cost alone: the environmental benefits of producing all the CO2 at a single point close to the disposal location, where it can be easily captured and stored, has significant environmental benefits. The costs calculated for this example show that the capex for CO2 storage are significantly lower for options 1c and 1d. CONCLUSIONS Transmission and disposal of CO2 is a challenge for engineers, and there are many considerations to be made, including capex and opex, safety, environmental impact, logistics of construction, etc. The model presented in this paper can be used for initial assessment of the costs of energy transmission and CO2 capture, and allows quick and easy comparison of different options for gathering COz from multiple sources and of various energy transport development cases. The sensitivity to a wide range of factors, such as output of power stations, fuel supply flowrate, pipeline diameter, operating pressure, terrain and country can also be assessed. The cost estimation is based on well-established industry standard sizing techniques and the contractors' in-house estimating methods using industry norms, and the clear audit trail within the model means that the costs can be used with confidence. REFERENCES

1.

RH Perry (Ed), Perry's Chemical Engineers' Handbook, 7th Edn, 1997 IEA Greenhouse Gas R&D Programme Report, Carbon Dioxide Disposal From Power Stations, IEA Greenhouse Gas R&D Programme, Cheltenham, UK

3.

ARCADIS Geraht & Miller, Inc., Fuel Cycle Energy Conversion Efficiency Analysis, 25 May 2000

4.

Foster Wheeler, Foster Wheeler StarChem Methanol Process, 30 July 2001

POLICY- OVERVIEW

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1139

E X P E R I E N C E C U R V E S FOR E N V I R O N M E N T A L T E C H N O L O G Y AND THEIR R E L A T I O N S H I P TO G O V E R N M E N T ACTIONS E.S. Rubin l, M.R. Taylor 2, S. Yeh 1 and D.A. Hounshell 1 l Department of Engineering and Public Policy, Carnegie Mellon University Pittsburgh, PA 15213, USA 2 Richard & Rhoda Goldman School of Public Policy, University of California, Berkeley Berkeley, CA 94720-7320

ABSTRACT We seek to improve the ability of integrated assessment models (IA) to incorporate changes in CO2 capture and sequestration (CCS) technology cost and performance over time. This paper presents results of new research that examines past experience in controlling other major power plant emissions that might serve as a reasonable guide to future rates of technological progress in CCS systems. In particular, we focus on U.S. and worldwide experience with sulfur dioxide (SO2) and nitrogen oxide (NOx) control technologies over the past 30 years.

INTRODUCTION

Large-scale energy-economic models used to study global climate change and carbon management options often ignore the impacts of environmental technology innovation and diffusion, or they use simple representations such as exogenously-specified (often arbitrary) rates of change in cost or efficiency over time. The predicted impacts of proposed policy measures can depend critically upon these assumptions. Thus, better methods are needed to model technological change and its relationship to government policy. This is especially true for CO2 capture and sequestration (CCS) technology, an important new class of environmental technology with the potential to allow continued use of fossil fuels without significant greenhouse gas emissions to the atmosphere. Research efforts are underway worldwide to develop this technology and evaluate its effectiveness. Large-scale energy-economic and integrated assessment models also are being used to evaluate the potential of CCS in competition with other options for CO2 control. We seek to improve the ability of such models to represent and quantify the changes in CCS technology cost and performance over time as a function of pertinent variables, including the effects of alternative government actions or policies. Toward this end, this paper presents results of new research that examines past experience in controlling other major power plant emissions that might serve as a reasonable guide to future rates of technological progress in CO2 capture and sequestration systems. In particular, we focus on U.S. and worldwide experience with sulfur dioxide (SO2) and nitrogen oxide (NOx) control technology over the past 30 years, seeking answers to the following related questions: (1) how did the deployment, performance, and cost of these environmental technologies change over time? And, (2) how were these changes and technological innovations related to government actions and policies?

1140 DEVELOPMENT

OF EXPERIENCE

CURVES

Two widely used emission control technologies at coal-fired power plants are flue gas desulfurization (FGD) systems used to control SO2 emissions and selective catalytic reduction (SCR) systems used to control NOx emissions. Both technologies are post-combustion control systems applied to the flue gas stream emanating from a coal-fired boiler or furnace. In contrast to environmental controls that are applied either prior to or during combustion, FGD and SCR systems represent the technologies having the highest pollutant removal efficiencies currently available for coal-burning plants. They are also the most expensive technologies for emissions control, and for this reason requirements for their use have been highly controversial.

Historical Deployment of FGD Systems. FGD systems (also known as scrubbers) encompass a variety of technologies that have been extensively described and discussed in the literature [1]. By far the most prevalent technology, accounting for approximately 86% of the world market, are socalled "wet" FGD systems employing limestone or lime as a chemical reagent. These systems can achieve the highest SO2 removal efficiencies (historically around 90%, but today as high as 98 to 99%), but they generate a solid residue that must either be transformed into a useful byproduct (gypsum) or disposed as a solid waste. So-called "dry" FGD systems typically use lime as the reagent in a spray dryer system that is less efficient than wet FGD systems but adequate to achieve the less restrictive SO: removal requirements for low-sulfur coals allowed by the New Source Performance Standards (NSPS). Because of their limited applicability, lime spray dryers and other forms of dry SO2 removal account for less than eight percent of the total FGD market [ 1].

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Figure 1.

Figure 1 depicts the worldwide growth in FGD installations over the past three decades. The y-axis measures the total electrical capacity of power plants whose flue gases are treated with wet lime or limestone scrubbers. Figure 1 also shows that the United States has led in the deployment of this technology. Today, approximately 30 percent (80,000 MW) of U.S. coal-fired capacity is equipped with FGD systems, most of which are wet scrubbers.

Relationship to SOz Control Requirements. The onset and growth of FGD use in each country reflects the adoption of national (and in some cases international) regulations that were sufficiently stringent so as to require or encourage the use of FGD as an emissions control strategy. In the United States, stringent requirements for SO2 control can be traced to the Clean Air Act Amendments (CAAA) of 1970 and 1977. Many existing power plants chose to retrofit FGD systems in order to meet state and local emission regulations designed to achieve the national ambient air quality standards for SO2 established under the 1970 CAAA. For new power plants, federal New Source Performance Standards (NSPS) set by the U.S. Environmental Protection Agency (EPA) required the use of "best available control technology" (BACT). The first NSPS for coal-fired power plants, established in 1971, defined BACT as a performance-based standard limiting SO2 emissions to 1.2

1141 pounds per million Btu (lb/MBtu) of fuel energy input to the boiler. This emission standard corresponded to roughly a 75 percent reduction from the average emission rates at the time, but allowed new plants to comply either by burning a sufficiently low sulfur coal, or by installing an FGD system while burning high-sulfur coals. In 1979, a revised NSPS was promulgated that replaced the performance-based standard with a technology-based standard requiring all new coal-fired plants built after 1978 to employ a system of continuous emission reductions achieving between 70 and 90 percent SO2 removal, with the percentage depending upon the sulfur content of the coal being burned. Effectively, this meant the use of an FGD system on all new coal-fired plants. The lower removal efficiency limit applied to plants burning low sulfur coals typical of those in the western United States, while the higher limit of 90 percent removal applied to plants burning higher sulfur coals characteristic of the Midwest and eastern U.S. More recently, the 1990 CAAA established a national emissions cap for SO2 to address the problem of acid deposition. To achieve this limit, existing power plants were required to further reduce their SO2 emissions by roughly 40 percent below their 1990 levels. Power plants could comply in a variety of ways (including emissions trading), but owners of some plants chose to install FGD systems. In other countries, stringent controls on SO2 emissions were implemented initially in Japan and later in Germany. The first modem utility-scale FGD systems were installed on Japanese power plants in the late 1960s and served as benchmarks for early FGD adoptions in the United States. In 1983, in response to growing concerns about the destruction of German forests from acid rain, Germany enacted stringent new regulations requiting the installation of FGD systems on all large coal-fired plants already in service. Subsequently, other European nations also adopted regulations requiting FGD on coal-fired power plants. Resulting Trend in FGD Cost. The deployment of FGD systems over the past several decades has been accompanied by improvements in performance and reductions in the cost of this technology. We use the concept of an "experience curve" (often called a learning curve) to characterize these reductions in cost. Such curves have been discussed extensively in the literature for a wide range of technologies, including energy technologies [2-6]. Cost reductions are typically described by an equation of the form: Yi = ax[ b, where yi = c o s t t o produce the ith unit, xi = cumulative production through period i, b = learning rate exponent, and a = coefficient (constant). According to this equation, each doubling of cumulative production results in a cost savings of (1 - 2-b), which is defined as the learning rate, while the quantity 2 -b is defined as the progress ratio. These cost reductions reflect not only the benefits of learning by doing at existing facilities, but also the benefits derived from investments in research and development that produce new knowledge and generations of a technology. The development of an experience curve for FGD systems is not straightforward because many of the factors that influence cost are not directly related to improvements in the FGD technology [7]. To obtain a more accurate picture of real FGD cost reductions, we use a series of studies performed by the same organizations over a period of years using a consistent set of design premises as the basis for FGD cost estimates. These studies reflect the contemporaneous designs and costs of FGD systems installed at U.S. power plants. Figure 2 shows the experience curve developed for FGD capital cost. All costs are adjusted to a common basis for a standardized 500 MW power plant burning a high sulfur coal (3.5 % S) with a wet limestone FGD system achieving 90 percent SO2 removal. Total capital cost shows a significant decline over time. Many of the process improvements that contributed to lower costs (especially improved understanding and control of process chemistry, improved materials of construction, simplified absorber designs, and other factors that improved reliability) were the result of sustained R&D programs and inventive activity, as documented and described elsewhere [7]. Increased competition among FGD vendors also may have been a contributing factor. Such influences are difficult to discern in most studies of experience curves because the available data typically represent the cost to technology users (i.e., technology prices) rather than the cost to technology developers.

1142 However, a careful look at the underlying technological changes over several decades indicates that the FGD cost reductions shown here primarily reflect the fruits of technology innovation.

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Figure 3. Cumulative installed capacity of SCR systems on coal-fired power plants from 1980 to 2000.

Historical Deployment of SCR Systems. Figure 3 shows the historical trend in the worldwide growth of SCR capacity. Here, the earliest use of SCR is seen in Japan beginning in the 1970s, followed by widespread adoption in Germany in the mid-1980s. The U.S. has been the laggard in SCR use, with the first units on coal-fired plants installed only in 1993. Over the next few years, however, U.S. capacity of SCR systems is expected to grow significantly in response to recently enacted NOx control regulations. SCR systems also have been installed on electric power plants burning oil and natural gas since these systems also produce NOx during combustion. The total capacity of SCR systems on non-coal utility systems for U.S. power plants was approximately 11.5 GW in 1996 [8], most of which was installed only in the last decade.

Relationship to NOx Control Requirements. As with FGD systems, the onset of growth in SCR capacity reflects the stringency and timetable for NOx regulations in different countries. In the United States, the control of power plant NOx emissions initially followed the same timetable and regulatory approach as for SO2, beginning with the 1970 CAAA and 1971 NSPS. The key difference was in the stringency of applicable requirements. Under the 1970 CAAA, existing power plants were largely unaffected by state-level requirements to achieve NO2 air quality standards. For new sources, the EPA performance standards imposed only modest requirements that could be met at low cost using low-NOx bumers (LNB) for combustion. As SO2 emission restrictions grew more stringent (and more costly) during the 1970s and 1980s, NOx emission requirements for coal plants did not change appreciably until the 1990s.

1143

The acid rain provisions of the 1990 CAAA required many existing coal-fired plants to install "reasonably available control technology" in the form of low-NOx burners and other combustion modifications. In 1994, EPA established much more stringent emission reduction requirements (averaging about 85 percent) for existing power plants as part of a regional strategy to attain the health-related air quality standards for ground-level ozone. Achieving these stringent NOx reductions requires retrofitting SCR systems at many existing power plants. A massive expansion in SCR installations is thus now underway in the United States. A 1997 revision to the Federal NSPS also now requires a high level of NOx control that is currently achievable only with SCR systems in most cases. In contrast to the U.S. situation, the use of SCR in other industrialized countries began many years ago in response to stricter NOx emission limits. Japan first enacted strict requirements in the 1970s and pioneered the development of SCR technology for power plant applications. In the mid1980s, Germany required the use of SCR systems on large coal-fired power plants as part of its acid rain control program. Subsequently other European countries also began to adopt this technology, as seen in Figure 3. 100%

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A P P L I C A T I O N TO I N T E G R A T E D ASSESSMENTS MODELS The resulting learning rates of 11% and 12% for FGD and SCR systems, respectively, are similar not only to each other, but also to the average learning rates found in other studies for a wide range of market-based technologies [4, 10]. We believe the quantitative results presented here can provide useful guidelines for assessing the influence of technological change on future compliance costs for new environmental control requirements for coal-based power plants. In this context, our preliminary experience curve for FGD systems was used as a surrogate for the rate of capital cost decline that might be expected if CO2 capture and storage (CCS) systems were deployed at power plants as part of a future strategy to reduce greenhouse gas emissions. Preliminary results from an integrated assessment modeling study carried out by researchers at IIASA [11] indicated that the cost of achieving a climate stabilization target was significantly lowered when the historical learning rate for SO2 capture systems was applied to CCS systems for fossil fuel power plants. Several methodological issues remain to be further explored in the context of modeling studies with long

1144

time horizons such as the 50- to 100-year time frames commonly used for climate policy analysis. In particular, it is unlikely that the learning rates observed during the initial development and deployment of a new environmental technology (like CO2 capture) will be sustained indefinitely as the technology matures [12]. Future studies will explore this and other issues as part of our continuing research in this area. ACKNOWLEDGEMENT

This project was supported by the Office of Biological and Environmental Research, U.S. Department of Energy, under Grant No. DE-FG02-00ER63037. The authors thank Dr. Leo Schrattenholzer and Dr. Keywan Riahi of IIASA for their collaboration on this project. REFERENCES

1. 2. 3. 4. 5. 6. 7.

9.

10. 11. 12.

Soud, H.N., FGD installations on coal-firedplants. 1994, IEA Coal Research: London. Arrow, K., The Economic Implications of Learning by Doing. Review of Economic Studies, 1962.29: p. 155-173. Dutton, J.M. and A. Thomas, Treating Progress Functions as a Managerial Opportunity. Academy of Management Review, 1984. 9(2): p. 235-247. Dutton, J.M., A. Thomas, and J.E. Butler, The History of Progress Functions as a Managerial Technology. Business History Review, 1984. 58(2): p. 204-233. Grfibler, A., N. Nakicenovic, and D.G. Victor, Dynamics of Energy Technologies and Global Change. Energy Policy, 1999.27(5): p. 247-280. Thompson, P., How Much Did the Liberty Shipbuilders Learn? New Evidence for an Old Case Study. Journal of Political Economy, 2001. 109(1): p. 103-137. Taylor, M., The Influence of Government Actions on Innovative Activities in the Development of Environmental Technologies to Control Sulfur Dioxide Emissions from Stationary Sources, in Department of Engineering and Public Policy. 2001, Carnegie Mellon University: Pittsburgh, PA. U.S. Environmental Protection Agency, EPA Clean Air Market Program: Emissions Data & Compliance Reports. 2002. U.S. Geological Survey, Minerals Information: commodity statistics and information. 2001. The Boston Consulting Group, Perspectives on Experience. 1972: Boston, MA. Riahi, K., E.S. Rubin, and L. Schrattenholzer, Technological Learning for Carbon Capture and Sequestration Technologies. Energy Economics, 2002. submitted. Klepper, S. and E. Graddy, The Evolution of New Industries and the Determinants of Market Structure. RAND Journal of Economics, 1990.21(1): p. 27-44.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1145

G R E E N H O U S E GAS INTENSITY T A R G E T S VS. A B S O L U T E EMISSION T A R G E T S N. Hrhne and J. Harnisch ECOFYS energy & environment, Eupener Str. 161, 50933 Cologne, Germany

ABSTRACT Emission limitation or reduction targets for countries under the international climate negotiations can be formulated as absolute targets, defining a fixed amount of allowed emissions (as in the Kyoto Protocol), or as intensity targets, defining an amount of allowed emissions per unit of the Gross Domestic Product (as recently proposed by the US government). In this paper, we discuss the pros and cons of these types of emission limitation or reduction targets. We find that intensity targets can provide advantages over absolute targets as they can lead to more certainty whether a target will be reached and they can account for unexpected economic changes. This is however only the case if emissions and GDP are well correlated, the strength of this correlation is know and used to set the target. For a limited number of examples we have shown that deriving the relationship between emissions and GDP (as needed for defining intensity targets) from historical data is difficult for most of these cases. Further analysis is necessary in order to be able set intensity targets in a way that maximises their advantages over absolute targets.

INTRODUCTION The United Nations Framework Convention on Climate Change (UNFCCC) calls for the stabilization of greenhouse gas concentrations at levels that prevent dangerous anthropogenic interference with the climate system. As a first step, the Kyoto Protocol defines greenhouse gas emission targets for industrialized countries. For further necessary steps, nations may want to agree on additional targets for possibly more countries. In this paper, we analyse the pros and cons of two ways to formulate emission limitation or reduction targets for countries under an international climate agreement: 'Absolute targets' and 'intensity targets'. Further, we analyse historical emission and GDP data using regression analysis. TWO TYPES OF T A R G E T S 'Absolute targets' define a fixed amount of emissions which is assigned to each country for a certain year (compare Eqn. 1). E.g. the Kyoto Protocol requires the European Union to reduce their total greenhouse gas emissions on average over the years 2008 to 2012 by 8% compared to 1990 levels, the USA by 7%. E m i s s i O n S allowed = E m i s s i o n S base year " F r a c t i o n

(1)

'Intensity targets' define an amount of allowed emissions as a function of one variable in the target year, usually the Gross Domestic Product (GDP), see Eqn. 2 and 3. The greenhouse gas (GHG) intensity is the amount of greenhouse gas emissions per unit of GDP. While for absolute targets the amount of allowed emissions in the target year is know in advance, for intensity targets this amount depends on the value of the GDP in the target year.

1146 EmissiOnS allowed GDPtarget year el

=

EmissionSbase

year

Fraction

GDPbas e year el

IGDetargetyearl el • Fraction EmissiOnS attowed = Emissi°nS baseyear • GOPbase year

(2) (3)

The main goal of setting a target as intensity target is that in the case the economy develops unexpectedly, the amount of allowed emissions changes as well. As a first approximation one can assume that if the GDP is 1% above the expected, the real emissions are also 1% above, therefore the target should be 1% higher. In this case the target is defined as decrease in GHG intensity, the elasticity el=l in Eqn. 1 and 2. As an example, the US government has recently proposed to reduce its greenhouse gas (GHG) intensity, measured as greenhouse gas emissions divided by the Gross Domestic Product, by 18% in the next 10 years [ 1], which is 2% per year. A reduction in the greenhouse gas intensity (Emissions per GDP) is the sum of two components: a reduction (or increase) of emissions and an increase (or reduction) of GDP. For example, a 5% reduction in the GHG intensity could be achieved by a 2% decrease in emissions and a 3% increase in GDP. Or a 2% reduction in the GHG intensity could be achieved by a 1% increase in emissions and a 3% increase in GDP. However, some sources of GHG emissions within a country may be not well correlated with the GDP. For this reason, Argentina had proposed a target in 1999 expressed as a function of the square root of the GDP (el=0.5) in the target year, since its agricultural emissions are not well correlated to the GDP [2]. An unexpected change in the economy by 1% changes the target by 0.5%. R E G R E S S I O N ANALYSIS To find out more about the relationship between emissions and GDP we analyse historic data of emissions and GDP. In long-term trends of the emission intensities for different countries (see [3]) we observe, that countries move through four basic stages during their development, where the emission intensity first increases, reaches a maximum and then decreases again: • In a first phase, the industrialization, energy use increases and GHG emissions grow faster than the GDP. Increasing proportions of the GDP are met with emission intensive activities. Consequently, the emission intensity increases. • In a second phase, the growth phase, the economic activity increases further, but emissions increase as fast as the GDP, the emission intensity is constant. • In a third phase, the decarbonization, the economy grows further but mainly in activities with low emissions. Both, GDP and emissions increase, but GDP faster than emissions, the emission intensity declines. • In a fourth phase, the emission reduction phase, the economy grows further, but the absolute emissions decrease, due to a restructuring away from emission intensive production. The emission intensity declines faster than the GDP grows. For a regression on historic data, we first assume a simple relationship between emissions and GDP: E(t) . c GDP(t) a. , .

.l(t)

E(t)

GDP(t)

c. GDP(t) a-'

(4)

where c and a are constants that are determined by the regression and I(t) is the emission intensity. A regression can be applied over periods of time where the emission intensity changes linearly. One question is whether coefficient a that we find here is the elasticity that is needed to set the intensity targets. For the regression we use C02 emissions from fuel combustion and GDP using purchase power parities from the same source [4]. India: The simple relationship between emissions and GDP was used for regression of data for India. For the period 1971 to 1991 we observe a coefficient a of 1.23. I.e. in that period, an increase in GDP of 1 % coincided with an increase in emissions of 1.23%. Between 1991 and 1997 the coefficient a i s only 1.01. (see

1147 Figure 2, left). The Indian economic is being restructured and in constant change. With the simple formula we cannot obtain the influence of the GDP on the emissions. 2500

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Figure 2" Emissions, GDP and intensity (Emissions/GDP) for India (left) and former USSR (right) Former USSR: Regression is also applied to data for the states of the former USSR. To ensure the consistency in the time series in this region, the aggregate of newly independent states is used after 1992. For regression from 1971 to 1990 to the simple formula (Eqn 3.) the coefficient a is 0.87 (Figure 2, right). The emission intensity decreased constantly at around 1% a year. Due to the economic collapse after 1990, the GDP and emissions decreased drastically. Since GDP decreased faster than emissions, the intensity increased. The coefficient a for regression over the period 1990 to 1999 is 0.78. The Russian Federation has an absolute emission target under the Kyoto Protocol, which it is likely to overachieve by far due to the economic decline. For the purpose of illustrating the effect of intensity targets during economic decline, we describe in two cases what would have happened, if the former USSR would have committed to an intensity target in 1990 that aimed at basically replicating the past trend.

As a first option, a target could be defined as a 1% decrease in GHG intensity per year as of 1990, as it has decreased between 1971 to 1990 (solid circles in Figure 2, fight). Taking the real GDP of the period 1990 to 1999, one calculates that the allowed absolute emissions under this target (solid triangles) would have been well below the actual emissions. For the case of economic decline, such target would have been very stringent and not met by the country, although absolute emissions declined considerably. As a second option, it could be assumed that the relation between emissions and GDP would stay constant and a target could be defined as E = c . G D P °87 , based on the regression 1971 to 1990. Taking the real GDP of the period 1990 to 1999, one calculates that the allowed absolute emissions under this target (open triangles) would have matched the actual emissions better than the first target. USA: The emission intensity of the USA declined from 1990 to 1999 on average by 1.7% per year (Figure 3, left). Regression to the simple relationship yields in a coefficient a = 0.45. Here the coefficient a describes the constant change. The emissions and GDP however show parallel fluctuations, we here also assume another function for the regression. Based on the idea that the GDP increases at an average rate (b) and any additional increase above (or below) that rate will increase (decrease) emissions with an elasticity el, we assume the following relationship and perform a regression: E ( t ) = c . e -b'a't . G D P ( t ) a

(5)

Using this formula from 1985 to 1999, we find that emissions increase on average by 1.3% (=ba) and the GDP has an additional influence with a = 0.88. Changes in GDP above or below the trend by 1%, change emissions with by 0.88%. This coefficient a can be interpreted as the elasticity needed for the intensity target.

1148 It may be noted such regression to emissions of all greenhouse gases, including emissions from forestry (not as in the previous case only CO2 emissions from fuel combustion) does not produce significant results. The is an indication the emissions of the other greenhouse gases are less directly correlated to GDP. 10000

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Figure 3" Emissions, GDP and intensity (Emissions/GDP) for the USA (left) and UK (right) United Kingdom: From 1971 to 1999, the UK reduced emissions while increasing GDP (Figure 3, fight). Regression to the formula Eqn. 5 did not yield significant results. The fluctuation in the GDP does not lead to parallel fluctuations in the emissions. The elasticity could not be obtained from regression of this data.

C O M P A R I S O N OF THE TWO TYPES OF TARGETS In this section, the characteristics of the two approaches are discussed comparatively. The discussion is summarized in Table 1.

Certainty to achieve an environmental goal: Under intensity targets, the total amount of emissions in the target year is not fixed beforehand, it can only be predicted as a range since it depends on the GDP know only after the target year. Under absolute targets, the total amount is fixed and, assuming that the target will be reached, the environmental benefits in terms of emissions are known. Uncertainty of the expected deficit or surplus: Several authors [5,6] mention as a main advantage of intensity targets, that it is more certain than under absolute targets whether the target will be reached or not. This question is analyzed in the following: Let us assume in the target year the emissions depend on the GDP with an elasticity of 0.8. An absolute target, an intensity target with el =1 and an intensity target with el=0.8 are defined for a country and actual emissions are very close to reaching those targets. But an unexpected additional change in GDP of 1% changes the emissions by 0.8%. • Under the absolute target, the allowed emissions would not have changed, real emissions would be 0.8% above the target. • Under an intensity target with el--I, the allowed emissions would now be 1% higher, the real emissions only 0.8% higher: real emissions would be 0.2% below the target. (Note that in such case unexpected growth makes the target easier, while unexpected economic decline would make the target more difficult.) • Under an intensity target with el=0.8, the allowed emissions would now be only 0.8% higher, as would be the real emissions: real emissions would be fight on target. We conclude that the uncertainty of the absolute surplus or deficit in emissions is dependant on elasticity between emissions and GDP. An intensity target with the el =1 provides an advantage over an absolute target,

1149 if the actual elasticity is larger than 0.5, which is assumed to generally be the case. An intensity target with the elasticity set at the actual level would provide even more certainty about the deficit or surplus.

Economic growth: Many countries, especially developing countries, will only accept emission limitation targets, if these do not harm opportunities for economic growth. Absolute targets are often seen as capping emissions and therefore capping economic growth, even if the level of the absolute target is above the current level. Absolute targets can also become a high economic burden, if the emissions increase more than expected or can create "hot air", if they are too loose. Intensity targets are perceived as providing this flexibility and allowing for more emissions if the economy is growing faster than expected. Almost unconstrained economic development can be pursued under an intensity target that is close to the business-as-usual GHG intensity development. If, however, significant reductions in the GHG intensity below business-as-usual are required, an intensity target can be equally restraining as an absolute target. An intensity target is only more flexible if unexpected economic developments occur. As shown in the previous section, average annual changes in GHG intensity differ substantially between countries. Setting percentage reductions in GHG intensity are equal for a group o f countries would advantage those countries with higher economic growth. Intensity targets would therefore be applied differentiated for countries.

Technical requirements: For absolute targets, emissions have to be calculated, usually by collecting activity data and emission factors. The emission calculations have to be reviewed. For intensity targets, the GDP has to be calculated in addition to the emissions. Doubt are often mentioned regarding the non-ambiguous calculation of the GDP: It could be expressed in local currency, based on exchange rates or on purchase power parities; for many developing countries, the GDP does not cover the informal sector; for centrally planned economies, the GDP growth rates are sometimes challenged as being overestimated. However, whether the GDP is calculated in local currency, based on exchange rates or on purchase power parities is only relevant if drastic changes occur (like a crash of one currency used) or a target of one country is compared to that of another. Further, the International Monetary Fund has established rules and review procedures for the calculation of the GDP TABLE 1 PROS AND CONSOF DIFFERENTTYPESOF TARGETS

Absolute tarl~ets

Intensity, tarl]ets

Pro

• Total emissions fixed • Limited number of decisions in setting the target • Target of this type have been agreed under the Kyoto Protocol

Con

• Rigid, if economy and emissions develop unexpectedly leading to 'hot air' or high burden

• Provide flexibility, if GDP higher than expected • Can prevent hot air in case of economic decline • Prediction more certain than for absolute emissions, if emissions and GDP well correlated • Total emissions not fixed • Further data requirement (GDP), acquisition and review • Relationship between emissions and GDP need to be known to set target • More separate decisions in setting the target

• Stringency depends on many factors

• Stringency depends on more factors than for absolute targets • Stringency difficult to compare between countries

1150

Negotiations: In an intemational process, the emissions limitation or reduction targets for different countries have to be negotiated and agreed by all participating countries. For absolute targets, equal percentage reductions could be applied to all countries (one decision), or they could be of different stringency for different countries (n decisions, n = number of participating countries). The negotiation of the reduction values is difficult, but still relatively simple, because only one number per country has to be agreed. The judgement of this one number is relatively difficult, because many variables influence the total absolute emissions (all activity data and all emission factors). Countries have already negotiated such targets for the Kyoto Protocol. Intensity targets would always have to be differentiated, since the relationship between emission and GDP will be different in all countries. The differentiated intensity targets may be more difficult to negotiate than differentiated absolute targets, since a reduction and an elasticity has to be agreed (2n decisions). The judgement of the target involves also an explicit judgement of the relationship between emissions and GDP. More variables influence the emission intensity (all activity data, all emission factors and also the activity in emission extensive sectors). This makes it more difficult to agree on intensity targets than on absolute targets.

CONCLUSIONS We considered two ways to formulate emission limitation or reduction target: absolute targets and intensity targets. We conclude that intensity targets can provide several advantages over absolute targets: They can lead to more certainty whether a target will be reached and they can account for unexpected economic changes upwards and downwards. This is however only possible if emissions and GDP are well correlated, the strength of this correlation is know and used to set the target. If the intensity targets are set assuming a stricter link between emissions and GDP as it actually occurs, unexpected growth makes the target easier, while unexpected economic decline makes the target more difficult. For a limited number of examples we have shown that deriving the relationship between emissions and GDP from historical data as needed for defining intensity targets is difficult for most of these cases. The considered countries were in different phases of development and the relation between emissions and GDP was not always apparent. Further analysis is necessary in order to be able set intensity targets in a way that maximises their advantages over absolute targets.

REFERENCES US government (2002), A new U.S. Climate Change Strategy: A New Approach, available at http ://www.whitehouse.gov/news/releases/2OO2/O2/climatechange.html Argentine government (1999), Revision offirst national communication according to the UNFCCC, available at http://unfccc.int/resource/docs/natc/argnc 1e.pdf Grubb, M.J., C. Hope, R. Fourquet (2002), Climatic implications of the Kyoto Protocol: the contribution of international spillover. Climatic Change 54, 11-28 International Energy Agency (2001), C02 emissions from fuel combustion (2001 Edition). ISBN: 9264-08745-1 Baumert, K.A., R. Bhandari, and N. Kete, (1999) What might a developing country climate commitment look like? World Resources Institute, Climate Note, ISBN: 1-56973-407-0 Philibert, C. and Pershing, J. (2001), Considering the Options: Climate Targets for All Countries. Climate Policy 1, 211-227.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Crown Copyright © 2003 Published by Elsevier Science Ltd. All rights reserved

1151

CANADIAN INITIATIVES ON CO2 CAPTURE AND STORAGE: TOWARDS ZERO EMISSIONS FROM FOSSIL FUELS Kelly Thambimuthul, Gilles Mercier I, Malcolm Wilson 2, Bob Mitchell 3 and Mahmuda Ali 3 1Natural Resources Canada, Ottawa, Ontario, Canada 2 University of Regina, Regina, Saskatchewan 3 Alberta Environment, Edmonton, Alberta ABSTRACT The capture, geological storage and/or utilization of CO2 represent an attractive option to reduce greenhouse gas emissions in Canada. With CO2 capture, co-incidental benefits arising from the removal of a number of secondary air pollutants generated from the utilization of fossil fuels provide additional opportunities to address a number of associated air pollution control issues. As a result, a number of Canadian federal, provincial government and industry-supported initiatives are currently underway aimed at achieving these goals. This paper describes several projects that have been undertaken to characterize the CO2 storage potential geological sinks and for the development and deployment of storage/utilization and capture technologies for achieving near zero emissions of CO2 and other atmospheric pollutants from fossil fuel use. INTRODUCTION

There has been interest in the implementation of components of zero emissions technology (CO2 capture, storage and utilization) for some time in Canada. At the first conference organized by the IEA Greenhouse Gas Programme on CO2 capture and storage in Oxford, UK in 1993, Canadians gave papers on, among other topics, amine capture, membrane separation and mineral carbonate formation in geological media. Canadian activities prior to that time included pilot projects on CO2 enhanced oil recovery. A western Canadian information network was also in operation, bringing together interested players and exchanging information on various aspects CO2 capture, storage and utilization technologies. Since negotiation of the 1997 Kyoto Protocol, Canada has been working diligently towards its ratification. The target is to reduce annual greenhouse gas emissions to a level of minus 6% by 2008-2012 relative to the 1990 level, which is estimated to have been the equivalent of 601 Mt of CO2. In early 1998, the Canadian federal, provincial and territorial ministers of energy and environment initiated work on a national climate change strategy with a mandate to develop a plan to meet the Kyoto target. This in turn prompted the formation of a national initiative on CO2 capture and storage at a meeting held in Regina in March 1998, with subsequent gatherings held in Calgary, Halifax and once again in Regina. The federal government provided further recognition of the importance of emissions reducing potential of capture and storage technologies in October 2000 in its National Implementation Strategy on Climate Change adopted by ministers. This strategy will be implemented through a series of 3 annual business plans or Climate Change Action Plans, the first of which started in 2001. Areas of focus of Canadian initiatives under the 2001 Climate Change Action Plan include: technology development and cost reduction of CO2 capture using amine separation, oxy-fuel combustion and gasification; CO2 storage with enhanced oil

1152 recovery; enhancement of methane recovery with C02 injection and storage into deep coal beds; recovery of methane hydrates with simultaneous CO2 storage; acid gas re-injection; storage capacity assessments of Canadian coal seams, sedimentary basins, oil and gas reservoirs and oil sands tailings streams. Many of the initiatives underway involve public/private sector partnerships and international collaboration, with several of the projects also being led by the private sector. The various initiatives underway are described below. INITIATIVES ON CO2 CAPTURE TECHNOLOGIES AND PLANT SYSTEMS

Amine Separation -International Test Center for COz Capture The intent of this program of activity undertaken by the International Test Center for CO2 Capture located at the University of Regina in Saskatchewan is to undertake testing of amines and associated process developments for the capture of CO2 from relatively dilute, but large volume sources of CO2 such as coalfired electrical generators, natural gas turbines and commercial boilers. The capabilities of the Center include bench scale work, small-scale pilot testing and pre-commercial testing on a larger pilot facility attached to a slipstream from a coal-fired power generating station at Boundary Dam in Saskatchewan. Current work is evaluating the optimal use of existing amine technologies. Work will soon proceed to the testing of alternative amines or amine mixtures with the ability to improve mass transfer reduce process energy consumption and the associated capital and operating costs. It is anticipated that current research will extend over a 3 to 4 year period. The federal and provincial governments are providing capital funding for the project. A consortium of government and industrial participants contribute to an annual operating budget of $550,000 with more than 50% of these funds coming from industry sources. Oxy-fuel Combustion - CANMET Energy Technology Center, Ottawa CANMET CO2 Consortium: This pre-competitive research consortium led by the CANMET Energy Technology Center in Ottawa and coordinated as an international R&D project by the IEA Greenhouse Programme, is investigating oxy-fuel combustion based CO2 capture methods. Work which began in 1994 with the building of a state of the art pilot plant facility for oxy-fuel combustion is currently in Phase 6 of a work program focused on the development of O2/CO2 recycle combustion strategies for retrofit to existing pulverized coal fired power plants. The core research program is aimed at development of computer simulation of oxy-fuel flames and validation of burner concepts using the purpose built oxy-fuel combustion pilot plant. Integrated, multipollutant capture mechanisms for the removal secondary pollutants, after primary particulate capture in an ESP or bag filter, are being studied in a condensing heat recovery and scrubbing environment using technology supplied by McDermott Technologies Inc, USA. Boiler simulation tools are being developed for use in a HYSYS working environment. Outputs of the program are confidential to participants who fund the program, however several papers describing non-confidential data have been released in the public domain. The consortium's activity is currently supported by the Canadian federal government, Alberta government, US Department of Energy, TransAlta Utilities, Sask Power, Ontario Power Generation, McDermott Technology Inc and Air Products and in the past by EPCOR, Nova Scotia Power and Air Liquide. Oxy-Fuel Field Demonstration Project: This project is aimed at the selection of an optimal 02/C02 recycle combustion method for a natural gas fired industrial scale boiler, the development and demonstration of required burner technology and participation in a field storage experiment led by the Alberta Research Council (see below) to study the use of a variable COz/N2 product stream for enhanced coal bed methane recovery with CO2 storage at a site to be determined in Western Canada. The project is receiving $1.5 million in funding over a period of 5 years from the 2001 Climate Change Action Plan and is currently seeking industrial partners.

Closed Gas Turbine Cycle Project: Performance evaluation of various closed gas turbine cycles utilizing oxy-fuel combustion to produce power and capture CO2. Work program includes simulation activities and primary research at two Canadian universities. Work undertaken with Carleton University in Ottawa is aimed at understanding the

1153 fundamentals of compressor performance when changing the primary working fluid to C02. Funding will also support a project to design and construct a micro-turbine system to study the operation of a closed cycle gas turbine. Work underway with the University of Waterloo is aimed at developing simulations of a solid oxide fuel cell (SOFC) system integrated with a closed cycle gas turbine. The project is receiving $250,000 in funding over a period of 5 years from the 2001 Climate Change Action Plan (CCAP). The Zero Emission Coal Alliance (ZECA)

A US-Canadian consortium, comprised of 18 members representing governments, research organizations and the coal, utility, mining, and equipment manufacturing industries has proposed the development of a novel, highly efficient technology to generate electricity and/or hydrogen from coal with zero atmospheric emissions. Expanding on ideas originally proposed by the Los Alamos National Laboratory in New Mexico, U.S.A., the ZECA concept comprises a coal gasification power plant to produce electricity via a high-temperature solid oxide fuel cell (SOFC) and a mineral carbonation plant to store the CO2. First, coal is gasified to produce hydrogen and CO2. The hydrogen is then used to fuel the SOFC. The CO2 formed is reacted with lime to form calcium carbonate, which is calcined at high temperature using the waste heat from the SOFC and separated into a pure CO2 stream and the original lime. The lime is continuously recycled for CO2 capture from the process stream. The pure CO2 is sent to the mineral carbonation plant and reacted with serpentine or olivine (magnesium silicates) to form magnesium carbonate and silica, which are then returned to the serpentine mine. Magnesium carbonate is benign and thermodynamically stable, thus guaranteeing permanent and safe storage of the COz. ZECA completed a US$716,000 techno-economic feasibility study in November 2001 that did not identify any fatal flaws in the concept and concluded that the gasification power plant technology showed good performance, high overall efficiency (around 70%), with competitive electricity costs relative to other advanced power generation schemes incorporating CO2 capture. Technical and business plans to design, construct and operate a pilot plant within five years are currently being developed. These plans will be presented to shareholders and potential investors in the near future.

Canadian Clean Power Coalition An association of 7 Canadian utilities, coal producers and the US Electric Power Research Institute, the Coalition proposes a program focused on "securing a future for coal-fired electricity generation". Initiatives provide for the development, construction and operation of a full-scale demonstration project by 2007 that will remove GHG and other secondary pollutant emissions of concem from an existing coal fired power plant and a similar demonstration project by 2010 applied to a greenfield coal fired power plant. Implementation is expected to cost around $1 billion. Phase I of the project (conceptual engineering and feasibility studies) worth about $5 million has been underway since September 2001, with secure industrial funding and signed agreements with the provinces of Alberta, Nova Scotia, Saskatchewan and the federal government. Completion of Phase I is planned for mid-2003 with the identification of the technologies to be used in the field demonstrations. Phase II (detailed engineering and construction) is expected to commence in late 2003. Efforts to find funding for Phase II scheduled for completion by 2010 are just commencing. INITIATIVES ON CHARACTERISATION OF THE CAPACITY OF COz STORAGE SINKS

Storage of C02 Canada's Sedimentary Basins Sedimentary basins have various degrees of suitability for CO2 storage in geological media as a result of different conditions and geological, hydrostatic and thermal characteristics. The purpose of the project is to identify on a continental scale the suitability of approximately 70 sedimentary basins in Canada for CO2 storage in geological media. On a regional scale, the suitability for CO2 sequestration of the Alberta basin and of the Canadian part of the Williston basin (shared with the US) is being assessed both geographically

1154 and stratigraphically. At the present time this project led by the Alberta Energy and Utilities Board (AEUB) has completed studies on the Alberta basin with expected completion of the Canadian part of the Williston basin in December 2002. Project funding of $270,000 from the federal and Alberta government, the latter from the AEUB.

Storage of C02 in Alberta's Oil and Gas Reservoirs Alberta currently has approximately 26,000 gas pools and more than 8,500 oil pools in various stages of production and depletion. The ultimate capacity for CO2 sequestration in these pools has been estimated using the Alberta Energy and Utilities Board reserves database. Results to date indicate that the ultimate CO2-storage capacity in Alberta's gas reservoirs not associated with oil pools is 9.8 Gt CO2. The storage capacity in the gas cap of approximately 5,000 oil reservoirs is 2.2 Gt COa. In contrast, the storage capacity in depleted oil pools is only 637 Mt CO2. Of the more than 8,500 oil pools in Alberta, 4,273 reservoirs were identified as suitable for CO2-flood EOR. Estimates of the incremental CO2-storage capacity in these reservoirs at CO2 breakthrough and at 25 and 50% hydrocarbon pore volume (HCPV) of injected CO2 indicate that an additional 117, 360 or 673 Mt CO2, respectively, would be stored through CO2-flood EOR. The objective of the last stage of the project is to develop and apply reservoir ranking methodology that will consider such elements as reservoir characteristics, CO2 capacity, injectivity, depth, distance from CO2 sources and timing, in order to identify the hydrocarbon reservoirs that should be considered first in the implementation of large-scale CO2 sequestration in oil and gas reservoirs in Alberta. The project led by the Alberta Energy and Utilities Board (AUEB) commenced in 2000 with expected completion in March 2003. Project funding of $240,000 from the Alberta Energy Research Institute coveting operating expenditures and more than $300,000 worth of manpower resources provided by AUEB.

COz storage capacity of deep coal seams in the vicinity of large C02 point sources This project aims to utilize the many oil and gas well intersections of deep coal seams in Alberta in the vicinity of large CO2 point sources to determine the distribution, thickness and depth of deep coals and to determine reservoir properties including pressure and temperature and through experimentally derived CO2 adsorption isotherms to assess the in place storage capacity of CO2 expressed as Mt/km 2. The work undertaken by the Geological Survey of Canada has continued intermittently since 1997 with current funding at $275,000. Ongoing work to be completed in 2003 is funded by the 2001 Climate Change Action Plan. Work funded by the Canadian Clean Power Coalition, Nova Scotia and the federal government will also assess the CO2 storage capacity of deep coal seams in Nova Scotia. INITIATIVES ON CO2 STORAGE AND UTILIZATION

lEA Weyburn COz Monitoring and Storage Project The primary objective of the project is to understand geo-sequestration of GHG, particularly CO2 piggybacking on the EnCana Corporation's CO2 miscible flood project at the Weyburn oil reservoir located in southern Saskatchewan. The scope of work includes understanding mechanisms of storage and the degree to which CO2 can be permanently retained in geological formations. The technology and know-how thus obtained can then be applied in selecting appropriate CO2 storage sites and in designing and implementing successful CO2 storage projects worldwide. The ultimate deliverable is a credible assessment of the permanent containment of injected CO2 as determined by long-term predictive simulations and formal risk analysis techniques. This 4 year project managed by the Petroleum Technology Research Center in Regina and coordinated as an international demonstration project by the lEA Greenhouse Gas Programme, receives total cash funding of $20.5 million and additional in-kind contributions valued at approximately an equal amount. Funding participants include the following organizations - Natural Resources Canada, Saskatchewan Energy and

1155 Mines, Government of Alberta, US Department of Energy, European Community, EnCana, Sask Power, Nexen Canada Limited, BP, Dakota Gasification Co, TransAlta Utilities, E N A A - Japan and TotalFinaElf. Enhanced Coal Bed Methane Recovery f o r Zero Greenhouse Gas Emissions

Supported by the IEA Greenhouse Gas Programme as an international demonstration project and led by the Alberta Research Council, this Canadian project is looking at the commercial viability of coal bed methane (CBM) in Alberta through enhancement of CBM recovery factors and production rates in low permeability CBM reservoirs by injection of CO2-rich waste streams; and reducing greenhouse gas emissions by subsurface injection (and storage) of CO2 into coal beds with added value from production of CBM. Phase I of the Canadian project was the initial assessment and feasibility of injecting pure CO2 into deep Mannville coals. Phase II was the design and implementation of a micro-pilot test for injection of pure COz in an existing CBM well located at Fenn-Big Valley in Alberta following Amoco Production Company procedures. Phase III was the assessment of reservoir response to different compositions of injected flue gases and the design and implementation of a multi-well pilot project. Phase IV is the matching of novel combustion and separation technologies to produce a CO2 waste stream with CBM reservoirs to carry out additional multi-well ECBM pilot tests. To date, all testing undertaken in Phases I-III has been successful and the economics of the process is being accessed. It is expected that the final results will show gas producers the best way to enhance production from low permeability CBM wells. On the other hand, reducing greenhouse gas emissions is a priority to the utilities and is addressed. Cost curves will be generated to assess the price per tonne of CO2 stored in coal reservoirs based on a wellhead price of natural gas and composition of flue gas injected. Current funding participants include Environment Canada, Canadian Climate Change Action Plan, Geological Survey of Canada, Alberta Innovation and Science, Alberta Geological Survey, Saskatchewan Energy and Mines, US Department of Energy, UK Department of Trade and Industry, Netherlands TNO, Japan Coal, CSIRO Australia, Gas Technology Institute, Suncor Energy, BP, Burlington Resources, Conoco Canada, EnCana Corporation, MGV Energy Inc., ExxonMobil Canada, Husky Energy, PetroCanada, TransCanada Pipelines, EPCOR Utilities, TransAlta Utilities, Air Liquide, Sproule International, Tesseract, University of Alberta, University of British Columbia and BJ Services Canada. The project started in 1997 and is expected to end in 2005. To date more than $4 million Canadian has been expended on the project. Acid Gas Re-injection in Alberta, Canada

At the end of 2001 there were 31 sites in Alberta where acid gas was re-injected into depleted oil and gas reservoirs and deep saline aquifers primarily as a safe method of disposal of waste HaS streams. The composition of the re-injected gas varies from 20% COz and 80% H2S to 95% CO2 and 5% H2S. These acid gas injection operations in Alberta represent an analogue for geological sequestration of CO2. Thus, the study of the acid gas injection operations provides the opportunity to learn about the safety of these operations and about the fate of the injected gases, and represents a unique opportunity to investigate the feasibility of CO2 geological storage. The Alberta Geological Survey (AGS) of the Alberta Energy and Utilities Board (AEUB) and the Alberta Research Council (ARC) are jointly carrying out a project to review the information submitted by operators to EUB in the process of obtaining approval for and running these 31 acid gas injection operations. AGS is reviewing the subsurface characteristics and ARC is reviewing the surface facility characteristics of these operations. One of these sites will be selected and undergo a comprehensive due diligence to establish the viability and importance of this technology for creating greenhouse gas emission credits when a trading market is firmly established The initial assessment project will run from December 2001 to October 2002 with $ 205,000 in funding from Canadian federal and provincial governments, other government agencies and the IEA Greenhouse Gas Programme.

1156 Sequestration of Carbon Dioxide in Oil Sands TaUings Streams The availability of high purity carbon dioxide (from hydrogen production) at oil sands refineries is an opportunity to use this refinery waste stream to favorably manipulate the properties of the oil sands extraction tailings waste stream. The chemistry of the oil sands tailings stream is such that the physical, ionic and mineral sequestration of CO2 can be promoted. This work will establish the limits to these three mechanisms of sequestration and define the possible operating conditions and benefits leading to a pilot demonstration of what would be a completely new technology. The project led by the CANMET Energy Technology Center- Devon receives $1 million in funding over a period of 5 years from the 2001 Climate Change Action Plan. Industry and provincial interest is being solicited. Suncor has contributed some funds in the past and has agreed to provide up to $50,000 in kind support for 2002.

Simultaneous Geological C02 Sequestration/CH4production from natural gas hydrate reservoirs This research project led by the Geological Survey of Canada, addresses the feasibility of geologic sequestration of CO2 as a hydrate and the possibility of coincident CO2 sequestration/CH 4 production from natural gas hydrate reservoirs such as those occurring offshore of Canada's coasts or in the Arctic. New laboratory investigations will establish the fundamental geologic controls (physical and geochemical) on CO2 hydrate formation and stability in porous media. Assessments of the suitability of candidate marine, lacustrine and Arctic reservoirs will be undertaken using existing geologic data and new field data acquired in conjunction with the Mallik 2002 International Gas Hydrate Production Research Well (also led by the Geological Survey of Canada). Linkages to the Mallik program will contribute substantially to the understanding of the physical, geochemical, geothermal and permeability characteristics of an actual gas hydrate reservoir. Funding of $307,000 by the 2001 Climate Change Action Plan over a period of 4 years. CONCLUSIONS Significant R&D activity is underway in Canada aimed at the development of CO2 capture, storage and utilization technologies that could achieve near zero emissions of greenhouse gas and other atmospheric pollutants from fossil energy use. Assessments of the storage capacity of CO2 in geological media indicate that a significant quantity of CO2 can be sequestered in sedimentary basins, the most significant of those evaluated that occur in the provinces of Alberta and Saskatchewan. The serendipitous co-location of geological storage sinks in regions of oil, gas and coal-mining activity in the western Canadian sedimentary basin also provides some synergistic opportunities in matching sources and sinks for greenhouse gas emissions from fossil fuel use with some commercial benefits that can be gained from CO2 utilization in enhanced oil and coal bed methane recovery operations. Canadian initiatives on the development of more cost efficient methods of CO2 capture from fossil fueled processes are primarily focused on the development of improved amine and oxy-fuel combustion based systems but with work also underway on coal gasification based capture technologies. There is a significant degree of public and private sector cooperation in Canada for the development and deployment of CO2 capture, storage and utilization technologies to address global climate change, with several of these initiatives also soliciting the active engagement of other international participants. ACKNOWLEDGEMENTS The authors gratefully acknowledge the contributions of various project leaders who provided descriptions of their individual projects listed in this paper and as a part of activities coordinated by the Canadian CO2 Capture and Storage Technology Network (CCCSTN). CCCSTN also gratefully acknowledges funding received under the Government of Canada's 2001 Climate Change Action Plan.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Crown Copyright © 2003 Published by Elsevier Science Ltd. All rights reserved

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AUSTRALIA'S RENEWABLE ENERGY CERTIFICATE SYSTEM David Rossiter and Karla Wass Regulator and Manager, Office of the Renewable Energy Regulator Kings Avenue, Barton ACT 2600, Australia GPO Box 621, Canberra ACT 2601, Australia Tel: 61 2 6274 1436, Fax: 61 2 6274 1725

ABSTRACT Concern about climate change and concerted international action to reduce greenhouse gas emissions are powerful new drivers for renewable energy. Australia has developed a national tradeable renewable energy certificate system to encourage additional renewable energy in electricity supplies. The paper outlines the objectives of the Renewable Energy (Electricity) Act, its legal framework, describes the tradeable certificate mechanism and summarises the experience of the first year (2001) of operation of the Act.

AUSTRALIA'S R E N E W A B L E ENERGY C E R T I F I C A T E SYSTEM B A C K G R O U N D AND INTRODUCTION

On 20 November 1997 the Prime Minister of Australia in his statement "Safeguarding the Future." Australia's Response to Climate Change" committed to working "with States and Territories to set a mandatory target for electricity retailers to source an additional two percent of their electricity from renewable sources by 2010." The measure became known as the Mandatory Renewable Energy Target (MRET). This paper outlines the objectives of the Renewable Energy (Electricity) Act, its legal framework, describes the tradeable certificate mechanism and summarises the experience of the first year of operation of the Act.

OBJECTIVES AND OUTLINE OF ACT There are three objectives stated within the Act. They are: • encourage the additional generation of electricity from renewable energy sources; • reduce greenhouse gas emissions; and • ensure energy sources are ecologically sustainable. The Act sets up a liability for persons making certain acquisitions of electricity. Liable acquisitions are typically those purchases o f electricity by large buyers who did not generate the electricity

1158 themselves, for example electricity retailers. Liable entities are required to discharge their liability by surrendering Renewable Energy Certificates to the Regulator or pay a shortfall charge. This creates a demand for certificates and provides one side of the market. Renewable energy certificates can only be created by eligible accredited renewable energy generators. This creates the supply side of the market. Through the market liable entities can trade directly or indirectly with certificate producers to acquire certificates to meet their liability. Large buyers of electricity such as wholesale purchasers and retailers are collectively required to source an additional 9500 GWh of their electricity from renewable energy sources by 2010 relative to 1997. This takes Australia from around 16,000 GWh per annum of renewable energy in electricity in 1997 to about 25,500 GWh per annum (over 11% of total) in 2010, or an increase of about 60% in that period. The rate of liability is set annually in regulations to achieve the targets set for each year. TABLE 1 ANNUAL ADDITIONAL RENEWABLE ENERGY TARGETS FOR ELECTRICITY SUPPLIES RENEWABLE ENERGY TARGET (MWH)

Year

Renewable Energy Target (MWh)

Year

Renewable Energy Target (MWh)

2001 2002 2003 2004 2005

300,000 2006 4,500,000 1,100,000 2007 5,600,000 1,800,000 2008 6,800,000 2,600,000 2009 8,100,000 3,400,000 2010 - 2020 9,500,000 Note: Target for 2001 is for nine month period from 1 April 2001 to 31 December2001. All other targets are for full calender years.

Legal framework The mandatory renewable energy target is implemented through two Acts. They are the Renewable Energy (Electricity) Act 2000 and the Renewable Energy (Electricity) Charge Act 2000. The former Act details the requirements and provisions to enable the liability and certificate system to operate and the latter Act sets the penalty of A$40/MWh for shortfalls in certificate surrender. Both Acts are available at www.orer.gov.au.

Tradeable certificates Renewable energy certificates can only be created by registered persons generating electricity above their 1997 baseline. Generally, these persons have to register under the Act, apply for accreditation and successfully achieve accreditation before they are eligible to create certificates. However for solar water heaters and small generation units (under 10kW and under 25 MWh per year) registered persons can be deemed to be eligible for a fixed number of certificates for certain types of equipment. Upon accreditation eligible renewable energy generators that have exceeded their baseline may enter an internet-based registry and create certificates any time after they have generated the additional electricity.

1159

Experience offirst year's operation The Act started full operation on 1 April 2001. The following sections describe the first year of operation from 1 April 2001 to 31 December 2001. Registration and Accreditation In 2001, the ORER received 126 applications for registration as a registered legislation. Applications for accreditation of a power station must be made by a Both of these actions attract fees - A$20 for registration and a sliding scale fee for accreditation depending on the size and complexity of the power plant. The vary from A$20 to A$3,000.

person under the registered person. for an application accreditation fees

In 2001 the ORER received 152 applications for accreditation of power stations. The majority of these applications were received prior to the 1 April 2001 start date, although applications continued to be submitted throughout the year. Table 2 shows the status of the 152 applications at the end of 2001. TABLE 2 STATUS OF APPLICATIONS FOR ACCREDITATION AT END OF 2001 STATUS OF APPLICATION Accredited Pending accreditation (still being processed) Rejected* Withdrawn Awaiting payment of fees Total number of applications for 2001 *Rejected includes applications that were combined with other applications.

NUMBER OF APPLICATIONS 126 19 1 3 152

Table 3 lists the eligible renewable energy sources and the number of accreditations for each source. Small Generators and Solar Water Heaters In order to encourage participation of small generators using hydro, wind or photovoltaics, where the system is less than 10kW capacity and producing under twenty five certificates per year, and some solar water heater installations, these types of systems are eligible for deemed numbers of renewable energy certificates. Certificates for these systems can be assigned to an agent who may act on the owner's behalf to reduce the net transaction time and costs. Renewable Energy Certificates Created As at 17 July 2002, 794,562 certificates had been created and registered for 2001 generation. Table 3 lists the eligible renewable energy sources from which the certificates were created. Surrender of Certificates For 2001 a target is stipulated in the legislation of 300,000 certificates. The Regulator received 314,863 certificates for 2001 liabilities (see Table 3) although not all of these were accepted. While more than 300,000 certificates were surrendered, the legislation allows adjustment of the renewable power percentage in future years to take account of any 'overs' and 'unders' in the target achievement.

1160

TABLE 3 ACCREDITATION AND CERTIFICATE STATUS R.E. Source

No. Accreditations*

Hydro Solar Landfill gas Wind Bagasse Sewage Gas Wood waste Black liquor Food and agricultural waste Municipal solid waste Solar water heaters Small generation units Totals:

56 23 19 10

1 N/A N/A 126

No. Certificates Created 293,876 528 86,538 95,017 57,791 9,292 36,740 14,631 -

No. Certificates Surrendered** 154,746 38,912 49,676 1,052 17,587 7,785 -

200,112 37 794,562

45,105 314,863

*Three landfill gas projects were combined with other landfill gas applications. *Wood waste projects used cofu'ingtechnology. *Some projects were hybrid i.e. wind/solar- they have been counted only under the dominant eligible renewable energy source. ** As of 15 February2002.

DISCUSSION This has been the first year of operation of the first national renewable energy certificate trading scheme in the world. Preliminary analysis of the year's performance indicates that the scheme is operating well and compliance is being achieved. Several issues have arisen during the year. Of particular interest is the baseline issue, as it shows the level of detail that needs to sit behind the framework legislation at all levels for it to function effectively. Baselines

Baselines are required for all power plants under the legislation but they are typically zero for all power plants that first generated electricity after 31 December 1996. Less than half the power plants accredited for 2001 had zero baselines. Baselines were calculated mainly for hydro, landfill gas and bagasse (sugar mill waste) power plants, which reflects historic renewable energy supply in Australia. The most complex processes were for setting baselines for hydro power plants and bagasse power plants due to the inherent variability of their renewable energy sources. A sugar mill is a good example of how a baseline is derived. The methodology used was negotiated at workshops with the industry and with independent technical consultants. The methodology takes into account the annual variability of sugar cane harvest area, crop, yield and fibre content to establish the sugar mill production for a typical 1997 year configured as it was at that time. Additionally, auxiliary loads are apportioned between electricity generation plant and sugar processing equipment.

1161

EXPECTED INVESTMENT The total expected investment in renewable energy over the twenty year life of the measure is about A$6 billion. Due to the nature of investments needed to create renewable energy certificates it is anticipated that investors will tend to enter the market in the first five or so years of the measure. This will enable investors to amortise these investments over more than ten years. At this early stage it is difficult to estimate how much investment has been triggered by the Act since projects often proceed for multiple reasons. However approximately $200 million of investment appears to have already occurred and over $600 million further investment appears to be firmly committed. Many other project proposals have also been mooted representing considerably more investment but not all can proceed. For example one State alone has enough wind farm prospects to exceed the target for 2010 though not all projects could proceed without major power system stability issues arising.

TRADING IN THE M A R K E T Though many projects have forward sold their output of RECs some spot market activity has occurred. As early December approached the very limited spot market showed prices were rising and thus tended to stimulate the wider production of RECs. Spot prices in the range of $32 to $36.50 MWh have been reported by third parties for the 2001 period. But most RECs appear to be bought and sold under forward agreements and price disclosure is not normally available on these trades. However it is generally believed these forward trade prices are lower than spot.

CONCLUSIONS The Renewable Energy (Electricity) Act 2000 is operating well with over 150 accredited power plants by mid-2002 and many small generation units contributing towards the operation of the measure. For the year 2001 the certificate target was 300,000 MWh of additional renewable energy and over 790,000 MWh appears to have been generated and claimed to date. The surrender of over 314,000 MWh of those renewable energy certificates for the year bodes well for the achievement of the Act. The tradeable renewable energy certificate approach used in the Act is novel in Australia and internationally as a mandated national target. The Act represents a major change in how additional renewable energy electricity generation is valued in Australia. The industry has responded rapidly and effectively to this change and appears to be well positioned to assist Australia in meeting this greenhouse emission reduction measure.

REFERENCES 1. Office of the Renewable Energy Regulator Website www.orer.gov.au 2. Renewable Energy Certificate Registry Website www.rec-registry.com 3. Renewables Target Working Group (1999) Final Report to the Greenhouse Energy Group:

Implementation Planning for Mandatory Targetfor the Uptake of Renewable Energy in Power Supplies May 1999. Australian Greenhouse Office, Canberra.

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1163

F I N A N C I A L INCENTIVES FOR C L I M A T E N E U T R A L E N E R G Y CARRIERS Chris Hendriks, 1 Mirjam Harmelink, 1 and Rob Cuelenaere 2 ! Ecofys Energy and Environment, P.O. Box 8408, NL-3503 RK Utrecht, Netherlands, [email protected] 2 Ministry of Housing, Spatial Planning and Environment, The Hague, Netherlands

ABSTRACT The Dutch government is currently examining the possibilities to promote the production and use of climate neutral energy carriers. Climate neutral energy carriers are energy carriers from fossil fuels with a low level of associated emissions of greenhouse gases. To judge whether a project qualifies for financial support understanding must be obtained on additional costs and avoided emissions. A conceptual framework is developed and applied to five different case studies for the production and use of climate neutral energy carriers. When taking the whole lifecycle of the energy carrier into account, the emission of the production and use of climate neutral hydrogen varies per project and ranges from 17 to 33 kg of carbon dioxide equivalent per gigajoule. The emission factor for climate neutral electricity for the examined projects amounts to 0.2 to 0.5 kg per kWh.

INTRODUCTION Climate neutral energy carriers are defined as hydrogen and electricity produced by means of fossil fuels and by which (a substantial part of) the produced carbon dioxide is stored or put to good use. The term "climate neutrality" of an energy carrier refers to the share of the energy cartier that can be marked as climate neutral. To judge whether a project qualifies for financial support the climate neutrality needs to be taken into account. All changes in the emissions of greenhouse gases in the production chain should therefore be determined. The emissions of production and application of an energy neutral energy carrier are compared to the emissions in a reference system. The results of the study are used to develop a calculation methodology which should be used for project developers to submit an application for financial support. In addition, the production costs of climate neutral hydrogen and electricity are compared to the current prices of natural gas and electricity for small consumers.

STARTING CONDITIONS C L I M A T E NEUTRAL ENERGY C A R R I E R S The production and application of climate neutral energy carriers should fulfil a number of conditions in order to qualify for possible financial support: • the climate neutral energy carriers should be produced from fossil energy carriers in addition to which the carbon dioxide is stored or put to good use, • the produced climate neutral energy carriers should be electricity or hydrogen, and • the reduction of carbon dioxide emissions may not be used to fulfil existing obligations or agreements.

1164 It was expected that production technologies and application of climate neutral energy carriers might considerably differ in terms of greenhouse gas emissions and (additional) costs compared to fossil fuel energy carriers. To examine these variations systematically, we introduce two concepts: the system boundaries and the reference system. At the hand of five case studies the climate neutrality and additional costs are assessed. In this study we restrict the system boundaries to seven different elements which form the total chain of production and application of (climate neutral) energy carriers. The different chain elements are displayed in Figure 1. The production chain includes: 1. Extraction and production of the fossil energy carrier. 2. Transport of the fossil energy carrier. 3a. Production of the climate neutral energy carrier (e.g. hydrogen or electricity) and CO2 or carbon. 3b Compression of the CO2. 4. Transport and/or distribution of the CO2 or carbon. 5. Storage of the CO2 or carbon. In this step the CO2 is stored or put to good use. 6. Transport and distribution of the climate neutral energy cartier. 7. End-use of the climate neutral energy carrier. This means the use of the climate neutral energy cartier by the end-user.

4

!

1

''

2

3a

' ' r°duti°n°fH

production ~ . Transport . ~ climateneutral fossil energy carried- If°ssd energy came1 I energycarrier & CO2/carbon

II

II

3b Compressionof CO2

Transport CO2/carbon

5 [~Storage or good useI I I CO2/carbon ]

6 Distribution H climate neutral energy carrier

7 End-use climate neutral energy carrier

Figure 1: Chain e l e m e n t s in a p r o d u c t i o n chain for c l i m a t e n e u t r a l e n e r g y carriers The 'reference system' is defined as the amount of greenhouse gases that would have been emitted and the costs that would have been made in the absence of the project. The reduction of greenhouse gas emissions and additional costs due to the implementation of a production chain can be calculated by comparing the emission and costs of the production chain with the emission and costs in the reference system. In principle two different approaches can be applied to determine the emissions and costs in the reference systems. 1. In the multi-project approach generic emissions factors and cost figures for a certain activity are used to calculate the emission and generated costs in the reference systems. These generic emission and cost factors are project independent and can e.g. be derived from benchmarks. 2. In the project specific approach the emissions and costs in the reference system are calculated with project specific assumptions or measurements for all important project parameters. E.g. emission factors of one specific electricity production plant are used because it can be argued that the project replaces electricity generated by that specific plant.

Applying different approaches For the production of climate neutral electricity by means of a coal-fired power plant and storage of the CO2 in empty gas fields roughly three different approaches can be applied to calculate the emissions in the reference system: 1. The electricity generated with the project replaces the average produced electricity in the grid (e.g. the Dutch grid or the European grid);

1165

2. The electricity generated with the project replaces electricity produced by a specific technology mix (e.g. the average public mix, industrial power or a specific technology e.g. a combined cycle unit); 3. The electricity generated by the project replaces electricity generated by a specifically defined plant (e.g. due to the implementation of the project another (specific) power plant is closed down or not erected). When applying the different approaches to a zero emission power plant (i.e. PC3 characterised in TABLE 1) the amount of achieved CO2 emission reduction per kWh is: 0.2 kg CO2-eq per kWh when using the combined cycle as a reference system, 0.4 kg CO2-eq per kWh when using the average production mix in the Netherlands, 0.7 kg CO2-eq/kWh when applying the project specific approach. For the production of climate neutral hydrogen the reference system is defined as the use of natural gas. The emissions in the reference system can be calculated by taking the emissions of greenhouse gases for the production of natural gas in the Netherlands. In this case only a multi-project approach can be applied and the emission reduction per GJ hydrogen ranges from 43 kg CO2-eq/GJ H2 for PC1 to 27 kg CO2-eq /GJ H2 for PC2 (for comparison natural gas has an emission factor of 60 kg CO2-eq/GJ). CASE STUDIES This conceptual framework has been applied to five different case studies, which are listed in TABLE 1. The case studies represent the variation in the different elements in the production for a climate neutral energy carrier. The elements in the case studies were selected on basis of maturity for technology available, and whether it has a substantial emission reduction potential in the Netherlands. TABLE 1 CHARACTERISATION OF FIVE EXAMINED PRODUCTION CHAINS Code

Production facility

Storage/use of C02/Carbon

PC1 NaturalGas Reforming + fuel gas recovery Storage in coal layers by ECBM PC2 Coal gasification+ fuel gas recovery Storage in emptyNG field PC3 Coal combustionwith pure 02 (1) CO2 used in production of methanol C O 2 used in ~reenhouses + storage PC4a Fluegas recoveryof coal-ftredpower plant PC4b Fluegas recoveryof natural fired power plant CO2 used in greenhouses + storage PC5 Naturalprocessing (recoveryof abundant CO2) Storage in aquifer (1) this facilityis based on a zero emissionplant concept which is still in an early stage of development.

Climate neutral Energy carrier

Hydrogen Hydro~:en Electricity Electricity Electricity Natural gas

EXAMPLE O F C A S E STUDY In this paragraph we give a short description on one of the examined case studies. In production chain PC4b annually five petajoule of climate neutral electricity is produced by a conventional gas-fired power plant. The electricity is added to the grid. An amine process separates the carbon dioxide from the flue gases of the power plant. The recovered carbon dioxide is compressed and transported over 100 km. On average 25% of the recovered carbon dioxide is used in greenhouses, the remaining 75% is stored underground in empty natural gas field. In this example it is assumed that the electricity in the project replaces electricity produced by the 'average park' in the Netherlands. In the reference case gas engines locally produce the carbon dioxide for the greenhouses. In periods that carbon dioxide is not required for fertilising or co-incidence with heat demand, the carbon dioxide is stored into an empty natural gas field. TABLE 2 presents the comparison of the emissions in the project and the reference case for each chain element.

1166

TABLE 2 EMISSIONS OF CARBON DIOXIDE (GG/Y) FOR EACH CHAIN ELEMENT FROM THE ANNUAL PRODUCTION OF 5 PJE OF PRODUCTION CHAIN PC4B COMPARED TO EMISSIONS FROM THE REFERENCE CASE (ELECTRICITY FROM "AVERAGE PARK") # 1

2 3a 3b 4 5 6 7

Production chain element Extraction fuel Transport fuel Production energy carrier Compression carbon dioxide Transport carbon dioxide Storage/use carbon dioxide Distribution energy cartier Application energy carrier Total C02-eq emission Emission reduction

Reference 50.1 4.9 609.1 0.0 0.0 157.5 0.0 0.0 822

78%

Project 6.0 21.0 70

Comment Average fuel emissions is higher than for natural gas Gas engine with power efficiency (38%) and heat efficiency (38%) Compression energy: 430 kJe/kg CO2 No recompression required Annual use of CO2 in greenhouses No emissions occur during transport of electricity No emissions occur during use of electricity

46.9 0.0 157.5 0.0 0.0 301 63%

RESULTS Per case study, for each chain element the contribution to the total emission is determined. Figure 2 and Figure 3 show that the climate neutrality o f the energy carriers lies in the range of 7% to 77% (black bars in the figure). The figures show that the largest changes in emissions take place either at the end user (chain element 7) in cases where hydrogen is produced or in the production stage (chain element 3) for projects where electricity is produced.

20% 0%

.o_ -20% .E

(Natural Gas'i,£1~

(Natural Gasi!i!!

(Natural Gas)

-40%

~o

........ ;:~i~: :,)?!i,;)! ::~::::! ~:i!?i~ !~!!i~ ~!+~!~

-60% -80%

PCI: NG reforming and fuel gas recovery + ECBM + H2 in grid PC2: Coal gasification + CO2 in empty NG field + H2 in grid PC5: NG processing and storage of CO2 in aquifer

-100% [] 1 Extraction and production of fos.,il energy carrier [] 3a Production of CNE & CO2/carbon • 4 Transport CO2/carbon • 6 Distribution CNE

• 2 Transport fossil energy carrier [] 3b Compression of CO2 [] 5 Capture and storage/use CO2 [] 7 End-use CNE • Climate neutrality

F i g u r e 2 : C h a n g e s in e m i s s i o n in e a c h o f the c h a i n e l e m e n t s for the h y d r o g e n p r o d u c t i o n c h a i n (the r e f e r e n c e s y s t e m for e a c h p r o d u c t i o n c h a i n is i n c l u d e d in b r a c k e t s )

1167 20%

0%

B

l| PC3 ~,veragePark)

.2 -20%

,

~PC4a

I

gepark+g--engine) (Ar .

-m,A/

....

oE

•-

-40%

-60% PC3: Coalfiredzeroemissionplant+ methanolproduction. Conventionalcoalfiredplant+ CO2 deliveryto greenhouses+ storage PC4b: Naturalgas firedplant+ CO2deliveryto greenhouses+ storage

-80%

PC4a:

-100% [] i Extractionand productionof fossilenergycarrier • 2 Transportfossilenergycarrier [] 3a ProductionofCNE& CO2/carbon [] 3b Compressionof CO2 • 4 TransportCO2/carbon [] 5 Captureand storage/useCO2 • 6 DistributionCNE [] 7 End-useCNE • Climateneutrality Figure

3" C h a n g e s in e m i s s i o n in e a c h o f the c h a i n e l e m e n t s f o r t h e e l e c t r i c i t y p r o d u c t i o n c h a i n ( t h e r e f e r e n c e s y s t e m f o r e a c h p r o d u c t i o n c h a i n is i n c l u d e d in b r a c k e t s )

The main results per case study on costs and climate neutrality o f the energy carder are summarised in T A B L E 3. TABLE 3 S U M M A R Y OF T H E M A I N R E S U L T S F O R THE F I V E E X A M I N E D PRODUCTION CHAINS Code

Emission Factor

Costs a

Reference

PC 1 PC2 PC3 PC4a PC4b PC5

17 kgCO2/GJ Ha 33 kgCO2/GJ H2 0.2 kgCO2/kWh 0.5 kgCO2/kWh 0.2 kgCO2/kWh 59 kgCO2/GJ NG

13.5-16.2 euro/GJ H2 15 euro/GJ H2 0.08 euro/kWh 0.11 euro/kWh 0.09 euro/kWh 6.0 euro/GJ NG

Natural gas Natural gas Average park Average parldgas engineb Average park/gas engineb Natural gas

Climate neutrality c

71% 46% 77% 21% 63%

7% a) 15% discount rate. For comparison: prices for small consumers excluding energy tax and VAT: natural gas 5.9 euro/GJ; electricity 0.08 euro/kWh. b) 25% of the recovered CO2 is used in greenhouses; 75% is stored underground in empty natural gas fields. c) Climate neutrality compared to the reference in the former column.

Our analysis shows that the emissions from the total production chain of climate neutral hydrogen range from 17 and 33 kg of carbon dioxide equivalents per gigajoule. For comparison the emissions of natural gas for the whole production chain amount to 60 kg CO2-eq/GJ. The climate neutrality of the hydrogen amounts to about 71% when natural gas is used as feedstock, and to about 46% when coal is used. The emissions from the total production chain of climate neutral electricity amount to between 0.2 and 0.5 kg of carbon dioxide equivalents per kWh. For comparison, the emissions of electricity production facilities currently in operation range from about 0.4 to 1.1 kgCO2-eq/kWh. The climate neutrality ranges from 21% to 75%, depending on the application/storage of the recovered CO2 and the electricity production reference used. The calculated production costs for hydrogen ranges from 13 to 16 euro/GJ of hydrogen, whereas the current price for natural gas for end-users (excluding energy tax and VAT) is approximately 6 euro/GJ. The calculated production costs for electricity ranges from 8 to 11 euroct/kWh in the situation where the producer of the electricity delivers the CO2 for free to the customer (either a methanol producer or a greenhouse grower). The eight cents per k W h reflects the production costs of a new concepts for a zero

1168 emission plant in the USA, which is still in an early stage of development. However, in case the customer of the CO2 is willing to pay a price for the CO2, equalling the marginal costs of the energy saved by the customer, the electricity price could drop to 5 to 9 euroct/kWh. For comparison the current price for electricity for end-consumers (excluding energy tax and VAT) is approximately 8 euroct/kWh. The specific reduction costs for climate neutral hydrogen (using a discount rate of 5%) ranges from 150-250 euro/Mg of CO2. In the examined production chains the specific reduction costs for climate neutral electricity is very sensitive to the assumptions with regard to the energy price. The costs range from less than zero to 30 euro/Mg of CO2 avoided. SENSITIVITY OF RESULTS In the case of hydrogen production, generally only emission changes in chain element 3 (production of the climate neutral energy carrier and compression of the CO2) are substantial, and contribute up to 80% of the total emissions of the whole chain. In the case of electricity, generally only changes in emission in chain element 7 (end use of energy carrier) are substantial. Emission changes in element 1 (extraction and production of the fossil energy carrier) are only relevant when the (methane) emission factor of the fossil fuel used for the production of the climate neutral energy carrier differs substantially from the (methane) emission factor of the fossil fuel used in the reference system. Emission changes due to storage are negligible. However, in cases where the CO2 is applied in other production processes, e.g. in greenhouses, it has to be carefully analysed which part of the CO2 is stored in the product and which part of the CO2 is emitted to the atmosphere. The costs for climate neutral energy carriers are sensitive to the scale of production. In our analysis we assumed an annual production of 5 million gigajoule of hydrogen or electricity. A production unit twice as large as assumed in this study, might lead to a cost reduction of 10 to 15%. CONCLUSIONS Climate neutral electricity can be produced in the Netherlands at about 11 euroct/kWh, which is about 3 euroct/kWh higher than current electricity prices. To be competitive, financial support of about 3 euroct/kWh will be required. The climate neutrality of electricity in the examined cases varied between about 20 and 75% depending on the technology and reference used. When the financial support is applied to 100% climate neutral energy carriers only, the financial support should be about 4 and 12 euroct per 100%-climate neutral electricity in order to be competitive. This financial support can be lower, when enduser of carbon dioxide (e.g. greenhouse growers) are willing to pay a price for the recovered carbon dioxide. The production of hydrogen to replace natural gas in the grid is currently expensive. Climate neutral hydrogen production costs ranges from 13 to 16 euro/GJ, while climate neutrality ranges from 50% (coal gas as feedstock) to 70% (natural gas as feedstock). Current natural gas price is 6 euro/GJ. To cover the additional production costs (of the examined production chains), financial support between about 20 and 30 euro per 100% -climate neutral hydrogen will be required.

ACKNOWLEDGEMENT The authors want to thank the National Institute of Public Health and Environment and the members of the Interdepartmental working group 'Regulation Climate Neutral Energy Carriers' with representatives from the Ministries of Environment, Finance and Economic Affairs for their suggestions with respect to the content of the study and for their financial support.

REFERENCES I. Hendriks, C.A., Harmelink, M., Hofmans, Y., and De Jager, D. (2002) Climate neutral energy carriers in the regulatory energy tax (REB), Ecofys Energy and Environment, Utrecht, the Netherlands.

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1171

POSSIBLE I M P E R F E C T I O N OF I N T E R N A T I O N A L EMISSIONS T R A D I N G U N D E R THE EXISTENCE OF HOT AIR Akira Maeda Faculty of Policy Management, Keio University, 5322, Endo, Fujisawa, 252-8520, Japan

ABSTRACT This paper develops analytical models of emissions markets in which a large number of homogeneous regulated emitters participate, and analyzes sufficient conditions of initial permit distribution for the emergence of emitters with the market power. The conditions obtained give interesting policy implications for the hot air issue: the possibility of hot air is not just a political debate but also a more fundamental economic issue that is relevant to market efficiency.

INTRODUCTION

Market trading of emissions permits is widely considered to offer the least expensive means of meeting emission targets of greenhouse gases (GHGs), in particular carbon dioxide (CO2). ~ Moreover, it is considered that problems caused by environmental externalities can be resolved in an efficient manner by negotiations between parties involved when property rights are properly defined. Assuming that there is no transaction cost required and that no income effect is incurred, the equilibrium is independent from the initial allocation of property rights, which is the well-known Coase theorem, due to Coase [2]. One of the important premises behind these theories is that markets are perfectly competitive in a sense that all market participants are price-takers and no one can have the ability of controlling the market. Without the premise, emissions markets would not necessarily work in an efficient manner. Several studies have been conducted on the issue of market power in emissions markets, including Hahn [4] and van Egteren and Weber [7]. Their studies focus upon the behavior of market participants with market power in an emissions market and discuss the economic consequences. They commonly imply that the concentration of initial permit allocation to a specific regulated emitter would strengthen its market power and the degree of inefficiency of the market. The implication itself quite makes sense in that a market participant who initially holds a large proportion of permits available in the market would behave as a monopolist. The role of regulatory authorities, on the other hand, is to prevent the market from becoming the one in which regulated emitters with market power exist. From the regulator's point of view, it might be less For an extensive survey of the literature of market-based environmental policy instruments, including tradable permits, see Cropper and Oates [3]. For detailed discussion of the standard theory of emissions trading and the economic benefits it offers, see, for example, Montgomery [5], Baumol and Oates [1 ], and Tietenberg [6].

1172 important to analyze the consequence of the existence of market power. Rather, it is important to understand how many permits, initially allocated to each regulated emitter by an authority, would bring an emitter market power. In short, regulatory authorities designing and implementing permit markets need to understand what condition regarding initial permit allocation would sufficiently allow the emergence of emitters who hold strong market power. The answer key for sufficient conditions of initial permit allocation is not found at all in any previous studies including Hahn, and van Egteren and Weber. The Kyoto protocol, which has already been ratified or is in the process of ratification in many countries in these days, addresses emission targets for countries involved. Unconstrained emissions, which are emissions if no abatement efforts would be made, in the first compliance period of years from 2008 to 2012 will shortly be estimated. Subsequently, the actually necessary or redundant volume of emission right will be revealed for each country. Some countries in economic transition including Russia and Ukraine are predicted to hold a large volume of redundant emission right, which is known as "hot air." Some critics point out that due to the hot air, these countries in economic transition will not just be reluctant to make an effort in reducing greenhouse gas emissions, but also be able to benefit from the sale of hot air under the Kyoto mechanism, in particular the international emissions trading (IET) regime. Although the criticism itself does not make sense from the perspective of economic theory, 2 the possibility that hot air may cause market inefficiency cannot be excluded. However, it is regrettable that there is no theory or study that indicates how much hot air held by Russia and Ukraine specifically would give them the ability to control the international emissions market in future. This paper develops analytical models of emissions markets in which a large number of homogeneous regulated emitters participate, and analyzes sufficient conditions for the emergence of emitters with market power. Emitters considered are homogeneous in the sense that they have similar unconstrained emissions and similar emission abatement cost structure. Due to the homogeneity, the emissions market considered seems competitive at a first glance. The present paper shows whether it is the case or not depends upon initial emissions permit distribution. It yields conditions of initial distribution that are sufficient for the emergence of market power. The results obtained have interesting policy implications for the hot air issue: the possibility of hot air is not just a political debate but also a more fundamental economic issue that is relevant to market efficiency.

ANALYTICAL FRAME Consider an emissions market in which there are N regulated emitters engaging in permit trading. The notations in this model are defined as follows. i = 1... N: Regulated emitters. x, : Emissions abatement by emitter i. ( >_0 ) C , ( X , ) - c , X 2/2: Abatement cost function for emitter i. (Marginal abatement cost functions are assumed to be linear in X.) G,. : Unconstrained emissions by emitter i. (Emissions if abatement actions would not be taken at all.) Y,' Initial endowment of permits to emitter i. (They are assumed to be given to emitters gratis.) Oi =-Gi- Yi: The difference between unconstrained emission and initial permit holding. (When D i >__0, it indicates that the emitter will run out of permits. On the other hand, when Di < 0, it indicates that the emitter has redundant permits.) S: Emission permit market prices.

2 As long as the idea of the introduction of market mechanism to cope with the greenhouse issue is accepted, benefiting from market trades without any emission abatement effort should be considered as a rational economic behavior and being necessary for the development of efficient market. Therefore, the prevailing debate on hot air seems misleading, and is not properly addressed as an economic issue while the issue itself might be politically important.

1173 r,: The number of permits bought by emitter i. (T, _0 "selling.")

indicates "buying," while T, _0 indicates

For the simplicity of description, the following notations are also introduced. Ak -

c[ ~

, Bk

=

D i i=k

Notice that B, represents net shortage of initial permits necessary for compliance for emitters k to N. When an emitter behaves as price-taker in the market, the emitter faces a problem of deciding both permit trade and the level of emission abatement. The decision problem is described as follows. Min S. T,. + ciX 2/2 x,_>o,~, s.t. D~-X~-T,. <0

(1)

When the following assumption holds, I call the permit market competitive in the remainder. Assumption 1 (Competitive market)

All emitters in the market are price-takers. In a competitive permit market, all emitters follow the problem (1) to decide their trades by Assumption 1. Total volume of market trade must be equal to zero in the equilibrium, which is known as market clearing condition. The solution to the problem (1), with market clearing condition together, yields an equilibrium permit price as follows. Scour = A, . Max{B,, 0} (2)

E M E R G E N C E OF M A R K E T P O W E R

In the remainder, I replace Assumption 1 with other assumptions to compare equilibrium prices. Let me introduce the following assumption. Assumption 2 (The existence of a non-price-taker)

There are N-1 price-takers and one non-price-taker in the emissions market. The non-price-taker wishes to control permit market prices by deciding how many permits to buy or sell. (Without loss of generality, the non-price-taker is assumed to be Emitter 1.) Let S(T,) denote the permit market price when Emitter 1 sets its permit trade fixed at T,. Given Assumption 2, the decision problem for Emitter 1 is formulated as follows. Min S(TI ). T1 + ciX ?/2

XI>-O, Tt

s.t. D , - X , - T ~

<0

(3)

S(T,)= A2 .Max{B 2 + Tl, 0} The solution to the above problem is obtained as follows. (Due to limited space here, the detail of the derivation is omitted.) Tt" = ctD~-A2B2

if B2 >__0 and - B 2 / 2 < D ~,

c~ + 2A2 T," = -B~/2

if B2 - 0 and D, _ -B:/2,

T,'= c'D'-A2B2

if B2 _0 and ( - B z ~ l + A 2 / c l ) < D l ,

c~ + 2Az T~'=-B2

if B2_<0 and - B ~ < _ D , < _ ( - B 2 ~ I + A 2 / q ) , a n d

T~"= [D~, - B2]

if B2 -<0 and D, _<-B~.

1174 The optimal price for Emitter 1 is given as S No. =-S(T,'). Examining the solution, we would find that the optimal price is greater than the competitive price under Assumption 1 when Emitter 1 initially holds redundant emission permits. Also, we would find that the optimal price is less than the competitive one when Emitter 1 initially faces a shortage of permits. The next question that comes into one's mind is: who can become Emitter 1? In order to give an answer to this question, let me introduce the following assumption.

Assumption 3 (Homogenous abatement costs) All emitters have a same abatement cost function. That is: c, = c is infinitely large.

for

Vi. Also, the number of emitters, N,

Assumption 3 implies that any emitter is entitled to become Emitter 1 if it wishes. Whether the wish can be realized or not depends on thoroughly initial distribution of permits. This is addressed by the following proposition. (Due to the space limitation, the proof is omitted.) Proposition 1 (Sufficient condition for the emergence o f m a r k e t p o w e r ) Given Assumptions 2 and 3, Suo. = AzBz/2 > Sco,.p if 0 _ Bz/2 <--01, S uo. =-Sco,.p otherwise.

In short, the sufficient condition for Emitter 1 to be able to have market power is 0 _ B2/2 <_-D,. The implication of Proposition 1 is quite interesting. Even though Emitter 1 is in the same position with many other emitters with respect to abatement cost structure, it is able to control the market if it initially holds more than a certain amount of redundant permits. The amount is "the half of the net shortage of permits for all emitters excluding Emitter 1." Notice that the condition 0 _< B2/2 <_-D~ is equivalent to the following. B~ < -D~, B2 >__0, and D~ < 0. Thus, it can also be stated that if redundant permits are initially allocated to an emitter and if the absolute volume exceeds the net shortage of permits in the market (including the emitter itself), then the emitter can have market power. Let me examine the above result in the context of the Kyoto protocol. If the amount of the hot air from Russia and Ukraine exceeds net emission abatement requirement for countries listed in the Annex B, then an emissions trading regime with no trade restrictions 3 would allow these two countries to reserve their redundant emissions right for price negotiations and to lead the market to an inefficient one. At the same time, the proposition indicates that as long as the sufficient condition does not hold, there is room for achieving an efficient market even though the hot air exists.

NASH G A M E In this section, I replace Assumption 2 to extend the above setting to the one in which there are two non-price-takers.

Assumption 4 (Two non-price-takers) There are N-2 price-takers and two non-price-takers in the emissions market. Each non-price-taker wishes to

3 Whether emissions trading should be "supplemental" or not, and how much volume is defined as "supplemental" are currently policy debates. In order to focus on pure economic implications, let me put aside the issue and only consider the system without any restrictions on trading volume.

1175 control permit market prices by deciding how many permits to buy or sell. (Without loss of generality, they are assumed to be Emitters 1 and 2.)

Assumption 5 (Nash game) Given Assumption 4, Emitters 1 and 2 play a Nash game: Each of the two decides its own trade volume by taking the other's trade volume as given. The equilibrium is obtained as the cross point of their best-response functions. Emitter 1 solves the following optimization problem. Min S ( T I , T 2 ) . T I + c l X ? / 2 XI->0.T1 s.t.

(4)

D, - X , - T 1 < 0 S ( T I , T 2 ) = A 3 . M a x { B 3 + T 1 + Tz, 0}

B 3 > 0 holds, the solution to the problem yields a best-response function for Emitter 1 as follows. (Due to the limited space here, the detail is omitted.)

When

T~* = c~O, - ,43B 3 c, + 2A 3

if

`4-----------L~3 T2 c, + 2A 3

D, _< 0

and -B3

- 2Dr < T2,

T,'=-(B3 +/'2)/2

if D, _<0 and -B~ _/'2 -<-B3- 20,,

TI* -- [ O l ,

if D, _ 0 and /'2 -< -B3,

- B 3 - T2]

T1. = ciD~ - .43B 3 c I + 2`43

if

`43 7.2 c I + 2.43

D~ > 0

and

- B3 -

c, D~ < 7"2, c, + `43

T,* = -B~ - T2

if D~ > 0 and - B3 - D~ < T2 _< - B

7'1° = [D,, - B 3 - T2]

if

D, __ 0

and

3-

cl Di, C, + A 3

and

T2 < - B 3 - D , .

Emitter 2 also solves a similar problem. Then, the equilibrium price is calculated as s~o,, =-S(T,*',T~*). Let me add an assumption on abatement cost structure and initial emissions distribution as follows.

Assumption 6 (Simplification) 1) Given Assumption 4, the initial permit holding of Emitter 1 exceeds its unconstrained emission. On the D 2 > O. other hand, that o f Emitter 2 is less than its unconstrained emission. That is" D, < 0, 2) Emitters 1 and 2 have the same abatement cost function. That is: c, = c: - c . 3) The aggregate unconstrained emission out of other emitters, excluding Emitters 1 and 2, is equal to the aggregate emission target for them. In other words, net shortage or redundancy o f permits is zero. That is:

B,- '~-'~ (G, - Y,.): 0. i=3

The following proposition is obtained. (The proof is omitted due to the limited space.)

Proposition 2 (Nash equilibrium price and competitive price) Given Assumptions 4, 5, and 6, I) Scorn,>- SNo,h > 0 if D 2 > II) SN~sh>-Scomp> 0 if

2c + 3A 3

c+A 3

D I > 0,

- 2c + 3A 3 DI > D2 > - D ~ > 0 , C'k'A 3

and

III) Su~,h > Stomp = 0 if -D, >_D2 > 0. When N is large enough to take a limit to the infinity, we have `43 ~ o, which yields (2c + 3,43)/(c + `43)-~ 2. Then the following approximation holds. I) Sco~, -> SN~ > 0 if D 2 > -2D 1 > 0, II) SN~h >-Sco,, > 0 if -2D I > D 2 > -D l >_0, and III) SNa,h > Scoop = 0 if -D, _ D 2 > 0.

1176 The above proposition is interpreted as follows. Due to the initial permit allocation, Emitter 1 is basically a permit seller while Emitter 2 is a permit buyer. If excess amount of permits of Emitter 1 roughly exceeds the half of necessary amount for Emitter 2 (in an exact account, (c +A3)/(2c+3,43)), then Emitter 1 can exert its negotiation power on Emitter 2 and can set a selling price higher than the competitive market price. (Case II.) Moreover, if excess amount of Emitter l's permits exceeds the necessary amount for Emitter 2, the market price is supposed to be zero in a competitive market because the rest of trade requirement is assumed to be zero. However, the equilibrium price results in being strictly positive. (Case III.) To the contrary, if excess permits of Emitter 1 do not reach to the half of necessary volume of Emitter 2 (again, in an exact account, (c + A3)/(2c + 3A3)), then Emitter 2 in turn has a negotiation power to set a buying price lower than the competitive market price. (Case I.). Let me apply the above result to the interpretation of the Kyoto protocol. While the economies in transition such as Russia and Ukraine are estimated to hold the large amount of the hot air, Japan, Canada, Australia and other "umbrella countries" are estimated to have to make a strong effort to reduce emissions. In fact, Japanese GHG emission has been growing since 1990. Some estimates say that EU countries are not actually required to reduce emissions because the concept of the EU bubble allows them to trade emissions within the EU region. It is realized that the setting addressed in Assumptions 4, 5, and 6 reflects the current situation: Russia and Ukraine as Emitter 1, and Japan and other umbrella countries as Emitter 2. Proposition 2 tells that how large the volume of the hot air is, compared to the abatement requirements for Japan and other countries, is critical to whether or not Japan will be able to have negotiation power against Russia and Ukraine. If the hot air roughly exceeds the half of abatement requirement for Japan and others, Japan will be obliged to pay higher prices. Otherwise, Japan will be able to pull down prices by negotiation. CONCLUSIONS The findings of this study are addressed as Propositions 1 and 2. These propositions challenge a prevailing idea originating from Coase [2], the idea that the achievement of economic efficiency of markets is independent from the initial distribution of property rights, given that no transaction cost nor income effects exist. I am sure that the results here have never pointed out in the standard theory of tradable permits, too. In the context of the Kyoto protocol, the results indicate that the hot air issue is related, in a subtle way, to the economic efficiency (or inefficiency) that the Kyoto mechanism is supposed to offer. Policy makers are advised to give a deep thought to the results in order to actually implement the Kyoto mechanism in an efficient manner.

REFERENCES

1. 2. 3. 4. 5. 6. 7.

Baumol, William J. and Wallace E. Oates (1988), The Theory of Environmental Policy, Second Edition, Cambridge University Press. Coase, Ronald H. (1960) The Problem of Social Cost, Journal of Law and Economics, III, 1-44. Cropper, Maureen L. and Wallace E. Oates (1992), Environmental Economics: A Survey, Journal of Economic Literature, 30, 675-740. Hahn, Robert W. (1984), Market Power and Transferable Property Rights, Quarterly Journal of Economics, November, 753-765. Montgomery, David W. (1972), Markets in Licenses and Efficient Pollution Control Programs, Journal of Economic Theory, 5,395-418. Tietenberg, Thomas H. (1985), Emissions Trading: An Exercise in Reforming Pollution Policy, Resources for the Future, Washington, D.C. van Egteren, Henry and Marian Weber (1996), Marketable Permits, Market Power, and Cheating, Journal of Environmental Economics and Management, 30, 2, March, 161-73.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1177

THE EFFECT OF EMISSIONS TRADING AND CARBON SEQUESTRATION ON THE COST OF CO2 EMISSIONS MITIGATION Natesan Mahasenanl, Michael J. Scott l, and Steven J. Smith 2 1Pacific Northwest National Laboratory/Battelle, Richland, WA 99352, USA. 2joint Global Change Research Institute, Pacific Northwest National Laboratory/University of Maryland, College Park, MD 20740, USA.

ABSTRACT

The deployment of carbon capture and sequestration (CC&S) technologies is greatly affected by the marginal cost of controlling carbon emissions. Emissions limits that are more stringent in the near term imply higher near-term marginal costs and therefore encourage the deployment of CC&S technologies. In addition, allowing the trading of emissions obligations lowers the cost of meeting any regional or global emissions limit and so affects the rate of penetration of CC&S technologies. In this paper, we examine the effects of the availability of sequestration opportunities and emissions trading (either within select regions or globally) on the cost of emissions mitigation and compliance with different emissions reduction targets for the IPCC SRES scenarios. For each base scenario and emissions target, we examine the issues outlined above and present quantitative estimates for the impacts of trade and the availability of CC&S technologies in meeting emissions limitation obligations.

INTRODUCTION

Carbon capture and sequestration (CC&S) technologies remove carbon from emissions streams or the atmosphere and seek to sequester it in one way or another for a very long time. As such, deployment of CC&S technologies can be an important component of efforts to meet future emissions limits, either regionally or globally, and in the reduction of compliance costs. The magnitude and timing of sequestration opportunities and the opportunity to trade emissions permits affect the value of carbon, and therefore the cost of compliance. Trade lowers the marginal value of carbon in high-cost regions and raises it in low-cost regions [1]. In this paper we examine the issues outlined above and present quantitative estimates for the impacts on the marginal cost of carbon as well as the cost of compliance with a climate policy of stabilizing atmospheric CO2 concentrations at twice pre-industrial levels. We use PNNL's MiniCAM model version 2001 [2,3] as the analytical foundation for the analysis. MiniCAM is an integrated assessment model of global change. It includes representations of both the world's energy and agriculture systems for 14 world regions. Engineered capture and sequestration technologies are modeled generically in terms of their cost and performance characteristics. Carbon capture is explicitly represented in the model at key fuel transformation nodes. CC&S technologies are adopted if the economics are favorable. Terrestrial sequestration (in forests, agricultural soils, etc.) and sequestration in the ocean is not included in this analysis. We also model three cases in which varying degrees of trading are utilized to achieve a carbon mitigation path that results in a long-term atmospheric CO2 concentration of 550 ppm by the end of the century. The 550 ppm target or WRE550 is discussed extensively elsewhere [4]. In looking at long-term stabilization of atmospheric CO2 concentrations (as opposed to relatively short term efforts like the current Kyoto

1178 Protocol), it must be noted that the developing regions of the world markedly increase their emissions over the next century. Attaining a stable atmospheric concentration of 550 ppm by the end of the 21 st century cannot be achieved by the developed regions of the world (modeled here as the Annex I counties in the United Nations Framework on Climate Change (UNFCC)) alone--the non-Annex I countries have to undertake significant emissions controls. For our trading cases, therefore, we consider the following:

•

•

•

No T r a d e - - E a c h nation (region) undertakes its own emissions reduction and sequestration independently. There are many possible ways in which the WRE550 responsibilities could be specified. For this paper, we assume that individual Annex I country responsibilities are equal to those in the WRE550 case until 2020. Non-Annex I countries undertake no emission reductions until their combined emissions reach the same total as those of the Annex I countries (half the world total). This happens about 2020. Individual regions are then assigned emissions budgets under one of two allocation schemes described below. A n n e x I T r a d e - - R e s p o n s i b i l i t i e s are the same as in the no-trade case. The United States, Japan, Western Europe, Canada, Australia-New Zealand, Eastern Europe, and the Former Soviet Union create a trading block to trade carbon emissions permits (and in some cases, carbon sequestration credits). Non-Annex I countries retain individual country responsibilities. W o r m T r a d e - - A l l countries in the world trade emissions permits and sequestration credits. The same responsibility issues apply as in the previous two cases.

We also consider two different schemes for allocating the WRE550 emissions budget amongst the individual regions. These are: •

•

S c h e m e 1: Each country is allocated an amount of from the WRE550 emissions budget equivalent to its share of worldwide emissions for the unconstrained (base) case for each year in the remainder of the forecast period. For example, if China has 20% and 18% of the world's emissions in 2035 and 2050 under the base case, it is assigned the same % of the WRE550 budget in 2035 and 2050. S c h e m e 2: Emissions responsibilities after 2020 are assigned to each region in the 550ppm case according to the share of worldwide emissions in 2020. For example, if China has 19% of the world's emissions in 2020, it is assigned 19% of the world's emission budget under WRE550 for the remainder of the forecast period.

It must be stressed that these are two relatively simple allocations schemes, out of an infinite number of possibilities. Initial allocation of emissions budgets is a critical issue under climate policy, with literally trillions of dollars at stake over the next century. These two schemes were chosen purely for illustrative purposes. Scheme 1 seeks to proportionally reduce the emissions in each region, while Scheme 2 will require disproportionate percentage reductions in emissions over time, since regions with significant growth in emissions in the base case will need to reduce a larger fraction of their emissions. In looking at the future over long time horizons it is necessary to examine a number of plausible future pathways. We use a suite of scenarios documented in the Special Report on Emissions Scenarios (SRES) developed under the auspices of the Intergovernmental Panel on Climate Change (IPCC) and described in detail elsewhere [5]. The SRES scenarios are grouped in four families, each with a specific qualitative storyline that guides the numerical quantification of the scenarios. The scenarios are split along two primary dimensions (1 or 2, and A or B). The four scenarios families are, therefore, denoted as: A1, A2, B l, and B2. The A1 scenario has Sub-scenarios based on energy choices (balanced, fossil-intensive, emphasis on renewables, etc.). We show results from the B2 scenario in this analysis. Results for the other scenarios are similar.

Modeling Engineered Carbon Capture and Sequestration Technologies We base our energy penalty for carbon capture on Herzog et al [6] and assume that the phasing in of these more efficient capture technologies will occur gradually and will be completed 50 years after the initiation of carbon capture. Our assumptions on the additional capital investment for the CO2 capture system are based on the work of Gottlicher and Pruschek [7] and their comprehensive survey of over 300 studies of

1179 COz removal systems from fossil-fueled power plants, with the same assumption about costs decreasing over time. Freund and Ormerod [8] cite estimates for transport and disposal costs that range from $4.7/metric ton of CO2 to $21/metric ton of CO2 ($17/tC to $77/tC), depending upon the type and location of the sink. A similar range is estimated in more recent work [9]. We assume an intermediate value of $10/metric ton CO2, which works out to $37/metric ton C for all transport and disposal costs and hold this cost constant throughout the time period under study. Other estimates for specific transport and disposal opportunities vary from net savings in the case of using unminable coal and depleted oil fields to greater than $1000/tC for hydrates [10] to values in between [11]. We acknowledge the wide range of costs possible for specific transport and disposal but use the Freund and Ormerod [8] range as indicative of the distribution of the average cost of all opportunities. The results presented here are robust across this range of costs.

RESULTS No Trade Case The no-trade case begins with business as usual emissions through the early part of the 21 st century. By 2020, however, countries have to begin to reduce their carbon emissions from the path they otherwise would have followed per the shares described earlier. With sequestration options available, the amount of emissions can be higher by the net amount sequestered. In addition, the marginal and total costs of emissions control can be lower with CC&S. The cost of compliance under the B2 scenario with a 550 ppm climate policy under the two allocation schemes is shown in Figure 1. It is seen that CC&S can significantly lower the cost of compliance with the policy under either allocation scheme. It is also seen from Figure 1 that compliance costs under Scheme 1 are lower than the costs under Scheme 2. This is because the disproportionate reductions required in the developing regions under Scheme 2 leads to higher marginal values of carbon and therefore higher compliance costs. Under Scheme 1 (proportional reductions), the marginal values of carbon are lower in the developing regions (which account for a majority of the emissions worldwide by the end of the century), leading to lower compliance costs. It is also seen that in the middle of the next century, before the marginal values of carbon get high enough for widespread deployment of engineered CC&S, that compliance costs under Scheme 1 without CC&S can be cheaper than under Scheme 2 with CC&S.

2.5 - 0 - Scheme ! -A--Scheme 1 with CC&S

.~_ 1.5 ~

- 0 - Scheme 2 ---)(-- Scheme 2 with CC&S

1

~ 0.5 r~ 0 o

•--,

f'4

¢',1

o

~

¢',1

o

¢',1

~-1

t',l

Figure 1. Cost of compliance with 550 ppm policy under SRES B2 scenario with no trade Annex I Trading Case If trading in emission permits is allowed, it opens up the possibility of reducing the marginal costs of emissions abatement, as countries with higher marginal costs of emissions abatement purchase emissions permits from countries with lower marginal costs of abatement. Significant savings in total abatement costs can be realized from reallocating the actual carbon abatement. Figure 2 compares the cost of compliance with the 550 ppm climate policy under the SRES B2 scenario for the two allocation schemes, without CC&S. It is seen that while Scheme I realizes essentially no savings from limited trade, but has lower compliance costs than Scheme 2, even with trade. The lack of savings from trade in Scheme 1 is

1180

due to very similar marginal values for carbon in the Annex-I regions, reducing the potential for savings from trade. The savings from Annex-I trade are small even for Scheme 2, due to the similar marginal carbon values within the Annex-I regions. Note that the marginal value of carbon in a region depends on both the magnitude of emissions reductions and the proportion of fossil fuels in the energy mix, while the potential for savings from trade are dependent are differences in the marginal values of carbon.

3 ~" 2.5

-D-

S c h e m e 1- N o T r a d e

---A-- S c h e m e 1- A n n e x I Trade

1.5

---<>- S c h e m e 2- N o T r a d e

iI I ---)6- S c h e m e 2- A n n e x I k_ Trade

0.5 0 .--

¢,,i

¢,q

t--,l

¢,,I

t-,,i

t-,,i

Figure 2. Effect of Annex-I trade on cost of compliance under SRES B2 scenario The effects of trade and CC&S under Scheme 2 are shown in Figure 3. It is seen that the reduction in compliance costs with CC&S is much greater than the reductions realized through Annex I trade. I

I i

2.5

No Trade or CC&S

i

---A-- A n n e x I T r a d e Only t .~

1.5

-~- ccs~s o ~ A m e x I T r a d e with

cc~

9 0.5 0

.......jjI I i

I •--

¢q

cq

¢,q

t-,i

¢,,I

¢,,I

¢q

Figure 3. Savings from Annex I trade and CC&S for Scheme 2 under SRES B2 scenario

World Trading Case The gains from emissions trading are potentially much greater if the group of nations undertaking reductions could be expanded to include the non-Annex I countries as well as the Annex I countries. However, for Scheme 1, there is very little savings realized with worldwide trade, due to similar marginal carbon values worldwide. The savings from worldwide trade as compared to no trade and Annex I trade under Scheme 2 is shown in Figure 4. Note that the cost of compliance with the 550 ppm policy with worldwide trade is the same for the two allocation schemes, since the cost is determined by the overall emissions budget rather than regional allocations.

1181

~" 2.5

i - O - - N o Trade

._

1.5

~ O

'

I -~-

A n n e x I Trade 1

,~

World_Tra.de_. J

0.5

--

e~l

¢'q

t~l

t~l

~

eq

¢'4

Figure 4. Cost of compliance with 550 ppm policy for Scheme 2 under different trade cases It is clear that in the absence of CC&S technologies, worldwide trading leads to the lowest cost of compliance. This cost is compared with the cost of compliance with CC&S under different trade cases in Figure 5. It is seen that cost of compliance is lowest with the availability of worldwide trading opportunities as well as CC&S technologies. By the end of the century, the cost of compliance with the 550 ppm policy is significantly lower with no trade (or Annex I trade) but with engineered CC&S than with worldwide trading without engineered CC&S. However, in the middle of the next century, worldwide trade without CC&S is cheaper than no trade or Annex I trade scenarios with CC&S. This is because the marginal values of carbon are not yet high enough to encourage widespread deployment of CC&S technologies. Alternatively, until the cost of CC&S is lower than the marginal value of carbon at a given point in time, worldwide trading may lead to lower cost of compliance with climate policy. Therefore, a limited period of worldwide trade without CC&S can lead to a lower cost trajectory for compliance with climate policy than for cases with CC&S and no trade or Annex I trade.

2.5

[

- n - : Woria Tr~a-e-~-o---I CC&S World Trade with CC&S

1.5

t

- - 0 - N o Trade with CC&S

1

!

---N-- Annex I Trade CC&S

0.5

I i

.....

_ ~ ~ ~ ~ Figure 5. Cost of compliance with 550 ppm policy under different trade cases with and without CC&S

CONCLUSIONS The paper has demonstrated that engineered CC&S technologies can significantly reduce the marginal cost, and thereby total cost, of stabilizing the carbon concentration of the earth's atmosphere. This effect is independent of the trading regime that is in place. We have also demonstrated that savings due to trading in emissions limitations obligations are dependent on the allocation of emissions reduction obligations worldwide.

1182 There is some uncertainty over the permanence of engineered sequestration technologies, and the impacts of impermanent sequestration on carbon abatement or its cost will not be significant in the 21 st century, although they could add considerably more to the cost of abatement in the 22 nd century [ 12]. This is an important consideration that was not studied in the current work. While the results shown here are robust across a modest range of global average costs for transport and disposal of CO2, additional work in ascertaining the spatial and time distribution of average and marginal costs is necessary. Further study in these areas is essential to better understand the role of CC&S in climate policy.

REFERENCES

1. Edmonds, J., Scott, M.J., Roop, J.M. and McCracken, C.N. (1999). International Emissions Trading and Global Climate Change. Pew Center on Global Climate Change, Arlington, Virginia. 2. Dooley, J.J., Edmonds, J.A. and Wise, M.A. (1999). The Role Of Carbon Capture & Sequestration in a Long-Term Technology Strategy of Atmospheric Stabilization. PNNL-SA-30206. Pacific Northwest National Laboratory, Washington, DC. 3. Edmonds, J.A., Wise, M.A., Sands, R., Brown, R. and Kheshgi, H. (1996). Agriculture, Land-Use, and Commercial Biomass Energy." A Preliminary Integrated Analysis of the Potential Role of Biomass Energy for Reducing Future Greenhouse Related Emissions. PNNL-11155. Pacific Northwest National Laboratory, Washington, DC. 4. Wigley, T.M.L., Richels, R. & Edmonds, J.A. (1996). Nature. 379(6562):240. 5. Nakicenovic, N. and Swart, R., eds. (2000). Special Report on Emissions Scenarios. Cambridge University Press, Cambridge, U.K. 6. Herzog, H., Drake, E., and Adams, E. (1997). C02 Capture, Reuse, and Storage Technologies for Mitigation Global Climate Change. Energy Laboratory, Massachusetts Institute of Technology, Cambridge, MA. 7. Gottlicher, G and Pruschek, R. (1997). Energy Conversion and Management. 38 (Supplement): S173. 8. Freund, P" and Ormerod, W.G. (1997). Energy Conversion and Management. 38 (Supplement): S199. 9. International Energy Agency (IEA). (2001). Putting Carbon Back in the Ground. IEA Greenhouse Gas R&D Programme, Stoke Orchard, Cheltenham, Gloucestershire, U. K. 10. Freund, P. (2000). Progress in Understanding the Potential Role of C02 Storage. Fifth International Conference on Greenhouse Gas Control Technologies, Cairns, Australia, August 1316, 2000. 11. Stevens, S.H., Kuuskraa, V.A. and Gale, J. (2000). Sequestration of C02 in Depleted Oil and Gas Fields: Global Capacity, Costs, and Barriers. Fifth International Conference on Greenhouse Gas Control Technologies, Cairns, Australia, August 13-16, 2000. 12. Scott, M.J., Edmonds, J.A., Mahasenan, N., Roop, J.M, Brunello, A.L., Haites, E.F. (2001). International Emission Trading and the Cost of Greenhouse Gas Emissions Mitigation and Sequestration, First National Conference on Carbon Sequestration, Washington, D.C., May 14-17, 2001.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1183

CO2 EMISSIONS TRADING MARKET SYSTEMS AS AN ENVIRONMENTAL POLICY OPTION AND ASSESSMENT OF ITS EFFECT - EVALUATING INTERTEMPORAL TRADING IN PARTICULAR

Kazuya Fujime Managing Director & Chief Executive Economist, IEEJ, Inui Bldg., Kachidoki, 13-1, Kachidoki 1-chome, Chuo-ku, Tokyo 104-0054 JAPAN

ABSTRACT

In the theory of economics, to get the whole of GHG reduction targets satisfied efficiently, it is imperative to set a target amount of GHG reductions achievable by each country at a marginal cost equal to all countries. But, there is actually a gap between theory and a given target. In efficiency terms, it is desirable if each country could freely trade on the market "gap," or any difference between an optimal reduction amount for a country and a target specified by the politically compromised Kyoto Protocol. Emissions trading provides a mechanism of adjustment by selling or buying emissions (emissions permits). To explain clearly why emissions trading can have a cost reduction effect with a theoretical model in use, this paper first verifies an inherent function of emissions trading, which helps minimize a total reduction in cost by adjusting any "gap" between optimal and political targets, in both spatial and temporal terms. A Lagrangian function of a bilateral two-period trading model is used in the verification. Also, in order to demonstrate an effect of intertemporal trading, the "World Energy Industry Model," originally provided with an inter-area emissions trading function, was modified and given an additional intertemporal trading function to inter-area one before nan for simulation.

INTRODUCTION

This paper intends to offer an in-depth examination from the standpoint of economics of the "Kyoto Protocol" generally perceived as a product of intemational coherence in global warming abatement. A collective target set under the Kyoto Protocol requires industrialized countries to cut their combined greenhouse gas (GHG) emissions as of 2010 to a level "their annual average emissions in 2008--2012 should stay 5.2% below 1990 records." The Protocol also specifies reduction targets to be met by individual countries (areas). On top of the commitment period up to 2010 proposed under the Kyoto Protocol, during which specified targets should be met, subsequent five-year commitment periods to 2015, 2020, 2025 and 2030, each, were set and two scenarios were prepared. One is a "business-as-usual (BAU)" scenario in which the Kyoto

1184

target would remain unchanged even in the post-2010 periods. The other is a "tightening environmental constraint (TEC)" scenario, which assumes the Kyoto target would be the tighter in the later commitment periods. By varying banking and borrowing conditions, each scenario was simulated in a total of 36 cases. Simulation results showed that intertemporal trading was effective in cutting the emissions reduction cost by 3~26% in the BUA case, and by 4--7% in the TEC case, thus proving a cost reduction effect of intertemporal trading thanks to its temporal flexibility. Based on consideration described in this paper, the Kyoto Protocol can be counted as the first step toward warming abatement. In the capacity of environmental policy, the protocol can be evaluated as a step forward.

TOTAL COST MINMIZATION AND OPTIMAL SOLUTION BY BILATERAL TWO-PERIOD TRADING MODEL Emissions trading in a broad sense will be in practice multilaterally and over multiple periods. But, for simplification purposes, a theoretical model of bilateral two-period trading is used here in clarifying the essential nature of emissions trading, in which trading is in goods called emissions permits. In stricter terms, this model deals in synchronous bilateral trading, but does not cover intertemporal trading within a single country. On the contrary, intertemporal trading includes not the former but the latter. Anyhow, it remains unchanged that this theoretical model can explain theoretical grounds for the inherent function to emissions trading to help adjust any "gap" between an optimal solution and a political target. With bilateral two-period trading expressed in equations, the question of how to minimize the emissions reduction cost can be solved as described below. Xl=First country's CO2 reductions X2= Second country's CO2 reductions Yl=ax~ First country's marginal reduction cost curve Ya=bx2 Second country's marginal reduction cost curve Yli=First country's marginal reduction cost in i period, i=l, 2 yli=First country's total reduction cost in i period, i=l, 2 Y i=Second country's total reduction cost in i period, i=l, 2 2

i

yl=Eyl =: First country's total reduction cost throughout a given period, i=l, 2 y2=Ey2i=: Second country's total reduction cost throughout a given period, i= 1,2 y=yl+y2=: World's total reduction cost throughout a given period Y=l/2(a(x1')2+a(x,Z)2CDR+b(x2')2+b(x22)2CDR) (To be explained at the end of this section.) CDR=Composite discount rate=(1 +p)x(l +s)/(1 +r) x (1+t) xll=First country's optimal reductions throughout a given period Xl2=First country's optimal reductions in the second period x21=Second country's optimal reductions throughout a given period x22=Second country's optimal reductions in the second period Min Y, constraints are put as follows: (s, t)

~ ~-~x/= xll+x12+x21+x22=~ i=1 j = l

1185 Here, Rangange's equations are put as follows.

L(Xl 1...... X22,K)=Y+K (O,--X11--X12--X21--X22) Z,represents a marginal reduction cost. Xll x12 XEl'X22~"are differentiated.

~L/~x11=LI l--ax i 1-~,1==0

(1)

8L/Sx12=L12=aXl2CDR-~.=0

(2)

8L/Sx21=n2 l--bx21-~L=0

(3)

8I_JSx22=L22=bx22CDR-K=:0

(4)

8n/8~L=L~.=fx-x11-Xl2-x21-x22=:0

(5)

xll=K/a

Xl2=L/aCDR

X21=~]9

x22=~oCDR

With these put in the equations (5): ot-L/a-L/aCDR-L/b-L/bCDR =~-K (l/a+ 1/aCDR+ l/b+ 1/bCDR)=0 Hence, ;~=w'(1/a+I/aCDR+I/b+I/bCDR) = w'(1/a+l/b)+(1/a+l/b)/CDR=ot/(1/a+l/b)(l+l/CDR) Accordingly, Xl1=L/a=-~a(1/a+ I/b)( 1+ 1/CDR)= ~(1 +a/b)(1 + 1/CDR) x~2=L/aCDR=~(1 +a/b)(1 +I/CDR)CDR=w'(1 +a/b)(1+CDR)

X21=~/b:(L/b( I/a+ l/b)(1 + 1/CDR)=ot/(1+b/a)(1 + 1/CDR) x22=~j]gCDR=oJ(1 +b/a)(1+ 1/CDR)CDR=w'(1 +b/a)(1 + 1/CDR) Y(the world's minimum total reduction cost)can be described as follows. Y=Yl l+yl2+y21+Y22

yll=axllxll/2=a(xll)2/2

Yl2=aCDRxl 2xl2/2=aCDR(xl2)2/2

y21--Bx2Ix21/2__b(X21)2/2 y22=bCDRx22x22/2=bCDR(x22)2/2y=(1/2)(a (x11)2+a(x12)2CDR+b(x21)2+b(x22)2CDR

THEORETICAL GROUNDS FOR EMISSIONS REDUCTION COST CU'ITING EFFECT

INHERENT TO INTERTEMPORAL TRADING First, the tools provided by intertemporal trading are banking and borrowing of emissions permits. Literally banking means to bank emissions permits, consumable in a coming period, otherwise sold or leased.

1186 Borrowing means to borrow emissions permits to be consumed during a current period, with equivalent ones to be paid back in a coming period. Theoretically not only trading partners include others (other areas) but also owned permits in current or coming periods are tradable. Moreover, a coming period is not limited to the next period to come but includes any period ahead. Effects of intertemporal trading have analogy with those of spatial trading, which means this trading can be considered as if temporal dimensions were identical to spatial dimensions. However, affected by interest rate, technological advance, aggravating capacity of COz sinks, emissions-permits price rises, etc., intertemporal trading itself does not allow application of a simple analogy by extrapolating the emissions cutting effect of spatial trading. It is because intertemporal trading requires changing conditions with time to be taken into consideration, a crucial difference from spatial trading. Listed below are major variables that are assunaed to affect intertemporal trading: Emissions-permits price increase (%/year): p Interest rate (%year): r Rate of technological advance (%year): t Rate of aggravating capacity of COz sinks (rate of gradually diminishing capacity with time of such sinks as oceans)(%year): s Of these variables, it is p and s that can facilitate banking of emissions, or emissions pemaits, by cutting more emissions than targeted for a current period, which can be used in achieving a target to be met in a period to come, or sold to earn profits. The variables that impede banking of emissions are r (advantageous if held in cash but working ill when possessed in the form of emissions permits) and t (to hold emissions permits accrued from immediate reduction efforts works ill because the same reduction efforts should cost less in the future). Conversely, when emissions permits are borrowed from those consumable in a period to come in order to meet an unattained portion of a reduction target for a current period during which few reduction efforts are made actually, r and t act as positive contributors, while p and s become impediments. By the way, s, counted as a net penalty for a delay in time, can be taken as part of the penalty of 1.3 times (5.4%dyear) for a delayed attainment of the first-period (5 years) target agreed at reconvened COP6 (in Bonn, Germany). For example, of the penalty, 5%dyear can be attributed to interest rate (r), and 0.4%dyear to aggravating capacity of sinks (s). But, as far as s is concemed, it is not easy to get it scientifically grounded well enough to yield an intemational accord. It is because forests and oceans are found to have different relations between rising CO2 concentrations and their capacities as sinks. In natural science terms, these involve too complex casual relations to pemfit quantification after all. And yet, they are taken as linear variables here as a matter of convenience (Masayuki Tanaka, 1993). The cost cutting effect ofintertemporal trading has been confirmed by SO2 (sulfur oxide) emissions trading in practice in acid rain control programs under the Clean Air Act of the U.S. (A.D. Ellerman et al 2000). Though not detailed here, most of the cost cutting effect ofintertemporal trading can be explained by analogy with the cost cutting effect of spatial flexibility. Yet, when emissions reductions are put on the x-axis and reduction costff-C (US$) on the y-axis, what's essential is to apply the same yardstick to all costs on the y-axis, which incur in different times. In short, the costs incurring in different times need to be discounted in present values. The question is what discount rate should be set. Simply considering, a discount rate can be identical to interest rate (r). But, as already discussed, intertemporal trading is affected particularly by emissions-permit price rises (p), aggravating capacity of COz sinks (s), and technological advance (t), which means these too should be reflected on a discount rate in present values. Namely, it was thought necessary to reduce the four principal factors (p, r, t, s), influential on intertemporal trading, to present values by a discount rate that takes them into consideration in a composite manner or the so-called composite discount rate, instead of a simple discount rate. What's discussed above is taken as CDR (composite discount rate), and the duration of years to carry out

1187 intertemporal trading as n years. It is p and s that facilitate banking, while r and t pose impediments. relations between CDR and the four factors in the n th year can be expressed as follows:

The

CDRn=(1 +p)" • (1 +s)n/(1+r)~• (1 +t)~=(1+p)~/(1+r)nx(1+s)~/(1+t)~ If the world has the only one energy industry trading emissions permits, the industry is expected to cut emissions and trade emissions permits in a way that such activities yield maximum economic surpluses = maximum profits. When a future is expressed as "total sales of emissions permits (permits price x reduced amount) - total reduction cost (cost/'F-C x reduced amount) = profits (economic surpluses)," the industry should bank when the equations are read now as the right side (RS) > the left side (LS). Similarly, the industry should prefer borrowing when RS < LS is more likely. What affects total sales in the future is Bn=(1 +p)nx(1 +s)n(p determines the price, and s does the size of trade), while what affects total cost in the future is Cn=(1 +r)nx(1 +t)n (r determines cost increases, and t does cost decreases and the magnitude of cost). Accordingly, the world energy industry tries to maximize profits (economic surpluses) (or minimize costs) by banking when the composite discount rate =CDRn=Bn/Cn>I, and by borrowing when Bn/CnI, while borrowing is in advance when CDRn=Bn/Cn
EMISSIONS-REDUCTION COST CLrITING EFFECT OF INTERTEMPORAL TRADING By taking advantage of analogy between intertemporal and spatial trading effects, examples of cost cutting by intertemporal trading can be shown as a figure. All of the questions, including CDR > 1, or <1, or = 1, and if trading, regardless of banking or borrowing, takes place or not, are shown in this single chart. While optimal solutions and roles of emissions trading were already explained in relation to the bilateral two-period trading model, the explanations also covered bilateral trading over a single period, which involved not intertemporal trading but inter-area trading alone. Intertemporal trading in the bilateral two-period style takes the form of either trading between the first and second periods within a single economic unit (country) or intertemporal trading between different economic units (countries). Here, given case-specific optimal solutions and their "gaps" from a given target to be adjusted by intertemporal trading, the conditions leading to an optimal reduced amount, an equilibrium marginal reduction cost, banking or borrowing, and an equilibrium are described in terms of total CO2 reductions (or), composite discount rate (CDR), and gradients of marginal reduction cost (a, b), which are all postulates. An example of bilateral two-period trading: 1st country 1st period x 1st country 2"d period : The marginal reduction cost curve of 1st country 1st period is taken as y=ax, and that of 1st country 2"d period as ~ D R a x . Here, in the absence of intertemporal trading, an optimal reduced amount is expected when xll=~/a(l+aJb)(l+l/CDR), x12=ct/(l+a/b)(l+CDR). Hence, it is when CDR=I. ~.=ct/(l*a+ I/b)(1 +I/CDR).

When y=ax=CDRax, no emissions trading takes place.

In this case, an equilibrium marginal reduction cost is expressed as

When the 1st country 1st period is taken as a unit (referred to as "unit" so as to

judge if resultant trading should be called banking or borrowing), banking takes place when its marginal reduction cost (=axlg)I. In this case, the cost can be trimmed as much as ABxEDx 1/2. On the other hand, borrowing takes place when axll>CDRax12 , that is, when CDR
This case results in a cost reduction ofAB' xFD' x 1/2.

1188 W O R L D ENERGY INDUSTRY M O D E L AND SIMULATION RESULTS The World Energy Industry Model is an LP model that is given a structure which illustrates the relations among energy flow from production to marketing, the amounts of CO2 reduced and the emissions reduction costs involved in the world energy industry. With this model, the six cases described below are simulated, then Tests A to F were made. (1) Base: BAU case: Assumes no restraints on emissions. (2) Case 0: Assumes certain restraints on emissions but no emissions trading. (3) Cases 1--4: Restraints on intertemporal trading are assumed to be gradually lessened in each case. Assumptions of Four Major Factors Influential on Intertemporal Trading In Tests A-F, combinations of the four factors and the composite discount rate were employed. The model was run in a total of 36 cases, and simulation results showed emissions trading was effective in cutting CO2 reduction costs.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1189

CDM INVESTMENT: MARKET ACTORS' PERCEPTIONS J.Buen Analyst, Point Carbon Gronnlundvn 1, N-3400 Lier, Norway Tel.: +47 924 29 400, e-mail: [email protected], URL: http://www.pointcarbon.com

ABSTRACT Which factors decide whether countries are attractive for investment under the Kyoto Protocol's Clean Development Mechanism (CDM)? This is the key question of this paper. It summarises some of the results of a Point Carbon report from May 2002 [ 1]. Companies in countries that are included in Annex 1 of the Kyoto Protocol (e.g. countries that have committed themselves to reduce greenhouse gas (GHG) emissions) can make CDM investments to fulfil their emissions reductions obligations. The paper ranks CDM host countries based on an expert poll as well as quantitative data on i) host country approval systems and ii) host country investment climate (including foreign direct investment and gross domestic product). INTRODUCTION The need for improving our understanding of the CDM owes firstly to the fact that it offers considerable near-term advantages compared to the two other flexible mechanisms under the Kyoto Protocol: Joint Implementation and International Emissions Trading. Secondly, the CDM seems likely to become a key determinant for carbon prices under the Kyoto framework in the mid-term. Clearly, the profitability of a CDM investment hinges on the specifics of the project in question. However, in this paper we attempt to generate general knowledge about factors that affect the attractiveness of CDM projects. In March 2002, Point Carbon asked 15 experts from companies and organisations currently playing key roles in preparing, funding and implementing CDM projects in which non-Annex 1 countries they would invest in CDM projects, and what factors were most important for making a CDM investment attractive, l They were asked to give the main arguments behind these answers. The questionnaire was supplemented by statistical material on all potential CDM host countries' investment climate and responsiveness to the Kyoto process (for a brief version, coveting only the CDM host countries deemed most attractive, see Appendices 1 and 2). Note that the number of experts is small, and the experience from CDM projects and policies still scarce. Thus, the r e p o r t - and this p a p e r - should be taken as an indication of current market trends and actor perceptions, rather than evidence of future CDM market development. WHAT DETERMINES THE ATTRACTIVENESS OF A CDM P R O J E C T ? The experts ranked host country CDM policies as extremely important for the attractiveness of a CDM project. This has several reasons: •

A non-Annex I country must have ratified the Kyoto Protocol to host CDM projects.

•

A particular host government's attitude towards CDM indicates how forthcoming it will be in approving CDM projects. Several interviewees were baffled that some host governments seemed to

Experts were also asked in what project types they would invest, but such aspects will not be coveredhere.

1190

lack interest even though CDM project developers brought several high quality projects to their attention. •

Related to the above: CDM host countries will likely take different approaches to whether or not they will tax CERs; demand CERs for funding of CDM projects; and impose sustainable development criteria on projects.

•

Quick government approval is crucial to minimise transaction costs (time, efforts and other resources needed to locate, negotiate and complete a deal) and thus total project costs. The World Bank Prototype Carbon Fund (PCF) experience so far supports this conclusion. While few nonAnnex I countries have clear-cut CDM policies, some have been more proactive than others (see section on the relative attractiveness of host countries below).

•

Even though a host governrnent approves a project, the project may be changed or stopped due to bureaucratic battles or other organisational problems, and thus yield lower emissions reductions than stipulated or none at all. This counts not only for the relations between national-level bureaucracies, but also local stakeholders, as project approval is no guarantee that local authorities in the project area approve of a project.

•

Non-Annex I countries' opinions have differed on which project types should qualify for CERs under the CDM. Thus, some countries might reject certain project types.

In sum, it seems sensible to focus on countries that give high priority to CDM, have experience with hosting climate projects, and are likely to approve projects. The interviewed experts ranked host countries' investment climate as the second most important factor determining how attractive a CDM investment is. Safety and political stability issues are important, especially in a short-term perspective. For example, Indonesia and Argentina have done much preparatory work for the CDM, and their authorities understand CDM better than do authorities in most other CDM host countries. Nevertheless, it is currently difficult to do transactions in these countries, due to political instability and economic turmoil, and capital investment would have to carry a substantial risk premium. TABLE 1 WHAT ARE THE MOST CRITICAL FACTORS DETERMINING THE ATTRACTIVENESS OF CDM INVESTMENTS? AVERAGE SCORE (10=MAX, 1=MIN.) Factor

Score

Host country CDM policies Investment climate in host country Techno-economic potentials Easy baseline estimation

9,4 7,6 6,5 6,2

Techno-economic potential was ranked third. The scope for technically feasible and low-cost reductions in the host country obviously forms a central part of the basis for sound investment. For example, not all CDM host countries have an abundance of project sites attractive for wind energy utilisation. Furthermore, selecting replicable and modular projects will increase revenues and reduce transaction costs over time. The reason techno-economic potential was ranked lower than investment climate and host country CDM policies, is probably that the problem fight now is not lack of techno-economic potential. China alone could probably muster enough projects to cover all emissions reductions necessary for companies and countries to fulfil their commitments under the Kyoto Protocol. Whether a country has a large technical and economic potential to host CDM projects is irrelevant if it is not eligible to host them, incapable of doing so effectively due to bureaucratic rivalries, or is downright uninterested. The challenge is to identify economically sound projects and reliable partners in areas that are economically and politically stable, and get project approval without incurring prohibitively high transaction costs. Companies investing in sectors they are active in and familiar with may secure industrial and strategic benefits and capitalise on the organisational learning achieved through replicating a project.

1191 While CDM is a means of increasing the retum on investment, it will rarely change a bad investment into a good one as long as carbon prices are low. Apart from some project types (notably those involving methane gas capture), the Certified Emissions Reductions (CER) stream will at present rarely constitute more than, say, 5-15 per cent of total revenues from a given project. Therefore, the CER stream is rarely the most important factor deciding whether a CDM investment is sound or not. It is just the icing of the cake. The most important aspect is whether a potential project is economically and financially sound as such. The baseline-setting process ensures CDM projects' environmental integrity. At the same time, too complex and time-consuming baseline-setting will increase transaction costs prohibitively. Our experts nevertheless viewed easy baseline estimation as less important for the attractiveness of a CDM project than the other factors above, perhaps as this is regarded as mere bureaucracy, rather than a bottleneck in itself. The experts also mentioned counterpart credibility and ability to tackle financial penalty or replacement of credits if the project underperforms; active and solid local equity investors; projects' environmental integrity; and effective relations with investor country authorities, as influencing project attractiveness. W H I C H CDM HOST COUNTRIES ARE CURRENTLY MOST A T T R A C T I V E ? Our expert poll suggests investors currently focus on countries that i) they have experience with or knowledge about; ii) are large (and well-known); iii) are in Asia or the Americas, rather than Africa; and iv) have considerable emissions reduction potential. Below, we examine the top six countries in the expert poll (see Table 2) against a set of other characteristics obtained from our country screening (see Appendices 1 and 2). TABLE 2 WHICH COUNTRIES ARE CURRENTLY MOST ATTRACTIVE? Rank 1 2 3 3 5 5 7 8 9 9 9

Country China Brazil Costa Rica South Africa India Mexico Chile South Korea Guatemala Indonesia Kenya

China tops the chart largely because of its huge project potential (especially in the energy sector), good investment climate and a fast-growing economy. China receives more FDI and development aid than any other non-Annex I country, and thus has considerable experience from such projects. Several Annex I countries (e.g. Canada, Germany and Italy) currently co-operate with the Chinese on projects that might produce CERs. China is establishing a government-lead group on CDM, ratified the Kyoto Protocol in September 2002, and submitted three projects to the recent Dutch Certified Emissions Reductions Procurement Tender (CERUPT). These features indicate that China is an attractive CDM host country. However, China is so far (May 2002) absent from PCF's project portfolio (as is India). The Chinese are keenly aware of their attractiveness as a CDM host country, and take their time in crafting a CDM policy that is in their best interest. After all, CDM projects will not constitute a particularly large part of FDI pouting into China. Furthermore, allocating prestige and funding in C h i n a - in this case the formal responsibility for CDM project approval and co-ordination - is very often a protracted process of consensus building. China (and India) are certain to attract more projects once their domestic CDM apparatus is in place. However, by then, other countries - especially those in Central America - will have gained valuable experience with such projects and thus improved their relative attractiveness for investors compared with

1192

the two Asian giants. Consequently, model simulations saying that most CDM projects will be in China and India may miss the target. Brazil has a considerable demand for new electricity sources and a large sink potential. Its country risk profile is not particularly good, but it has long experience with FDI, and healthy economic growth. Its CDM awareness is relatively high (although it has limited project experience) - it has established a UNFCCC focal point, and ratified the Kyoto Protocol. Costa Rica is the proof that our experts do indeed value project experience in their evaluation of potential CDM host countries. Its project potential is small, but its organisational capacity for CDM-like projects substantial, after having hosted 9 AIJ projects. It is politically stable and generally has a good investment climate. South Africa is English-speaking, has good infrastructure, a convertible currency, and relatively wellfunctioning financial markets. Although it tried hard to get up to speed for the Johannesburg Summit, it is still behind Kenya and Uganda in terms of CDM policy preparations. South Africa has both a considerable renewable energy development potential and possibilities for reductions in its current installed capacity.

While Mexico's baseline is not very emission intensive, it has a significant project potential. More importantly, it has AIJ experience, and negotiates a MoU with PCF. It might also one day be member of a North American Free Trade Agreement (NAFTA) GHG trading scheme, and has a good investment climate. India has an overwhelming project potential, especially in the energy sector, but its investment climate is less impressive. It also has a relatively weak organisational capacity for - and awareness o f - CDM. However, India posted 11 project idea notes to the CERUPT tender in January 2002 (of which 6 were invited to produce a full Project Design Document). There is a risk for long delays in project approval processes.

The results presented in table 2 should obviously be used with caution. Although the experts polled are among the leading analysts in this field, their in-depth knowledge is limited to just a limited number of countries. Hence, their answers indicate what current perceptions of which CDM host countries that will become attractive, rather than which countries that currently have the most investment-friendly CDM policy. In particular, analysts at Point Carbon that have followed China's policy in this area for half a decade were surprised that experts listed China as the most attractive country, given the fact that the experts rated the host country's CDM policy as the most critical factor. Experience from the AIJ phase and from recent projects has shown that it requires rather lengthy negotiations to gain political approval for a project, and that the division of regulatory authority is often unclear. Hence, China's current CDM policy is not particularly favourable. On this basis, it would seem that the ranking of host countries at least in part reflects the (experts' perceptions of) these countries' techno-economic potential for cheap emission reductions. This is inconsistent with what the polled experts - and indeed Point C a r b o n currently regard as the most important factor determining the attractiveness of a CDM project: host country CDM policy. Hence, the above ranking of countries should be treated with caution. Getting a better grip on host countries' CDM policies will thus be a natural focus in forthcoming CDM analyses by Point Carbon.

REFERENCES Point Carbon (2002), "CDM investments: Where and how?". Read public summary at URL: http://www.pointcarbon.com/article view.php?id = 1832. International Monetary Fund (IMF) (2001), Worm Economic Outlook (October).

1193 OECD (2002), Country Risk Assessment (18 April). Transparency International (2001), Corruptions Perceptions Index 2001. UN (2001), Worm Economic and Social Survey 2001. UNCTAD (2001), World Investment Report 2001. UNDP (2001), World Development Report 2000/2001 (December).

Abbreviations

AIJ: Activities Implemented Jointly. Cap.: Per capita. CERUPT val.: Project selected for validation after the first tender of the Certified Emission Reduction Unit Procurement Tender (Dutch CDM fund) in January 2002. Corruption Perceptions Index (Transparency Intemational). High numbers mean low CPI: perceived corruption. Foreign direct investment, in mill. USD. FDI: Share of global FDI divided on share of global GDP. FDI/GDP: Gross domestic product. GDP: Negative growth. Neg.: Under negotiation. Nego.: Prototype Carbon Fund (The World Bank). PCF: Being reviewed. Rev.: Tonne reductions of CO2-equivalent emissions. tCO2e:

1194

Appendix I: Top 20 countries' climate project experience Rank

i

,,

Country

Kyoto ratif.

China

All experience

Other experience

AIJ proj.

tCO2e

Sinks

Renew.

Other

4

1483794

0%

0%

100 %

CERUPT MoU Nego.

2

Brazil

3

Costa Rica

9

66905761

99 %

1%

0%

Nego.

4

South Africa

2

13000

0%

0%

100 %

Nego.

CERUPT PCF valid.** MoU*** Yes

Yes

5

India

6

Mexico

7 8

Chile South Korea

9

Guatemala

10

Indonesia

Yes

Yes

Yes

1

Yes

1

1

1494600

0%

0%

100 %

5

4286003

28 %

0%

72 %

Yes

4

18537135

56 %

16 %

28 %

Yes

3

4693558

0%

100 %

0%

Nego.

4

76070

0%

6%

94 %

Nego.

Yes

PCF proj.

Yes

Yes Yes

,

11

Kenya

12

Philippines

13

Thailand

14

Zambia

15

Honduras

Yes

4

16 17

Bolivia Venezuela

Yes

5

18 19

Swaziland Mozambique Colombia

* **

Yes Nego. 1

34100

Yes Rev.

0%

0%

I00 %

4782278

0%

100 %

0%

Nego.

Yes

65367018

85 %

0%

15 %

Nego.

Yes

Yes

Yes

***

Approval, accession and ratification, as of 6 May 2002. Projects from these countries have been selected for validation. The 10 most expensive per cent of the projects will not be approved. Includes country agreements linked to projects, not only MoUs.

Rank

Country

Appendix 2: Top 20 countries' investment environment Investment environment %GDPI" p.a. %GDP'[" GDP./cap.Real %GDP']" FDI FDI 90-99 2000 1990-98 2002 1 9 9 5 2000 1

China

10,7

8

2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Brazil Costa Rica South Africa India Mexico Chile South Korea Guatemala Indonesia Kenya Philippines Thailand Zambia Honduras Bolivia Venezuela Swaziland Mozambique Colombia

2,9 4,1 1,9 6,1 2,7 7,2 5,7 4,2 4,7 2,2 3,2 4,7 1 3,2 4,2 1,7

4,4 4,5 2,9 5,7 5,1 4,5 4,6 3,3 5,2 -0,2 3,7 3,1 3,6 6,2 2,4 5,6 2,5 2,1 2,1

6,3 3,3

10

6,9

35849 40772

30,9

1,3

2

3,5

2,0

5475 33547 30 337 400 10 1241 877 30 2144 100 30 9526 13162 10 2956 3674 20 1176 10186 20 75 228 0 4 3 4 6 - 4 4 5 0 Neg. 32 60 0

21,6 43,3 39,5 3,6 16,4 55,2 7,9 17,7 46,2 8,2

1,2 1,5 0,2 0,2 0,8

4 4,5 4,8 2,7 3,7 7,5

0,6 0,6 -0,7 0,1

6 3 4 3 3 2 2 6 6 6

1459 1489 2004 2448 97 200 69 282 374 731 985 4110 44 -37 45 139 1321 273

14,9 17,5 58,4 22,5 56,9 20,9 45,7 22,4 21,9

0,6 0,9 1,7 1,1 3,1 1,2 2,7 1,9 0,8

1,5 4,2 0,4

1,2 3,9 0,5

%FDI Inward FDI FDI/GDP OECD 1" 86stock, % Risk CPI 00" of GDP (1999) 98-00 avr. Ass.

2,3 5,7 1,2 3,2 3,7 3,5 1.4 3,1 2,3

-1,3 0,8 1,5 0,1 1,9 2,3

30

10 10 10 10 30 30 0 30 10

* "30%"=+30% growth; "20%"=+20-29.9%; "10%"=+ 10-19,9%; "0%"=+0-9,9%; "Neg"=negative growth. Sources: 2,3,4,5,6,7.

4 3 7 7 7 4 7 5

2,9 1,9

3,2 2,7 2

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1195

P O T E N T I A L E V A L U A T I O N OF C O 2 EMISSIONS R E D U C T I O N BY CDM P R O J E C T S - PROJECT DESIGN TO PROVIDE BENEFIT TO BOTH DEVELOPED AND DEVELOPING COUNTRIES Takanobu Kosugi l, *, Weisheng Zhou 2, and Koji Tokimatsu 1 Research Institute of Innovative Technology for the Earth 9-2 Kizugawadai, Kizu-cho, Soraku-gun, Kyoto 619-0292, Japan 2 College of Policy Science, Ritsumeikan University 56-1 Toji-in Kitamachi, Kyoto 603-8577, Japan

ABSTRACT

The clean development mechanism (CDM) contributes not only to the cost-effective achievement of CO2 emissions reduction target of developed countries, but also to sustainable development in developing countries. For the purpose of promoting CDM projects, flexible frameworks are suggested for the distribution of benefits produced by implementing the projects to adjust unbalanced benefit distributions between the investor and host countries. One of the suggested flexibilities is to let the gross economic profit, all of which is conventionally considered to be given to the developing side country, be partly returned to the developed side country; another is to let the investment be shared between both sides. Through cost-benefit evaluations of the projects of installing combined cycle power generation and cogeneration plants in China as example case studies, it has been verified that the application of these flexibilities heightens the possibilities for the projects to be compatible with CDM under the uncertainties of economic conditions, e.g., economic value of the certified CO2 emission reduction. Since there is a huge potential of CO2 emissions reduction due to technology transfers from developed countries to developing countries, the promotion of implementing CDM projects is highly recommended in order to accelerate the technology transfers. INTRODUCTION

The clean development mechanism (CDM) is well known as a part of the flexibility mechanisms of the Kyoto protocol, and is an incentive to transfer technologies from developed countries to developing countries. The promotion of CDM projects is recommended since technology transfers by using CDM, etc., are expected to cost-effectively reduce CO2 emissions and to also contribute to sustainable development in developing countries. For this aim, in this paper, we suggest flexible frameworks on the benefits distribution of CDM projects to provide benefits to both sides of developed and developing countries.

F R A M E W O R K OF CDM PROJECT TO PROVIDE BENEFITS TO BOTH COUNTRIES

There are several candidates of CDM projects which are expected to bring CO2 reduction credits to developed countries (investors) and benefits on sustainable development to developing countries (hosts) sides. However, there exists a concern that an unbalanced distribution of the benefits to the two sides may lessen the incentives to promote many CDM projects, since the future economic value of CO2 credit is uncertain and * Author for correspondence. E-mail: [email protected]

1196

there is even a possibility for some projects to be not cost-beneficial for both sides. Hence, well-coordinated frameworks are suggested to make the benefit distributions as balanced as possible. The concepts of the frameworks are as follows [ 1]. The implementation of a CDM project is expected to make not only economic but also environmental profits. Here, the gross economic profit includes the cost or fees of electricity and fuel saved by implementing the project. Subtracting the investment cost for installing a technology from the gross economic profit derives the net economic profit. The environmental profit consists of the reduction of pollutant emissions and the CO2 reduction credit that corresponds to the certified emission reduction according to the CO2 emissions reduction by the project. Suggested are flexibilities of distributions of the gross economic profit and the investment between the investor and host countries, aiming to balance the benefit distribution and to assure the investor side a certain profit regardless of the price of the CO2 credit. One of the flexibilities is to let the gross economic profit, all of which are conventionally considered to be given to the host country, be partly returned to the investor side; another is to let the investment be shared between both sides. We hereinafter refer them as "economic profit sharing" and "investment sharing" for the former and the latter, respectively.

CASE STUDY OF CDM P R O J E C T

Example Cases Fuel switching, energy efficiency improvement, renewable energy utilization, forestation, and other several technologies for reducing CO2 or non-CO2 greenhouse gases are candidates to be transferred from developed countries to developing countries as CDM projects. The example cases we evaluate in this paper are the projects of installing natural gas-fueled high efficient combined cycle power generation and cogeneration (combined heat and power generation) technologies in a region of southeast China where natural gas has been becoming accessible through pipelines from west China. The hosts of these projects are in China and the investor is assumed to be from Japan. For installing a natural gas combined cycle power plant in the electricity supply sector, referred to as the Combined cycle case, conventional coal thermal power and hydropower electricity generation is replaced by the combined cycle power generation. When installing a natural gas-fired gas turbine cogeneration system on the demand side, referred to as the Cogeneration case, the electricity demand is satisfied by the electricity generated by the cogeneration system installed in a district instead of purchasing utility electricity, and steam is supplied by the cogeneration instead of conventional coal-fired boilers. In both cases, fuel switching and energy efficiency improvement effects are anticipated. The major parameters used in evaluating the example cases are listed in Table 1. The reference values are obtained from the literature [2,3] and field surveys. In the Combined cycle case, a natural gas combined cycle plant is installed and operated with a high net power generation efficiency of 55.0 % (LHV) at a capacity factor of 63.4 %. In the Cogeneration case, a 50 MW-cogeneration plant supplies all or part of the electricity and steam demands in an industrial district where the expected peak electricity and steam loads are 140 MW and 586 GJ/h, respectively. See Ref. [4] for more details of the demand in the district. Evaluated Economic and Environmental Profits

The COz and SOx emissions reduction effects are estimated for two cases of the CDM project. The economic and environmental profits are then evaluated according to the reference values of the parameters shown in Table 1 and to the estimated emissions reduction effects. In evaluating the environmental profits, the CO2 reduction credit is calculated based on the assumption that the unit price of the CO2 reduction credit reaches 250 S/t-C*. The SOx reduction effect is quantified by multiplying the estimated SOx emissions reduction * This value is rather high as a C O 2 credit price anticipated until the first commitment period of the Kyoto Protocol. It is merely used for showing an example where both the Japan and China sides can obtain positive net total profits without a distribution flexibility suggested in this paper. Refer to the sensitivity analysis described later in this section.

1197 with the cost of desulfurisation in a coal-fired power plant using the lime/limestone-gypsum process [5]. Only SOx is considered as a pollutant here; however, the environmental profits are expected to be greater if the emissions reduction of other pollutants, e.g., NOx and particulate matters, are taken into consideration. The amounts of the emissions reduction are estimated on a static baseline that assumes that conventional energy technologies will remain constant without the projects implementation. TABLE 1 MAJOR PARAMETERS USED FOR EVALUATION Item Energy generation plant (For Combined cycle case) Natural gas combined cycle ............._g.oa!...th~a~...P..owe_r...P.!.~t

Reference value

Efficiency: 55.0 % (net), Capital cost: 518 $/kW, Capacity factor: 63.4 %

..................E.f..DLenc

-y..L.3...-8.~...L°-/.°-....(ne.t)-~...cap.!.ta!.-c~s.t~..-.6...7..5.......-$..~w...(w!t...h..~ut....d...e--s...9.~)

..........................................................................

(For Cogeneration case) Natural gas cogeneration Efficiency: see Ref. [4], Capital cost: 2000 $/kW, Capacity: 50 MW Heat supply boiler Efficiency: 90.0 %, Capital cost: 0 (already installed), Fuel: coal (without de-SOx) ........................................................................................................................................................................................................................... (For both cases) Annual expense rate: 17 % Fuel CO2 emission coefficient: 14.9 kg-C/GJ, Sulfur content: 0 %, Price: 4.30 $/GJ Natural gas CO2 emission coefficient: 26.3 kg-C/GJ, Sulfur content: 1.04 %, Price: 1.63 $/GJ Coal Share: Coal thermal power 75 %, Hydropower 25 %, Utility electricity Power transmission loss rate: 6.66 %, Consumer price: 26.3 $/kW/yr (fixed; according to the maximum demand), , 18.6 $/GJ (variable; according to electricity consumption) Note: Energy contents of fuels are based on the lower heating values (LHV). Table 2 summarizes the profits calculated for the two cases. It can be found from Table 2 that, although the operation of each of the natural gas combined cycle and cogeneration plants brings a gross economic profit, i.e., savings of fuel and electricity costs or fees, the investment to the capital cost of the plant exceeds the gross profit, and thus the net economic profit becomes negative for each of the cases. That is, from the viewpoint of conventional economic benefit only (or, even if the environmental profits of the SOx reduction effects are additionally taken into consideration), the projects of installing the plants are not feasible. In other words, these CO2 mitigating projects have positive CO2 abatement costs. These results imply that it is impossible to independently introduce the plants only by China. Therefore, an incentive policy is required to promote the installation to reduce the CO2 and SOx emissions. TABLE 2 EFFECTS OF INSTALLINGNATURALGAS COMBINEDCYCLE AND COGENERATION PLANTS AS CDM PROJECTS Case Combinedc y c l e Co~eneration Installed capacity (MW) 300 50 CO2 emissions reduction (kt-C/yr) (=AEc) 146.1 37.4 SOx emissions reduction (kt-S/ff) 7.75 1.94 .....Net.economic..profi.t..(m!.!.!i~..$.../..~)_(-A+B.).............................................................................................. -.....1...1..:..4....0... ........................................................................... .7..4.3....8.......................................... Item ......~vestment ._(-....A...) .................................................................................................................................................................... -.....2...6...4..2........................................................................ -....!.....7......0..0 ..................................... Gross economic profit (=B) 15.02 12.62 Environmental profit (million$../.~.)t~-C+D) . 41.96 10.71 -gOTrea~ci~o~efr-ec~(S:D)'~

........................................................................................................................ 3i-a~ ................................................................................ i:g~ ........................................

.....T.ota!...p.ro.0.t....(m!!.!i~$./~.)....(-.~+...D_C...+...D). Item

_~o.fit...f..or...J.apan.s.!.de_(-A~)

............................................................................................................ 3.0.:..56 .................................................................................. 6.-.3....3_ ......................................... ................................................................................................................10..12. ................................................................................ 7._...7.:...6....5 ....................................

Profit for China side (=B+D) (For reference) CO2 abatement cost (S/t-C) ( = - (A+B)x 1000/AEc) "~ Assuming the price of C O

2

20.44

13.98

78.0

117

credit is 250 S/t-C, .2 Assuming the SOx avoidance value to be 700 $/t-S.

By applying the CDM, the CO2 reduction credit becomes accountable as an environmental profit, and

1198 consequently, the total sum of the net economic and environmental profits can be positive for both cases as seen from Table 2. When we simply assume that the Japan side bears all the investments and obtains all the CO2 reduction credits and the China side gets all the gross economic profits produced by implementing the CDM projects, the net total profits for the Japan side are less than those to China in both cases. It is particularly noticeable that the profit for the Japan side is negative in the Cogeneration case even when all the CO2 credits are translated to Japan. To solve the problem of these unbalanced profit distributions is highly recommended in order to promote the CDM projects.

Profits Distribution for Promoting CDM Project Let us consider applying the flexibilities of the profits distributions we have suggested to the projects. Figure 1 shows the flow charts of the fund and profit using the Cogeneration case as an example where the net total profit for the Japan side has been evaluated to be negative as described above [6].

Net profit - 7.65 milllon$/yr ,I. 9.35 0-'-3.16 million$/yr milli°n$~Devel°pedl I "1 country I Investment lad (Japan) 117"00mllli°n$/yr I 1-1

side '

Net profit 13.98 million$/yr Net profit Net profit 13.98 million$/yr ,I- 7.65 million$/yr .I. 6.33~3.17 million$/yr ,I. Investment, labor, etc. 6.33-~-3.17million$/yr 1 36 9.35 0"--3.16million$/yr 7.65~10.81 1.36 IDevelopingLc.~llionS/y r mllll°n~Y~lDevelopedl Investment millionS/yr JDevelopingL¢mlllion$/yr

II ~un_t~ ~-'."'~, l"~-. I, I s,de Ill, ,

~lnput ( c o s t ) 1 2 . 6 2

~~

c?.un_t~.117.00mimonStyrl ~ 4, i s,de I 9.35-~6.19 /input(cost, millionS/yr ~

~ ~"~'J

I I

|

II country I-" (China) I~I side I-

Return

million$/yr

(Installation of CHP) million$/yr I

...............~ 0!J~u! (P.!0fit).,,~............................

[ . ~ million$/yr

I million$/yr I

.36 I

(a) Economic profit sharing

(Installation of CHP) i~ ~'

.~.............

~ Output (profit,

I million$/yr

I million$/yr I

million$/yr

~illlon$/yr I

(b) Investment sharing

Figure 1: Flow charts of fund and profit in the CDM project where both China and Japan can get benefits in the Cogeneration case When the flexibility of"economic profit sharing" is adopted, as shown in Figure 1 (a), returning at a rate of approximately 60 % or higher in the total gross economic profit to Japan side enables the net profit for the Japan side to be positive; the return rate of about 90 % is requested in order to balance the net profits for both sides. Alternatively, providing about 40-70 % of the total investment by the China side makes the net profits close to being balanced using the "investment sharing" flexibility as shown in Figure 1 (b).

Sensitivity Analysis of Projects Compatibility Though we have discussed in a deterministic way so far the assumptions for the costs and prices parameters used in the example cases, we should note that there are some actual uncertainties in the values of the parameters. The uncertainties will affect the compatibilities of the projects with CDM. For example, if the capital costs of the combined cycle and cogeneration plants are supposed to be half as cheap as the values originally assumed in Table 1, the net economic profits become positive so that the China side can implement the projects independently without CDM in both cases. Another example is the price of the CO2 credit which we consider the most uncertain parameter; if the CO2 credit price becomes cheaper while the other conditions are unchanged, the total sum of the net economic and environmental profits of both projects becomes negative and thus the incentives to implement the CDM projects no longer exist. Figure 2 illustrates the results of simple sensitivity analyses from the viewpoint of the uncertainties of the capital cost and CO2 credit price. The compatibilities of the CDM projects can be observed in Figure 2 for various combinations of the values of capital cost and CO2 price. The compatibilities are classified into the

1199 following four types: (1) the project is economically profitable for the China side with no financial support from the Japan side so that the CDM is not necessarily applied when the capital cost is very cheap; (2) the project is very compatible with the CDM since it is profitable for both sides without the suggested flexibilities on profits distributions applied when the CO2 credit price is relatively high; (3) the project can be compatible with the CDM when the suggested flexibilities are applicable though the net profit is negative for at least one side; and (4) the project produces a negative net profit and is not compatible when the capital cost is very high or the price of the CO2 credit is relatively low. The suggested flexibilities of the profits distributions relax the conditions on the capital cost and C 0 2 credit price required for the project to be compatible with the CDM as indicated in Figure 2. Although we have not dealt with the uncertainties of the other parameters, e.g., fuel cost, sensitivity analyses with regard to them can be similarly done and the flexibilities also play important roles in order for the project to have a better compatibility.

300

600 500

250 tO

400

200 "o oc,i 0 0 ~o

"o

150

o

100

"200 o

o

o .t-

.e-

~-

300

a.

50

0

100 0

1o0 200 300 400 500 600 700 Capital cost of combined cycle plant $/kW)

(a) Combined cycle case Figure

500

1000 1500 2000 2500 3000 Capital cost of cogeneration plant $/kW)

(b) Cogeneration case

2: Sensitivity analysis on compatibility of the CDM project - Q ~ • Economically profitable for China, i.e., CDM may not be applied, ( ~ " Quite compatible with CDM, " ompatible with CDM by economic profit sharing or investment sharing, Not compatible, i.e., total profit is negative.

~

POTENTIAL OF CO2 EMISSIONS REDUCTION BY TECHNOLOGY TRANSFER The trajectory of the C O 2 emissions in China towards 2100 in a business-as-usual case, calculated by using the integrated assessment model DNE21 [7], is shown in Figure 3 [8]. The CO2 emissions will consistently increase in this century and reach 5.5 billion t-C in 2100 without any CO2 mitigation policy in China. This drastic increase in CO2 emissions is basically due to the population growth and rapid economic development; however, another important reason for this is a high CO2 intensity, i.e., CO2 emissions per unit GDP, in China compared to Japan. Fhe high C 0 2 intensity in China is caused by the following three factors: (1) inefficient utilization of energy, (2) high dependency on carbon-intensive fuels, i.e., coal, and (3) high ratio of energy-intensive industry. As for the efficiency of energy utilization, the total efficiency in China was only 28 %, which was about as half that in Japan in 1990. Also in 1990, the rate of coal consumption of the total primary energy consumption was 76 % in China whereas it was only 17 % in Japan.

1200 Based on these facts, we have estimated the potential of CO2 emissions reduction based on technology transfers from Japan to China. Figure 3 indicates the estimated CO2 reduction potential hypothesizing that the CO2 intensity in China becomes the same as that in Japan by completely improving the three factors to Japan's levels [8]. As seen in Figure 3, the CO2 emissions in 2100 is potentially almost halved, where 60 % of the reduction potential is due to energy efficiency improvement; 26 % is by fuel switching, and 14 % is by an industry structural change. The implication of this is that the promotion of technology transfers by using CDM is of great importance in order to reduce CO2 emissions.

5

•~

0-..,4 "O E

E O

(0"~3 v

¢._O

tO

-E~ -=~ 2 (!) "1~ 0 o

1 0 2000 2010 2020 2030 2040 2050 2060 2070 2080 2090 2100 Year

Figure 3" CO2 reduction potential in China assuming that China's CO2 intensity decreases to Japan's level by technology transfer, etc., in a business-as-usual case

CONCLUSION The flexibilities of benefit distribution using "economic profit sharing" and "investment sharing" are suggested in this paper for promoting CDM projects to transfer environmentally friendly technologies from developed countries to developing countries. Through example case studies, we have verified that the application of these flexibilities heightens the possibilities for many candidates of technology transfer projects to be compatible with the CDM. We have also shown the huge potential of CO2 emissions reduction due to technology transfers to a developing country, using China as an example. ACKNOWLEDGEMENT This study was supported by the New Energy and Industrial Technology Development Organization (NEDO), Japan. REFERENCES 1. Zhou, W. (2000) Policy Science 7(3), 369. (in Japanese) 2. Li, Z., et al. (2001). In: Abstracts of SEEPS (Societyfor Environmental and Economics and Policy Studies) Conference 2001, pp. 44-45. (in Japanese) 3. ShanghaiJinqiao (Group), Ltd., Co. and Shanghai Pudong New Area Statistic Bureau (2000). 1999 Annual Report of Shanghai Jinqiao Export Processing Zone.

4. 5. 6. 7. 8.

Kosugi,T., Tokimatsu, K. and Zhou, W. (2002) Energy and Resources, in press (in Japanese) Takeshita,M. (1995). Air Pollution Control Costsfor Coal-fired Power Stations, IEA COALRESEARCH. Kosugi,T., Tokimatsu, K. and Zhou, W. (2002) Policy Science 9(2), 39. (in Japanese) Fujii, Y. and Yamaji, K. (1998) Environmental Economics and Policy Studies 1(2), 113. Zhou, W. (2002) Policy Science 9(2), 45. (in Japanese)

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1201

ECONOMIC EVALUATION OF SECTORAL EMISSION REDUCTION OBJECTIVES FOR CLIMATE CHANGE Chris Hendriks, l David de Jager, I Jochen Hamisch, 2 Judith Bates, 3 Leonidas Mantzos, 4 and Matti Vainio5 1 Ecofys Energy and Environment, P.O. Box 8408, NL-3503 RK Utrecht, Netherlands, [email protected] 2 Ecofys Energy and Environment, ETZ, Landgrabenstr. 100, Nuremberg, Germany 3 AEA Technology Environment, E6 Culham, Abingdon, Oxfordshire OX14 3ED, UK 4 E3M_Lab, ICCS/NTUA, Iroon Polytechniou 9, Athens 15773, Greece 5 European Commission, DG Environment, B-1049 Brussels, Belgium

ABSTRACT This paper summarises a study that identifies a least-cost allocation of objectives for different sectors and greenhouse gases so that the European Union would meet its Kyoto target o f - 8 % in 2008-2012 compared to 1990 emissions. For the purposes of the study it was assumed that the EU would comply with its Kyoto target without the "Kyoto mechanisms", l The study concludes that the marginal abatement cost amounts to ~99 42/tCO2-eq if each Member State fulfils their Kyoto "burden sharing" target individually. However, the cost would be reduced to ~99 20/tCO2-eq if the EU Member States fulfil their Kyoto obligations jointly, allowing to take measures where they are most cost-effective. In this least cost case, the annual compliance cost in 2010 is estimated at ~99 3.7 billion. The compliance cost would be fairly small in most sectors. INTRODUCTION At the Conference of the Parties in Kyoto in December 1997, the Member States of the European Union jointly committed themselves to reduce their emissions in the period 2008-2012 by 8% compared to the 1990 emission level. The reductions concern six (groups of) greenhouse gases: carbon dioxide (CO2), methane (CH4), nitrous oxide (N20) and three categories of fluorinated gases (HFCs, PFCs and SF6). In the European Environment Council of June 1998 the Member States agreed to "share the burden ''2 of the 8% target so that some Member States would commit to a higher reduction target while others were allowed to increase their emissions. In 1990/1995 the EU15 Member States emitted a total of 4138 Mtonnes of CO2 equivalent (Mt CO2 eq.). At the end of the decade emissions were at about the same level, whereas in projections up to 2010 emissions will increase by about 1% if no additional policies are assumed to be implemented. This paper summarises the results of a two-year study to identify a least-cost allocation of objectives for different sectors and greenhouse gases that allows the European Union to reduce its greenhouse gas emissions by 8% by 2008 - 2012 compared to 1990 emissions. This approach will fully maintain the environmental integrity of the Kyoto Protocol, while identifying those policies and measures that achieve The Kyoto mechanisms are International Emissions Trading, Joint Implementation and Clean Development Mechanisms. As the compliance costs of the EU are likely to be higher than in other Parties to the Kyoto Protocol, it is plausible that the EU would comply with its Kyoto target partly by acquiring emission rights. Thus, in reality it is likely that the reduction target for the EU would be lower than -8%. This was, however, beyond the scope of this study. 2 The "Burden Sharing Agreement" was reached in June 1998. The European Community and EU Member States deposited the rafitifaction papers to the UN on May 31,2002. The greenhouse gas reduction targets are: European Community -8%, Austria -13%, Belgium -7%%, Denmark -21%, Finland 0%, France 0%, Germany -21%, Greece +25%, Ireland +13%, Italy -6½%, Luxembourg -28%, the Netherlands -6%, Portugal +27%, Spain +15%, Sweden +4%, and the United Kingdom -12%%.

1202 the Kyoto target in a manner that minimises the cost. Simply, the intention is to identify a least-cost allocation so that the cost of production of energy and other goods would increase as little as possible. The study combines 'top-down' and 'bottom-up' methodological approaches and compares them as far as possible. As both approaches have their strengths and weaknesses, they complement each other, and increase understanding of different cost-effective greenhouse gas mitigation options. In the 'bottom-up' approach for each sector technological reduction options and associated costs were analysed with the GENESIS database. The results of the 'top-down' analysis with the PRIMES model give good insight in the total compliance costs for the EU. The study was conducted for the Environment Directorate General of the European Commission by a research team consisting of Ecofys (co-ordinator), AEA Technology Environment and E3M-Lab of the National Technical University of Athens. BOTTOM-UP APPROACH The bottom-up approach is the engineering-economic analysis of individual emission reduction options. In this approach a detailed inventory is carried out to the technical emission reduction options available before 2010 in all economic sectors. The options are characterised on emission reduction potential, investment costs, operation and maintenance costs, operational benefits and lifetime. The database GENESIS compiled by Ecofys and AEA Technology contains over 250 reduction options (56 for the energy supply sector, 24 for fuel related emissions, 91 for industry, 17 for transport, 32 for households and services, 18 for agriculture and 13 for the waste sector). It should be noted that even this level of detail does not cover the full variety of options that are available. However, differences between Member States are taken into account, if relevant. For instance, differences in climate makes building insulation more effective in reducing emissions in Finland than in Spain. Doing so, the study gives a reliable approximation of the emission reduction potentials and associated costs on sector, Member State, on European Union level, and by (group of) greenhouse gas. TOP-DOWN APPROACH In the top-down approach, the PRIMES model developed by NTUA is used in which all options are analysed simultaneously. In the top-down approach only the energy-related CO2 emissions are modelled. The top-down approach is less detailed compared to the bottom-up approach and it is more difficult to separate distinct options from one another. However, the advantage of the top-down approach is that the results are 100% consistent within the model. To include also the non-CO2 information, a meta-model has been developed. In this model, PRIMES data is completed by emission reduction data of the GENESIS database for non-CO2 greenhouse gases (NCGGs) and process emissions of CO2. COMPARISON OF BOTTOM UP AND TOP DOWN APPROACHES Figure 1 shows the results of the bottom-up analysis in a cost-curve (calculated with a discount rate of 4%, energy related CO2 emissions only). The presented reduction potential for 2010 should be compared to the frozen technology reference level 3 of 4194 MtCO2. The -8% level of 2823 Mt can be obtained with an emission reduction potential of 1372 Mt CO2. Figure 2 presents cost curves for the bottom-up and the top-down approaches for the energy-related CO2 emission only. In the range of 3000 Mt CO2 the results of the two approaches are surprisingly close to each other with a similar carbon value a t - 8 % target level. In both approaches the costs gradually increase from zero in the baseline to about ~50 per tonne CO2 in the case of 500 Mt reduction compared to the baseline. When reading the figure, it should be noted that:

3 The frozen technology reference level serves for the bottom-up analysis as a (theoretical) reference level in which no additional development to reduce emissions from 1990 onwards are included. The baseline serves as a reference level for the top-down approach and the meta-model in which all options with zero costs or less are incorporated.

1203 •

in the PRIMES analysis emission reduction options with negative costs are already assumed to be implemented in the baseline. in the PRIMES analysis substantial reductions occur below 2700 Mt and no further reductions result from the GENESIS data. This can be explained mainly by the fact that in GENESIS the reduction options become exhausted, whereas PRIMES allows for further reactions of the systems, like dynamic expansion of the market potential for the various emission reduction options, indirect interaction of demand and supply for energy and structural changes.

•

5O0 600 "[ 2010 EU-lS

400 t C02SuPl:~Cutve 4. ~ en~ions e.~u~) u 200

I ~

100

m

-I00

, ~

20 B I ~

600

400

!|

800

1000

\

s_,.,.~ 1200

1400

1600

r x Fmz~ technologyreferenoelevel ...... GENE,S 4%

il~

r

ilr'

C O z ~ level

,,

~. L,,,,,

~-

~s

%

v

1800

100

o

~.~ u

-

~ -100

10

2500

3000

~~ . ~ . -. . ~ -

- -~ - - --,

, . . . . . .

3500 ""~1~

4 )0

I

-500

-200 r=mtss~n redu~on ~

M o m e COzy.)

Figure 1 Cost curve for the GENESIS energy related CO2 emission reduction in the EU15

Remaining emissions after implementation (Mr GO2)

Figure 2 Cost curve for the GENESIS and PRIMES approach

EUROPEAN UNION WIDE RESULTS TABLE 1 presents the distribution of direct emissions of greenhouse gases in the base year, for the 2010 baseline, and in the most cost-effective solution for 2010 where emissions are reduced by 8%. The least cost allocation implies that some sectors need to reduce their emissions by more than 8% compared with 1990. These are energy supply (11%), fossil fuel extraction (46%), industry (26%), agriculture (8%) and waste (28%). Since (with the exception of energy supply) greenhouse gas emissions in these sectors were projected to decrease, the real effort needed to make the required reductions is less than it appears. Taking this into account, the real reductions that these sectors would need to make from their projected 2010 emissions are much lower: for fossil fuel extraction (16%), industry (12%), agriculture (4%) and waste (13%). Emissions in the remaining sectors would need to be reduced from their projected levels in 2010 as follows: transport (4%) (assuming the full implementation of the voluntary agreement with the European, Japanese and Korean car manufacturers to reduce CO2 emissions from cars by 25% by 2008), households (6%), commercial and public services (15%). The overall weighted reduction remains at 8% from 1990. According to the least-cost allocation of sectoral objectives EU-wide, the compliance costs for the EU would be ~99 3.7 billion per annum for the period 2008-2012. 4 Compared to the baseline, the cost increase will be low for most sectors: the average electricity and steam generation costs would increase by 10%, energy costs for most energy demand sectors would increase by 5% at most. For example, costs for all household energy services and related equipment will increase by about ~99 56 per household, per year. The six most important ways for the EU to reach the Kyoto target in the most cost-effective manner are identified as being: • Decarbonisation of energy supply • Further switching from coal to gas. • More efficient generation of power (e.g. increasing the share of Combined Heat and Power). • Increase in the use of renewable energy (notably biomass and wind energy).

4 With the ACEA/JAMA/KAMA agreement incorporated in the baseline; full flexibility scenario, i.e. a European-wide allocation of least-cost objectives for different sectors. If the agreement was excluded from the baseline, the compliance costs would be E99 2.9 billion higher.

1204 • • • • •

Improvement of energy efficiency, particularly in industry, households (retrofitting) and the services sector. Further reduction of nitrous oxide from the adipic acid industry and implementation o f reduction options in the nitric acid industry. Reduction of methane emission in coal mining, the oil and natural gas system as well as waste and agriculture sectors. Reduction of fluorinated gases in specific applications, e.g. industrial processes, mobile air conditioning and commercial refrigeration. Energy efficiency improvement measures in the transport system. TABLE 1 DISTRIBUTION OF DIRECT EMISSIONS OF GREENHOUSE GASES IN 1990/1995" in the 2010 baseline and in the most cost-effective solution at the EU 15 level for 2010 where emissions are reduced by 8% compared to the 1990/1995 level. Mtonne C02-eq.

Emissions

Baseline

Cost-effective

Change

Change

1990/1995

emissions 2010

objective 2010

from 1990/1995

from baseline

Breakdown per gas C a r b o n dioxide o.w. energy related Methane Nitrous oxide HFCs PFCs

SF6 Total

3232 3068 462 376 52 10

3376 3193 380 317 84 25

3104 2922 345 282 54 19

-4% -5% -25% -25% 4% 90%

-8% -8% -9% - 11% -36% -24%

5

7

3

-40%

-57%

4138

4190

3807

-8%

-9%

1190 95 894

1206 61 759

1054 51 665

-11% -46% -26%

-13% - 16% - 12%

Breakdown per sector E n e r g y supply Non-CO2 fossil fuel Industry

Transport

753

984

946

26%

-4%

Households Services Agriculture Waste Total

447 176 417 166

445 200 398 137

420 170 382 119

4138

4190

3807

-6% -3% -8% -28% -8%

-6% - 15% -4% -13% -9%

RESULTS PER MEMBER STATE

TABLE 1 shows an EU-wide allocation of least-cost objectives for different sectors. If each Member State fulfils their target individually according to the Burden Sharing Agreement, the least-cost allocation (percentage change from 1990/1995 by sector) changes by coincidence so little, that the percentages in TABLE 1 would not alter significantly. However, the marginal abatement costs would increase from ~99 20/tCO2 eq. to ~99 42/tCO2 eq. (weighted EU average), and the total compliance cost of all EU Member States would increase from ~99 3.7 billion to ~99 7.5 billion per annum. The marginal abatement cost in each Member State would range from ~99 1/tCO2 eq. to over ~99 100/tCO2 eq. One way of interpreting the difference between the EU-wide allocation and the Member State based allocation approach is to identify this as a potential for EU-wide emission trading. 5 An alternative way to interpret the difference is a recommendation for the allocation of a specific number of permits to those sectors that would be given the possibility to participate in emission trading and specific objectives to those sectors that are subject to other policies and measures. These interpretations are useful to keep in mind when 5 In this case it would be (unrealistically) assumed that emission trading would be possible across all sectors and all greenhouse gases. Thus, EU-wide emission trade could save as much as half of EU Member States total compliance costs. In its proposal for a Directive for EU-wide emissions trading dated 23 October 2001 (see http://europa.eu.int/eur-lex/en/com/pdf/2001/e~h501PC0581.pd0 the European Commission suggests that in the first instance only CO2 from energy production, cement, iron and steel, paper and pulp would be included. This represents sligthly under half of the EU's greenhouse gas emissions

1205 using this study to identify policies and measures either at the EU level, i.e. in the Working Groups of the European Climate Change Programme, or in Member States.

CAVEATS OF THE STUDY A number of reasons may exist why not The role of non-CO2 greenhouse gases automatically the potentially cheapest identified Our analysis shows that the specific costs of allocation should be adopted. A few of them are emission reduction of non-CO2 greenhouse gases stipulated: (NCGG) are relatively low compared to energy /) some options may not be politically or related CO2. At EU-level implementation of the otherwise feasible e.g. due to strong lobby most cost-effective options results in a 22% group pressure or due to technical or social reduction objective for NGCC emissions, whereas difficulties, CO2 'only' need to be reduced by 4%. ii) choosing a longer time horizon than used In addition to the reduction options in industry in this study (2008-2012) could give rise to (adipic and nitric acid production), considerable a different allocation, since the longer-term reduction potentials can be found for methane potential of technological progress is taken emissions by the extraction, transport and into account. Such consideration of distribution of coal, oil and natural gas; emission allocations was beyond the scope of this reduction of HFCs in the cooling sector and in the study, production of foams. If the EU15 reduction iii) some options, such as fuel cells, have not objective of-8% were only to be realised by been included in this study because of their emission reductions of energy related CO2 technological limitations and expected development up to 2010, iv) it is possible that some mitigation options have been omitted, or that the potential of some measures has been over or under-estimated, v) due to the extensive coverage of all gases and due to the unavailability of detailed data in some sectors (e.g. aviation) it has not been possible to cover all sectors equally deeply, vi) due to paucity of data, land-use change and the corresponding changes in biological sinks have not been included, vii) for the purposes of this study, it was assumed that the EU would reach its target without using the flexible mechanisms. CONCLUSIONS The inventory of technical reduction potentials shows that significant emission reductions are achievable within the EU with state-of-the-art technologies: in 2010 up to levels that are 20% below the emission levels of 1990/1995. According to the analysis the main contribution should come from the energy sector and industry. A fuel shift from coal to natural gas is seen as the most important option with a significant reduction potential. The additional costs of this option are dependent on local market circumstances and the effects of the ongoing liberalization of the energy markets. The analysis shows that the electricity price for end-users would increase by about 5%. Reduction options in industry are a further improvement of energy efficiencies in industrial production processes and various end-of-pipe measures that reduce the emissions of N20 (e.g. in the nitric and adipic acid industry), PFCs and HFCs. From both the bottom-up and the topdown recta-analysis, it is evident even if the European Union complies with its Kyoto obligations without the Kyoto Mechanisms, the costs would be rather low (the marginal cost is about ~99 20-25/tCO2 eq). This study has clearly demonstrated that cost-effective implementation of the Kyoto Protocol calls for different sectors to make differing quantitative contributions to reduce greenhouse gas emissions. Allocating to every sector, or to even every actor within a sector, the same reduction objective may be perceived by some as "fair". However, using a different definition of equity where the "effort" of each sector is the same rather than the emission reduction percentage, differentiated sectoral reduction objectives would be identified.

1206 This study has shown that such differentiated reduction objectives are, from an economic perspective, highly desirable provided that the objectives are established in order to minimise costs to the society. Even if the analysis carried out in this study is comprehensive, it still represents only a 'snapshot' of the EU situation in 2000. Thus, the sector specific allocation of emission reduction objectives would change if, for instance economic growth changed substantially, if some sectors underwent rapid growth changes or if technological breakthroughs facilitated cheaper emission reduction options. Thus, the emission reduction objective allocations described in this study are likely to alter in the years to come and thus, consider these allocations in a dynamic context. In particular, the optimal allocation is likely to be different in the second commitment period (i.e. after 2012).

ACKNOWLEDGEMENT

Role of the study in the European Climate Change Programme (ECCP) The results of the study were the analytical underpinning of the European Climate Change Programme (http://europa,eu.int/comm /environment/climat/eccp.htm), which was launched in March 2000. As the results of the study were known to be significant, Environment Directorate-General organised seven stakeholder workshops to validate the assumptions and projections made in the study. These workshops, as well as the discussions in the ECCP working groups, helped to increase understanding of the reduction options and costs of complying with the Kyoto Protocol. With the study all working groups had a consistent basis for staring their work, and were able to see the links between their work. For instance, the three working groups on Energy Supply, Energy Consumption and Transport were frequently discussing same issues and could use the study as the common point of reference.

The authors want to thank the representatives and experts of industrial organisations, environmental organisation organisations, govemments and the European Commission involved in this study for their support, information and critical review on drafts of the study results. The authors wish to recognise that the study was made as a contract with the Environment Directorate-General of the European Commission.

REFERENCES Blok, K., De Jager, D., and Hendriks, C.A. (2001). Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change- Policy Maker's Summary, Ecofys Energy and Environment, AEA Technology, National Technical University of Athens, Utrecht. 2. Blok, K., De Jager, D., Hendriks, C.A., Kouvaritakis, N., and Mantzos, L. (2001) Comparison of 'Topdown' and 'Bottom-up' Analysis of Emission Reduction Opportunities for C02 in the European Union (Memorandum), Ecofys Energy and Environment / National Technical University of Athens, Utrecht. 3. Capros, P., Kouvartakis, N., and Mantzos, L. (2001) Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change. Top-down Analysis of Greenhouse Gas Emission Reduction Possibilities in the EU. National Technical University of Athens, Greece. 4. Hendriks, C.A., De Jager, D., Blok K., De Beer, J., Hamisch, J., Joosen, S., Phylipsen, D., Kersschemeeckers, M., Byers, C., Patel, M., Bates, J., Brand, C., Davison, P., Haworth, A., and Hill, N. (2001) Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change." Bottomup Analysis of Emission Reduction Potentials and Costs for Greenhouse Gases in the EU, Ecofys Energy and Environment and AEA Technology, Utrecht, The Netherlands. 5. More information on the GENESIS database can be found on http://www.ecofvs.com/climate/datasale_en.html. 6. All reports and supporting sector reports prepared can be downloaded from http://eur•pa.eu.int/c•mm/envir•nment/envec•/c•imate-change/sect•ra•-•bjectives.htm 1.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

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NEW RENEWABLE ENERGY INNOVATION PARTNERSHIPS: ELEMENTS OF A CONSTRUCTIVE CARBON STRATEGY FOR NORWAY'S INDUSTRY AND G O V E R N M E N T J. Buen, Research Fellow, Centre for Technology and Society, Norwegian University of Science and Technology E-mail: [email protected], Tel." +47 7359 8115, Fax: +47 7359 1327

ABSTRACT

Norway has two major problems. First, an enormous budget surplus, resulting from petroleum exports, which economists say could overheat the Norwegian economy if reinvested on the Norwegian mainland. Second, the dependence on the petroleum sector for continued economic growth. There is consensus that new industry needs to be developed in order to maintain Norwegians' standard of living when the petroleum revenues start dwindling. This paper argues that these problems might be ameliorated through solving a third problem, namely Norwegian industry's need to meet its obligations under the Kyoto Protocol. This, it argues, could be done in a manner that would stimulate creativity and new strategies among both greenhouse gas (GHG) emitters; the financial community; and new renewable energy (NRE) companies in Norway and key non-Annex 1 countries alike.

INTRODUCTION

Norwegian government and business should consider joining their counterparts in key non-Annex1 countries in NRE innovation partnerships to co-commercialise small-scale NRE technologies 1 in order to meet Norway's Kyoto commitments. The partnership projects could be financed through a new public-private carbon fund whose liquidity would be ensured by i) stimulating Norwegian companies to diversify the risk related to their emissions reductions efforts through investing in this fund to obtain necessary credits, and ii) reinvesting parts of the Petroleum Fund (NPF, see explanation below). The paper suggests the organisational setup of such NRE innovation partnerships. It also presents a number of arguments for why such partnerships could stimulate GHG emissions, innovation and economic development both in host countries and Norway.

A BRIDGE O V E R T R O U B L E D OIL

NRE innovation partnerships between Norway and selected non-Annex 1 countries may contribute towards solving the problem of building new, clean, energy-efficient and knowledge-intensive

1 This paper followsthe guidelines of the CDM Executive Board (EB) for small-scaleproject activities. They include renewable energyproject activities with maximumoutput capacity of
1208 Norwegian export industry while not overheating the Norwegian economy. Mainly because it is the second largest oil and gas exporter in the World, Norway has had substantial budget surpluses since the mid-1990s. Fearing the Norwegian economy would be overheated if the revenues were invested domestically, the Norwegian Parliament has decided that the bulk of this money be transferred to a petroleum fund that can only invest outside Norway. The size of the fund was about 85 billion USD in April, but is set to more than double within a few years. Critics say the NPF bereaves emerging Norwegian industry of necessary capital to grow internationally, and funds its competitors in other countries. This, they argue, slows the development of new, more knowledge-intensive and less energy-intensive industry that can secure continued economic growth after the petroleum era. A public-private carbon fund can help accommodate these differences, by making it possible to strengthen existing as well as emerging Norwegian industries by investing petroleum revenues outside Norway. This could be done by channelling a certain percentage of the NPF's profits to a new fund that invests in innovation partnerships involving new renewable energy companies in Non-Annex-1 countries as well as their counterparts from Norway and other Annex 1 countries (the private part of the funding will be discussed below). The volume of such a fund would be too limited to satisfy requirements for the diversion of risk if it were only to concentrate on Norwegian companies. Furthermore, relatively few Norwegian companies operate in this field so far, and their capacity for international operations is limited. Allowing non-Norwegian companies to participate would probably also improve the fund's legitimacy. Finally, the European Free Trade Agreement's (EFTA) Surveillance Authority (ESA) could easily interpret this as giving special privileges to Norwegian industry. Although the carbon fund cannot be directed at Norwegian investments only, a carbon fund established in Norway would make it much simpler for Norwegian NRE industry to obtain financing for co-operation projects with non-Annex 1 partners. If Norwegian companies whose projects are financed by the fund invest their project profits in Norway, this would contribute to the overheating of the Norwegian economy. However, this problem might partly be solved through a strategy inspired by the one Norwegian authorities used towards foreign petroleum companies investing in projects on the Norwegian continental shelf between 1979 and 1991 (the so-called "Technology Agreements", or "Goodwill Agreements", see e.g. [ 1, 2]). Companies participating in projects financed by the carbon fund would have to agree to invest a certain percentage of both initial carbon funding and subsequent sales revenue in R&D in the host country related to the project in question, in return for low taxes and fees and no extra costs placed on exports to Norway. This would not only secure the transfer of Norwegian companies' competencies to their host country counterparts - and vice v e r s a - but also minimise the risk of overheating the Norwegian economy. This could be further secured by demanding that the local operations be registered in the host country. Then, investment in production facilities, labour etc. would be under host country rather than Norwegian economic jurisdiction.

THE CASE FOR A CARBON FUND: OTHER ARGUMENTS

The NRE innovation partnership strategy provides many other benefits - both for Annex 1 countries like Norway, Clean Development Mechanism (CDM) host countries, and the global combat against climate change.

Supporting existing Norwegian industry NRE innovation partnerships may provide a legitimate, low-risk and low-cost way for Norwegian and other Annex 1 companies of meeting their emissions reductions obligations. In mid-June

1209 2002, the Norwegian Parliament accepted the Government's proposal to establish a domestic GHG emissions trading scheme in the period 2005-2007 in sectors not currently charged for their carbon dioxide (CO2) emissions, equalling about a third of Norway's GHG emissions [see e.g. 3,4,5,6,7]. In 2008, the domestic cap-and-trade system is to be extended to the sectors that are currently subject to a CO2 tax, and the cap of the system will be decided by Norway's Kyoto commitment (Norway is allowed to increase its GHG emissions by 1% from 1990 levels). As opposed to the proposal for an EU emissions trading scheme, companies can also use credits from e.g. the CDM to offset emissions. Norway's industry consumes more energy and raw materials than most other Annex 1 countries' industries. However, operations of companies likely to be targeted under the above-mentioned GHG trading system are often less GHG-intensive than their competitors' (of which many are located in non-Annex 1 countries), and the costs of in-house emissions reductions subsequently higher. These companies could therefore be interested in using the Kyoto mechanisms to fulfil their emissions reductions obligations while staying competitive. They will probably also be looking to diversify risk and minimise transaction costs associated with reducing emissions. One way of achieving this could be to transfer capital to a new public-private carbon fund, which invests in projects yielding GHG emissions reductions. The fund will be financially solid, as it is partly government-financed. It will build up competence on the project types in which it invests, and it will invest in several different projects, in countries exposed to different types of country risk) to diversify risk. The fund rather than the fundraisers will have the direct contact with project developers. The abatement costs will probably be low as well. The fight to emit 1 tonne of CO2 equivalent emissions (tCO2e) can be bought for 2-4,5 USD/tCO2e in existing international carbon markets. This is lower than projected costs for Norwegian companies wishing to reduce emissions domestically. International carbon prices might drop further towards 2008. Furthermore, GHG-intensive Norwegian industry - notably the processing i n d u s t r y - may have more trouble locating cheap domestic emissions reductions opportunities than many of its competitors. It has limited scope for reducing emissions from its own operations [3]. GHGintensive Norwegian industry cannot invest in cheap incremental reductions in coal power plants, as electric power in Norway is produced from cheap, clean hydropower. 2 As a growing number of sectors have been charged for their emissions of CO2 since 1991, many cheap abatement measures in these sectors are therefore already implemented.

Making legitimate emissions reductions The processing industry - joined by the Labour party, now experiencing a rare period in opposition - has questioned the environmental integrity of investing in cheap CDM projects abroad to reduce GHG emissions. Admittedly, some might raise their eyebrows if the industry were to insist on obtaining all its reductions through buying "hot air" (excess allowances) from Russia or Ukraine. However, let us say the processing industry makes all its reductions through investments in the proposed carbon fund. The chance that such initiatives are not sustainable is probably smaller than what would be the case for voluntary initiatives in the Norwegian processing industry. Climate projects in non-Annex 1 countries stimulate cleaner development. They reduce just as much emissions as the measures would do if implemented in Norway. As the climate problem is global, reducing emissions has the same effect in Ougadougou as in Oslo. It is hard to see why it is problematic that projects in non-Annex 1 countries yield cheap reductions. If so, it means that such projects can compete with investments in emissions reductions in Annex 1

2The constructionof large dams entails considerableGHG emissions, for example due to all the cement used, but this developmentphase is over in Norway.

1210 countries. Nothing is better. Thus, through the CDM, industry could make its reductions in a very legitimate manner, for a lower price: currently 2-4,5 USD/tCO2e.

Developing clean, knowledge-intensive Norwegian industries NRE innovation partnerships may stimulate the development of Norwegian competence on carbon funds and on the development and commercialisation of selected new renewable energy technologies; both would be valuable contributions to the global efforts to reduce greenhouse gas emissions as well. Much of the NRE competence could be gained from the non-Annex 1 countries selected; they might have more experience in technology development and diffusion than do the Norwegians. In a situation when world energy-related research is being reduced, this initiative also is remarkable in that it would devote resources to research in the host countries.

Creating technological niches NRE partnerships linked to the CDM would create technological niches with predictable and longterm framework conditions for Norwegian and host country companies co-commercialising new renewable energy technology, e.g. throughout the period until the end of the first Kyoto commitment period in 2012 (and possibly beyond). While Norway contributes a larger share of its GDP to development aid than almost any other country in the World, the use of these funds has not been guided by any particular energy innovation strategy. Developing NRE innovation partnerships may be a step towards utilising development aid as a technological niche where selected technologies are allowed to develop in relative protection from market pressures, often at locations where the willingness to pay for NRE technology solutions is high, while maintaining the key objectives of such aid. Consequently, producers can cut costs, due to organisational learning and economies of scale.

Enabling market access in host countries NRE partnerships could help NRE companies from Annex 1 countries gain a foothold in nonAnnex 1 countries' growing markets. Planning procedures and local opposition slows the deployment of such technologies in Annex 1 countries. Furthermore, markets for such technologies are projected to rise in non-Annex 1 countries, as they are currently on the verge of an explosive development of energy infrastructure. As many key non-Annex 1 countries have considerable experience in the production of NRE equipment, and their labour costs are much lower than countries like Norway, there are good reasons for establishing production facilities there instead of for example in Norway. Nevertheless, knowledge-intensive employment (administration, marketing, strategy etc.) related to the partnership would most probably grow in Norway as well, especially because the funding would come from Norway.

Stimulating commercialisation in host country NRE partnerships would stimulate NRE commercialisation in the non-Annex 1 countries selected. As mentioned above, many such countries have an existing R&D community and industrial base. However, they may lack the capital and knowledge of export markets necessary to gain market shares outside their home market. If and when this is the case, NRE innovation partnership could provide a channel to new markets.

1211

Signalling moral responsibility, improving legitimacy Reinvesting parts of the NPF in a fund investing in NRE partnership projects would signal that Norway acknowledges its particular moral responsibility in reducing greenhouse gas emissions, due to the fact that the economic welfare of its citizens is based on a result of indirect exports of greenhouse gases to other countries. Norway not only gets the revenue from extracting and exporting these natural resources, but also avoids most of the environmental hazards (other than global warming) occurring through their lifecycle, as its own energy consumption is mainly based on electricity from hydropower. Establishing such a new fund would also improve the NPF's legitimacy. Apart from the moral aspects mentioned above, the fund has also spurred critical press coverage because it has invested in nuclear power technology companies, weapons industries, and tobacco companies.

Improving further climate negotiations with non-Annex I countries The innovation partnership strategy could also potentially stimulate even more constructive negotiations with non-Annex 1 countries on the participation in a possible global GHG reduction regime after the period covered by the Kyoto Protocol (2013 onwards). The need for transfer of climate-friendly technologies has been a key requirement from non-Annex 1 countries in the climate negotiations so far. While this claim is legitimate, the requirement that Annex 1 countries let go of their patents is unrealistic. The closest one could get towards accommodating arguments that do not take private ownership into account, may be an innovation partnership strategy resembling the one suggested in this paper.

Supporting small-scale N R E CDM projects

A carbon fund supporting NRE innovation partnerships will strengthen the role of small-scale new renewable energy projects in the CDM. While work to reduce transaction costs of such projects is ongoing, many of the transaction costs of doing CDM projects are fixed costs. This favours larger projects generating more CERs. Furthermore, the project-based Kyoto mechanisms require the project developer to document that their project actually reduces emissions more than what would have been the case if the project had not been implemented. This is much more demanding for NRE technology companies than, say, coal power companies. The latter have considerable administrative capacity, and has few difficulties documenting that emissions from their own coalfired power plant go down when an efficient boiler replaces an inefficient one. A solar energy company typically has few, overworked employees. They have limited capacity to engage in trying to convince independent auditors and the CDM EB that people within the project's boundaries will actually replace their kerosene, diesel aggregates and paraffin with solar power.

CONCLUDING REMARKS Note that government involvement in the carbon fund would subsidise polluting industry and thus violate the polluter pays principle. However, the fund - including the industry's own contribution, at GHG market price - will pay a premium for high-quality GHG emissions reductions (as smallscale CDM projects have a higher carbon price than large-scale ones). This means industry will pay more than market price for these reductions. The fund will also finance industries competing with the traditional, polluting industries, not the traditional industries themselves. Furthermore, the CDM will likely not generate enough CERs to cover the needs of buyers (like Norway). If it does not, Norway would have to buy excess allowances (often denoted as "hot air") from Russia. This

1212 will be highly controversial. Russia has these allowances because its economy collapsed just after 1990 (the base year from which Annex 1 countries' Kyoto targets are counted). Thus, Norway can choose between generating credible CERs now to meet its Kyoto commitments, through a carbon fund giving limited subsidies to Norwegian industry, or meeting Kyoto commitments through buying highly controversial hot air from Russia later. The NPF currently operates according to financial, and not political, objectives. There are several examples of unsuccessful petroleum funds where financial and political objectives are not clearly separated. Therefore: if the proposed fund is established, it should have clear political objectives that should be given more emphasis than the financial ones. The NPF, on the other hand, should maintain its strictly financial focus. This paper has proposed that parts of the profits from the NPF be invested in a new public-private carbon fund with the clear political objective of financing small-scale new renewable energy projects in non-Annex 1 countries. Similarly, Norwegian companies that need to reduce their GHG emissions under Norway's domestic emissions trading regime could do so by contributing to this fund. This would improve the NPF's image; stimulate Norway's emerging energy technology companies; and give established Norwegian industry a low-risk, low-cost and legitimate way of reducing their emissions. The Norwegian economy would not be less overheated- and so would the globe.

REFERENCES

1. Blichner, L. (1995). Radical Change and Experimental Learning. PhD thesis. University of Bergen: Department of Administration and Organisational Science. Report 37. 2. Warhurst, A. (1988). Comparative Study of UK and Norwegian Science and Technology Policy for the Offshore Oil Industry, Science Policy Research Unit, Sussex University. 3. Norwegian Ministry of the Environment (2002). Norway's third national communication under the Framework Convention on Climate Change (12 July).. 4. Norwegian Ministry of the Environment (2002). Summary in English: Report No. 15 to the Storting (2001-2002) 5. Norwegian Ministry of the Environment (2001). Summary in English: Report No. 54 to the Storting (2000-2001) - "Norwegian climate policy". 6. Norwegian Ministry of the Environment (1999). A Quota System for Greenhouse Gases: A policy instrument for fulfilling Norway's emission reduction commitments under the Kyoto Protocol (summary of study) (17 December). 7. Point Carbon (2002). GHG emissions trading in Norway: Preparing for the global Kyoto market. URL: http://www.pointcarbon.com/article_view.php?id= 1889. 8. Norwegian Ministry of the Environment (2001). Agreement on the reduction of greenhouse gas emissions between the Ministry of Environment and the Aluminium Industry (1 November).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) 2003 Elsevier Science Ltd. All rights reserved

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OPTIMIZATION OF NATURAL-GAS UTILIZATION AT LANZHOU CITY IN CHINA Tetsuo TEZUKA and Cheng Min XIN Department of Socio-environmental Energy Science Graduate School of Energy Science Kyoto University Yoshida-honmachi Sakyo-ku, Kyoto 606-8501, Japan

ABSTRACT

The natural-gas transport pipeline project from Sebei (in Qinghai province) to Lanzhou was completed in June 2001 along with the West-Gas-To-East project. It is needed the cope with the increased demand for natural gas in Lanzhou city. The infrastructure design for energy supply in developing countries need not be the same as that for developed countries. Another important feature of investment in infrastructure is "irreversibility". Once the infrastructure is constructed, it is not easily removed. This means that the optimal design for energy supply and demand before an investment in infrastructure is often different from the one after the investment. This study investigates the strategy for infrastructure development in a city of a developing country, such as Lanzhou, by using a simplified linear programming model. The CDM (Clean Development Mechanism) incorporated in the Kyoto Protocol prompts investments from developed countries into projects that reduce carbon-dioxide emissions. The CDM project is designed to ensure carbondioxide emission reduction, compared with a baseline scenario (ie. that without the CDM project). The model simulation demonstrated that some CDM projects could prevent the implementation of certain projects that could realize greater emission reductions. This means that the effect of the CDM project should be carefully evaluated, despite the opinion that CDM procedures should be simplified so as to promote CDM project implementation.

INTRODUCTION

The West-Gas-to-East project is being executed as part of the development of China's Westem Regions. This project is to construct a pipeline with a length of 4,200 km to convey natural gas from Tarim Basin to Shanghai. The Chinese government has adopted a policy to promote natural gas consumption despite the presence of large coal reserves. Many other natural-gas pipeline projects have also been started, as well as the West-Gas-to-East project. The natural-gas transport pipeline project from Sebei (in Qinghai province) to Lanzhou was completed in June 2001 and permits Lanzhou city to increase its natural-gas demand. A city in a developing country has several problems in increasing natural-gas demand that include immature infrastructure, small population density and financial difficulties. From this viewpoint, the planning of infrastructure for energy supply in developing countries would be different from that in developed countries. Another important feature of investment in infrastructure is "irreversibility", which is closely related to the concept of "sunk cost" in the field of economics. Once infrastructure is constructed, it is not easily removed. This means that the optimal design for energy supply and demand before investment in infrastructure is usually different from that after the investment. This study investigates the optimal strategy for infrastructure

1214 development in a city of a developing country, such as Lanzhou City, by using a simple linear optimization model. A natural-gas-related project is often considered as a candidate for CDM (Clean Development Mechanism) projects. The CDM project is designed to reduce carbon dioxide emissions, compared with the baseline scenario, ie. the business-as-usual (BAU) scenario, without the CDM project. Therefore, this paper also discusses the problems of the investment in infrastructure under the CDM framework. The outline of this paper is as follows: in the next section, the features of Lanzhou City are summarized from the viewpoint of energy consumption. Then, the outline and the addtionality issue of CDM are briefly explained. As for the optimization model, only the essential points of the model structure are explained, as space for the paper is limited. The results of the model simulations show that comparison with the baseline figure is not sufficient for the CDM project to reduce efficiently future carbon dioxide emissions.

OVERVIEW OF LANZHOU CITY IN CHINA Lanzhou is the capital of Gansu province with five urban districts, i.e., Chenguan, Qilihe, Xigu, Anning and Honggu, and three suburban counties, i.e., Yongdeng, Yuzhong and Gaolan. The urban district of Lanzhou has the area of 1.6 thousand km 2 and the population of 2.6 million. There are five months of heating season every winter. The floor area in urban district is 49.83 million m 2 in 1999, and the total heating-floor area is 37.60 million m 2, of which 20.97 million m 2 has central-heating systems. The heat is supplied by two cogeneration plants and also by many boilers. The number of the boiler houses for heating is 1159, of which 0.17% are cogeneration plants, 31.8% are large central-heating boilers, while the remainder, 69%, are small boilers. In order to increase the energy efficiency of heating and to improve the air quality, the local government in Lanzhou is planning to increase the central-heating area. Lanzhou is known as an industrialized city with old heavy-industry plants. Due to the plants consuming a lot of coal, there is serious air pollution in the city area. According to the Air Quality Communiqu6 issued by large cities in China, Lanzhou always ranks as the most seriously polluted city. The major air pollutant in Lanzhou is the SPM (suspended Particulate matter). In 1999, the annual average TSP (Total Suspended Particles) is 0.66 mg/m 3 that is 2.3 times over the National Air Quality Standard II. The annual average of SO2 concentration is 0.066 mg/m 3, which is 9.6% over the National Air Quality Standard II. Therefore, Lanzhou is considered to be a good candidate for fuel switching from coal to natural gas.

CDM PROJECTS IN LANZHOU CITY

The CDM is a flexible mechanism defined in the Article 12 of the Kyoto Protocol for mitigating global warming problems. The CDM allows countries of Annex I parties (mostly developed countries) to acquire certified emission reductions (CERs) by undertaking greenhouse-gas mitigating project activities in countries of non-Annex I parties (mostly developing countries). The country that accepts CDM projects is called a "host country". A CDM project is requested to contribute to sustainable development in a host country. The CER is verified and certified by a designated operating entity. The CER can be used by the project investor (Annex I parties) to comply with its Quantified Emission Limitation and Reduction Commitment (QELRC), and also can be sold in the global and/or regional carbon-credit markets that are supposed to appear when the Kyoto Protocol comes into effect. The purposes of CDM are to assist Annex I parties in achieving compliance with their QELRC with least cost, and more importantly, to assist non-Annex I parties in achieving sustainable development for contributing to the ultimate objective of the Convention. Specifically, a certified CDM project should meet the following requisitions: (a) Voluntary participation approved by each Party involved; (b) Real, measurable and long-term benefits related to the mitigation of climate change; and (c) Reductions in greenhouse-gas emissions that are additional to any that would occur in the absence of the certified project activity. The last one is called "additionality".

1215 The concepts of additionality can be classified into "financial additionality" and "economic additionality". The former requires CDM projects to be additional to the ODA projects, for example, and the latter requires that there are some institutional, technological and/or economic barriers that prevent the project from being implemented. For validating a project as a CDM project, the amount of greenhouse-gas emissions owing to the project should at least be less than the baseline, that is, the amount of the greenhouse-gas emissions of the BAU scenario where the CDM project is assumed not to be implemented. As is easily understood, the baseline problem depends much on the system boundary for evaluation. In spite of this fact it is often said that the strict evaluation criteria results in much high transaction cost in CDM procedures and defeats good CDM projects. The idea of "small scale CDM" is partly due to this reason. However, it has a risk to adopt questionable projects that may increase greenhouse-gas emission as is demonstrated in the below. In the research project of[1 ] jointly executed by JST, Tsinghua University and Renmin University of China identified are the following four kinds of possible CDM projects for using natural gas in Lanzhou city: 1) Fuel conversion of old coal-fired cogeneration plant (such as Xigu cogeneration Plant, Lanzhou Second cogeneration Plant), 2) Fuel conversion of old coal-fired central-heating boilers, 3) Developing new type of heating system that transports natural gas to every building or house for individual heating, 4) Building new natural-gas-fired power plant (such as the planning in Hexi Region). It should be noted that the above-mentioned projects are closely related to the construction of infrastructure. The energy demand per capita in Lanzhou still remains much lower than that of Hokkaido in Japan with the same range of temperature of Lanzhou. This fact means there is much greater freedom in designing the infrastructure in Lanzhou, as well as other cities in developing countries.

S I M P L I F I E D ENERGY-SUPPLY O P T I M I Z A T I O N M O D E L As explained above, the purpose of this paper is to clarify the effect of irreversibility in constructing infrastructure. We developed, therefore, a simplified linear-optimization model with the features as in the following: 1) Electricity, natural gas and hot water are treated as energy carriers, 2) Distribution of energy consumers in a city are taken into account, 3) Locations of energy conversion plants can be decided through simulation, 4) Simulation results can be optimized from the viewpoints of economy and environmental load, i.e., CO2. The basic energy flow of the model is shown in Figure 1. The simplified city structure is shown in Figure 2. Cogeneration plants are classified into three categories: large-scaled plant, medium-scaled plant and smallscaled plant. As is shown in Figure 2, each type of plant has its own location. The optimization procedures decide the capacity of each type of plant. As the model is of linear type, the energy transportation cost is represented as a linear function of the amount of energy transported. In this paper, the details of the model are not explained due to space limitations. Please refer to the reference [2] for the detailed equations and parameters of the model.

SIMULATION RESULTS The important feature of using the linear optimization model is the sensitivity analysis. In this study, the investment costs of gas-pipelines and large-scale cogeneration plants are selected as the parameters for the sensitivity analysis. Let us suppose two different cases. One is the case that the gas pipeline has already installed in the city, and the other is the case where large-scaled cogeneration plants have already been constructed. In optimizing the model, with some infrastructure, the investment cost for that already installed need not be included in the cost calculation. There can be various levels of installation of infrastructure. Therefore, the parameters are changed in a range from 0 to 2 in the analysis of this study.

1216 The value used for parameter normalization is less important in this simulation study. The smaller the normalized value of the parameter, the greater the corresponding infrastructure for exploitation. The simulation results are shown in Figure 3 and 4 respectively. In Figure 3, region A is the combination of small- and medium-scale cogeneration plants, region B is of small- and large-scale plants, and region C is of boilers and large-scale plants. It is important that the amount of CO2 emission of the cost-minimizing scenario varies with the value of parameter. If gas-pipelines are completely installed, the CO2 emission may increase, as distributed cogeneration plants cannot be installed because of economic reasons. As for Figure 4, region A is a combination of boilers and large-scaled cogeneration plants, region B is of small- and large-scale plants, and in region C, the share of small-scale plants increases. The construction of largescale cogeneration plants prevents small-scale cogeneration plants from being installed, because of economic factors, as in Figure 3. This paradox is due mainly to the difference in criteria of the CDM project and the city planning. The criterion of the CDM project is the amount of CO2 emission, and that of city planning is the total cost. It should be noted that the cost-minimizing scenario may change after some infrastructure has been installed, and that the validated CDM project may increase the amount of CO2 emission, even if the CDM project is not on such a large scale.

CONCLUSIONS In this study, the problems of installing infrastructure in developing countries are demonstrated, based on simulations of the simplified linear optimization model. As is explained at the beginning, infrastructure investment has the feature of irreversibility. Conversely, the CDM project that decreases the amount of CO2 emission below the baseline may actually increase the amount of CO2 emission. This is because the optimal path of the infrastructure investment changes after some infrastructure has been installed. Therefore, the planning of infrastructure should be conducted carefully from the long-term viewpoint, even if projects are small, such as small-scale CDM projects. As a future study, a dynamic path to a developing society has to be investigated for cities in developing countries. This study was executed partly supported by the project, "Towards an Optimal Framework for the Preservation of Global Environment", the Core Research for Evolutional Science and Technology (CREST) of Japan Science and Technology Corporation (JST). We appreciate the valuable discussions in the project meeting with the members of CREST project. We are also grateful to Professor Ji Zou of Renmin University of China for his contribution to the CDM research in Lanzhou city.

REFERENCES 1.

2.

Zou, J., et al. (2002). Feasibility Study on Creating Project in the Context of Introducing Natural Gas in China, Research Report of "Towards an Optimal Framework for the Preservation of Global Environment", Japan Science and Technology Corporation (JST). XIN, C. M. (2002). Optimization of Natural Gas Use in Lanzhou city of China, Master Thesis of Graduate School of Energy Science, Kyoto University.

1217

Energy Conversion

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electric power heat supply

ill ~'i ~ c°°k~g I

i

Figure 1: Energyflow in the optimizationmodel.

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Area A

ower r smission

and distribution ~ Pressure ~ ' .................................. L ~ Consumer ' ~ %g~.

m A

Large power plant Middle power plant

Middle ~ ~ Preslure ~ / / / I ~ Low Pressure

Figure 2: The simplified city model.

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1218

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,

,

,

,

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45

7.6 r I totalannualc°st

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F i g u r e 4: Simulation results o f sensitivity analysis taking the investment cost of large-scaled cogeneration plant as a parameter.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1219

POTENTIAL FOR CO-UTILISATION OF COAL WITH OTHER FUELS TO REDUCE GREENHOUSE GAS EMISSIONS I. M. Smith and J. M. Topper IEA Clean Coal Centre Gemini House 10-18 Putney Hill London SW15 6AA UK

ABSTRACT Energy reserves, price and security of supply issues are discussed in the context of the prospects for coal and policies to reduce greenhouse gas (GHG) emissions. Projections indicate that coal will remain a major source of energy for the foreseeable future with most of the demand growth in developing countries. Currently available power generating technologies, deploying coal with other fuels (natural gas, biomass and refuse derived fuels) are examined. These include pulverised coal-fired boilers, cyclone boilers, circulating fluidised bed combustion, and integrated gasification combined cycle. Examples of successful, partial substitution of coal by other fuels in power stations are highlighted, including the GHG emissions reductions achieved as well as the costs where available. Among various options for use of coal with other fuels, hybrid gasification and parallel cofiring of coal with biomass and natural gas appear to have the greatest potential to reduce GHG emissions. Much may also be achieved by cofiring, reburning and repowering with gas turbines. The best method differs between different power systems. Co-utilisation of biomass with coal is a least cost option to reduce GHG emissions where the fuel prices are comparable, usually due to subsidies or taxes. The role of biomass is likely to increase in future due to greater use of subsidies, carbon taxes and emissions trading. The CDM, JI mechanisms as well as emissions trading, outlined in the Kyoto Protocol, should provide opportunities for clean coal technology transfer and diffusion. This will sometimes be associated with co-utilisation, particularly with biomass.

INTRODUCTION

The prospects for coal use in power generation have always been affected by energy reserves, price and security of supply of fuels in different regions. Environmental issues are playing an increasingly important role. In 1997, the Kyoto protocol marked a political decision to take steps to mitigate climate change by reducing GHG emissions. Coal is the most carbon intensive of all fossil fuels and is therefore most affected. In the long term only CO2 capture and storage could offer a means to approach zero emissions. Under current conditions, the greatest potential for economic GHG emissions reduction from coal-fired power

1220 generation is by co-utilisation with other, less carbon intensive fuels, especially natural gas or biomass.

COAL PROSPECTS AND THE K Y O T O MECHANISMS Major coal reserves are to be found in north America, Europe, the former Soviet Union and Asia/Pacific. By contrast, almost two-thirds of the world oil reserves are concentrated in the Middle East and more than two thirds of the world gas reserves are in the Middle East and the republics of the former Soviet Union. Coal has mainly been used for domestic consumption and is regarded as a strategic source of energy, protecting many countries from over-dependance on energy imports. However world coal trade is increasing [ 1]. Coal supplies nearly one quarter of the global primary energy which totalled 413 EJ in 1999. Its most direct competitors are oil (36%), gas (20%), nuclear (7%) and the renewables (14%) including biomass. Coal is the largest single source of electricity in the world at 38% in 1999 [2] and will be used increasingly in this sector. Power generation is projected to account for almost 70% of the coal used in 2020. Growth in coal use in OECD countries is small while China and India account for nearly 70% of the incremental demand to 2020. The primary focus of oil is in the transport sector. The share of gas in electricity production is growing. Biomass is currently only making a small contribution to electricity generation but combustible renewables and waste are projected to provide 295 TWh electricity generation in 2020. This could be much higher given strong government support [3]. Policies to reduce GHG emissions are expected to be applicable in the short term in developed countries. Most new coal-fred power plant will be built in developing countries, mainly in Asia. Hence there is potential to reduce GHG emissions from coal by deploying best available technologies. The project-based Clean Development Mechanism (CDM) and Joint Implementation (JI) provide opportunities for clean coal technology transfer and diffusion [4,5].

COAL W I T H NATURAL GAS The CO2 reduction is generally a function of the reduced emission factor for natural gas (15 g/MJ LHV) compared to coal (26 ~ M J LHV) [6]. Cofiring of coal and natural gas is used at up to 30% natural gas and up to 100% at some PC boilers to maximise fuel flexibility [7]. Rebuming appears to be optimum at 20 th% in PC plants and at 23 th% in cyclone boilers with a small loss in efficiency [8,9]. Repowering by integration of a gas turbine can involve substitution of coal by up to 100% natural gas in PC plant, enhancing efficiency substantially [ 10]. Tests at up to 10 th% were successful on pilot scale CFBC [ 11 ]. Cofiring natural gas with coal may present a useful measure to meet emission targets for both CO2 and SO2 with flexibility [7]. The cost of electricity is largely determined by the price differential between coal and natural gas. Simulation work undertaken from 1996-1998 indicated that a PC plant became competitive with GTCC when the price of natural gas was double the price of coal [12]. Use of natural gas as a rebum fuel may be economically justifiable for NOx reduction and CO2 reduction is an ancillary benefit. For example, 20 th% natural gas reburn at the 158 MWe, wall-fired boiler, Cherokee Unit 3, CO, USA, and on the larger, 600 MWe units at Longannet, Scotland, UK, achieves 50-60% NOx reductions with 8-9% CO2 reduction [8,9,13]. The power generating capacity worldwide which is not using NOx control amounts to 483 GWe. There appears to be considerable potential for reducing CO2 emissions by introducing reburn for NOx reduction more widely [ 14].

1221 Partial or parallel repowering includes several ways of coupling a gas turbine to the existing coal boiler. This can reduce CO2 emissions by around 20-50% by increasing the net plant efficiency and by substituting natural gas for some of the coal [7,15,16]. The fuel flexibility is an asset in view of the fluctuations in the price of natural gas. Also, the gas turbines can be integrated so as to improve the part load efficiency and hence maintain CO2 reductions at part load [ 17]. Some repowering options are compared in Table 1, based on a survey of European power station data [ 18]. The full repowering option involves far more capital expenditure than the partial repowering. The cost of CO2 reduction depends largely on the price of gas relative to coal but the difference between full repowering with natural gas and hot windbox repowering is marginal at the higher gas price. In this case the levelised cost of repowering with 100% natural gas exceeds that of new clean coal technologies. Similar results in favour of partial repowering were found in the USA using a much higher price differential with coal at 0.5 US$/GJ and natural gas at 4 US$/GJ [ 19].

TABLE 1 CO2 REDUCTION AND COST OF VARIOUS REPOWERING OPTION IN EUROPE [18] C02 reduction, %

Capital cost, US$/kWe

Levelised cost, Cost of CO2 reduction, Base (+25% gas price) Base (+25% gas price) US$/MWh US$/tCO2

24.3 (24.3) Sub-critical PC + FGD 17 1185 36.8 (36.8) 83 (83) New clean coal technology 58 630 33.3 (40.5) 18 (32) Natural gas combined cycle 53 500 38.4 (46.4) 31 (48) Gas turbine + HRSG (100% natural gas) Hot windbox repowering 22 200 31.0 (34.9) 39 (54) (32% natural ~as) At 6% real rate of interest, capital costs for new capacity based on a depreciation time of 25 y; levelised costs assume a remaining life of 15 y for refurbished plant; 68% load factor for base load plant. Price of coal=1.67 US$/GJ, price of natural gas=3.34 US$/GJ.

COAL W I T H BIOMASS Burning of biomass releases about 30 gC/MJ LHV [6] but the emissions are compensated by uptake of carbon during growth. Hence biomass is regarded as carbon neutral. Current use ofbiomass in smaller plant, for example in the USA, has disadvantages. Such a use of biomass with its lower fuel heat content make existing biomass-fired power stations inefficient with heat rates of 14-21 MJ/kWh or even higher. By contrast coal-fired power stations have heat rates in the range 9.5-13.7 MJ/kWh. Some herbaceous biomass, for example switch grass, increases slagging and fouling. Fly ash from biomass combustion does not always meet fly ash standards, reducing its marketability [20]. In Europe, the contribution of biomass and waste to power production in coal-fired power stations is increasing rapidly due to both political and economic incentives. The capital costs of biomass cofiring retrofits at coal-fired power stations are competitive with new construction of biomass only plant. The substitution rates are summarised for different coal technologies in Table 2 [ 14]. PC Plant The 600 MWe Gelderland power station in the Netherlands includes 20 MWe which is supplied by wood. The powdered wood is fed into four special burners. A total of 60 kt/y of demolition wood and wood waste

1222 substitutes for 45 kt/y of coal and reduces CO2 emissions by 110 kt/y. There are also CH4 emissions reduction due to avoidance of landfilling the waste wood and a gain in efficiency compared to burning the wood in modem waste incinerators which have an overall electrical efficiency of only 21% [21,22]. The high potassium and chlorine content of straw often causes slagging and fouling at high substitution rates. Pretreatment is under investigation in Denmark, for example by pyrolysis and extraction of the potassium and chlorine from the char by water. The increased cost due to pretreatment would be offset by the gain in not having to landfill the fly ash produced from cofiring raw straw [23]. An example in the USA [24] involves shredding and pulverising wheat straw and alfalfa stems to a size suitable for cofiring with pulverised coal. The rate of use of biomass may be restricted due to fly ash quality. In the Netherlands, the current limit for cofiring is <10 wt% ofbiomass. However, research is in progress to allow evaluation of ash quality based on technical parameters, rather than on fuel. Applications for ashes from high percentages of cofiring of biomass with coal are also under investigation [25]. Meanwhile, indirect co-utilisation allows greater fuel substitution without impairing ash quality. For example, the Kymij~rvi cogeneration plant, jointly owned by the city of Lahti and Imatran Voima Oy in Finland, has been used since January 1998 to demonstrate direct gasification of wet biomass and refuse derived fuel (RDF) using a CFB gasification system. The hot, low heating value gas product is used in the existing PC boiler. Typically, when the fuel moisture is about 50%, the heat value of the gas is only about 2.2 MJ/m 3. There is an estimated 300 GWh/y of various types of biomass and waste within the economic transport distance of 30-80 km to substitute for about 15% of the fuels burned in the main boiler. This could reduce coal consumption by 30% with a CO2 reduction of 10% [26,27].

Cyclone Boilers The higher heating values of other fuels improve c0firing of wood and coal on cyclone boilers in the USA. Some efficiency .losses due to high moisture content of the wood may be offset by adding tyre derived fuel (TDF). At the 188 MWe Willow Island boiler 2, it is estimated that at least 10 wt% wood waste and about 10 wt% TDF will be fired [28]. Petroleum coke and wood waste were cofired with coal in a 160 MWe boiler at the Bailly Generating Station. Cofiring wood waste with coal reduced CO2 emissions typically by about 3 t for each tonne ofbiomass burned. This included avoidance of CH4 which would be emitted atter landfilling the wood waste. The optimum mixture was coal with 7.5% wood waste and 22.5% petroleum coke, estimated to decrease CO2 emissions by >136 kt/y [29]. CFBC

As shown in Table 2, the highest biomass substitution rates have been achieved in CFBC, giving 50% CO2 reduction. However, elevated N20 emissions with a high CO2-e in FBC technology would detract from the overall reduction in GHG emissions. Also, CFBC has net plant efficiencies which are no better than those of subcritical PC combustion. Both straw and wood waste are being used successfully at CFBC in Europe [ 14].

1223

Technology

TABLE 2 SUMMARY OF RATE OF SUCCESFUL SUBSTITUTION BY OTHER FUELS (th%) PC Cyclone CFBC IGCC

Natural gas cofiring and duel firing rebum repowering Wood biomass added to coal pile separate injection rebum gasification, cofiring product gas

up to 100 10-20 up to 100 up to 10 up to 20 20 3-5

22-23

up to 15

50

10

15

IGCC The technical feasibility of co-gasification in a purely coal-fired IGCC process is still uncertain. Cogasification of about 10 th% willow biomass in an oxygen blown, entrained flow type of IGCC at Puertollano, Spain is estimated to reduce the net electrical efficiency by around two percentage points. This loss may be reduced after further optimisation and integration. The CO2 emissions are reduced by 129159 kt/year depending on the kind of co-gasification concept applied. The costs per tonne of CO2 avoided are about 25-66 US$/t, comparing favourably with CO2 removal technologies at 34-103 US$/t [30].

CONCLUSIONS

Coal has been regarded as a strategic source of energy, protecting many countries from over-dependence on energy imports. According to projections, coal is expected to continue to be a major source of energy for the foreseeable future with most of the demand growth in developing countries. Co-utilisation of natural gas and/or biomass with coal is an effective means of reducing CO2 emissions. The reduction is approximately in proportion to the emission factor for natural gas and biomass is regarded as carbon neutral. There is an added CO2 reduction for repowering with a gas turbine through increased plant efficiency. Fuel flexibility is an advantage for fluctuating natural gas prices. Burning biomass in a large coalfired power station is far more efficient than in a modern waste incinerator or in small, inefficient boilers. Substitution of waste wood for coal also avoids the formation of CH4 in landfills. Hybrid gasification and parallel cofiring of coal with biomass and natural gas appear to have the greatest potential to reduce GHG emissions from coal-fired power stations. Much may also be achieved by cofiring, reburning and repowering with gas turbines. The best method differs between different power systems. Coutilisation of biomass with coal is a least cost option to reduce GHG emissions where the fuel prices are comparable, usually due to subsidies or taxes. More use of subsidies, carbon taxes and emissions trading is likely to increase the role ofbiomass in future.

REFERENCES

Grimston, C. G. (1999). Coal as an energy source, lEA CCC, London, UK. lEA (2001). Energy balances of non-OECD countries 1998-1999. OECD/IEA, Paris, France. lEA (2000). World Energy Outlook 2000. OECD/IEA, Paris, France. Rousaki, K. (2001). Market mechanisms for greenhouse gas emissions reduction, lEA CCC, London, UK.

1224

5. 6. 7. 8. 9. 10. 11.

12.

13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24.

25. 26. 27. 28.

29. 30.

Vemon, J. L. (2002). Strategy for coal to reduce greenhouse gas emissions by technology transfer to developing countries, lEA CCC, London, UK. lEA (1999). C02 emissions from fuel combustion 1971-1997. OECD/IEA, Paris, France. Doig, A. and Morrison, G. F. (1997). The use of natural gas in coal-fired boilers, lEA CCC, London, UK. Fernando, R. (2000). Hybrid plants for coal~gasfiring, lEA CCC, London, UK. Golland, E. S., Macphail, J. and Mainini, F. G. (1998) Modern Power Systems 18, 79. Dalton, S. (2000). In: Coal - the future. 12th international conference on coal research, pp. 1-11, South African Institute of Mining and Metallurgy, Johannesburg, South Africa. Lu, Y., Anthony, E. J., and Perto, F. (1999). In: Circulatingfluidized bed technology VI. proceedings of the 6th international conference on circulating fluidized beds, and exhibition: fundamentals, systems, applications, pp. 639-645, DECHEMA Deutsche Gesellschaft ~ r Chemisches Apparatewesen, Chemische Technik und Biotechnologie e.V., Frankfurt am Main, Germany. Evans, R. H., Ye, H., Millar, S., McMullan, J. T., Williams, B. C., McCahey, S., Campbell, P. E. and Mcllveen-Wright, D. R. (2000). In: Joule III Programme Clean Coal Technology R&D, pp. 383-412, EC Directorate-General for Science, Research and Development, Brussels, Belgium. DTI (2000). Best practice brochure: Longannet power station. DTI, London, UK. Smith, I. M. and Rousaki. K. (2002). Prospects for co-utilisation of coal with other fuels - greenhouse gas emissions reduction, lEA Coal Research, London, UK. van der Linden, S., Fetescu, M. and Burkett, J. (1997). In: American Power Conference 59th annual meeting of the American power conference, pp. 1211-1216, Illinois Institute of Technology, Chicago, IL, USA. Chodkiewicz, R., Porochnicki, J. and Swirski, J. (1999). In: Power-Gen Europe '99, PennWell UK, Harold Wood, UK. Kotschenreuther, H., and Miermann, L. (2001) VGB PowerTech 81, 3. Eurelectric (2000). C02 reduction: some technology and investment options and estimated costs. Union of the Electricity Industry, Brussels, Belgium. Simbeck, D. R. and McDonald, M. (2001). Electric Utilities Environmental Conference, SFA Pacific, Mountain View, CA, USA. Paul, D. and Maronde, C. (2001). In: Proceedings of the 26th international conference on coal utilization and fuel systems, pp. 215-226, Coal and Slurry Technology Association, Washington, DC, USA. Penninks, F. W. M. (2000). In: Proceedings of the EU seminar on the use of coal in mixture with wastes and residues 11, pp. 45-50 BEO Projektrager Biologie, Energie, Umwelt, J~lich, Germany. Venendaal, R. and van Haren, P. (1999). Learning from experiences with alternative fuels in electric power generating plants. CADDET, Sittard, The Netherlands. Jensen, P. A., Sander, B., and Dam-Johansen (1999). In: Joule IIIProgramme Clean Coal Technology R&D, pp. 695-730, EC Directorate-General for Research, Brussels, Belgium. Zygarlicke, C. J., Eylands, K. E., McCollor, D. P., Musich, M. A. and Toman, D. L. (2000). In: Proceedings of the 25th international conference on coal utilization and fuel systems, pp. 115-126, Coal and Slurry Technology Association, Washington, DC, USA. Meij, R. (2002). KEMA, Amhem, The Netherlands, personal communication. Nieminen, J. (1999). In: Power production from biomass III. Gasification and pyrolysis R and D and D for industry, pp. 184-194, VTT Technical Research Centre of Finland, Espoo, Finland. Palonen, J., Nieminen, J. and Berg, E. (1998) Modern Power Systems, 18, 37,39,41. Plasynski, S. I., Goldberg, P. M. and Chen, Z-Y. (2001). In: Proceedings of the 26th international conference on coal utilization and fuel systems, pp. 203-214, Coal and Slurry Technology Association, Washington, DC, USA. Tillman, D. A., Hughes, E. and Plasynski, S. (1999). In: Proceedings of the sixteenth annual international Pittsburgh coal conference, University of Pittsburgh, Pittsburgh, PA, USA. van Ree, R., Korbee, R., de Smidt, R. P. and Jansen, D. (2000). In: Joule 111 Programme Clean Coal Technology R&D, pp. 75-112, EC Directorate-General for Science, Research and Development, Brussels, Belgium.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1225

C O M M E R C I A L VIABILITY OF SPACE SOLAR POWER SYSTEM AS A CDM PROJECT Iwao Matsuoka I, Tetsuo Tezuka ~ and Takamitsu Sawa 2 1 Graduate School of Energy Science, Kyoto University, Yoshida-honmachi Sakyo-ku, Kyoto 606-8501, Japan 2 Institute of Economic Research, Kyoto University, Yoshida-honmachi Sakyo-ku, Kyoto 606-8501, Japan

ABSTRACT

The purpose of this study is to examine the commercial viability of the Space Solar Power System (SSPS). The SSPS generates electric power during Earth's orbit, and sends the power to the earth by a microwave beam. Firstly, we compared the cost of the SSPS with that of photovoltaic power plant on the ground. In this study, the power-generation cost of the SSPS is estimated, based on a detailed model. We also showed that the cost of the SSPS is in the range of that of photovoltaic power generation systems, with electric power storage. Secondly, we evaluated the feasibility of the SSPS as a CDM project. The Clean Development Mechanism (CDM) is one of the flexible measures referred to as the Kyoto Mechanism, that allows for the international transfer of CO2 emission permits. If an antenna for receiving the microwave beam, a rectenna, is set up in a country neighboring Japan, the SSPS can export the electric power to the country. The framework of CDM is considered applicable to this case. In this study, application of CDM to the SSPS project means that Japan can use carbon credits by erecting the rectenna in China. The effect of CDM on the generation cost is examined, assuming that the SSPS substitutes the coal-fired power plants in China. As a result, the SSPS can be commercially viable under the very restricted but possible conditions. INTRODUCTION

The Kyoto Protocol was adopted at the 3 rd Conference of Parties (COP3) of the United Nations Framework Convention on Climate Change (UNFCCC) in Kyoto in December 1997. The protocol includes an article that requires the 41 industrialized countries to reduce the average amount of emissions of CO2 and other greenhouse gases by at least 5% below the 1990 level during the period from 2008 to 2012. In 2001, we reached an agreement about its framework at COP7. In such a situation, the SSPS has been attracting much attention as a photovoltaic power generation system (PV system) that is not affected by the weather. In the United States, the Department of Energy (DOE) and National Aeronautics and Space Administration (NASA) re-started the study of the SSPS in 1996, not for the forthcoming energy crisis, but for reducing carbon dioxide (CO2) emission [1]. In Japan, the Ministry of Economy, Trade and Industry (METI) started the feasibility study of SSPS in 2000. WHAT IS THE SSPS?

The SSPS comprises three components: an orbiting platform carrying solar panels, a microwave transmission system that sends the generated electricity to the earth, and a rectenna, that is, a

1226 power-receiving antenna that collects the transmitted microwave on the ground and converts it to AC electric power. The study of SSPS started in 1969 in the U.S. when the concept of the SSPS was set up [2]. Although NASA/DOE created a concept model called the "Reference Model" in 1979, the study was stopped because of the technological difficulties and the influence of Reaganomics in early 1980's. After a 20 year break, the U.S. government re-started the study in 1995 and arranged over 30 concept models called the "Fresh Look Study" in 1997 [ 1]. This study extended the study of the SSPS from NASA. The U.S. congress provided a budget for the study of the SSPS, and in 2002, the National Science Foundation joined the study, in co-operation with NASA. In Japan, the study about the SSPS has begun recently. For example, the committee composed of the National Space Development Agency of Japan (NASDA)/Mitsubishi Research Institute (MRI) has discussed it since 1998, and METI has created an exploratory Committee for the feasibility study in 2000. Each committee arranged the original concepts of the SSPS. However, the studies in Japan are smaller than the studies in the U.S. and are focused on only on the project of each committee, unlike the projects based on national policies such as space development policies or national energy policies. The SSPS has several advantages. Firstly, no generator is needed on the ground and electric power can be obtained independently of the weather. In particular, in installing the generator on the geosynchronous earth orbit (GEO), the SSPS will be able to generate the electricity and send it stably at all times, except during the Earth's eclipse. Secondly, the SSPS emits no CO2 in generating power. The Life-cycle CO2 of the SSPS almost equals that of a nuclear power plant [3]. Moreover, it is possible to receive electricity at any place on the Earth, simply by setting up the rectenna. The Clean Development Mechanism (CDM), one of the flexible measures included in the Kyoto Protocol, permits industrialized countries to count the reduction of CO2 emissions through their investment in developing countries, as part of their own CO2 emissions reductions. If the rectenna is set up in a developing country (host country), an industrialized country can reduce CO2 emissions by substituting the electricity generated by fossil fuels with the electricity transmitted from the SSPS. In this Mechanism, the SSPS has one more advantage above nuclear power plants as nuclear power is on the negative list of the CDM project. COST ANALYSIS OF THE SSPS

Comparison of the SSPS with the PV system on the ground We compared the generation cost of the SSPS with that of the PV system on the ground, in order to show the necessity of placing the solar cells into the Earth orbit. Before this comparison, we produced the cost model of the SSPS based on the Grand-Design model by New Energy and Industrial Technology Development Organization (NEDO)/MRI in 1993 [4]. The procedures of the cost estimation of the SSPS are as follows [5,6]. TABLE 1 ASSUMPTIONS AND RESULTS OF ESTIMATION COST OF THE SSPS orbit net capacity* solar panels operating periods ETO (case # 1) ETO (case #2) generation costs case#1 case#2

assumptions

GEO 1GW always faced to the sun basically same as the Grand-Design 30 years 2nd generation rocket 3rd generation rocket 1/100 the cost of the current rocket marginal cost :18.0 yen/kWh 23.3 yen/kWh marginal cost: 10.8 yen/kWh 15.4 yen/kWh * : the maximum power abailable for consumer.

1227 Firstly, we estimated the electricity generation cost of the SSPS without taking the carbon credits into account. In this study, we selected two cases that are different in the model of the SSPS. The model of case# 1 is almost the same as the model in the Grand-Design. Case#2 is the low-cost case where we modified the cost data according to the newest concept for Earth-To-Orbit (ETO) transportation, "the 3rd generation rocket". Table 1 shows the estimation results about the generation cost of the SSPS. In case#l, the generation cost of the SSPS is estimated to be 23.3 yen/kWh and the marginal generation cost that is an additional cost for increasing the capacity is estimated 18.0 yen/kWh. And in the case#2 the generation cost is about 40 percent less than the cost in the case# 1. It is because the transmission cost gets more inexpensive in case#2. Secondly, we estimated the cost of the PV system on the ground. We assume that the net capacity is 1GW, the same as the net capacity of the SSPS. It is difficult to compare the SSPS with the PV system on the ground since their output characteristics are so different; the SSPS is a power plant for base-load electricity. However, the PV system on the ground generates electricity only in the daytime. Therefore, we assumed two cases: in case#A, we evaluated total generation costs. This means that the output fluctuation of the PV system on the ground is not taken into account. In case#B, the output of the PV system on the ground is assumed to be leveled by the electric power storages. In this study, the lead battery and the pumped storage are assumed to be used. We assumed that the PV system with the storage system could supply electricity at the level of 24GWh per day when it is sunny. It means that the PV system on the ground should generate electricity for both day and nighttime supply. Figure 1 shows the basic concept used to estimate the net capacity of the PV system on the ground. Table 2 [7,8] shows the details of the estimations. Table 3 compares the results. These results show that the SSPS will not compete with the PV system on the ground if the output fluctuation of the PV system is not evaluated. If the PV system is obliged to supply stably constant power, the cost of the SSPS is in the range of that of the PV system, which means that the SSPS can be considered competitive with the PV system on the ground from the viewpoint of economy.

'l .....

X GW

A + C :the electricity generated in the daytime B = C × total efficiency of the storage Y=
Icl Y GW

IAI

daythne

1

ni~tt~

Figure 1: Basic concept to estimate the net capacity of the PV system with the storage.

1228 TABLE 2 ASSUMPTIONS IN ESTIMATING THE COST OF THE PV SYSTEM ON THE GROUND power plant

lead battery pumped hydro

solar cell cost latitude rate of sunshine lifetime constraction cost

same to the SSPS 35 degree 12% 30 years same to the rectenna and values calculated from the data of constraction cost of the current solar cell

storage capacity total efficiency lifetime total efficiency lifetime

42GWh 25% 15 years 25% 40 years

TABLE 3 COMPARISON RESULTS OF THE SSPS AND THE PV SYSTEM ON THE GROUND SSPS

generation cost (yen/kWhI

15.4 - 23.3

case #A no strafe 10.4- 18.3

the PV on the Ground case #B with lead battery with pumped hydro 30.1 - 38.3 24.2 - 32.1

The feasibility o f the SSPS as a CDM project We can say that it is necessary to put the solar cells into orbit from the economic viewpoint. It is, however, difficult to say that the SSPS, without any economic measures, is commercially viable, even in the future electricity market in Japan in view of the current power generation cost [9]. Therefore, let us suppose that the electricity supply to a developing country by the SSPS is certified as the CDM project. The economic returns on the investment in the rectenna used to transmit electricity from an orbiting platform depend on the following two factors: one is the revenue from selling electricity, while the other is from the carbon credit, the price of which is determined in the emissions trading market. The higher the price of carbon emissions, the higher the returns on investment. Table 4 shows the conditions assumed in estimating the generation cost of the SSPS as the CDM project and the estimation results. China is selected for the host country. During the next few decades, it is expected that China's electricity demand will continue to grow [ 10]. Moreover, 70 percent of electricity demand in China is supplied by coal-fired power plants. Due to these reasons, we assumed that coal-fired power is replaced with the power of the SSPS. We examined the feasibility of the SSPS as the CDM project. Table 5 shows the maximum generation cost of the SSPS that is commercially viable, taking the cost of coal-fired power plant [ 11 ] and the carbon price as parameters. In the cost analysis mentioned above, the electricity generation cost of the SSPS is estimated to be more than 10.8 yen/kWh (See Table 4). Therefore, the SSPS can be commercially viable only if the power generation cost of coal-fired power plant in China is more than 6 yen/kWh and if the carbon price is set to 15,000yen/t-C, the maximum value we can assume.

1229 TABLE 4 ASSUMPTIONS IN ESTIMATING THE COST OF THE SSPS AS THE CDM PROJECT AND ESTIMATION RESULTS assumptions (CDM)

results the location of rectenna orbit platform rectenna transmission cost total generation cost (yen/kWh)

host country start of operation rectenna cost (land price) rectenna cost (for construction) carbon price electric power supply to be replaced generating cost (min) 4yen/kWh

China 2020 negligible 1/10 of Japan no more than 15,000yen/t-( coal-firedpower equal to the avarage generating cost of current coal-fired power in China generating cost (max) 6-7yen/kWh equal to the avarage generating cost of current coal-fired power in Japan CASE#1 CASE#2 Japan China (marginal) Japan China (marginal) 10,035 10,035 10,035 9,051 9,051 9,028 5,433 438 0 5,433 438 0 10,922 9,745 9,745 1,260 1,142 1,142 26,391 20,218 19,780 15,744 10,749 10,170 (100million yen) 23.3 18.3 18 15.4 11.3 10.8

TABLE 5 THE COMMERCIALLY VIABLE GENRATION COST OF THE POWER GENERATION AS THE CDM PROJECT The carbon price (yen/t-C) 10,000 15,000 50,000 20.4 8.9 7.3 22.4 9.3 10.9 23.4 10.3 11.9 (yen/kWh) [ ~ commercially viable cases from the viewpoint of economy

The generation cost of Chinese coal-fired power plant 4 yen/kWh 6 yen/kWh 7 yen/kWh

CONCLUSIONS

In this paper, firstly, the SSPS is compared with the PV system on the ground from the viewpoint of economy. The SSPS is considered competitive if the stability of the output is fully evaluated. Secondly, the feasibility of the SSPS as the CDM project is investigated. Based on the estimated results of this study, we can conclude that the SSPS as the CDM project is more commercially viable when compared with the case where it supplies electricity only to Japan. It has, however, been shown that the market price of the carbon credit should be at least 15,000yen/t-C so that the SSPS might be commercially competitive. As a future study, it will be necessary to investigate the viability of the SSPS with recent related technological developments; for example, highly efficient solar cells and power transmission by laser beam. We are also planning to investigate the optimal combination of the component technologies and the design parameters so that the total generation cost might be minimized.

1230 REFERENCES

1. NASA (1997). SPACE SOLAR POWER A FRESH LOOK AT THE FEASIBILITY OF GENERATING SOLAR POWER IN SPACE FOR USE ON EARTH. No. SAIC-97/1005, United States of America. 2. Peter E. Glaser (1968). Power from the Sun: Its Future. SCIENCE. Vo1.162, No.3856, pp.857-861. 3. Yoshioka K et al. (2001). C02 Load of Space Solar Power Satellite. Keio University, Japan. 4. Mitsubishi Research Institute Inc. and NEDO. (1994/95). Survey and Study on the Solar Power Satellite System, Japan. 5. Yoshida H, Mori M, Matsuoka I, H Nagayama (2001). Studies on the Economic and Social Aspects for the Benefit of Space Solar Power System. Proceedings of 52nd International Astronautical Congress, France. 6. Sawa T, Matsuoka I (2001). What Kind of Roles Can the SSPS Play in the Future Market of Electricity?. Proceedings of 2001 Asia-Pacific Radio Science Conference, Japan. 7. Subcommittee on the Evaluation of Photovoltaic Power Generation, NEDO. (1996). Survey on Evaluation of Photovoltaic Power Generation, Japan. 8. Uchiyama Y et al. (1996). Second Batteries and Their Future Prospects. Central Research Institute of Electric Power Industry, Japan. 9. Soda Y, Matsuoka I, Sawa T (2001). Evaluation of New Technologies for Electricity Supply System in View of Combating against Global Worming. Japan Science and Technology Corporation, Japan. 10. Li ZhiDong. (2001). Private Interview. 11. Agency of Natural Resource and Energy and MITI. (2000). EDMC, Energy Balance Tables in Japan, Japan.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1231

STUDY ON EFFECTIVE INSTITUTIONS TO M A K E CDM PROJECTS VIABLE Ryuji Matsuhashi 1, Sei Fujisawa l, Wataru Mitamura 2, Yutaka Momobayashi z and Yoshikuni Yoshida 2 Institute of Environmental Studies, Graduate School of Frontier Sciences, The University of Tokyo, 7-3-1 Hongo, Bunkyo-ku, Tokyo 113-8656, Japan z Department of Geosystem Engineering, Graduate School of Engineering, The University of Tokyo, 7-3-1 Hongo, Bunkyo-ku, Tokyo 113-8656, Japan

ABSTRACT The CDM (Clean Development Mechanism) is expected to facilitate technology transfer from developed to developing countries, as well as to economically reduce greenhouse gas emissions. In this article, we explored effective institutions to make CDM projects viable. For this purpose, we estimated IRR, internal rate of return and other indicators on profitability for 42 CDM or JI projects, taking account of volatilities in price of CER, certified emission reduction. As a result of Monte Carlo simulations, expected values and standard deviations in IRR of the projects, were shown quantitatively. Then, we evaluated various risks in the CDM, concluding that diversification of investment is effective in suppressing these risks. Therefore, securitization of CDM finance was proposed to facilitate the diversification of investment. Namely, we presented the concept of a CDM bond, which is a project bond with CER. We also investigated the role of governments in suppressing risks in CDM. Referring to CERUPT, initiated by The Netherlands' government, the institution of insured CERUPT was proposed to suppress the downside risks in IRR of the projects. We concluded that it is possible to make CDM projects viable by the insured CERUPT and CDM bond. INTRODUCTION Degradation of the global environment and depletion of resources are becoming serious threats to sustainable development of humankind. In particular, there has been growing concern on climate change caused by increase of greenhouse gases. Although Annex 1 countries in the Kyoto Protocol have to control their greenhouse gas emissions according to the assigned amount, greenhouse gas emissions such as CO2 are increasing in most countries. Therefore, we need to explore efficient and fair ways of internationally reducing greenhouse gas emissions. Under these circumstances, the Clean Development Mechanism (CDM) is expected to be a powerful option to suppress the difference between the North and the South, as well as to economically reduce greenhouse gas emissions. PRESENT SITUATIONS ON CDM PROJECTS

Profitability of CDM Projects The institution of CDM has been intensively argued, based on the Kyoto Protocol. In particular, issues on "additionality" are significant to certify projects as CDM. From past interpretations on investment additionality, operational entities would not certify a project as CDM, if it were profitable even without revenue from sales of CER. Interpretation on the investment additionality changed in the COP7 meeting in Morocco. According to the Marakesh Accord, in COP7, they could certify a project as CDM, which is profitable without CER revenue. Nevertheless, the past interpretation on investment additionality seems to

1232 still be alive in some developing countries. Under such circumstances, profitability of CDM projects must be evaluated cautiously, so that these projects can be carried out. Therefore, we investigated the overall profitability of 42 CDM and JI projects, of which feasibility studies were performed under sponsorship of NEDO. Data on initial investment cost, annual running cost, annual production of main commodities such as electricity, and annual reduction of equivalent CO2 emissions were acquired from NEDO's reports on each project (Matsuhashi [ 1]). The projects evaluated include various types of CDM and JI, such as fuel switching from coal to natural gas, efficiency improvement in the industrial sectors, recovery of methane from coal mining, and energy conservation in the commercial and residential sectors. These projects have different characteristics, especially in revenue structure. If a CDM project is on high efficiency power generation, revenue is from sales of electricity and CER. Most projects rely on main products such as electricity, as well as CER, for revenue. However, the share of CER value in total revenue is different, depending on the characteristics of each project. For instance, shares of CER sales are generally high in projects which recover methane from coal mining and utilize the gas for power generation, town gas production or methanol synthesis. In such projects, they convert the recovered methane into equivalent CO2 reduction by multiplying by 21 as the Global Warming Potential. Thus, equivalent CO2 emissions become considerable, so that revenue from CER sales often exceeds sales of the main products. On the other hand, the share of CER value would be relatively small in projects of efficiency improvement in fossil-fueled power generation.

Monte Carlo Simulations for Estimating Risks Accompanying CDM Projects Volatility in future CER value is generally higher than that in the value of a main product. Therefore, a CDM project relying to a greater extent on CER value is exposed to a higher risk. If the price of CER does not rise as anticipated, the project would not generate sufficient revenues for the project sponsors. Conversely, sponsors would receive more revenues from the higher price of CER. In particular, participation of the USA, even from the second commitment period, would immediately increase the price and increase revenue of the project. So as to quantify the above risks, we performed Monte Carlo simulations on the profitability of CDM projects. We estimated IRR, internal rate of return, of 42 projects by Monte Carlo simulations, on which economic data were acquired from NEDO's reports. Major assumptions for the simulations include: 1. We estimated an implied volatility in CER price from present data on call option by the Black-Scholes equation. Based on the estimation, the volatility was assumed to be 23%. 2. Annual escalation of main products such as electricity was assumed to be 3%. Volatility in price escalation of main products is assumed to be 1.5%. 3. We estimated IRR of each CDM project through generating 100,000 random numbers according to the above assumptions. 4. Present price of CER is assumed to be 4 US$/t-CO2 based on the current data. 5. According to the estimation by global energy model, DNE (Akimoto [2]), the price of emission permits will rise to 22 US$/t-CO2, which corresponds to 21% of annual escalation. However this is the case, in which USA ratifies the Kyoto Protocol. Under present circumstances, the possibility of the USA's participation is very slight. Therefore, we set a more conservative annual escalation of CER price as 10%. 6. We assumed 10 years' BOT for financing projects, which comprises Build, Operate and Transfer. This is because an option of the period for generating CER from one project was determined as 10 years in COP7. After 10 years, all the assets concerning the projects will be transferred to host countries' governments or companies. Trade-in prices of transferred assets were assumed to be 10% of initial investment. Figure 1 shows the computed results of the Monte-Carlo simulations. Namely, it depicts expected values and standard deviations in IRR of the 42 projects with and without CER revenues. This figure indicates how risks and returns in the projects increase by including revenues from CER sales. Although Figure 1 tempts us to make portfolios of various projects, it is necessary to investigate characteristics of risks so as to evaluate the effectiveness of such portfolios. Risks accompanying CDM projects are generally classified as follows.

1233 1.

2.

3. 4. 5.

The risk is certainly significant that volatility in CER price will change revenue in CDM projects. This is already taken into consideration in the above Monte Carlo simulation. Here the risk is named as 'CER risk'. Another risk is also crucial, whether a project could be certified as CDM or not. If the project were not certified by operational entities, sponsors of the project could not acquire CER. The risk is named as 'certification risk'. We should pay attention to a risk that the amount of CER will change due to modified baselines in future. We call this 'baseline risk'. We should also be cautious as to whether a CDM project is approved by host countries or not. A CDM project is also accompanied by country risks due to political or economical instability in host countries. Here we call risks in 4 and 5 as 'country risks'.

Among the above-mentioned risks, certification risk and baseline risk strongly depends upon project types. If they could improve technologies of recovering and combusting methane from coal mining in host countries, baseline in the project recovering methane would be lowered, leading to reduction of CER units. In the worst case, operational entities might not certify the project as CDM. So as to suppress these risks, we should invest in different types of projects, rather than in similar ones. Conversely, risks in 4 and 5 depend upon political and economic stabilities in host countries. So as to lower these risks, we should invest in projects in different countries, rather than in a single country. CER risk itself is difficult to avoid by portfolios of CDM projects, since it is similar to systematic risks in the market of securities. However, we could control certification risk, baseline risk and country risks by diversification of investment. In summary, further investigation is deserved to make effective portfolios that include CDM projects to reduce the above-mentioned risks.

0.6 0.5 0.4

+

0.3

~

+ 02 0.1

-

+ + .........

='1=--

I

0 0.02

0.04

-0.1 S tandard d e v h t b n oflRR

)6 i

i[ With CER r e v e n u e + WithoutCER r e v e n u e ]

Figure 1" Expected values and standard deviations in IRR of the 42 projects with and without CER revenues

SCHEMES TO MAKE CDM PROJECTS VIABLE

The Concept of CDM Bond From observations in the last section, it is desirable for sponsors to diversify investment into various projects in various countries so as to reduce baseline risk, certification risk and country risks. There

1234 could be various measures to realize the above scheme in CDM projects. One such measure is a partial securitization of financing CDM. Here, we propose the concept of the CDM bond as a type of securitization. Figure 2 shows the scheme of the CDM bond. Namely, investment banks or security companies evaluate total risks in CDM projects, structure them and make CDM bonds and project bonds with CER units. They can then sell them to individual investors, general companies and to QIB, qualified institutional buyers. In some cases, they can make portfolios of CDM bonds to sell them as 'CDM Fund' such as the present 'Eco Fund'. Possible investors or QIB would be companies that wish to supplement their own efforts to reduce CO2 emissions by the CER, to raise their environmental ranking, or to adopt it simply as an investment business.

] .Investment . . . Banks ] ~ecurlty compames

Qualified InstitutionalBuyers Other Companies 1

~ ' ' ~ " ~ "~ [CDMBond [ ~Arrangement] ~] Coupon ] / ~, • I Sponsors [ , ~ ~. ." I General companies I [ Purchase ] ~ ~ 7 / ~ ~ I

ReT~quity

I" Ii~;pecialPurpose[~ I ungmators ~.J Company ] ~l (Project company) I Financing~ Salesrevenue

Fmanctal . . . organizations . ]"

TM

CashF l ~ x e eI u t iIo n

CDM projects] Figure 2: Financial flow accompanying partial securitization of CDM projects From the standpoint of investors, it depends on their attitudes toward the risk and in which projects they prefer to invest. It also depends on the necessity of CER in each company. Namely, some companies take the investment imperative to comply with the Voluntary Action Program expressed by Nihon Keidanren, while others take it just as environmental business or an advertisement. If there are wide varieties of securities to be sold in the market, individual investors, companies or QIB, are able to buy them according to their own attitude toward the risk and necessity of CER. Thus, the concept of securitization of CDM deserves further investigation. We will establish the institution more concretely and evaluate it in our future work.

The Concept of lnsured CER UPT So as to reduce risks in CDM, governments of donor countries could also play an important role. In this respect, CERUPT, CER Units Procurement Tender, initiated by The Netherlands's government, deserves attention. In CERUPT, the government purchase CER units acquired from CDM projects, on which host countries and donor countries ratify Kyoto Protocol. In future, other governments would also take establishment of such system into consideration including Japan. If a donor country's government could offer a lowest price for CER unit in such system, it could contribute towards suppressing the downside risk in IRR of CDM, resulting from volatilities in CER price. Here, we call the concept as 'Insured CERUPT', that could suppress downside risks in CDM by determining a minimum price of CER. We compared IRR of a CDM project with and without the Insured CERUPT, which recovers coal-mine methane to utilize it for power generation in a developing country. Figure 3 shows the estimated profile of IRR of the project with and without the Insured CERUPT, in which the government shows the lowest price of CER at 4 US$/t-CO2, present price in emission trading. Figure 3 makes us recognize the effect of the Insured CERUPT to suppress downside risks in the project. Thus the institution by the government could also help making CDM and JI projects viable.

1235

25.0%

20.0%

15.0% OOm~withInsured CERUPT i ihhout Insured CERUPT 10.0%

5.0%

0.0% RR

Figure 3: Probabilistic distribution of IRR estimated by Monte Carlo simulations with and without the Insured CERUPT

The Effect of the Proposed Institutions We then evaluated the 13 value, as defined in Eqn. 1. Here, the value of 13 is utilized to assess sensitivity of IRR to increasing rate of CER price. IRR =/3(Rc~ )+ 7 RcER" Rate of increase in CER price.

(1)

Based on the concept of the securitization and the evaluated value of, we can evaluate risks and returns in portfolios, which admits diversified investments. In this analysis, we took a combination of the portfolios and the insured CERUPT to make JI and CDM projects viable. Based on the following assumptions, we determined the most possible combinations in 42 projects as shown in Figure 4. This figure indicates effects of the securitization and the Insured CERUPT. 1. In the scenario of business as usual, we selected projects as marketable, in which IRR exceeds 15% even without revenue from CER. We calculated the sum of equivalent CO2 reductions by adopted JI and CDM projects. This is the criterion which ordinary trading companies rely on for carrying out projects. 2. In the scenario of the Insured CERUPT, we selected projects as marketable, in which IRR exceeds 15% including CER revenues with the institution. We then calculated the sum of equivalent CO2 reductions by adopted JI and CDM projects, as above. This is the criterion in which the government establishes the institution of the Insured CERUPT. 3. In this scenario, we selected the most possible projects by making portfolios that insured the following risk/return formulae. Namely, we maximized the number of adopted projects, under constraints of Eqn. 2. Eqn. 2 implies a basic relationship between risks and returns observed in securities market. Rf and ct was determined from present data on the market. p _>R/+ crop" Retum of a portfolio, R/• Risk free rate, cr : Risk of a portfolio, a" Constant •

(2)

4. In this scenario, we selected the most possible projects by making portfolios, that insured the same risk/return constraints as above. In this sceanario, we also take the Insured CERUPT into consideration.

1236 Namely, we evaluated the total effects of controlling risks by portfolios and the Insured CERUPT.

~Vlilliont-CO2/year) 35

I

BAU

I

INSURED CERUPT

PORTFOLIO

PORTFOLIO+INSURED CERUPT i

Figure 4: Equivalent

CO2

reductions by adopted JI and CDM

CONCLUSIONS

In this paper, we explored efficient institutions to make CDM projects viable. For this purpose, we estimated IRR and other indicators on profitability for 42 projects, taking account of volatilities in CER price and other costs. As a result of Monte Carlo simulations, expected values and their standard deviations in IRR were quantitatively shown. Risks accompanying CDM projects were identified as CER risk, certification risk, baseline risk, and country risk. Although it is difficult to suppress CER risk by diversifying investment into various CDM projects, we could effectively control certification risk, baseline risk or country risks by portfolios of various types of projects in various countries. Therefore, securitization of CDM finance was proposed to facilitate the diversification of investment. Namely, we presented the concept of CDM bond, which is project bond with CER. We also investigated the role of governments to suppress risks in CDM. The institution of the Insured CERUPT was proposed to suppress downside risks in IRR of the projects. Then we evaluated 13 value to assess sensitivity of IRR to increasing rate of CER price. Based on the evaluated value, we explored the most possible combinations in 42 projects, with and without proposed institutions. Evaluated results indicated that the Insured CERUPT and CDM bond could enable us to make CDM projects viable. ACKNOWLEDGEMENTS The author is grateful to Shunsuke Mori, Tetsuo Tezuka, Tsuyoshi Iwama and Junichi Murakami for their useful comments in frequent discussions on CDM. REFERENCES 1. Matsuhashi R. (2002), Investigation of effective institution to make CDM projects viable, paper presented at UNIDO/MRI Forum on CDM and Kyoto Protocol: Opportunities for Japan in Asia 2. Akimoto K., Matsunaga A., Fujii Y., Yamaji K. (1998) Game theoretic analysis for Carbon Emission Permits Trading among Multiple World Regions with an Optimizing Global Energy Model (in Japanese). Transactions of Japan Institute of Electrical Engineers 118-C, p 1424 3. Matsuhashi R., Yoshida ¥., Fujisawa S., Momobayashi ¥., Ishitani H.(2002), Investigation of institutions for making CDM viable, Proceedings of 21th annual meeting on energy resource, p541-546

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1237

ECONOMIC AND G R E E N H O U S E GAS EMISSIONS ASSESSMENT OF EXCESS BIOMASS E X T R A C T E D FROM FUTURE KRAFT PULP MILLS A. Adahl, S. Harvey and T. Bemtsson Department of Heat and Power Technology, Chalmers University of Technology, 412 96 Grteborg, Sweden.

ABSTRACT Different studies have shown that the process heat requirements of future pulp mills can be satisfied using available internal biomass (bark and lignin), which are process by-products. Assuming that biomass is CO2 neutral, further reducing the process heat demand will not therefore lead to further reduction of Greenhouse Gas (GHG) emissions - unless the excess biomass is extracted and used elsewhere to substitute fossil fuels. Previous work has demonstrated the potential to extract and export significant amounts of biofuel from future pulp mills. The associated extraction costs can be competitive with conventional forest fuels. However, biofuel extraction reduces the mill's potential to cogenerate electric power. This reduced power output must be compensated by increased purchased power from the grid, with associated costs and emissions. Such emissions must be affected to the extracted biofuel, which cannot therefore be considered as CO2 neutral. This paper presents results for costs and associated greenhouse gas emissions for excess biofuel extracted from a pulp mill. The results show that the extraction costs are competitive, but that the greenhouse gas emissions associated with the exported biofuel can be significant and must therefore not be neglected.

INTRODUCTION

Biofuel prices have begun to increase in Sweden [ 1], as a result of increased demand resulting from energy and environmental policy instruments [2]. Similarly, EU policy [3] aims at increasing usage of biomass as a renewable fuel. To develop future sustainable energy systems with low greenhouse gas (GHG) emissions, it is necessary to not only increase use ofbiofuels, but also to use such fuels as efficiently as possible. Swedish kraft pulp mills currently use oil and intemal biofuels to satisfy process heat demands. The Swedish "EcoCyclic Pulp Mill" project has defined the energy system for a reference mill incorporating best available technology [4]. According to this project, future pulp mills should not only be energy selfsufficient using internal biofuel resources, but should also be able to export excess bark and lignin [5, 6]. Internal biofuels are pulp process by-products, and the total production costs for biofuel extraction can be computed based on costs for process integration measures to reduce the mill heat demand (and thereby the process biofuel consumption), biofuel processing costs, and changes in electric power costs since decreasing the mill steam demand decreases the amount of electric power that can be cogenerated. Furthermore, biofuels are generally assumed to be CO2 neutral ~ due to the closed carbon cycle. However, given the above I Other sources of GHG emissions associated with biofuel usage include for example harvesting and transportation. Land use practises can also impact net GHG emissions for biofuels. These aspects are not further considered in this study, since these emissions are assumed to be charged to the pulping process.

1238 mentioned changes to the mill steam and power balances resulting from biofuel extraction, the exported biofuel should not be considered as CO2 neutral, but should rather be charged with the emissions associated with the extraction process. The aim of this paper is to assess costs and global GHG emissions associated with biofuel extracted from a future pulp mill. The paper presents a case study based upon a Swedish kraft pulp mill. Identifying potential energy efficiency measures for retrofitting of a pulp plant requires the use of appropriate tools. The measures considered in this paper were identified in previous work at the authors' department using process integration tools, including both traditional pinch technology tools [7, 8] and advanced tools specially suited to retrofit situations [9, 10]. A description of appropriate tools for systematic analysis of GHG emissions associated with process integration measures may be found in [ 11 ] and [ 12].

CASE STUDY PULP M I L L PLANT CHARACTERISTICS The pulp mill studied in this paper is a Swedish combined pulp and board mill producing 530,000 tonnes/year of board based on both CTMP and sulphate pulp. The current mill heat demand is 195 MW. Electricity is cogenerated for on-site use. Additional power is purchased from the grid. Effluents from part of the plant are currently discharged to an aerated pond. New environmental restrictions require that the load on the pond be decreased. In order to treat the effluent stream its concentration must first be increased in a pre-evaporator. Conventional pre-evaporation increases the mill steam consumption. Alternatively, process excess heat identified by pinch technology could be used as a heat source. In previous work at the authors' department [ 13], excess heat suitable for effluent pre-evaporation has been identified at three temperature levels. The excess heat could also be used as heat source to generate additional steam by heat pumping, thus reducing the boiler fuel consumption. Three alternative process integration measures were therefore investigated for decreasing boiler steam consumption to drive the pre-evaporation process, namely: (I) heat pumping of low temperature mill excess heat; (II) recovery of mill excess heat; (III) use of recovered mill excess heat in combination with heat pumping. Based on available process stream data and heat pump characteristics, the potential for delivered heat from the heat pump was estimated to be 5 MW, using a conventional mechanical vapour recompression (MVR) heat pump. The three alternative solutions are analysed with the conventional steam solution as baseline (reference). Table 1 summarises the key data for the analysis. The reference situation requires an increase of biofuel consumption in order to meet the increased steam demand of 18.6 MW. Alternative III decreases the plant's steam demand by 22.1 MW compared to the reference, i.e. not only the pre-evaporator unit can be run using waste heat only, but steam from the MVR heat pump can be used to reduce the boiler steam demand for other parts of the mill. The potential for biofuel export from the mill was estimated based on the following assumptions: -

Oil is not used as a fuel at the mill, i.e. a reduction of steam demand (compared to the reference) leads to a corresponding potential for biofuel export, adjusted for conversion efficiencies; Extracted biofuel may be in the form of bark or lignin. Energy requirements and emissions associated with further processing and transporting of the extracted biofuel are not considered; The biofuel boiler efficiency is set at 0.85, based on the fuel lower heating value; The changes in cogenerated electric power associated with changes in mill steam demand are estimated based on the mill's steam turbine operating curves [ 14]. The mill operates 8760 hrs/year, including the cogeneration unit. Although current electricity prices in Scandinavia do not justify year round cogeneration, a number of studies (e.g. [15]) indicate a clear need for increased base-load (year-round) power generation in the near future.

1239

TABLE 1 DATA FOR RETROFIT ALTERNATIVES

Retrofit Measures

Process data Decreased Number of presteam demand evaporator w.r.t, reference units

[MW]

Ref I

II III

Pre-evaporator heat source (BS=Boiler Steam) Boiler steam only BS + Heat pumping of excess heat BS + Excess heat Excess heat and heat pumping

Investment data Heat Rearrangements for evaporator pump heat pump [MSEK] [MSEK] [MSEK] Pre-

Results Extracted biofuel [GWh/year]

Increased power from

~d [GWh/year]

76.6

0

0

0

0

5.0

76.6

5.52

4.6

64

15.7

9

17.1

110

0

0

221

38.7

9

22.1

110

5.52

4.6

286

54.6

4

A S S E S S M E N T OF E X T R A C T I O N C O S T S A N D A S S O C I A T E D G H G E M I S S I O N S

Three alternative energy saving measures are investigated for the pulp mill, as discussed in the previous section. The baseline chosen is conventional live steam pre-evaporation for the pulp mill. The biofuel released from the pulp mill is considered as a by-product of the pulping process, i.e. LCA GHG emission values associated with biomass harvesting and transportation together with biomass raw material costs are allocated to the pulping process and not to the by-products. Biofuel extraction costs are therefore constituted by investment costs to reduce the boiler steam demand (see Table 1) plus increased grid power purchase costs due to the decreased potential for mill-site cogeneration (Table 1 presents the estimated increase in power purchases from the grid). Extracted biofuel processing costs (e.g. drying and pelletising) are not considered in this study. Capital costs are annualised using the annuity method with a capital recovery factor of 0.2 (except for the heat pump where 0.42 is used, reflecting the demand for a shorter payback period for this type of equipment). As discussed previously, the different measures considered affect the pulp mill electric power balance, and additional power must be purchased from the grid (see Table 1). The GHG emissions associated with the additional power generated by the grid must be allocated to the extracted biofuel. Three levels of electricity grid emissions are considered (Table 2), reflecting uncertainty about the evolution of the power system mix of technologies, and about the corresponding choice of baseline for calculations. Two levels of electricity prices are considered. The low value reflects the current situation in Scandinavia, with low power prices due to market deregulation and relative abundance of low-cost generation capacity. The higher value reflects a future situation where it is assumed that the power price is set by the generation costs of new natural gas fired combined cycle plants (NGCC).

TABLE 2 ELECTRICITY GRID SCENARIOS Electricity price on the Nordic power market (SEK/MWh) 150 300

Electricity grid GHG emissions (kg/MWhe0 110

300

380

150 300

890

Corresponding electricity production in the future deregulated Northern European electricity market Average Nordic power system based on hydropower, nuclear power and fossil fuel power plants Natural gas combined cycle (NGCC) power generation as marginal production technology Coal-fired steam turbine power plants as marginal production technology

1240 RESULTS Figure 2 shows the results for biofuel specific extraction costs resulting from the considered pulp preevaporation plant retrofit measures. For comparisons, the figure also shows the current Swedish market price for bark and other wood-waste fuels taken from [ 1]. The market price for premium forest fuels is higher, but in this study it is assumed that the biofuel extracted is bark or lignin. Due to uncertainty regarding the attractiveness of lignin on the biofuel market, it is assumed in the study that this type of fuel has the same market value as bark. In order to motivate such an investment, the biofuel extraction costs must clearly be lower than the market value for the extracted biofuel. As shown in the figure, the specific extraction costs vary for the different pulp mill measures considered. The market electricity price also has a significant impact on the extraction costs. Regardless of the electricity price, the extraction costs associated with Measure I is higher than the market value of the biofuel. For the lower electricity price, Measures II and III are competitive, whereas for the higher electricity price, only Measure II is competitive. The figure also shows that if biofuel market prices increase in the future, all three measures are likely to be competitive, even with future high electricity prices. 160

•,-'

ca

Current biofuel

140

market:~ce:

O

u _~ 120 o ~ lOO

90 SEWMWh

C

I Low electricity market pdce

"~w O

m

I High electricity market price

20 I

II Measures

III

Figure 2: Biofuel specific extraction costs associated with process integration measures at the pulp mill (Note: extraction costs include annualised investment costs plus electricity costs due to changes to the site power balance) It should also be noted that Figure 2 presents specific biofuel extraction costs. The total investment depends on the amount extracted (see Table 1). Measure I corresponds to a relatively low biofuel extraction potential (64 GWh/yr.) at a relatively high specific extraction costs. Measures II and III correspond to a significantly higher extraction potential (221 resp. 286 GWh/yr.) at significantly lower specific extraction costs. Figure 3 presents results for global CO2 emissions increase for all retrofit measures, compared to the reference boiler steam driven pre-evaporators. The results are presented as specific emissions per unit extracted biofuel. The key values from Figures 2 and 3 are presented in Table 3. Three levels of emissions associated with grid electric power generation are considered (see Table 2) for assessing the impact on global GHG emissions associated with changes to the pulp mill net power balance. For comparison purposes, the figure includes reference values typically used in LCA assessment studies for GHG emissions for three types of fuels, namely oil, natural gas and virgin forest fuel. The results presented in Figure 2 showed that electric power prices have a significant impact on specific extraction costs. Figure 3 shows that the impact of grid emissions is even more significant. From a GHG emissions perspective, extracted biofuel is only comparable to virgin forest biofuel only when grid emissions are low. If grid emissions are high, the GHG emissions associated with the released biofuel are somewhat lower than natural gas GHG emissions, but clearly much higher than for virgin forest biofuels.

1241

• I=

3001 iiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiii~~~i~iiii~-NaturOil-~~--al~// 250,

CorroarableLCA I 002 errission values

.9

w ~,-,. 200

• Low electricity grid

E~ e~ 0

150

emissions

tO o ~ ol _.u ~ 100

Virginforest biofuel(bark)

o Q.

[] Intermediate electricitygrid emissions

[] High electricity grid

o I

u

III

emissions

Measure

Figure 3: Global

CO2

emissions associated with extracted biofuel

TABLE 3 SUMMARY OF BIOFUEL EXTRACTION COSTS AND SPECIFIC CO2 EMISSIONS

Measures at the pulp mill 1 [I I

Electricitymarketprice (SEK) 150 300

Biofuel extractioncost (SEK/MWhfuel)

Electricitygrid emissions (ks/MWh¢,) ll0 380 890

Specific C O 2 emissions

(kg/MWhfuel)

103 139

56.5 82.8

16.2 81.7 206

8.76 56.1 145

I I

67.0 95.6 10.5 62.0 159

DISCUSSIONS As pulp mills become more energy efficient, there is an increasing potential export of excess biofuel from this industry. The goal of this paper was to investigate costs and associated GHG emissions for extracted excess biofuel, based on results from a case study that investigated technical and economic opportunities for excess heat utilisation in a Swedish pulp and board mill. The study accounts for costs and emissions resulting from changes in the mill's electric power balance. The results show that for the case study considered, excess biofuel can be extracted at costs that are often competitive compared with the market value of the extracted fuel. The extraction costs are significantly higher when the economic value of the loss of cogenerated power is high. As the demand for biofuels increases in the future, there is therefore a clear incentive to further investigate extraction of excess biofuel from pulp mills. This may be seen as a business opportunity by the industry itself, or alternatively it may be seen as an opportunity for external investors wishing to invest in a secure source of low-cost biofuel. Jointventure strategies involving both mills and external market actors may also be attractive. International investors may become interested in the Swedish pulp mill biofuel surplus potential, under the terms of the joint implementation mechanism provided for in the Kyoto protocol. Swedish biofuel could thereby be used for e.g. fossil fuel substitution in biofuel-deficient areas of Europe. This study however shows that, unlike virgin forest biofuels, extracted biofuels can have relatively high associated emissions (in certain cases close to the emissions levels of natural gas), depending on the

1242 reference grid emissions associated with electric power generation. In order to achieve global greenhouse gas reductions, biofuel must clearly be used for substitution of fossil fuels. Furthermore, given the GHG emissions associated with excess biofuels extracted from pulp mills, these fuels must be used to be used to increase usage ofbiofuels, and should not compete with virgin forest biofuels, as discussed in [ 16]. In order to assess the cost-effectiveness of extracting excess biofuel from pulp mills as a means to reduce global greenhouse gas emissions, it is clearly important to include the final usage of the extracted biofuel in the analysis. Furthermore, the results of this study show that the specific extraction costs are dependent on both the nature of the energy-efficiency measures implemented in order to release the excess biofuel, and on the economic value of the cogenerated electric power. Thus, the cost-effectiveness of greenhouse gas emissions reduction based on extraction of excess biofuel from pulp mills and usage of this biofuel to substitute fossil fuels requires a detailed analysis adopting a suitable system perspective so as to account for all major effects. Results from this type of study must be used as input for such an analysis.

REFERENCES

.

9. 10. 11. 12. 13. 14.

15. 16.

The Swedish Energy Agency. (2002). Prisblad fOr biobriinslen, torv mm. Nr 2/2002, www.stem.se. The Swedish Government. (2002). Energipropositionen 2002, www.regeringen.se. The EU Commission of the European Communities, Commission Staff Working Paper (2001). Third Communication from the European Community under the UN Framework Convention on Climate Change, www.europa.eu.int. STFI. (2000). Final report KAM 1, 1996-1999, Report A32. STFI, Stockholm, Sweden. Wising, U. (2001). Licentiate Thesis, Chalmers University of Technology, Sweden. Algehed, J. (2002). PhD Thesis, Chalmers University of Technology, Sweden. Linnhoff, B e t al. (1994). User's Guide on Process Integration for the Efficient Use of Energy. IChemE, Rugby, UK. Linnhoff, B. (1994). Chem. Eng. Progress, Vol. 90, No. 8, 32-57. Carlsson, .A., Franck, P.-A., and Bemtsson, T. (1993). Chemical Eng. Progr. Vol 89 (3), pp 87-96. Nordman, R., and Bemtsson, T. (2001). Canadian Jnl of Chem. Eng. Vol 79 (4), pp 655-662. Axelsson, H., Asblad, A., and, Bemtsson, T. (1999). Applied Thermal Eng., Vol. 17, 993-1003. Adahl A., Harvey S. and, Berntsson T. (2000). ECOS 2000 proceedings, Eurotherm Seminar 65. 2000;(3): 1213-1224. Bengtsson, C., Nordman, R. and, Berntsson, T. (2002). Applied Thermal Eng., Vol. 22, 1069-1081. Bengtsson, C., and Karlsson, M. (1999). Co-operation of the MIND-method and the Pinch Technology - energy efficient pre-evaporation of bleach plant filtrate using waste heat. Report nr 4, ISSN 1403-8307, Program Energisystem, Link6ping University, Sweden. Energimyndigheten. (2001). Liiget p& den Nordeuropeiska elmarknaden - ett fdrsOk till en problemorienterad analys. Report nr ER23:2001 ISSN 1403-1892, Eskilstuna, Sweden. Energimydnigheten. (2001). Underlag for m&lformulering for L&ngsiktiga avtal med energiintensiv industri. App. 3 in N~ringsdepartementet report Ds 2001:65, Fritzes, Stockholm.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1243

TRANSPORTATION, CDM, AND GHG EMISSION REDUCTIONS Ming Yang (PhD) 1 and Xin Yu (PhD Candidate) 2 ~Energy Economics and Technology, 12 Kiah Street, Glen Waverley, Victoria, Australia, email [email protected] 2Department of Management, Monash University, Australia, Email: [email protected]

ABSTRACT This paper aims at presenting information on how transport technology, management and clean development mechanism (CDM) facilitate GHG emission reductions in urban passenger transport. Efficiency factors of urban passenger vehicles are analysed. Emissions from various transportation fuels and vehicles are demonstrated. The paper also shows two case studies about the impact of transportation planning and CNG motor vehicles on a cleaner city environment. Then, this paper briefly introduces the CDM of the United Nations Framework for Climate Change Convention (UNFCCC) and describes how CDM will leverage additional financial resources from Annex B parties to the developing countries. This paper concludes that governments in developing countries have various opportunities to mitigate climate change, and that integrated transportation planning and clean transport technology combined with clean development mechanism will assist government decision makers of the developing countries to better develop their transportation systems.

INTRODUCTION Of all human activities, driving motor vehicles produces the most intensive CO2 emissions and other toxic gases per capita. A single tank of gasoline releases 140 ---180 kilograms of CO2. Yang [ 1] indicated that over 25% of transportation-related GHG emissions originate from urban passenger travel. Throughout major cities in Asian developing countries, unsustainable trends in urban transportation have already been manifested as frequent congestions, periodic gridlock, a lack of funds for desired road rehabilitation and maintenance, and evidence linking respiratory illnesses and deaths to poor air quality. Many city governments in developing Asian countries still have opportunities to make things better. In Hanoi and Ho Chi Minh City in Vietnam, for example, urban passenger transportation is currently dominated by motorbikes. The city governments are about to develop buses. With the development of the Vietnamese economy, people would shift from motorbikes to cars. Two options, i.e. private or mass public transportation modes are facing Vietnam. Urban passenger travel presents unique challenges and opportunities if it is to contribute towards achieving GHG emission reductions. Private cars and motorbikes, often with only a single occupant, dominate a Contact by December 2003: Efficiency Adviser, Asian Development Bank, 6 ADB Avenue, Mandaluyong City, 0401 Metro Manila, The Philippines, email: mvan~(~,adb.ore. However, the viewpoints expressed in this article are solely those of the authors, and they do not represent those of the Asian Development Bank

1244 personal travel. However, compressed natural gas (CNG) vehicles release about one quarter less gasoline vehicles. Some of other noxious emissions are even less than this ratio.

C02

than

This paper presents emissions from various transportation fuels and vehicles, and shows city governments how to initiate economically sustainable and environmentally-friendly transportation modes by two case studies in China. In addition, the paper demonstrates how to access additional capital investment in transport sector via CDM from the developed countries to support sustainable development in developing countries. This paper is descriptive and experimental rather than academic research. It may interest policy makers in developing countries, who are less aware of climate change and urban passenger transportation efficiency. This paper will help them better understand how to reduce GHG emissions and local pollutions in developing their urban transportation systems.

V E H I C L E EFFICIENCY FACTORS Vehicles efficiency factors vary on the basis of different assumptions and methodologies. Generally speaking, buses are the most energy and GHG-emission intensive in per v e h i c l e - 1 0 0 km travel; but motorbikes and cars are the most intensive in terms of per-person per 100 km traveled. See Figure 1.

10

60 -[ ............................................................. 50 I

Gasoline and Diesel buses

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I

...........................................................

0 1990

1995

2010

2020

1990

1995

2010

2020

Source. Adopted and revisedfrom [2]

Figure 1: Average Fuel Efficiency Factors for Urban Travel (Canada)

The left hand chart in Figure 1 shows the energy intensity of buses, cars and motorbikes in Canada in 1999. Gasoline and diesel buses rank the highest in the range of 40 to 50 liters per 100 km traveled. The least energy intensive vehicle is the motorbike, consuming less than 10 liters per 100 km. Diesel and gasoline cars burn about 10 to 20 liters per 100 kin. However, in terms of per-person kilometer traveled, the order of energy intensities is reversed. The right hand chart of Figure 1 shows the energy intensity in liters per person per 100 km. We assume that all the vehicles are half loaded, i.e., 25 people for a bus, 2.5 for a car and one person for a motorbike. Then, energy intensity range order will be inverted when compared with the case in the left chart. The gasoline motorbike requires 7-9 liters per person-100 km travel, but a bus rider consumes no more than 2 liters. Diesel and gasoline cars are in the range between 4 to 7 liters per person- 100km. In Asia, mass transportation will be more efficient than the scenario described in the right chart, because buses in Asia are usually more than half-loaded and cars are less than half-loaded.

1245 EMISSIONS FROM FUELS TABLE 1 shows the weighted GHG emissions in moles of CO2 equivalent per vehicle-mile traveled (VMT) which is equal to the un-weighted quantity multiplied by the global warming potential per mole of each gas, relative to carbon dioxide. One can see that compressed natural gas (CNG) and liquefied petroleum gas (LPG) vehicles emit least GHGs among all the transportation fuels and alternatives. TABLE 1 WEIGHTED MISSIONS FROM FOSSIL FUELS (Unit: Moles of CO2eq per VMT (Weighted) Greenhouse Gas

Gasoline

Diesel

Compressed Natural Gas

Liquefied Petroleum Gas

Carbon Dioxide (C02)

7.9

7.88

5.64

Methane (CH4)

0.22

0.22

0.91

0.17

Nitrous Oxide (N20)

0.54

0.54

0.54

0.54

Nitrogen Oxides (NOx) CarbonMonoxide (CO)

1.06

1.06

0.99

0.99

0.97 0.97

0.92 0.98

Total

10.71

10.68

9.03

8.61

Source: Wang [3] a n d USEIA [4]; Note: one Mole contains 6.023 x 10e3 molecules or atoms

The above two sections show that buses are the most energy efficiency mode among all transportation means in terms of person-km traveled, and that CNG and LPG are the least carbon emitting fuels per vehicle mile traveled (VMT) if the fuels' GHG emissions are calculated in weighted moles. We would conclude that CNG and LPG buses are one of the best modes in urban passenger transportation. This argument is also supported by two case studies in China.

CASE STUDY 1: INTEGRATED TRANSPORTATION PLANNING IN XIAMEN A project was undertaken in 1997 aiming at solving the traffic congestion and air pollution problems in Xiamen by an integrated transportation planning. The project team analyzed policies adopted by the Xiamen municipal government to improve the transportation conditions and air quality. A detailed description of the project is available in Yang [ 1]. In the following, we present the key results of the study. Eight main components in the Xiamen's integrated transportation planning are presented: 1. Deciding system boundary; 2. Forecasting transportation demand; 3. Integrating all possible elements related to transportation system focusing on mass transportation and CNG vehicles; 4. Using access not just mobility; 5. Designing alternative scenarios; 6. Using linear programming model to carry out system optimization; 7. Evaluating planning results; and 8. Implementing the plan. Figure 2 shows the relationships and steps of the components. The following measures were adopted by the Xiamen municipal government to reduce vehicle transportation demand: 1. Improve the city outline plan for new city development zones. Tourism industrial facilities, commercial and entertainment facilities, schools and hospitals will be developed in each zone; 2. Design special transportation means for residential areas, where large trucks are not allowed to enter; 3. Focus on public transport development and establish alternative modes of transport. These include: pavement; bicycle lanes; bus lanes; high-occupancy vehicle lanes; integrate system with trains, bus and bicycles; pricing measures; and market based parking measures; 4. Leave lee-ways in road planning; 5. Build express roads across the city and high way around the city; 6. Reduce the number of one-way streets and roads; 7. Towing system should be pout into operation in the main roads of the city; 8. Adopt special

1246 policies to attract investment in transportation infrastructure, levy fuel consumption taxes and inspect vehicles regularly; 9.Levy high penalty on those whose vehicle tail gas does not meet the standards; 10.Construct parking lots with the development of new roads and buildings; and 11. Develop high efficiency and least carbon emission vehicle technologies in the city.

Decide S~tem

Design systemscemrios

Boundary lb. v

IVk~polilnnhegi~ Tmnsl:ortsyslem Demandforecesting Ton-kndpezson-tri~ In~gm~all p~s~le elements Iamd/EdtEalim/Imlm-triW/ commerciW...

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~ast costoptimizafions Li~r Pmgm_mmodel

Planningresulte~luation

O~inionof stakeholders

Access mtjlmtmobility Pho~ linterr~tlm~lsl ml~tmr~...

Figure 2: Methodological Framework for Integrated Transportation Planning

CASE STUDY 2 - COMPRESSED NATURAL GAS VEHICLES IN BEIJING In 1995 in Beijing, 800,000 vehicles daily produced an estimated 24,000 tons of CO1, 320 tons of hydrocarbons, 12 tons of oxides of nitrogen (NOx), 67 tons of non-methanol carbide, 24 kilograms of benzene and lead Guo [5]. The Beijing Municipal government manages about 70,000 fleet vehicles, 10% of total vehicles in Beijing in 1996. These fleet vehicles include buses, taxies, post trucks, and the trucks used by environmental and sanitary sectors and by Beijing transportation companies. A project team funded by the USEPA worked with North China Vehicle Research Institute, which would be willing to invest in gas filling station development and importing retrofitting technology from New Zealand. Detailed information on the project is available in Yang [6]. In the following, we briefly present the results: 1. 350 gas filling stations are needed in Beijing, and each feeds 200 at 500 M3/hr; 2. Using New Zealand (NZ) CNG Vehicle technologies to reduce conversion investment; 3. Comparing the NZ CNG vehicles with gasoline vehicles in Beijing: (1) CO reduced by 97%; (2) Hydro-carbon reduced by 72%; (3) NOx reduced by 39%; and (4) CO2 reduced by 25%; 4. GHG emission reduction for one gas fill station (for 200 vehicles) is about 39,000 tons of CO2 per year. Since 1997, CNG vehicles have been developing very quickly in Beijing. About one third of the city buses weas run by CNG engines in Beijing by September 20011.

i Source:Author's on-site surveyin Beijing in September2001.

1247 CDM FACILITATES CLEAN TRANSPORT

Clean Development Mechanism (CDM) is a modified version of Joint Implementation that was included in the Kyoto Protocol for project-based activities in developing countries. In Article 12.2 of the Protocol, the parties established the CDM for the purposes of assisting developing countries in achieving sustainable development and helping Annex B parties meet their emissions limitation and reduction obligations. Under the supervision of an Executive Board of CDM, private and public funds may be channeled through this mechanism to finance projects in developing countries. With CDM, countries co-operate in an emissions mitigation project in a developing country with the donor country acquiring the Certified Emission Reduction Units generated by the project while the host country benefits from the contribution of the project to sustainable economic development through investment in environmentally sound technologies. It is estimated that US$ 1.2 billion will be transferred as CDM funds from Annex B countries to the developing countries each year during the next decade. In the following, as an example, we present the willingness to pay of the government of Netherlands as a simple example of the funding source. Under the Kyoto Protocol the Dutch obligation is to reduce its GHG (green house gases) emissions by 6%, compared to the reference year 1990. Already in 1999 the Dutch government decided to score 50% of this obligation on a national level and the remaining 50% (125 million tonnes of CO2) abroad by application of the Flexible Mechanisms CDM, JI (Joint Implementation) and IET (International Emissions Trading) CERtYPT [7]. The government of Netherlands also is willing to pay the CER at the price of about US$ 4. See TABLE 2. If the Netherlands acquires the 125 million of CERs by CDM, the total funding source from the Netherlands will be about US$ 600 million. TABLE 2 WILLINGNESS TO PAY CO2 CREDIT BY THE NETHERLANDS GOVERNMENT CDM Projects Renewables energy (excluding biomass): Energy production by using clean, sustainable grown biomass (excluding waste) Enerb,y efficiency improvement Others, among which fossil fuel switch and methane recovery

Prices EUR 5.5 US$ 4.8 EUR: 4.4 US$ 3.8 EUR: 4.4 EUR 3.3

US$ 3.8 US $ 2.9

Source: CERUPT [8]; Note to exchange rate: On Feb 15, 2002, 1 EUR = 0.873 US$, Source: http ://goeurope.about. com/gi/dynamic/offsite.htm, 9site=http%3A %2F°/~2Fwww.x-rates.com%2 F

POSSIBLE CDM TRANSPORT PROJECT EXAMPLES IN ASIA

Substitution of passenger buses for motorbikes in main cities of Vietnam In Hanoi and Ho Chi Minh City, motorbikes are currently dominant in passenger transportation. As indicated early in this article, motorbikes are one of the most energy and GHG intensive means of transportation. Mass transportation system does barely exist in the two cities. If the city governments would develop mass transportation, CNG buses for instance, it will definitely benefit global and local environment conservation. Developing mass transportation needs to be well planned. Without a good plan, bus and train system may not be able to work due to traffic congestions. The development of bus lanes, regulations on the use and registration of motorbikes should go hand in hand. Consequently, an integrated transportation planning, followed by government policy and regulations on vehicle uses, and implementation of mass clean fuel vehicle development may be good steps for the municipal governments in Vietnam to adopt.

1248

CNG vehicle promotion in Bangladesh Bangladesh is rich in natural gas resources but short of petroleum supply. In 2000, Bangladesh imported about 58,400 barrels of oil per day [9]. Developing CNG vehicles will not only benefit environment, but also reduce burden of foreign currency expenditure. The government of Bangladesh is preparing to convert and replace about 100 thousand petrol and diesel vehicles with CNG vehicles. Evidently, CDM will add extra benefits to the CNG project and make the project financially and economically viable.

CONCLUSIONS

A survey shows that transportation modes from most energy efficient one to least efficient one are: buses, cares and motorbikes. Furthermore, CNG and LPG vehicles are the least emission technologies so far. We would say that developing CNG buses is one of the best options to promote environmental friendly urban passenger transportation for those countries where domestic natural gas resources are available. Two case studies show that the substitution of CNG vehicles for petrol or diesel vehicles will not mitigate GHG emissions but also benefit local pollution reductions. Government policies and regulations should have a good transport plan, encourage the use of mass transportation and discourage the use of private cars and motorbikes. CDM will facilitate advanced technology and fund transfer from the developed countries to the developing countries. It may change some financially distractive projects into attractive ones. Future CDM projects in Asia may include the substitution of CNG buses for motorbikes in major cities in Vietnam and CNG vehicle development in Bangladesh. CNG vehicles and CDM are motoring towards cleaner cities in Asia.

REFERENCES

Yang M., (1998) Transportation and Environment in Xiamen, Transportation Research D, Elsevier, UK, Vol. 3, No. 5, pp. 297-307. Hagler Bailly (1999), Strategies to Reduce GHG Emissions from Passenger Transportation in Urban Canada, Final report for National Climate Change Process, Transportation Table Passenger (Urban) Sub-group, Toronto Ontario. Wang M. (1995) Measurement of Emissions: Greenhouse Gas Estimates for Alternative Transportation Fuels, Unpublished final report prepared for the Energy Information Administration, Vienna, VA, December. USEIA (1993), Emissions of Greenhouse Gases in the United States 1985-1990, DOE/EIA-0573, Washington CD, September, p 15. Guo X. Y. (1996) Pre-feasibility of Developing Compressed Natural Gas Automobiles in Beijing, China North Vehicle Research Institute, Beijing Yang M.. Kraft-Oliver T., Guo X. Y. and Wang T. M. (1997), Compressed Natural Gas Vehicles Motoring Towards a Cleaner Beo'ing; Applied Energy, Elsevier, UK, Vol. 56, Nos. ¾, pp, 395-405. CERUPT (2001), Implementation of the Clean Development Mechanism by the Netherlands, Ministry of VROM, Netherlands. CERUPT (2001) Terms of Reference for CDM project development, Ministry of VROM, Netherlands. USDOE (2001), http://www.eia.doe.gov/emeu/cabs/bangla.html

NON-CO2 GASES

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1251

AN ASSESSMENT OF THE ABATEMENT OPTIONS AND COSTS FOR REDUCING THE EMISSIONS OF THE ENGINEERED CHEMICALS J. Hamisch l, J. Gale2, David de Jager 1 and Ole Stobbe l IECOFYS energy & environment, Eupener Str. 59, 50933 Cologne, Germany 2IEA GHG Programme, Stoke Orchard, Cheltenham, Gloucestershire, GL52 7RZ, UK

ABSTRACT

This work assesses the contribution to climate change resulting from emissions of the group of halogenated greenhouse gases. A bottom-up emission model covering 22 technological sectors in four major regions is described. For annual emissions of HFCs, PFCs and SF6 which are regulated under the Kyoto Protocol the relative contribution is projected to increase to 2% (600 MT CO2 eq.) of global greenhouse gas emissions by 2010. This trend is expected to continue, emissions are projected to grow to a contribution of roughly 3% (870 MT CO2 eq.) in 2020 compared to 0.9% (300 MT CO2 eq.) in 1996. For HFCs, PFCs and SF6 this study identifies global emission reduction potentials of 260 MT CO2 eq. per year in 2010 and 640 MT CO2 eq. per year in 2020 at below US$50 per ton. These values correspond to roughly 40% and 75% of projected emissions in 2010 and 2020, respectively. INTRODUCTION

This study covers the radiative impact of the following compounds: chlorofluorocarbons (CFCs), hydrochlorofluorocarbons (HCFCs), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), sulfur hexafluoride (SF6), halons and methyl bromide. For decades, these synthetic halocarbons have been widely used e.g. as refrigerants, blowing agents in foam production, propellants for aerosol applications, solvents, surfactants and fire-fighting. The non-ozone-depleting HFCs are progressively substituting CFCs and HCFCs in many of their applications, leading to rapidly growing emissions rates of HFCs. For this reason, and because of their atmospheric persistence, they have been included into the Kyoto-Protocol. PFCs and SF6 have also been included for the same reasons. Reilly et al. [ 1] have shown that a failure to control the growth of emissions of these gases can significantly increase the costs of compliance with the Kyoto Protocol as additional CO2 reductions have to be achieved in other sectors (such as power sector) to compensate for this growth. The direct global warming potentials I (GWP) of these gases range from a few hundred to more than 20,000 times CO2-equivalent, when calculated over a 100-year period [2]. Within the stratosphere, the chlorinated and brominated compounds are the prime causes of ozone depletion. This contribution to ozone depletion adds an indirect cooling to the radiative effect of these compounds. In the case of the so-called halons (bromofluorocarbons) and methyl bromide this indirect cooling effect by far outweighs the direct effect. The uncertainties associated with net global warming impact of these compounds are large [2, 3, 4]. In this study, the average ! Reportedas

C O 2 equivalents(CO2 eq.) based on the IPCC (2001) [4] globalwarmingpotentials(100 year period).

1252 value of the maximum and the minimum net-GWPs is used as the default GWP value for the ODS. THE M O D E L AND DERIVED SCENARIOS

The economic evaluation required a dynamic and detailed bottom-up emission model to connect emission projections to reduction options and associated costs. The current knowledge of emission levels for the gases is still fairly limited. There is virtually no database or emission model that would provide a consistent coverage for more than a few compounds. Neither do most existing emission inventories allow projections of future emission levels. Therefore, it was decided to develop an emission model for this study in order to have a consistent and transparent coverage of an extended number of emission sources from various sectors. The model was built for use in comparative mitigation assessments and not for applications in atmospheric sciences. It thus did not need to have a high spatial or temporal resolution or produce emission data for each individual species. Its main strength is a consistent link between past and future emission levels. The model provides a reasonable representation of different technological sectors, a technology oriented link between emission levels and abatement options and - last but not least a high degree of flexibility for modification of sector specific data like emission factors, growth rates, GWP data and alike. Fundamentally, the temporal evolution of emissions in this model is calculated as the product of an emission factor and a technological activity. Both are generally assumed to be time- dependent: the former due to "incremental" technological change (e.g. improved containment of refrigerant) and the latter through economic growth (e.g. increasing demand for domestic refrigeration) or major shifts between technologies (e.g. the switch between different classes of refrigerants). The emission model which was created for this study builds on the experience gained for a recent study for the European Commission [5]. It covers 22 different sub-sectors that contribute to emissions of the halogenated compounds covered by this study. These sub sectors include; commercial refrigeration, cold storage and food processing, industrial refrigeration, stationary air conditioning and heat pumps, transport refrigeration (road, rail, ship), heat pumps (for heating only), domestic and small commercial (hermetic) refrigeration, mobile air conditioning, extruded polystyrene (XPS), polyurethane (including one component foams), polyisocyanurate and phenolics, solvents, metered dose inhalers (MDI), technical aerosols, by-product emissions of HFC-23, primary aluminium production, semiconductor production, magnesium production, use of gas insulated switch gear, manufacture of gas insulated switch gear, fire-fighting, soil and fruit fumigation, manufacturing and distribution losses. Due to the generally poor spatial resolution of available activity data for most processes covered by this analysis it was decided to build it around only four major regions: North America (USA and Canada), Western Europe (European Union (EU-15), Norway, Switzerland, Iceland), Japan and Rest of World (Latin America, Oceania, Africa, Asia (excl. Japan), the Commonwealth of Independent States and the Eastern European Countries in Transition).The regions used are the same as in most of the recent United Nations Environmental Programme (UNEP) Technical Options Reports. By using this small number of regions it avoided the need to create, use and report so-called "proxy data" for certain regions and countries (e.g. according to their share of gross domestic product of a larger region). Such proxies, generally have a significantly higher uncertainty than the original values from technology inventories for the four major regions. In the past North America, Europe and Japan together have been responsible for by far the largest share of emissions (>80%) of the halogenated compounds with large regions such as China, India or Africa contributing comparably little despite their large populations. The model has been designed to derive emission estimates for three years (base year, 2010 and 2020) covering a period of roughly 25 years. As the base year is close to the present, the year 1996 was selected for which data coverage by the UNEP Technical Options Reports is most complete for almost all processes in which ODS have been used in the past. In a few instances the years 1995 and 1997 had to be used as the base year in certain sectors due to the lack of data for 1996. The resulting error, however, is very minor compared to the overall uncertainties of emission estimates in this field.

1253 The reference scenario which is calculated for the years 2010 and 2020 is set up to make conservative assumptions about technological progress, i.e. it avoids reliance on large autonomous emission reductions without a corresponding regulatory framework. In regions in which companies, through their actions, already anticipate future regulation on greenhouse gas emissions, this might lead to an overestimate of future emissions. As a result e.g. in the case of Europe, derived reference scenarios from this study result in higher projected emission levels than analyses specifically dedicated to the European Union [5, 6]. The choice of present and future emission factors is based on a number of relevant studies [5, 6, 7, 8]. However, many simplifications had to be made for reasons of practicability and limited data availability. The projected evolution of emission factors in the future was based on expert judgement since internationally no accepted standards exist for this purpose. Resulting uncertainties are accordingly fairly large. Assumptions on the evolution of emission factors and the baseline penetration of improved technologies are the main sources of uncertainties. Underlying economic growth scenarios for different regions and applications are generally of lesser importance. With only a few notable exceptions, uncertainties of emission estimates and projections will generally be as high as +50% on a 95% confidence level. This value is limited to estimates of emissions in terms of mass flows of substance. The conversion into hypothetical 100-year carbon dioxide equivalents increases uncertainties significantly especially for the ODS. The reference scenario has been designed under the assumption of full compliance with the Montreal Protocol in all regions. This study was not designed to assess the costs of an accelerated phase-out of ODS in one or several regions. Therefore, the model permits an emission abatement exclusively for non-ODS comprising the Kyoto-gases: HFCs, PFCs and SF6. However, it is important to keep in mind that a number of interactions do exist between the transitions under the Montreal Protocol and potential emission reductions under the Kyoto Protocol. For the purpose of this study it was not attempted to economically capture such effects. Instead a natural turnover of capital was assumed. The main abatement options comprise improved containment, use of alternative fluids, use of not-in-kind technologies and process modifications in the case of point sources. Please refer to Harnisch and Hendriks [5] for details. While ODS emissions rapidly decline until 2020, the gases regulated under the Kyoto Protocol exhibit a fairly steep increase from 1996 to 2020. They are projected to double between 1996 and 2010 and then grow by slightly less than another 50% until 2020 (300, 600, 870 MT CO2 eq., respectively). Assuming a stabilisation of emission levels of the greenhouse gases in the Kyoto basket at 1995 levels, HFCs, PFCs and SF6 will globally contribute about 2 % of CO2 eq. emissions in 2010 and grow to 3 % in 2020 compared to about 0.9% in 1996. ASSESSMENT OF ABATEMENT AND C O N T R O L OPTIONS The emission reductions are calculated on an annual basis. All cost data of this report are calculated as 1999 US$. Abatement costs were calculated from the sum of annualised investment costs and annual operating and maintenance costs divided by mean annual emission savings. The annual operation and maintenance costs were assumed to remain fixed over the depreciation period. The annualised capital costs are calculated by multiplying the total investment with the annuity factor. Investment costs were annualised over their lifetime (here 15 years are used as default value) at a discount rate of 5% per annum which is a value commonly used in a macro-economic analyses. However, this is well below discount rates used for commercial investment decisions (10-30% per annum depending on the specific industrycorrespondingly resulting in higher specific abatement costs). The cost information used in this study is taken from a database created as part of the analysis "Economic Evaluation of Emission Reductions of HFCs, PFCs and SF6 in Europe" [5]. The study contains a detailed description of most technological abatement options used in this study for the IEA GHG. Notable exceptions are solvents and technical aerosols for which cost estimates from March [6] and MDI for which cost data from Enviros [9] were applied. Leakage and recovery in fire-fighting is assumed to exhibit a comparable cost structure to commercial refrigeration.

1254 Generally, it is assumed that economic and technological conditions across the globe will be comparable to the situation in the European Union. In the short term, this assumption will obviously be violated in many developing countries and in the economies in transition. In the longer run, it currently seems very appropriate to assume a continuation of the ongoing economic and technological convergence across the globe. To limit the complexity of this analysis, generally only one abatement option was assigned to each of the 22 sectors modelled. Based on the experience from the study for Europe often the least cost option among several candidates was selected. Alternatively, a weighted mean from a number of options was calculated to appropriately address different sub-sectors as was the case for the fairly diverse field of polyurethane foam production or for aluminium production. The selection of a technological option is not intended to be prescriptive. It is fully recognised that a dynamic process of research and development is currently reshaping many of the sectors studied. Frequently, new approaches nowadays marginalise what seemed to be a dominant technology. With a timeframe of 20 years ahead, many of the proposed abatement options can only be intended as "backstops" i.e. giving an indication that the final technical solution cost will exhibit equal or smaller costs than the proposed approach. TABLE 1 OVERVIEW OF EMISSIONREDUCTIONPOTENTIALSFOR HFCs, PFCs AND SF6 1996

2010

Cost range a

Total emissi ons b

Total emissi ons b

Reduction potential b

2020

Cost range a

Total emissi ons b

Reduction potentiaP

<0 10-20 120-50 Region

<0 I 0-20 I 20-50

98

187

2

53

27

255

3

135

56

74

157

2

38

22

200

3

92

44

48

86

0

20

18

106

0

46

36

Rest of World

75

175

5

50

22

312

8

143

77

WORLD

295

605

9

161

89

873

14

416

213

North America Western Europe Japan

a Expressed as 1999 US$ per ton of CO2 equivalent Expressedas MT CO2 equivalents per year Table 1 gives an overview of the emission reduction potentials for different cost ranges in each of the regions. Figure 1 shows the globally aggregated marginal supply curves for 2010 and 2020. Above US$ 50 per ton of CO2 equivalent no estimates are given due to scarcity of data in the high cost range. On the global level this implies that in 2010 more than 40% of projected emissions can be abated at below US$ 50 per ton of CO2 eq. This share increases to over 75% in 2020. The regional variance of these values is significantly smaller than calculated for energy intensive processes like for example the iron and steel industry [ 10].

1255

/too ,

g 80 o

-~

60

40 20

~

o 0

200

100

300

400

500

600

700

800

Abated emissions [MT C02 eq per year]

Figure 1" Emission reduction supply curve for HFCs, PFCs and SF6 in 2010 and 2020

TABLE 2 COEFFICIENTSFOR EXPONENTIALLEASTSQUAREFITSTO ABATEMENTCURVES: MARGINALCOST [AS US$(1999)] = A x EXP(B x REDUCTION[AS MT CO2 EQ.]) 2010

2020

a=0.2984,b=0.0750, R2=0.91

a=0.6732, b=0.0256, R2=0.87

North America West. Europe

a=0.3281,b=0.0972, R2=0.91

a=0.7533, b=0.0341, R2=0.86

Japan

a=0.4853, b=0.1611, R2=0.86

a=0.6492, b=0.0687, R2=0.88

Rest of World

a=0.0793,b=0.1025, R2=0.89

a=0.4302, b=0.0252, R2=0.87

World

a=0.2281, b=0.0256, R2=0.91

a=0.5846, b=0.0082, R2=0.88

For convenient use in energy models (of the type of Reilly et ak[1]) Table 2 contains the parameters for exponential least square fits to the aggregated marginal abatement curves for HFCs, PFCs and SF6 in the model regions. Please note that the choice of the exponential regression curve represents a conservative choice, implying that for a number of applications in would be extremely costly to find non-emissive alternatives in the short to mid-term. ACKNOWLEDGEMENTS This article summarises the findings of the study: Harnisch, J., O: Stobbe, D. de Jager; Abatement of Emissions of Other Greenhouse Gases: "Engineered Chemicals"; Ecofys (Utrecht) undertaken for the International Energy Agency Greenhouse Gas R&D Programme (IEA GHG); Cheltenham, February 2001. REFERENCES

[1] Reilly, J. et al.; Multi-Gas Assessment of the Kyoto Protocol; Nature, 401, pp. 549-555, 1999. 2] IPCC; Climate Change 1995 - The second IPCC Scientific Assessment; Intergovernmental anel on Climate Change, World Meteorological Organization & Umted Nations Environmental Programme, Cambridge University Press, Cambridge, 1996. [3] WMO; Scientific assessment of ozone depletion: 1998; Global Ozone Research and Monitoring Project - Report No. 44, World Meteorological Organization, Geneva, 1999. [4] IPCC, Climate Change 2001 - The Third Assessment Report - Working Group 1, Cambridge, 2001. [5] Harnisch, J. and C.A. Hendriks; Economic Evaluation of Emission Reductions of HFCs, PFCs and SF6 in Europe; Directorate General Environment of the Commission of the European Union, Prepared by Ecofys energy & environment; Cologne, April 2000.

1256 C ] March; Opportunities to Minimise Emissions of HFCs from the European Union; ommissioned by Directorate General Enterprise of the European Commission; United Kingd..om, September 1998. [7] Oko-Recherche: 'Aktuelle und kianftige Emissionen treibhauswirksamer fluorierter Verbindungen in Deutschland', German Environmental Protection Agency, Germany, December 1996 [8] Oko-Recherche: 'Emissions and Reduction Potentials of Hydrofluoro-carbons, Perfluorocarbons and Sulphur Hexafluoride in Germany'; German Environmental Protection Agency, Germany, October 1999 [9] Enviros; Study on the use of HFCs for metered dose inhalers in the European Union; Commissioned by the International Pharmaceutical Aerosol Consortium (IPAC); Manchester, September 2000. [10] Gale, J. and Freund P.; "Greenhouse Gas Abatement in Energy Intensive Industries", Proceedings of the Firth International Conference on Greenhouse Gas Control Technologies published by CSIRO, pp. 1211-1216, 2001.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1257

POTENTIAL R E D U C T I O N OF F L U O R O C A R B O N EMISSIONS U N D E R THE E N F O R C E M E N T OF N E W LAWS IN JAPAN T. Hanaoka l, Y. Yoshida l, R. Matsuhashi 2 and H. Ishitani 3 Department of Geosystem Engineering, Graduate School of Engineering, The University of Tokyo, 7-3-1 Hongo, Bunkyo-ku, Tokyo, 113-8656, JAPAN 2 Department of Environmental Studies, Graduate School of Frontier Sciences, The University of Tokyo, 7-3-1 Hongo, Bunkyo-ku, Tokyo, 113-8656, JAPAN 3 Department of Media and Governance, Graduate School of Media and Governance, Keio University, Endo 5322, Fujisawa, Kanagawa, 252-8520, JAPAN

ABSTRACT The objective of this study is to evaluate the potential for reducing fluorocarbon emissions as a measure for the abatement of global warming by enforcing new laws: the Law for Recycling of Specified Kinds of Home Appliances [2001 ] and the Law for Recovering and Decomposing of Specific Fluorocarbons [2002]. In this study, we focused on the three different kinds of fluorocarbons: CFCs, HCFCs and HFCs, and targeted refrigerant use because of the availability of relevant data. We first estimated future fluorocarbon emissions from the targeted appliances; we next compared those emissions to the level of CO2 emissions in 1990 by the units of tons of CO2 equivalent. As a result of this study, it was found that fluorocarbon emissions in 2001 and 2010 would be equal to 6.6% and 2.7% of the level of CO2 emissions in 1990 respectively. Moreover, if we can implement a 100% rate of recovering refrigerants from appliances in every recovery route after enforcement of new laws, in the future between 2001 to 2010, we can reduce a large amount of emissions which correspond to 2.0 to 4.5 % of the level of CO2 emissions in 1990, even if we take into account the fluorocarbon leakage at the recovery stage as well as the energy-related CO2 emissions by using fuel in transportation and decomposition of fluorocarbons. INTRODUCTION

The Kyoto Protocol [1997] regulated the emissions of six types of greenhouse gases (GHGs): CO2, CH4, N20, hydrofluorocarbons (HFCs), sulphur hexafluoride (SF6), and perfluorocarbons (PFCs). Under the protocol, Japan committed a 6% reduction from the level of equivalent CO2 emissions in 1990. However, it is a difficult task for Japan to achieve this reduction target by reducing the energy-related CO2 emissions, as its energy efficiency has already reached the world's highest level. Therefore, by considering the large effects on global warming caused by fuorinated GHGs, measures for reducing emissions of non-CO2 GHGs can be regarded as one of the important strategies to comply with the Kyoto Protocol. The restrictions for emissions of chlorofluorocarbons (CFCs) and hydrochlorofluorocarbons (HCFCs) have been omitted in the Kyoto Protocol, because CFCs and HCFCs have already been regulated as ozone depleting substances (ODSs) under the Montreal Protocol [ 1987]. However, they are also chemically related anthropogenic GHGs and have a much larger impact on global warming than CO2. For example, global warming potential (GWP) of CFCs per unit of weight is about 4000 to 12000 times larger than that of CO2. Furthermore, with regard to HCFCs and HFCs which are alternatives to CFCs, GWP is about 500 to 3000 times larger than that of CO2. Therefore, CFCs and HCFCs have effects on global warming as well as ozone depletion. The important point to note is that the production of CFCs was abolished by the end of 1995 in developed countries; however, appliances that contain CFCs are still in operation in Japan. Thus, recovering fluorocarbons becomes an important measure for the abatement of global warming. Therefore, the purpose of this work is: (a) to forecast the future emissions of fluorocarbons: CFCs, HCFCs and HFCs in Japan, and (b) to evaluate the potential for emission reductions by enforcing the new laws as measures for abating global warming as one of the strategies to comply with the Kyoto Protocol.

1258

D E F I N I T I O N O F DATA

ASSUMPTIONS

Definition of End Use Categories In this study, CFCs, HCFCs, and HFCs are targeted because of their widespread use and the availability of relevant data. Fluorocarbons are used for various purposes. For instance, CFCs, HCFCs, and HFCs are used as refrigerants, foams for thermal insulation and shock absorber, solvents, aerosol propellants, etc. We will focus on refrigerant use, not only because refrigerants account for 20 - 60 % of the total production [ 1] of CFCs, HCFCs and HFCs, but also because it is relatively simple to introduce devices for recovering refrigerants from each appliance. We focused on the following appliances shown in Table 1, which were provided as targets by new laws: the Law for Recycling of Specified Kinds of Home Appliances [2001 ] and the Law for Recovering and Decomposing of Specific Fluorocarbons [2002]. However, the refrigerants in these appliances represent 30 - 50% of the total refrigerant use, while refrigerants in air conditioners are also widely used in airplanes, trains, ships, etc. Because of the difficulty in gathering relevant data on the amount of hermetic refrigerants in appliances, they are not considered in this study.

Cate~:o~ Refrigerator Air conditioner

Refrigerator and air conditioner for business use

TABLE 1 END USE CATEGORIES OF REFRIGERATOR AND AIR CONDITONER Classification Detail Refrigerator Household refrigerator Air conditioner for motor vehicles Automobile air conditioner Truck air conditioner Bus air conditioner Air conditioner for houses Small air conditioner Medium-and-large air conditioner Central air conditioning equipment for buildings Single-packaged-type air conditioner Centrifugal-type air conditioner Reciprocating-or-screw-type air conditioner Condensing unit Refrigerating unit for transportation Condensing unit Freezing-and-refrigeratingunit Refrigerating display case Self-contained-type refrigerating display case Remote-condensing-unit-type refrigerating display case Freezer, Ice maker, Drinking water cooler Vending machine for beverage

Detailed Data of Appliances The detailed data, such as lifetime of appliances, hermetic refrigerants per appliance, initial refrigerant, alternative refrigerant, are described in Table 2 and Table 3. However, we assumed these data under the following conditions: a) The amount of hermetic refrigerants per appliance is different in size and its efficiency even though they are in the same category. Therefore, we use average data reported by experts from various user industries [2, 3]. b) In the category of air conditioners for motor vehicles and for houses, household refrigerators, we estimate their average lifetimes as follows: 1) estimating the number of stock appliances in the market by using the weible distribution model, 2) comparing the estimated values to statistical data on stocks, 3) determining the lifetime by using the least squares method. With regard to the other appliances, we refer to the average lifetime reported in reference [2] because of the unavailability of statistical data on stock appliances in the market. In the future, there is a possibility of using new alternative refrigerants, for example, the HFC-blended refrigerants or the non-fluorinated refrigerants such as Hydrocarbons (HCs). However, these alternatives are still uncertain and not in the mainstream in the market; thus, we assume that the present alternative refrigerants will be kept in the future. TABLE 2 DATA OF TARGETED APPLICANCES WITE INITIAL REFRIGERANTS OF HCFC s Targeted equipment Equipment Hermetic Initial lifetime [year] refrigerant[kg] refrigerant Small air conditioner 11.2 0.7 HCFC-22 Medium-and-large air conditioner 11.2 0.83 HCFC-22 Single-packaged-type air conditioner I0 5.4 HCFC-22 Reciprocating-or-screw-type air conditioner 15 30 HCFC-22 Remote-condensin$-unit-type refri~eratin~ display case [for refrigerator] I0 7 HCFC-22

Alternative refrigerant R410A R410A R410A HFC type HFC type

1259

TABLE 3 DATA OF TARGETED APPLIANCES WITH REFRIGERATNS OF CFCs Initial Alternative refrigerant refrigerant CFC-12 HFC-134a Household refrigerator (refrigerant) CFC-11 HCFC-141b Household refrigerator (blowing agent) CFC12 HFC-134a Automobile air conditioner CFC-12 HFC-134a Truck air conditioner CFC- 12 HFC-134a Bus air conditioner CFC- 11 HCFC-123 Centrifugal-type air conditioner R-502 HCFC-22 Refrigerating unit for transportation [for freezer] CFC-12 HFC-134a 2.7 Refrigerating unit for transportation [for refrigerator] R-502 HCFC-22 Half-opened-type condensing unit CFC-12 HCFC-22 10 2.2 Closed-type condensing unit R-502 HCFC-22 10 2 Freezing-and-refrigerating unit [for freezer] CFC- 12 HCFC-22 10 2 Freezing-and-refrigerating unit [for refrigerator] R-502 HCFC-22 1.7 Self-contained-type refrigerating display case [for freezer] CFC-12 HCFC-22 10 0.45 Self-contained-type refrigerating display case[for refrigerator] R-502 HCFC-22 14.4 Remote-condensing-unit-type refrigerating display case [for freezer] CFC-12 HFC-134a 0.4 Freezer CFC-12 HCFC-22 Ice maker 8 0.3 CFC-12 HFC-134a Drinking water cooler 10 0.1 CFC-12 HCFC-22 7.5 0.3 Vending machine for beverage Note: In this study, refrigerant use is in focus. However, we discuss blowing agent of closed-cell-foam for thermal insulation in the category of household refrigerator because of availability of relevant data. Equipment lifetime [year] 12.0 12.0 11.1 8.0 11.8 25

Targeted equipment

Hermetic refrigerant [kg] 0.15 0.6 0.75 0.75 4.2 420

Environmental Impact: GWP Values When we take into account the effects of global warming by fluorocarbon emissions, it is counted in units of "ton of CO2 equivalent (mass multiplied by global warming potential)" with the radioactive impact value of Global Warming Potential (GWP) over a certain time horizon. GWP values of refrigerants in end use categories are described in Table.4. In this study, we use the 100-year GWP values [4] which are assumed as the standardized values by Intergovemmental Panel on Climate Change (IPCC). TABLE 4 ENVIRONMENTAL IMPACTS

EMISSION ESTIMATE METHODOLOGY Estimation o f Future Production In order to calculate the overall release rates of fluorocarbons, the time delays between production and emission need to be estimated for each category and each end use. Appliances of these products are grouped into categories according to the time scale of their emissions into the atmosphere. We refer to the reports [2, 3] consulted by experts from user industries in order to make appropriate groups of categorization. In this study, we first estimate the future production of appliances. We assume that the production of appliances [6, 7, 8] is affected by GDP. However, we also need to take into account that the appliances in focus will be mainly affected by other factors, such as substitution to other appliances. Therefore, the future production X t is described by the following linear regression equation:

x oX-=--t-A' ( 6DPo P' ) ~(~o) A •

Constant value

a " Elasticity of GDP,

r " Elasticity of alternative production

... (1)

1260 Y: Production of other appliances that affects the targeted appliance X

Xo, Yo, GDPo: Data in the first year Estimation of Future Emission By using production data Xt, we next estimate the future emissions of fluorocarbons from the appliances. We assume that the weibul distribution model, which is often used as the methodology of lifetime modeling in statistics, applies to the lifetime of these appliances. In this model, the remaining appliance rate R(r-7") in r [year], which is sold in 7' [year] with an average lifetime T [year], is shown as equation (2). R ( r - y) = exp[-L(m)(~-~-~-) m ] where

L(m) = {F(1 + L ) } m

...(2) ...(3)

in

in : The weibul parameter When we regard S r as the production of a certain appliance in y [year], the total waste W~ in r [year] is calculated by adding wastes from the appliance which is produced in each year before the year r. Therefore, fluorocarbon emissions from refrigerant use can be estimated by means of multiplying the number of wastes Wr by the amount of hermetic refrigerants per appliance.

let = £ {Sr x { R ( r - r ) - R ( r + l - r ) } }

... (4)

g=t o

where

to: Data in the first year

Recovery Ratio of Refrigerants We define the recovery rate of refrigerants C r as the following equation: C r -- Cap X C e f

where

... (5)

Cop • Implemented rate of recovering refrigerants from appliances Cef : Technical efficiency of recovering hermetic refrigerants per appliance.

Though technical efficiency Cef represents "the feasible efficiency of recovering hermetic refrigerants per appliance under the practical technique at present", recovering efficiency can be raised by improving the technical efficiency of a recovery-device and extending the operation time of recovering. In this study, we refer to the data on technical recovering efficiency based on the practical technique, which is estimated by experts from user industries [2, 8, 9].

Estimation of C02 Emissions by Energy Consumption In this study, we estimate CO2 emissions by energy consumption during the transportation and decomposition of fluorocarbons. By collecting the questionnaires, we assume transportation conditions which describe the means of transportation and the average distance from recovery places to decomposing facilities, and we estimate CO2 emissions during the transportation based on these data. On the other hand, when we consider energy consumption during the decomposition of fluorocarbons at decomposing facilities, energy consumption is different at each facility, as are their decomposing techniques. In this study, we estimate CO2 emissions during decomposition by assuming that a Rotary Kiln Incinerator is used as a major decomposing facility

RESULTS AND DISCUSSION

Emissions of Fluorocarbon Fluorocarbon emissions in tons from the targeted equipment are shown in Figure 1. The emissions converted into tons

1261 of C O 2 equivalent are shown in Figure 2. CFCs have been replaced by HCFCs and HFCs under the regulation of the Montreal Protocol, and the production of CFCs had been already abolished by the end of 1995. Therefore, as Figure 1 indicates, the emissions of initial refrigerants, i.e. CFCs, will decrease in the future; on the other hand, the emissions of altemative refrigerants such as HCFCs and HFCs will increase. However, it was found that the emission of HCFCs would decline after the peak in 2008 because HCFCs would be also replaced by HFCs. Moreover, when we take into consideration the effect on global warming in Figure 2, total fluorocarbon emissions in CO2 equivalent sharply decreased after the peak in 1997, because emissions from initial refrigerants, i.e. CFCs which have much larger scales of GWP than HCFCs and HFCs, have declined since 1995. This figure shows that prompt action for preventing CFC emissions will have effective results in the short and middle term for the abatement of global warming and recovering CFCs should be completed before 2010. Thus, recovering fluorocarbons should be introduced immediately and accurately, and it takes higher priority than other measures such as energy efficiency innovation or energy saving, which usually takes a long time to show results. Within the Kyoto Protocol, Japan committed a 6% reduction from the level of CO2 emissions in 1990. Therefore, when we compare the total fluorocarbon emissions in each year to the level of CO2 emissions in 1990, fluorocarbon emissions in 2001 and 2010 are equal to 6.6% and 2.7% of CO2 emissions in 1990 respectively. In addition, it was found that the total fluorocarbon emissions will be stable after 2010, and it corresponds to approximately 2.5% of CO2 emissions in 1990. Thus, from a quantitative point of view, recovering fluorocarbons has a significant effect and this measure has a potential for emission reductions in order to fulfill the Kyoto Protocol, if we include CFCs and HCFCs.

r 25 ~1

~ CFCs - - . - - HCFCs ~ HFCs

• L_~-~,..yo~a!.........

o 20

F

90

!

80

-.4 ~

70

~-

,

i

~CFCs --~--- HCFCs ~ HFCs

!

~

Total

~15 50

~lO

40 30

",,~

_

~5

20

,-r

I

--~

t4 r -

10 o

0 1990

1995

2000

2005

2010

2015

2020 year

Figurel: Fluorocarbon Emissions in tons

1990

1995

2000

2005

2010

2015

2020 year

Figure 2: Fluorocarbon Emissions in tons of CO2 equivalent

A 100 % Recovery Rate by Enforcement of New Laws Several investigations about policy implementation of recovering fluorocarbons have been reported by the government. When we estimate fluorocarbon emissions from the targeted appliances by referring to the result [10], which reports the policy implementation of the actual recovery rate before enforcement of new laws, fluorocarbon emissions in 2000 are equal to 5.8% of the level of CO2 emissions in 1990. There is no governmental report about detailed statistical data on the actual recovery rate after the enforcement of new laws: the Law for Recycling of Specified Kinds of Home Appliances [2001 ] and the Law for Recovering and Decomposing of Specific Fluorocarbons [2002]. Therefore, we calculate emission reductions in the most progressive case at a 100% implemented rate of recovering refrigerants from appliances. In addition, we take into account the fluorocarbon leakage at the recovery stage as well as the energy-related CO2 emissions by using fuel in transportation and decomposition. The results of emission reductions of fluorocarbons in CO2 equivalent are described in Table 5. Compared to fluorocarbon emissions in CO2 equivalent, the energy-related CO2 emissions by transportation and decomposition of fluorocarbons account for only a small ratio of total CO2 emissions. Therefore, by recovering fluorocarbons, we can reduce a large amount of emissions in CO2 equivalent which correspond to approximately 2.0 4.5 % of the level of CO2 emissions in 1990, if we can implement 100% of recovery rate in every recovery route. However, as table 5 indicates, we cannot disregard the effect of leakage rate at the recovery stage; thus, when we discuss measures for abating global warming, it is important to diminish the leakage at the recovery stage as well as to

1262

improve implemented rate of recovering refrigerants from appliances in the market. TABLE 5 THE ESTIMATED EMISSION REDUCTIONS UNDER A 100% IMPLEMENTED RECOVERY RATE CO2emissions by transportation Fluorocarbon leakage The amount of Category of equipment at recoverystages and decomposition recovered fluorocarbons [106 t-CO~] [ 106t-CO2eq] [106 t-CO2eq] 61.45 Air conditioner for motor vehicles 0.1153 92.12 6.30 0.0197 Household refriBerator(refriBerant) 25.19 Household refriBerator(thermal insulation) 12.13 0.0703 48.51 47.36 0.1437 71.04 Air conditioninB for houses 1.23 0.0173 I1.10 Central air conditioninBequipment 41.74 0.0546 10.44 CondensinB unit Refrigerating displaycase 17.78 0.0270 11.85 307.52 0.4479 150.75 Total Note) Data in each category indicates the sum of emissions from 2001 to 2010 CONCLUSIONS In this study, we focused our attention on the effect of fluorocarbon emissions on global warming, and estimated future emissions from the targeted appliances which use fluorocarbons as refrigerants, and evaluated the potential for emission reductions as measures for abating global warming as one of the strategies to fulfill the Kyoto Protocol. These results lead to the conclusion as follows: (!)

(2)

When we compare fluorocarbon emissions from 2001 to 2010 with the level of CO2 emissions in 1990, the emissions in 2001 would be approximately equal to 6.6%, and those in 2010 will be equal to 2.7% of CO2 emissions in 1990, respectively. Even though we take into account the energy-related CO2 emissions by transportation and decomposition of fluorocarbons, we can reduce a large amount of fluorocarbon emissions in CO2 equivalent which correspond to approximately 2.0 - 4.5 % of the level of CO2 emissions in 1990, if we implement 100% of recovery rate in every recovery route.

In the future, it will be necessary to raise recovery rate immediately in order to reduce fluorocarbon emissions. Therefore, it is important to reinforce the recovery system in the market and to prevent leakage at the recovery stage by improving the efficiency of recovery-devices. In conclusion, for abating global warming, it is indispensable not only to restrict the production of fluorocarbons, but also to recover fluorocarbons from appliances. Moreover, it is important to perform those measures in developing countries as well as in developed countries. Therefore, the measures for reducing fluorocarbon emissions should be implemented with intemational cooperation. REFERENCES 1. Japan Fluorocarbon Manufactm'es Association, The production data of CFC, HCFC and HFC in each use and each category (in Japanese). Tokyo 2. Japan Refrigeration and Air Conditioning Industry Association, The Working Group of Recovering and Recycling Fluorocarbon, (1993). The Investigative report on fluorocarbon consumption in refrigerant use and feasibility of recovery (in Japanese). Tokyo. 3. New Energy and Industrial Technology Development Organization, (1997). The investigative report on the trend of alternative fluorocarbons as measures for mitigating global warming (in Japanese). pp. 109-113. Tokyo. 4. Japan Fluorocarbon Manufactures Association, The data of environmental impact and safeness of fluorocarbons (in Japanese). Tokyo 5. Japan Refrigeration and Air Conditioning Industry Association, (1980-2002). HVAC&R Data book (in Japanese). Tokyo. 6. Japan Electrical Manufactures Association, (1970-2002). The domestic production data on household electrical appliances (in Japanese), Tokyo 7. Japan Automobile Manufactures Association, (1970-2002). Monthly statistical data on motor vehicle (in Japanese).

Tokyo 8. Ministry of International Trade and Industry, Chemical Deliberative Council, Ozone Protection Group, (1997). The report on future measures for recovering CFC: an interim report (in Japanese). Tokyo. 9. Environment Agency, Air Quality Bureau, Planning Division, Wide Area Atmospheric Protection Office, (1996). The investigative report on model cases of recovering and decomposing of fluorocarbons (in Japanese). Tokyo. 10. Ministry of the Environment, Air Quality Bureau, Planning Division, (2001). The investigative report on recovering fluorocarbons in 2000 (in Japanese). Tokyo.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1263

DIRECT GLOBAL W A R M I N G EMISSIONS FROM FLAT PANEL DISPLAY M A N U F A C T U R I N G AND REDUCTION OPPORTUNITIES Scott C. Bartos I and C. Shepherd Burton 2 U.S. Environmental Protection Agency, 1200 Pennsylvania Ave. NW (6202J) Washington D.C. 20460 2 2047 Huckleberry Road San Rafael, CA 94903

ABSTRACT

The U.S. Environmental Protection Agency (EPA) has worked with the semiconductor industry to reduce perfluorinated compounds (PFCs) emissions since 1995. Semiconductor manufacturers commonly use several PFCs such as CF4, C2F6, SF6, and NF3 to create, on silicon wafers, the intricately patterned layers of insulating and conducting materials. These gases are the strongest and most persistent greenhouse gases currently known contributing to global warming for many generations. Flat panel display (FPD) fabrication is a rapidly growing electronic sector that also uses and emits PFCs in processes similar to those used in semiconductor manufacturing. EPA is evaluating PFC use and emissions from FPD fabrication processes and seeking to develop emission reduction technologies and transfer successful gas management strategies from semiconductor manufacturers. Of the many FPD technologies, it appears only Active Matrix Liquid Crystal Displays (AMLCDs), also called Thin Film Transistor (TFT) LCDs, use PFCs. TFT LCD production is expected to grow at greater than 20% compound annual growth rate (CAGR) through 2010. This paper investigates PFC emissions from this rapidly growing sector and explores public/private partnership opportunities that may expedite emission reduction efforts.

INTRODUCTION

The long-term socioeconomic and environmental challenges presented by global climate change have motivated governments, including the United States, to take actions to stabilize and reduce anthropogenic greenhouse gas emissions. The world's leading climate scientists expect a global temperature increase of 1.4 to 5.8°C by 2100 to cause system wide changes including elevated sea level, increased risk of damage to crops, more intense precipitation and flooding, and an extended range and activity of pest and disease vectors (IPCC, 2001). The U.S. Environmental Protection Agency (EPA) is working together with industries through voluntary partnerships to reduce emissions of greenhouse gases. EPA's Non-CO2 Gases and Sequestration Branch manages several such partnerships with industries that use and emit the strongest greenhouse gases; the perfluorocarbons, hydrofluorocarbons, and sulfur hexafluoride (SF6)(collectively termed perfluorinated compounds (PFCs) for this discussion). Table 1 lists the global warming potentials (GWPs) and atmospheric lifetimes for some of the most common electronic chemicals.

1264 TABLE 1 ATMOSPHERIC CHARACTERISTICS OF CO2 AND PERFLUORINATED COMPOUNDS (PFCs)

Compound

Atmospheric (Years)

Lifetime

Global Warming Potential (100-year time horizon) A 1 1,300

200 C02 HFC-134a 14.6 10,000 9,200 C2F6 6,500 CF4 50,000 NF3 B 740 10,800 3,200 SF6 23,900 A IPCC, 1995 - 1995 values agreed upon in Kyoto Protocol and used for EPA's partnerships. B IPCC, 2001 - values for NF3 were not availableduring IPCC's 1995 assessment. One of EPA's most ambitious voluntary partnerships is with semiconductor manufacturers. PFCs are critical during semiconductor manufacture of microprocessors, memory chips, digital signal processors and many other integrated circuits (ICs). International collaboration between government and the semiconductor industry led the World Semiconductor Council (WSC) in 2000 to voluntarily establish a goal to reduce PFC emissions by 2010 to 10 percent below 1995 emission levels. PFCs are also used to manufacture fiat panel displays (FPDs). In this paper, we discuss parallels between PFC use and emissions during FPD and semiconductor manufacture, in order to explore their potential relative contributions to global warming. We provide, for the first time, estimates of PFC use and PFC emissions from FPD manufacture. We also identify actions that can reduce PFC emissions from FPD manufacture.

PFC USE AND THE FLAT PANEL DISPLAY INDUSTRY Semiconductor manufacturing materials, equipment and methods have enabled the commercial success of FPDs, particularly those that employ active matrix liquid crystal display (AMLCD) technology. Virtually all FPDs used in laptop computers, desktop monitors, video monitors, cell phones, digital cameras, handheld computers and personal digital assistants (PDAs) are made on large glass plates. During AMLCD manufacture, the glass is the substrate on which an array of thin-film-transistors is fabricated to control the individual pixels (three TFTs per pixel) that form the image of the display. As in semiconductor manufacturing, PFC gases are critical to the FPD industry's plasma-based etching and CVD cleaning processes. Through at least 2010, both application of and demand for TFT-LCD technology are likely to grow dramatically. The driver for this growth is replacement of the cathode ray tube (CRT) technology used in TVs and other displays. (DisplaySearch, 2001; Stanford Resources, 2002). Since 1998, the TFT-LCD (or AMLCD) manufacturing capacity increased 4.5 times, a compound average growth rate (CAGR) of 45 percent through 2002. For the next five years, industry analysts forecast TFT-LCD capacity to grow at a 25 percent CAGR; forecasts beyond 2007 are not published. By 2007, Stanford Resources forecasts TFT-LCD manufacturing capacity will equal but 30 percent of the total direct-view (desktop monitor and TV) manufacturing capacity, which CRT technology currently dominates. If TFT-LCD manufacturing costs continue to drop as anticipated, FPD market analysts expect TFT-LCD technology will replace the CRT TV, providing opportunity for continued if not accelerated growth. Additional high volume markets for the TFT-LCD technology are PDAs, mobile phones, digital cameras and automotive displays. Based on these factors, we expect the capacity growth of TFT-LCD now underway will not fall below double-digit growth rates through 2010 c. c Of the FPD technologies touted as competition for TFT-LCD's dominance and therefore PFC use, industry analysts believe the only contenders are the relativelymature plasma displaypanel (PDP) technologyand the relativelyyoung emissive organic light emitting diode display (OLED) technology. PDP manufacture does not use PFCs and competes only in the very-large display-size applications, representing <5% of forecasted production capacity of direct-view manufacturing technologies (Stanford Research, 2002) . Pixels in active matrix OLEDs will be driven with TFTs should the technology become competitive. We conclude that PFC use in FPD manufacture will be neither increased nor decreased by PDPs or market acceptance of OLED technologyin active matrix displays.

1265 AMOUNTS

OF PFCs USED DURING

FPD MANUFACTURE

Most FPD manufactures use similar TFT and LCD fabrication processes in which deposition and etching processes produce an intricate pattern of transistors on glass substrates. (Bardsley, 2002 and WTEC, 1992). Plasma enhanced chemical vapor deposition (PEVCD) and dry etching processes- so prevalent in semiconductor manufacturing - improve TFT-LCD yields and factory throughput, as well as provide the lower process temperatures required for large-display manufacture. These and other factors are contributing to the large growth in TFT-LCD substrate capacity, which by 2005 is projected to exceed 95 percent of the semiconductor substrate capacity. To date, alternatives to PFCs have not been identified for commercial application in either semiconductor or TFT-LCD manufacture. However, technologies to reduce PFC use and/or PFC emissions from semiconductor and TFT-LCD manufacture are commercially available (Worth, 2000). Despite the comparable sizes of the substrate capacities of TFT-LCD and semiconductor industries, considerably more PFCs are used in semiconductor manufacturing. PFC sales figures indicate that in 1995 world semiconductor industry used approximately 4.4 million pounds (Burton, 1997). For the same year, we estimate that world PFC use in LCD manufacture was approximately 70,000 pounds (Burton, 2002). Figure 2 presents the expected growth in PFC use by the semiconductor and TFT-LCD manufactures for the period 1995 - 2005. The estimates in Figure 2 indicate that PFC use by TFT-LCD manufacturers will grow from approximately 1 percent of semiconductor use in 1995 to approximately 6 percent in 2005. The higher transistor densities and circuit complexity explain why greater volumes of PFC gases are consumed in IC manufacturing process as compared to FPDs. The transistor density, for example, of a Pentium 4 chip (217 mm 2 with 47 million transistors and 7 wiring levels) exceeds the corresponding density of a 15" laptop display more than 5,000 times (1024 by 768 pixels with 3 transistors per pixel, or 2.4 million transistors on a single layer).

100,000,000

10,000,000

0 u. o.

1,000,000

100,000

10,000

F-ii~SS-~-2-O~)-0-d=dos,

_ .........

]

Figure 2" Comparison of PFC Use in TFT-LCD and Semiconductor Manufacturing, 1995 - 2005 Nevertheless, the gap in use can be expected to narrow somewhat as TFT-LCDs move to higher resolution or larger panels, or both.

Industry reports indicate use of N-F3, CF4, C2F6 and SF6 in FPD manufacture, with C2F6, CF4 and NF3 being the gases dominantly used. NF3, like C2F6 and CF4, is used to clean PECVD chambers after deposition of thin dielectric films in both semiconductor and TFT-LCD manufacture. FPD manufacturers appear to prefer NF3 to C2F6because chamber cleaning time is shorter and emissions are lower with NF3.

1266 Interestingly, the rapid growth in TFT-LCD capacity from 1995 - 2000 produced shortages of NF3; currently NF3 demand and supply seem balanced with demand expected to grow at 46 percent CAGR through 2004 and supply at 48 percent CAGR over the same period (SEMI, 2000). Estimated Emissions

PFC Emissions from semiconductor and LCD manufacture result from PFC gases passing unutilized through the process equipment. Such emissions can be quantified using estimates of gas consumption and utilization, which is performed annually by the semiconductor industry (WSC, 2002 and Beu and Brown, 1998). For the period 1995 - 2005, Figure 3 depicts a preliminary estimate of world PFC emissions (in lbs.) from TFT-LCD manufacture. Three cases are considered for three alternative kinds of process gases: (1) only C2F6 is used in chamber cleaning, (2) both C2F6 and CF4 are used in equal amounts; and (3) only NF3 is used. For each case, the proportion PFC used in etching is kept to 20 percent of the total, and no variation of etch gas composition is considered. We assume gas utilization in semiconductor and LCD manufacture is identical. For comparison, PFC emissions from semiconductor manufacture are also presented under a business-as-usual situation together with the semiconductor PFC emissions reduction goal established in 2000 by the WSC. Qualitatively speaking, it appears that by 2010, PFC emissions from TFT-LCD manufacturing could exceed the WSC goal. Further research and analysis are required to refine these numbers, however.

100,000,000

10,000,000

o E '"

1,000,000

Q.

<

t00,000

10,000 1995

2000

2005

Year

[

BAll C2F6

B50:50 C2F6-CF4

~AII NF3

K] Semiconductor

]

Figure 3- Comparison of PFC Emissions from TFT-LCD and Semiconductor Emissions, 1995-2005 EMISSION REDUCTION ACTIVITIES AND TECHNOLOGIES Leading FPD manufacturers recognize their contribution to PFC emissions. In July 2001, representatives from the world's largest TFT-LCDs manufacturing companies agreed through its World LCD Industry Cooperation Committee (WLICC) to make "...efforts to reduce PFC emission through fair and equitable burden and active information exchanges, adopting effective approaches toward implementation of global warming countermeasures." (www.jeita.or.jp/english/press) Member-companies of the WLICC as of July 2001, through their respective trade associations, are Sharp Corp., Hitachi Ltd., Toshiba Corp., NEC Corp.,

1267 Samsung Electronics Co. Ltd., LG.Phillips LCD Co. Ltd., and Acer Unipac Optoelectronics. Together, these companies account for 56 percent of the TFT-LCD world manufacturing capacity in 2002. (DisplaySearch, 2002) Companies are also taking individual action. AKT, a joint venture between Applied Materials, Inc. and Komatsu Ltd., provides Remote Clean technology on PECVD systems used to make TFT-LCDs. The Remote Clean TM employs NF3 with a utilization efficiency of> 99 percent. AKT recently shipped its latest Generation 5 AKT-15K PECVD system to LG.Phillips, which also reduces NF3 consumption by 30 percent relative to its Generation 4 10 K PECVD system. Samsung Semiconductor also recently reported that it reduced the amount of NF3 gas by 23 percent at its Chuan TFT-LCD plant by shortening the time for chamber cleaning. (www.samsungelectronics.com/semiconductors/esh activity/processes.html) Jointly developing and sharing reduction technologies with the semiconductor industry may achieve additional emission reductions. Examples of such promising cross-over technologies include (1) using c-C4F8 as a drop-in alternative chamber cleaning gas for C2F6, (2) capture and reuse of PFCs from the exhaust stream, and (3) catalytic thermal or plasma abatement before release to the atmosphere.

CONCLUSIONS

The rapidly growing FPD manufacturing industry has the potential to emit significant amounts of PFC gases, possibly exceeding the semiconductor industry's emissions by 2010. Voluntary partnerships between industry and governments are successfully identifying and implementing PFC emission reduction technologies in Asia, Europe, and the United States. EPA's collaboration with semiconductor manufacturers provides a model of a public/private initiative yielding benefits both to business and the environment. FPD manufacturers are encouraged to form similar collaborative partnerships with governments and voluntarily reduce emissions of these long-lived heat-trapping pollutants. The opportunity exists today for many of the PFC emission reduction technologies developed through the semiconductor industry partnership to be transferred and applied to similar FPD manufacturing processes, saving the FPD industry time and money while protecting the climate.

REFERENCES

1. Bardsley, J. N. 2002. "International OLED Technology Roadmap: 2001 - 2010," presented at Flat Panel Display (FPD) Manufacturing Conference, Session 2: OLED Manufacturing, SEMICON West2002, July 19, 2002, San Jose, CA. 2. Beu and Brown, 1998. "An Analysis of International and U. S. PFC Emissions Estimating Methods", presented at A Partnership for PFC Emissions Reductions, SEMICON Southwest, Austin, TX. October 19, 1998. 3. Burton, C. S. 1997. "Analysis of World and US PFC Sales Data for US EPA Based on Surveys Conducted by DataQuest and Rose Associates", Memo to file, October 1997. 4. Burton, C. S. and Beizaie, R. 2001. "EPA's PFC Emissions Vintage Model (PEVM) v.2.14: Description and Documentation", ICF Consulting, 60 Broadway St., San Francisco, CA.94111. 5. Burton, C. S. 2002. "Analysis of PFC Use Data for EPA Based on PFC Surveys Provided to US EPA by EIAJ", Memo to file. 6. DisplaySearch, 2001. "FPD and Capital Equipment Market Outlook", presented at Flat Panel Display (FPD) Seminar, SEMICON West2001, July 17, 2001, San Francisco, CA. 7. DisplaySearch, 2002. Flat Panel Display Fabs on Disk, January 2002 Edition, Copyright 2002. 8. Intergovemmental Panel on Climate Change, Climate Change 2001: Impacts, Adaptation, and Vulnerability, 2001. (Available at www.ipcc.ch/pub/wg2SPMfinal.pdf). 9. SEMI, 2000. "Nitrogen Trifluoride: A 'Hot' Gas in the Battle against Global Warming", SEM1 Industry Research & Statistics, November 2000. (Available at www.semi.org)

1268 10. Stanford Resources, 2002. "Creating the OLED Market: Balancing Supply and Demand", presented at Flat Panel Display (FPD) Manufacturing Conference, Session 2: OLED Manufacturing, SEMICON West2002, July 19, 2002, San Jose, CA. 11. Vritis, R. N. and Cao, J. 2001. "In-Situ Chamber cleaning of Low-K Films in a 200 mm DxZ Chamber", presented at A Partnership for PFC Emissions Reductions, SEMICON Southwest, Austin, TX. October, 15,2001. 12. Worth, W. 2000. "Reducing PFC Emissions: A Technology Update", Future Fab International, Issue 10, p. 57 (2000). 13. WTEC, 1992. "Manufacturing, Infrastructure and Equipment for AMLCDs", ITRI, Loyola University, Loyola College of Maryland, see www.wtec.org for report.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1269

N E W A L T E R N A T I V E GAS PROCESS FEASIBILITY STUDY FOR PFC EMISSION R E D U C T I O N F R O M S E M I C O N D U C T O R CVD C H A M B E R C L E A N I N G Tatsuro Beppu 1, Yuki Mitsuil, Katsuo Sakai 1 and Akira Sekiya2 Semiconductor CVD Chamber Cleaning Project, Research Institute of Innovative Technology for the Earth (RITE), Japan 2Research Center for Developing Fluorinated Greenhouse Gas Alternatives, National Institute of Advanced Industrial Science and Technology (AIST), Japan

ABSTRACT

Activities, results and concepts of the Semiconductor CVD Chamber Cleaning Project are introduced and reviewed in the present paper. The project target is a new alternative gas process development and feasibility study for PFC emission reduction from the semiconductor CVD chamber cleaning process. This project focused on construction of a complete system providing performance higher than that of the conventional systems by selecting an alternative cleaning gas with a low GWP value and shorter lifetime in the atmosphere, PE- CVD processes and abatement systems. As a result, some scenarios are shown, according to this guideline, namely systems using COF2, F2, CF3OF and process optimization. Considering the usage volume, a safe system should be constructed, coveting every phase from production, delivery, and storage to consumption. From this viewpoint, COF2 is a leading contender for use in the next-generation of semiconductor mass-production processes. Using a production-scale evaluation tool for the PE-CVD, cleaning performance evaluation was executed for the COF2/O2 cleaning system and a good result was obtained.

INTRODUCTION

Global action to cope with global warming is progressing and has been attracting great attention, from the Rio Earth Summit and United Nations Framework Convention on Climate Change (1992) and The Third Conference of Parties to FCCC (1997, COP3, Kyoto Protocol) to the Johannesburg Summit. According to the Kyoto Protocol, "Policy statement to cope with Global Warming" was issued in Japan in 1998. In this statement, alternative fluorocarbons and other gases (HFC, PFC and SF6) emission suppression was determined as one measure to cope with global warming. This statement outlines plans for the industrial to suppress such emissions, and the development of alternative materials as part of a national project. Based on this statement, the Semiconductor CVD Chamber Cleaning Project's 5 years program was launched (Oct., 1998) ~). The project's formal name is "Research and Development of Semiconductor CVD Chamber Cleaning Systems for Electronic Device Manufacturing using New Alternative Gas instead of SF6 and PFCs". Fluorine atom-containing gases such as PFCs and SF6 are used as Plasma Enhanced Chemical Vapor Deposition (PE-CVD) chamber cleaning gases for removing the SiO2 or Si3N4 deposited on the inner walls of CVD chambers that are used to deposit thin film insulation on silicon wafer during the mass production of semiconductor LSIs. These gases have large global warming potentials (GWP), four orders higher than that

1270 of C 0 2 , and very long lifetimes in the atmosphere. The efforts to develop the technology for the gas emission suppression started circa 1994 (2). The Semiconductor CVD Chamber Cleaning Project's approach involves the development of a new alternative cleaning gas system valid for the reduction of global warming gas emissions from the semiconductor manufacturing process, by selecting a gas with a lower GWP value. For this development, co-operation within the semiconductor device manufacturing industry, semiconductor equipment fabrication industry and the chemical industry is essential. This co-operation was achieved within the framework of a national project. The World Semiconductor Council (WSC) established the 2010 PFC emission reduction target of 10%, using 1995 as the base year. The project's mission is to develop the technology to support the progress of industry toward achievement of this reduction target.

RESEARCH THEMES AND RESULTS There are four research themes: the fundamental properties of CVD cleaning gases, a new alternative c v D cleaning gas, a new CVD cleaning process, and overall evaluation• The results achieved so far for each of these four research themes are presented below.

Research on the Fundamental Properties of CVD Cleaning Gases In the semiconductor mass-production process, SiO2 or Si3N4 thin films are deposited on Si wafer using PECVD machine. Plasma cleaning with the fluorine containing gases of CVD chamber inner wall after the deposition is essential to keep the Si LSI production yield. For this cleaning, hexafluoroethane C2F6 or 300

200

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i

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F i g u r e 1: Temperature dependence of the etch rates of PE-CVD SiO2 film and PE-CVD Si3N4 film in the case of remote plasma etching using F2 (10%) / Ar, NF3, C2F6 (50%) / O2or C3F8(50 o~)/O2 3)

,-,

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Figure

2" Correlation of relative F-atom density and SiO2 etching rate. 4)

1271 nitrogen trifluoride N F 3 has been used conventionally. Using these standard gases, the plasma decomposition reaction was observed, with exhaust gas species observation by Fourier-Transform Infrared Spectrometer (FTIR), Optical Emission Spectrometer (OES), Quadrupole Mass Spectrometer (QMS), etc. From these observations and etching performance observations, essential characteristics necessary for the cleaning gas have been surveyed. NF3 has been regarded as a gas for which a new gas with small GWP value should be substituted. As a result, it was reconfirmed that the important chemical species working as an active agent in the cleaning process is the fluorine atom (radical) o, 4). Figure 1 shows the experimental results; these confirmed that the active chemical species from the different molecules have the same etching activation energy in the remote plasma system (3). Figure 2 shows the linear relationship between the fluorine atom concentration observed by OES and the etching rate for the SiO2 in the capacitively-coupled plasma system (4)

New Alternative CVD Cleaning Gas Development In the present project, research on a new alternative CVD cleaning gas has been proceeding, including research on chemical species which are well known but not used as cleaning gases. In the case of alternative gas candidates that cannot be supplied commercially, the importance of chemical gas synthesis increases. So, a collaborative scheme between RITE and the National Institute of Advanced Industrial Science and Technology (AIST) has been established and the project's Tsukuba laboratory was set up within the premises of AIST. Selection of new alternative gases from numerous chemical species is very troublesome, even when candidates are limited to materials that include fluorine atoms. So, a database for the evaluation of molecules containing fluorine atom has been constructed. Evaluation points are cleaning performance, reactivity with atmosphere components, reaction exhaust gas reactivity and handling safety. First, from the boiling point database, the number of species to be evaluated was reduced to about 700. From these 700 species, about 100 species were selected from the viewpoint of their handling safety and other characteristics. For these selected chemical species, evaluation rating has been performed. For the chemical species that received a high rating, etching performance has been evaluated using experimental plasma equipment. By

I CF3OF/O 2 NF3 / AJ ~

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100%

Gas Concentration(vol%)

Fig~3 Evaluation ofCOF 2 , F 2 ,CF3OF 5-8) this evaluation procedure, 24 attractive species have been selected for more precise evaluation. As a result, it was revealed that carbonyldifluoride COF2 ~5), nitrogen fluoride oxide F3NO (6), trifluoromethyl hypofluorite CF3OF ~7)and fluorine F2 ~8) have a possibility of suppressing global warming gas emission

1272 drastically, provided these gases are used under particular conditions. Etching performances for these gases are shown in Fig.3. Horizontal axis shows the concentration of the examined gas against the oxygen or argon used as diluting gas. For the molecules including carbon atom, cleaning performance appears together with the mixing condition with oxygen. However, in the case of F2 and reference gas NF3, oxygen mixing is unnecessary. So, Ar was selected as the dilution gas. As revealed in this figure, COF2 shows etching performance of a level similar to that of the conventionally used cleaning gas C2F6, but the exhaust gas global warming potential is improved drastically (5). Etching performance of F2, shown in the same figure, is also notable (8). Although at low concentration of less than 40%, F2 and NF3 show very similar etching performances, these gases shows very different performances at high concentration. In the case of NF3, as the concentration increases, it is difficult to sustain plasma sustaining. As a result, etching performance does not improve. On the contrary, plasma instability at high concentration was not observed for the F2 case. As the result, etching performance increases linearly up to 100%. This result suggests that F2 has the potential to provide a cleaning performance twice as effective as that of NF3. Although the physical meaning of the difference is not revealed, the following conjecture is made. In the case of plasma fed with F2 molecules, generated F atoms and F ions do not recombine without an energetic relaxation process. On the contrary, in the case of NF3, many fragments of molecular structure, NF, NF2 and ions of these fragments, should be generated in its plasma. These fragments can recombine with F atoms or ions with the molecular vibration mode relaxation process. The situation of CF3OF is located between COF2 and F2. In the case of this molecule, O-F chemical bond energy is low, and so release of F atom is easier than in the case of other PFC molecules. CF30 radical easily emits F atom to generate COF2 instantaneously. This simulation corresponds with the observed results. The high performance of fluorine molecule at low dilution condition was considered to be of great interest. However, to realize the cleaning condition, high concentration F2 delivery is necessary. The oxidation reaction of F2 molecules is so furious that it is very dangerous if it is handled incorrectly. Of course, the toxicity is high. So, in order to utilize F2 in the semiconductor device manufacturing industry, it is necessary to develop a new additive technology that utilizes the superior performance of F2 without revealing the bad characteristics of F2. Also, for CF3OF and COF2, it is important to prepare procedures for safe handling safely corresponding to the reactivity of these molecules. COF2 is a well-known material produced in the reaction exhaust gas of C2F6and 02 in the PE-CVD chamber cleaning process. Thanks to its hydrolytic characteristics, construction of an abatement system is relatively simple. In the present project, COF2 has been judged to be the most attractive candidate alternative to the conventional cleaning gas C2F6 and NF3. So, in the present fiscal year, a marathon test using mass production line level PE-CVD machine and a task force working on ways of ensuring the safe usage of COF2 are progressing. As mentioned above, conventional cleaning gases C2F6, NF3, SF6, etc. have very large GWP values, and very long lifetime in the atmosphere, and so this project focused on the construction of a complete system construction providing performance higher than that of the conventional systems by selecting an alternative cleaning gas with a low GWP value and shorter lifetime, PE-CVD processes and abatement systems. This is a very unique feature of this project. As a result, some scenarios have been shown in accordance with this guideline.

New CVD Cleaning Process Research The third research theme of the project is a new CVD cleaning process. Although research on a process is proceeding at Tsukuba with the use of plasma evaluation equipment, substantiated evaluation using mass production line level PE-CVD machine is necessary. So, the equipment was introduced into the clean room of the project's Totsuka laboratory in November 1999. Using this machine, the insulator thin film PE-CVD on 8-inch Si wafer and chamber cleaning were performed successively for multi-wafer automatic processing. For this PE-CVD system, alternative gases were introduced for evaluation. Evaluation points are the time for the cleaning measured with OES monitoring for the chamber plasma, or FTIR monitoring for the exhaust gas species.

1273

1~o%

lOO%

NF3+Ar

NF3+He

NF3+N2

C2F6

COF2

C3F8

C4F8

CLEANING GAS

Figure 4: In-situ CCP Cleaning Results (P-SiO film) (9) As shown in Fig.4, good result have been obtained for COF2 using the PE-CVD machine (9). It was found that cleaning time using COF2 is equivalent to that using a conventional gas, and that the quantity of global warming gases emitted was reduced to approximately 1% of that in the case of using a conventional C2F6/O2 gas. Exhaust gas environmental load is denoted with the MMTCE (Million Metric Ton Carbon Equivalent) per process in this figure. Regarding the applicability decision of the COF2/O2 system to a real LSI mass-production line, particle generation observation in the marathon run is to be an important information. The results of the preexamination are shown in Fig.5. Particle generation is suppressed to a low level. A marathon run of 1000 wafers was programmed. In the middle of this run, particle generation occurred due to abnormal discharge. Although the data was split into two pieces, a good result was confirmed for the particle generation for the initial 250 wafers and for the latter 350 wafers. From these results, a condition required to use COF2/O2 cleaning gas system for a real production line, was deduced to be clarified. The cleaning equipment systems mentioned so far all use the same capacitively coupled plasma (CCP) electrode for the insulator thin film deposition. In addition to these results, a remote plasma cleaning system, conventionally used for NF3, was surveyed for PFCs, as shown in Fig.4. The figure indicates that PFCs showed performance comparable to that of NF3 in the case that certain revisions were made to the system. In the present project, PE-CVD hardware was considered to be a part of the cleaning process.

Cleaning set time : 120 [sec] P a r t i c l e S i z e : > 1.0 [ m i c r o n ]

4o

m a x -- 2 5 , m e a n = 13.8

3o < u. O

2o

A

i

r

,

3

, 5

(

~ 7

i

J 9

i

A

I1

:

i

i

13

A

15

i 17

J

J

L

19

,

i

21

, 23

WAFER NUMBER Figure

5:

Particle

COF2

numbers

in situ CCP

for 24 wafers cleaning

9)

running

test with

i

1274

Overall Evaluation The fourth part of the project is an overall evaluation to examine objectively the preceding three parts. Multiple choices in the matrixes of cleaning gas materials, hardware designs including abatement systems for exhausted gases, and process designs are examined. In this examination, a cleaning system superior to the conventional one is clarified through a process of total optimization. The selection of materials with small GWP values leads inevitably to the selection of a gas with reactivity. Chemical inactivity and handling safety of conventionally used PFCs will be deteriorated by this selection. However, the selection will indicate the direction in which technical development should proceed in order to arrive at low cost abatement of the undestroyed cleaning gas in the exhaust gases. If the alternative cleaning gas were substituted for the conventional cleaning gases, the total volume of gas usage be huge. Considering the volume, it would be necessary to construct a safety system coveting every phase from production, delivery and storage to consumption. From this viewpoint, COF2 is a leading contender for use in the massproduction process for semiconductor devices. CONCLUSIONS This project is in its final fiscal year, the year to March 2003. Already, in the course of the project, some candidate new CVD chamber cleaning systems have been selected. At present, research on issues concerning safe usage and the cost of ownership is nearing completion. Kyoto protocol is now to increase its existence as a treaty. So, the WSC target to decrease the PFC gas emission 10% by 2010 compared to the benchmark year of 1995, will or should turn toward the eventual target toward zero-emission of artificial chemical materials that cause deviation from the environmental balance. At the same time, production of high-performance LSIs at low cost can be expected to remain as an important objective. So, the authors think that it is essential to continue the global effort toward the higher targets. ACKNOWLEDGEMENTS The authors are grateful to all the researchers and staffs participating in this project. They are also indebted to the New Energy and Industrial Technology Development Organization (NEDO), the Ministry of Economy, Trade and Industry (METI), the Japan Electronics and Information Technology Industries Association (JEITA) and RITE for support extended throughout this work. REFERENCES 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13)

Beppu, T., (2000), 7th Annual International Semiconductor Environmental Safety and Health (ISESH) Conference, Dresden, Germany. Maroulis,P., Langan,J., Johnson,A., Ridgeway, R. and Withers,H.,(1994), Semiconductor International, 17, (13),108. Mocella,Michael, T., (1994), Proceedings of the 1994 MRS Spring Meeting. Beu, L. and Brown, P.T., (1998), 23ra IEEE/CMPT International Electronics Manufacturing Technology Symposium, 277. Wani,E., Sunada, T., Suzuki, S., Kosano, Y., Mitsui, Y., Takaichi, T., Beppu, T. and Sekiya, A. (2000), Electrochemical Society Proceedings of the 1st International Symposium on The Global Climate Change Proc. 2000-20, 221. Suzuki,S., Wani, E., Sunada, T., Shibata, K., Morimura, T., Mitsui,Y., Kosano, Y., Takaichi, T., Beppu, T. and Sekiya, A., (2000), Electrochemical Society Proceedings of the 1st International Symposium on The Global Climate Change Proc. 2000-20, 231. Mitsui,Y., Kosano, Y., Takaichi, T., Beppu, T. and Sekiya, A. (2001), 8th Annual International Semiconductor Environmental Safty and Health (ISESH) Conference, Kenting, Taiwan. Fukae,K., Mitsui, Y., Tomizawa, G., Sekiya, A., Takaichi,T., Beppu, T.,(2001) ACS Meetings 15th Winter Fluorine Conference, St. Petersburg, USA. Tomizawa,G., Mitsui, Y., Fukae, K., Kosano, Y., Tamura, M., Sekiya, A., Takaichi,T., Takase, T. and Beppu, T., (2001) 79th Spring Conference of Chemical Society of Japan. Ohira,Y., Mitsui, Y., Yonemura, T., Tamura, M., Sekiya, A., Sakai, K., Takase, T., Takaichi, T. and Beppu, T., (2002) 81st Spring Meeting of Chemical Society of Japan. Tanaka, K., Mori, I., Mitsui, Y., Sekiya, A. and Beppu, T., (2002), 49th Spring Meeting of Japanese Applied Physics. Ohira, Y., Mitsui, Y., Yonemura, T., Sakai, K., Takaichi, T., Takase, T., Beppu, T. and Sekiya, A., (2002) 9th Annual International Semiconductor Environmental Safety and Health (ISESH) Conference, San Diego, USA. Okura, S., Shibata, K., Murata, H., Mitsui, Y., Sakai, K., Beppu, T. and Sekiya, A., (2002) 9th Annual International Semiconductor Environmental Safety and Health (ISESH) Conference, San Diego, USA.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1275

RD&D IMPLICATIONS OF M U L T I G A S RADIATIVE F O R C I N G S C E N A R I O S

D. Beecy l, V. Kuuskraa 2, and P. DiPietro 3 ~U.S Department of Energy, Office of Environmental Systems, 19901 Germantown Road, Germantown, MD 20874-1290 USA 2 Advanced Resources International, 1110 N. Glebe Road, #600, Arlington, VA 22201 USA 3 Energetics Inc., 901 D Street, SW, Suite 100, Washington, DC 20024 USA

ABSTRACT Increasing attention is being focused on identifying the critical role of anthropogenic radiative forcing greenhouse gases, beyond CO2. Much of this interest stems from a series of papers in which Dr. James Hansen and his joint authors present an "alternative scenario for climate change in the 21 st century". In this paper, we discuss some of the technology implications of this "alternative scenario" and how successful RD&D may expand the set of technology options for reducing emissions of radiative forcing gases. Of particular importance are stopping the growth in CO2 emissions and seeking new solutions for significantly reducing non-CO2 greenhouse gas emissions. Emphasis is given to methane (the second most important greenhouse gas) and to the development and application of improved technologies for controlling methane emissions in the energy sector. INTRODUCTION

Recently completed studies argue for incorporating "climate or radiative forcing" greenhouse gas emissions for assessing global climate change i. While there is no single sufficient measure and the search for better approaches continues, these studies set forth arguments that radiative forcing should be used more widely than is the case today. Our own look shows that using radiative forcing can have significant implications on how one addresses the threat of climate change. As discussed by Manne and Richels ii, using radiative forcing becomes particularly important for cases where the rate of change in temperature is more of a concern than its absolute change. This paper examines the implications for the DOE Carbon Sequestration R&D Program of using radiative forcing for examining alternative pathways for stabilizing GHG emissions and global temperature. BACKGROUND

In mid-2000, Dr. James Hansen of the Goddard Institute for Space Studies with several colleagues wrote the i

Fuglestvedt, Jan S., Bemtsen, Terje K., Sausen, Robert and etc.. "Assessingmetrics of climate change, current methods and future possibilities". CICERO,December2001.

ii

Manne, A.S., and R.G. Richels, 2001: An Alternative Approachto Establishing Trade-OffsAmong GreenhouseGases, Nature, 5 April 2001, 675-677.

1276 article "Global Warning in the 21 st Century: An Alternative Scenario ''iii. The article was published in the "Proceedings of the National Academy of Sciences" and was broadly reviewed and critiqued as being controversial and potentially harmful to on-going discussions on climate change. Much of the criticism was based on an interpretation, by some, that Hansen was proposing a shift away from CO2 and other fossil fuel emissions toward a focus on reducing non-CO2 greenhouse gas emissions, namely methane, nitrous oxide, high GWP gases, and black carbon (soot). A closer reading of Hansen's "altemative scenario" article, and as further emphasized in Hansen's "An Open Letter on Global Warning" published in Natural Science iv, shows that Hansen recommended a balanced set of actions, involving both reductions of non-CO2 emissions and stabilizing of CO2 emissions. His stated goal for the alternative scenario was to limit human-made radiative forcing to about 1 watt/m 2 in the next 50 years. This scenario, plus rigorous further study of climate forcing factors and the carbon cycle, would allow time for progress in technology development and would provide information on adjusting emission reduction goals as understanding advances. As such, Hansen's "alternative scenario", while more stringent in its articulated goals, is philosophically consistent with the Administration's recently announced initiatives on global climate change (http://www.whitehouse.gov/news/releases/2OO2/O2/climatechange.html)to slow the growth of greenhouse gas emissions and eventually stop and reverse this growth -- and on its increased emphasis on non-CO2 emissions. IMPLICATIONS OF USING RADIATIVE FORCING VS. CARBON EMISSIONS The implications of using radiative forcing rather than just using equivalent carbon emissions and atmospheric concentrations for assessing climate change are significant: • First, radiative forcing introduces a criteria that more directly links human-source greenhouse gas emissions with their effects on climate change, Figure 1. • Second, using radiative forcing increases the near-term priority for addressing non-CO2 GHG emissions, such as methane, nitrous oxide and soot to a position equal with addressing CO2 emissions. (Longer-term, the priority would still be on reducing CO2 emissions.) • Third, a focus on radiative forcing would tend to shorten the critical time flame for action, to the first half of the 21 st Century (the next fifty years) rather than to the second half of the century or beyond, as posed by other climate change investigators. Radiative forcing is measured in watts per square meter, where 2 Watts, the approximate impact of past human-source GHG emissions in the atmosphere, is a heating of the earth's surface as if two miniature 1-Watt Christmas tree bulbs have been place on every square meter of the earth's surface. It is also equivalent to an increase in the brightness of the sun by about 1%. The current impact of non-GHG accounts for about one half of the radiative forcing emitted into the atmosphere from the year 1750 to year 2000, as shown on Figure 3. RADIATIVE FORCING AND EMISSIONS Hansen sets forth an altemative to the business as ususal (BAU) scenario that would lead to much less radiative forcing and thus only moderate climate change in the next 50 years. Compared to a BAU scenario that would add 3 Watts/m 2 by 2050, the "alternative scenario" Hansen, J., Sato, M., Ruedy, R., Lacis, A. and V. Oinas, 2000: GlobalWarming in the Twenty-firstCentury: An

Alternative Scenario, Proceedingsof the NationalAcademyof Sciences of the United States of America, vol.97, no. 18, 9875-9880. iv

Hansen, J., "An Open Letteron GlobalWarming", Natural Science, October 2000.

1277 would add only 1 Watt/m 2 during this time. Both of these would be in addition to the 2+Watts/m 2 of human-source radiative forcing already in the atmosphere. As shown in Figure 2, the "alternative scenario" would be achieved by limiting the increase of CO2 forcing to 1 Watt (from 2 Watts in the BAU) and by reducing non-CO2 GHG forcing to 0 (from 1 Watts in the BAU) by year 2050. Non-CO2 GHG emissions (particularly methane) would be significantly reduced. Anthropogenic emissions of CO2 would remain about the same as they are today, with a 2050 target for atmospheric carbon concentration of 445 ppm, a growth of 75 ppm from current levels. The overall aim is to keep added radiative forcing in the next 50 years at 1 Watt/m 2, and thus constrain the average global temperature increase to 3/4Ec (1.4EF). IMPORTANCE OF ADDRESSING NON-CO2 EMISSIONS Emissions of non-CO2 GHGs in the U.S. have increased in the past ten years, as shown below in Table 1. The units are teragrams of carbon-dioxide equivalent (Tg CO2 Eq.), using 100 years as the factor for calculating equivalent time-integrated radiative forcing. The numbers are from the most recent COz equivalency factors used in the Third IPCC Assessment Report (TAR). TABLE 1 u.s. NON-CO2GHG EMISSIONS(TG CO2 EQ.) 1990 1995

2000

Methane (CH4)

713

720

673

Nitrous Oxide (N20)

370

401

406

91

98

125

Total

1,174

1,218

1,204

% Total GHG

19.0%

18.7%

17.1%

High GWP Gases (HFCs etc.)

Source: IPCC Third Assessment Report (TAR) G WPs

A review of U.S. non-CO2 emissions from 1990 through 2000 (in Table 1) shows the following significant trends: • Methane emissions, the dominant non-CO2 GHG, have declined by 40 Tg C02 Eq., due primarily from increased mine degasification in coal mines (28 Tg CO2 Eq.), from increased landfill gas collection (11 Tg CO2 Eq.), and from reduced emissions from natural gas and petroleum systems (11 Tg CO2 Eq.). • Reduced methane emissions have been countered by increased emissions of N20 of 36 Tg CO2 Eq. and of High GWP gases of 34 Tg CO2 Eq. Increased use of fertilizer in agriculture and substitution of HFCs and PFCs for ozone depleting CFCs are responsible for these increases. Past actions by EPA's Natural Gas Star, Coal Mine Methane Outreach and Landfill Methane Outreach programs have contributed greatly to reductions in methane emissions. IMPORTANCE OF USING A SHORTER TIME HORIZON Using a 100 year GWP factor, non-CO2 gases account for about 17% of total GHG emissions on a CO2 equivalent basis. However, using shorter, 20 to 50 year (rather than 100 year), time

1278 horizon for establishing the equivalence of non-CO2 gases with CO2 significantly increases the impact of two of the non-GHG gases -- methane and HFC-32 -- on current and near-term climate forcing, as shown below in Table 2: TABLE 2 EQUIVALENCEFACTORS FOR NON-CO2GHGs 100 Year Factor 20 Year Factor Carbon Dioxide (CO2) I Methane (CH4)

1

1

23

62

Nitrous Oxide (N20)

296

275

HFC-32

550

1,800

Source." IPCC ThirdAssessment Report (TAR) GWPs

REDUCING THE RATE OF T E M P E R A T U R E CHANGE

1. Reducing Methane Emissions Currently, the estimated methane-based climate forcing is estimated at 0.7 Watts/m 2, approximately one-half as large as that for CO2. This includes both the direct forcing of 0.5 Watts/m 2 and an indirect forcing of 0.2 Watt/m 2. (Indirect forcing results from the effects of oxidized methane on cloud cover (H20 in the stratosphere) and on tropospheric ozone.) As such, this non-CO2 greenhouse gas deserves considerable attention. The "alternative scenario" sets forth a goal for a 30% reduction for methane-based radiative forcing, by reducing the concentration of methane in the atmosphere to 1,400 ppb from the current level of 1,740 ppb. This would contribute to a negative forcing of 0.21 Watts/m 2 in the next 50 years, bringing estimated methane-based radiative forcing in year 2050 to 0.5 Watts/m 2 (equal to the expected impact from the Kyoto Protocol). For this, the required reduction in anthropogenic methane emissions is about 25%, from current levels.

2. Domestic Sources o f Methane Emissions The three largest sources of anthropogenic, energy related methane emissions - - landfills, natural gas and petroleum systems, and coal mining - - all lend themselves to actions with economic benefits that may help defray a portion (or all) of the costs. • Landfill methane (with 204 Tg CO2 Eq. in 2000) can be collected and used for power generation and process heat, providing potential revenues. (Even if the methane is only combusted, the reduction in climate forcing is substantial). Regulations issued in 1996 require the largest U.S. landfills to begin collecting and combusting their landfill gas to reduce emissions. Currently, approximately one third of potential landfill methane emissions are avoided by flaring the methane or by capturing the methane emissions and converting them to energy. • Fugitive emissions from natural gas and petroleum systems (with 138 Tg CO2 Eq. in 2000) can be eliminated (or captured) providing increased natural gas sales, as have ben reported by BP, Williams and others. • Methane adsorbed within coal seams and surrounding rock strata (with 61 Tg CO2 Eq. in 2000) can be captured by pre-drainage ahead of mining and by mine degasification, offering an economically valuable by-product. Currently, 36 Bcf of methane, equal to nearly 30% of all underground coal mine methane emissions, is recovered (and productively used) by mine degasification programs.

1279 3. R&D and Technology for Lowering Methane Control Costs. The cost of reducing CH4 emissions from coal mining, from fugitive emissions during oil and gas production, and from methane (and CO2) emissions from landfills can be much less than the cost of achieving comparable climate forcing reductions from CO2. This is because many of the methane reducing actives provide economic benefits, with certain of them being economically selfsustaining. To achieve further cost-effective methane emissions reduction, US DOE's Fossil Energy managers are looking to initiate significant R&D activities in this area. In addition to reducing domestic methane emissions, with advanced technology the U.S. could achieve even more impact by supporting methane reduction actions in developing and market-transition counties. SUMMARY Adding radiative forcing to currently used GHG emissions and atmospheric concentration measures can provide valuable insights for establishing priorities for climate change technology initiatives and R&D. One such insight is giving additional emphasis to research programs and technologies that would lead to lower costs and greater efficiencies for reducing emissions of methane. Successful R&D in reducing methane and other non-CO2 GHG emissions may buy time for developing cost-effective technology that could lead to longer-term, deep reductions in CO2 emissions without significantly impacting economic growth and welfare.

Emissions (E) (002, CH 4, N20, HFC, PFC .... )

1

I Atmospheric Concentrations (el I

1

Radiative forcing (RF)

I

1

Climate Change Temperalure ('~T), p~cipitation (~p), sea level ('~SL)

1

Impacts Agriculture, ecosystems, energy production, social effects

1

Damages Welfare loss (e.g. monetaryunits)

Figure 1: Emissions to Climate Change to Damages. (Modified from Fuglestvedt and others, 2001)

1280 Business-As-l.lsuaJ Icenario

2W

CO 2

Ot~er Gases

3W

Alternative II©enar~

!

I

o

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Other Gases

c==3, 1W

Figure 2: Additions to Anthropogenic Radiative Forcing, 2001 to 2050. (Modified from Hansen, 2000)

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Figure 3: Global Radiative Forcing of the Climate System, Year 2000 Relative to 1750. (Modified from IPCC 2001)

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1281

D Y N A M I C M O D E L F O R M E T H A N E EMISSION FROM MANURE STORAGE M.A. Hilhorst & R.M. de Mol IMAG, P.O. Box 43, 6700 AA Wageningen, The Netherlands ABSTRACT Methane emissions from agricultural sources should be calculated in accordance with the IPCC good practice guidelines, based on emission factors and activity data. Emission factors are based on the volatile solids content, biodegradability and methane conversion factor (MCF), which differ per management system and climate region. Not included in the IPCC models are dynamic factors of storage systems, like storage time, loading and unloading rates and temperature. A new dynamic model has been developed to include these factors. A slurry pit is an accumulation system. Experimental results of Zeeman (1991) showed that emission velocity (m3/day) increases linearly with filling time, i.e. the relation between emission (m 3) and filling time is quadratic. The model is used to derive values for the MCF, depending on filling time and temperature. The dynamic model has been applied to a typical dairy and pig farm, with a large effect on the emission figures. The proposed model can be used to improve calculations of national emissions.

INTRODUCTION

The methane emissions from liquid manure are an important source of greenhouse gases from agriculture. Methanogenic bacteria produce methane when manure decomposes in an anaerobic environment. Manure management practice is a dominant factor that determines the methane emissions (IPCC, 1996). Emissions of methane from agricultural sources should be calculated in accordance to the IPCC Reference Guide (IPCC, 1996) and Good Practice Guidance (IPCC, 2001). Emission factors are based on the volatile solids content, the biodegradability and methane conversion factor (MCF) which differ per management system and climate region. Not included in the default IPCC methodology are dynamic factors of storage systems like storage time, loading and unloading rates and temperature. It is suggested in the Good Practice Guidance to include these factors (IPCC, 2001). A new dynamic model for methane emissions from liquid manure storage has been developed to facilitate the inclusion of these factors. The dynamic model is used to adapt the MCF in manure management systems typically used in the Netherlands (slurry pit storage). Resulting methane emissions will be compared with emissions based on default values of MCF.

BACKGROUNDS

The IPCC methodology for estimating national emissions is based on activity sectors (e.g. agriculture) and categories (e.g. CH4 emissions from manure management). The annual emission factor for livestock population i, EFi, in kg CH4 per animal from manure management is defined by (Eq. 4.17 in IPCC, 2001):

1282 k~r days. ( 1) B o •0.67 ~-~-. MCFjk •MSijk year where j is the management system and k is the climate region. VSi are the volatile solids produced daily in kg per animal within livestock population i. VS or organic matter is defined as the difference between the amount of matter after drying at 105°C and at 550°C. B0, represents the biodegradability, i.e. the maximum EF~ = VS i •365-

CH4 producing capacity in m3/kg VS and MCFjk is the CH4 conversion factor in % for manure management system j in climate region k. MSijk is the fraction of manure of the i's animal species/category, handled using manure system j in climate region k. Note that a slurry pit is an accumulation system. For an accumulation system, it is more convenient to calculate the emission per m 3 of slurry than per animal. Therefore, we will replace the emission factor EF in kg CH4 per animal per year by EF' in kg CH4 per m 3 slurry and VS in kg per animal by VS' in kg per m 3 slurry. Eq. (1) implies the application of default values of VS, MCF and Bo. Typical parameter values for Dutch livestock systems (slurry) are given in Table 1. The MCF values used for the Netherlands appear to be too low. Also the VS' values are not valid for the Netherlands, as they are inconsistent with other sources on manure characteristics. Application of the default MCF values according to the IPCC guidelines, instead of the Dutch practice values, results in higher values for the emission factor. Application of practical values of VS', instead of the IPCC values results in lower emission factors. The combined effect is shown in Table 1. EF'I is the official national CH4 emission estimate, but EF'2 is closer to Dutch practice. TABLE 1 Emission factors for slurry EF' in kg CH4 per m 3 slurry based on different sources for volatile solids VS' in kg per m 3 slurry and methane conversmn factors MCF in %. Bo is the biodegradability in m 3 CH4/kg VS. VS': IPCC (1996) VS': Dutch practice (Van Dijk, 1999) MCF: van Amstel (1993) MCF: IPCC, cool climate (2001) Livestockpopulation B0 VS' MCF EF'~ VS' MCF EF'2 Cattle (>1 month, no pasture) 0.17 124 5 0.70 66 39 2.93 Pigs 0.45 101 10 3.05 60 39 7.06 The default IPCC values for MCF may be replaced by country-specific values which can include factors like (IPCC, 2001): timing of storage or application, length of storage, manure characteristics, determination of the amount manure left in the storage facility (as a methanogenic inoculum), temperature of indoor and outdoor storage or daily and seasonal temperature variation. In this paper, a dynamic model to determine the MCF is proposed that can include such factors. MATERIAL AND METHODS

Dynamic emission model A common system for manure management in the Netherlands is slurry storage in a pit below the animal confinements. Such slurry pit storage can be considered as an accumulation system with continuous filling. The methane emission in such a system depends on the filling time and the inoculum. The emission over time in accumulation systems has been measured in several experiments by Zeeman (1991). Based on these experiments, we assume for this paper, that the emission velocity (m3/day) in an accumulation system is linearly increasing with the filling time (Figure 1). We also assume 1 m 3 ~ 1000 kg slurry and 1 m 3 CH4 = 0.67 kg CH4. The emission velocity of cattle and pig slurry in an accumulation system at 15°C is: 1Tlcattle15of(t) = (12+0.47"t)'0.67"10 -3 and mpigs15oc(t) = (12+0.75"t)'0.67"10 3 (2) where m(t) is the emission velocity of methane in kg CH4 per m 3 slurry per day and t the filling time in days. This implies that the relation between emission and filling time is quadratic. The methane emission EF' as a function of time in kg CH4 per m 3 slurry can be found from: EF'(t) = ~__om(r)dr

(3)

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O.OL.

1 0.02

,

o

,

,

~o

,

,

8o

. . . . . lz0 16o

z~0 ' Ao time (doys)

0 ~,0

.

.- ..... ~

.. . . . . . . . . . . 80 120

160 firne (cloys)

Figure 1: A copy of figures 1a and 5 of chapter 5 of Zeeman (1991) for the emission velocity of methane in liters CH4 per liters manure per day for cattle (left) and pigs (right). These experimental results are for digestion of slurry in a continuous accumulation system at 15°C with 14% inoculation. The filling time was 100 days. The straight line is added to show the approximately linear relationship between velocity and time. According to Zeeman's experiments Eq. (2) and Eq. (3) yield for cattle slurry EF'cattle 15°c(t) = (12"t+0.23"t2)'0.67" 10.3

(4)

EF'pigs 15oc(t) = (12"t+0.37"t2)'0.67 •10.3

(5)

and for pig slurry

These equations are valid within the experimental range and conditions of Zeeman (1991), with filling times till 100 days.

Relationship between IPCC-model and dynamic methane emission model Both the IPCC model (1) and the dynamic emission model (4) for cattle and (5) for pigs, describe the methane emission of a slurry storage. The dynamic methane emission model can be compared with the IPCC model. Replace EF by EF', VS by VS' and substitute MCF(t) for ~Y'MCFjk .MS~jk in Eq. (1). jk

Equating this result with Eq. (4) gives for cattle slurry: MCFcattle 15°c(t) = (1.07"t + 0.0205"t2) •10.3

(6)

and with Eq. (5) gives for pig slurry: MCFpigs 15oc(t) = (0.44.t + 0.0137"t2) •10.3

(7)

To illustrate the consequences of Eq. (6) and Eq. (7) on the MCF, in Figure 2 the MCF is calculated for different filling times for cattle and pig slurry at a constant temperature of 15°C.

1284 100 ............

........ 6 0 - -

[cattle.]

.Z.../'! °''''''" .....o.]."" '

U 40

2O i

0 !---'- ~ 0 20

40

60

80

100

120

|

4 ....... l - - f 140 160 180

Time (days) Figure 2: MCF's (%) for slurry storages for pigs and cattle calculated using the dynamic model as a function of filling times in days at 15°C.

Temperature of slurry storage facilities in the Netherlands The emission depends on the storage temperature, Eq. (6) and (7) are valid at 15°C, there is no emission below 4°C. Due to climate control in pig housing, the average temperature of the indoor stored pig slurry is around 17°C (Novem, 1991) during the year. However, since the data of Zeeman is valid at 15°C, we assume for these illustrating calculations the pig slurry to be stored at 15°C. This may imply an underestimation of the MCF. The temperature of the slurry pit in cattle housing will be related to the outdoor temperature. The average temperature of a cattle slurry pit is assumed to be 15°C during June, July, August and September, and 10°C during the other months. The methane emission at 10°C is assumed to be half the emission at 15°C. With the latter, Eq. (6) is rewritten as: MCFcattle ~0oc(t) - (0.53.t + 0.0102.t2) •10-3 (8)

RESULTS The dynamic model describes the relation between methane emissions and filling time for slurry storage. As an illustration the emission factors of a common cattle and pig farm will be calculated. Due to covering and the low temperature of the outdoor slurry storage the emission of methane is considered to be negligible low, compared to the emission from the slurry pit. It is assumed that at least 10% of the slurry will remain in the pit (as inoculum) because it is practical impossible to empty the pit completely. To calculate the methane emission on a yearly basis the MCF will be calculated using the dynamic model for each storage period, starting with the remaining of the last period until the pit is emptied. In Table 2 the resulting MCF and emission factor EF'3 are given. For pig farms all manure is stored in the slurry pit (typical capacity 400 m 3) of the pig housing. When the pit is full, manure is pumped to the outdoor silo. In case of manure application, manure is taken first from the pit, and from the silo if the pit is empty. Most manure will be transported to other farms and the rest will be applied on the farm in March and in August (2x50% of the stored manure). Here, Eq. (7) will be applied.

1285 The manure application times for cattle farms are observed average values for 2 years at 12 farms, which include grazing during May till October. In case of grazing, 50% of the manure is assumed to be dropped on pasture. The average manure application, expressed as a percentage of the manure stored in the pit, is 10% in February, 20% in March, 15% in April, 20% May, 15% in June, 10% in July and 10% in August (application is prohibited during the other months). Eq. (8) will be applied for the period October till May and Eq. (6) during the other months. TABLE 2 The methane conversion factor MCF (%) with resulting emission factor EF'I (kg CH4/m 3 slurry), calculated for pigs and cattle according to the static IPCC model of Eq. (1) compared with the MCF and EF'3 calculated using the dynamic models of Eq. (6), (7) and (8). Bo is the biodegradability in m 3 CH4/kg VS. VS' are the volatile solids in kg per m3 slurry. using static model (IPCC) using dynamic model: Eq. (6), (7) and (8) Livestock population I3o VS' MCF EF'l VS' MCF EF'3 Cattle (> 1 month, pasture) 0.17 124 5 0.70 66 21.5 1.61 Pigs 0.45 101 10 3.05 60 46.2 3.86

CONCLUSIONS Emissions of methane from agricultural sources are normally calculated in accordance to the IPCC good practice guidelines. A new dynamic model has been proposed to derive values for the MCF which include dynamic factors like slurry storage time, loading and unloading rates and temperature. Research from Zeeman (1991) suggests that the emission velocity is linearly increasing with filling time, i.e. the relation between emission and filling time is quadratic. As an illustration the model is used to derive values for the methane conversion factor MCF and the resulting emission factor, depending on filling time and temperature. The model has been applied to a typical pig and cattle farm. The results show that the procedure to determine the MCF can have a great influence on the emission factor. The proposed procedure can be used to improve calculations of national emissions and to define policies to reduce methane emissions from manure storage.

REFERENCES 1. IPCC, 1996. Revised 1996 IPCC guidelines for national greenhouse gas inventories: Reference manual. 2. IPCC, 2001. Good practice guidance and uncertainty management in national greenhouse gas inventories. 3. Novem, 1991. Commersialisering van koude vergisting van varkensdrijfmest onder stal met behulp van kapjessysteem, Novem/RIVM, Sittard/Bilthoven The Netherlands, no 9134, 50 p. 4. Van Amstel, A.R., R.J. Swart, M.S. Krol, J.P. Beck, A.F. Bouwman & K.W. van der Hoek, 1993. Methane. The other greenhouse gas. Research and policy in the Netherlands. Report no: 481507001, RIVM. 5. Van Dijk, W., 1999. Adviesbasis voor de bemesting van akkerbouwen vollegrondsgroentegewassen. PAV, Publicatie nr. 95, maart 1999. 6. Zeeman, G., 1991. Mesophilic and psychrophilic digestion of liquid manure. Thesis Agricultural University Wageningen.

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1287

COAL MINE V E N T I L A T I O N AIR M E T H A N E C A T A L Y T I C C O M B U S T I O N GAS TURBINE S. Su, A. C. Beath and C. W. Mallett CSIRO Exploration and Mining, Technology Court, Pullenvale, QLD 4069, Australia

ABSTRACT

This paper describes the development of a catalytic combustion gas turbine system that can use and mitigate methane in coalmine ventilation air. Each year underground coalmines throughout the world emit methane that is equivalent to over 200 million metric tons of CO2 in terms of the global warming potential from their ventilation systems. Although the concentration of methane contained in these ventilation air flows is quite low (typically less than 1 percent), the volume of ventilation air is so large that ventilation systems constitute the single largest greenhouse gas source from underground coal mines. The coalmine ventilation air methane catalytic combustion gas turbine technology being developed can be used to mitigate greenhouse effects of the ventilation air by catalytic oxidation and to generate electricity. This gas turbine system is simple and reliable compared to other systems. Bench-scale ventilation air methane catalytic combustion tests were used to obtain the design parameters of a pilot-scale demonstration plant. Four catalysts were tested at different temperature, pressure and CH4 concentrations. The experimental results are presented in this paper along with the brief description of methane catalytic combustion basics and the conceptual design of the ventilation air methane catalytic combustion gas turbine system.

INTRODUCTION

Methane (CH4) is the second largest contributor to global warming among anthropogenic gases, after carbon dioxide (CO2). It is estimated to be 21 times more effective at trapping heat in the atmosphere than CO2 over a 100-year period [ 1]. A major source of methane emissions is underground coalmines, estimated to produce approximately 10% of anthropogenic methane emissions worldwide [2]. This corresponds to a worldwide annual production of methane equivalent to over 200 million metric tons of CO2, in terms of CH4 global warming potential [ 1], from coalmine ventilation systems. Although the concentration of methane contained in these ventilation air flows is quite low (typically less than 1 percent), the volume of air that the systems move into, through, and out of the mine is so large that ventilation systems constitute the single largest source of methane release to the atmosphere from underground coal mines [3]. A typical gassy mine in Australia produces ventilation air at a rate of approximately 150 to 300 cubic meters per second [4]. This results in the Australian coal mining industry contributing approximately 6.5% of Australia's greenhouse gas production while producing only 1.9% of GDP (1995/1996) [4]. Of these greenhouse gas emissions from coal mining, 72% are in form of fugitive emissions of methane from underground mining. Typically, at a gassy mine methane is contained in the following three streams: (1) mine ventilation air, (2) gas drained from the seam before mining, and (3) gas drained from worked areas of the mine e.g. goafs. In Australia, approximately 64% of the methane emitted is contained in mine ventilation

1288 air at a concentration between 0-1%, and the remainder is in the combined drainage gas streams, typically at concentrations greater than 50% methane by volume. Ventilation air methane is difficult to use as an energy source as the air volume is large and the methane resource is dilute and variable in concentration. Several technologies have been or are being developed to dispose of the methane in mine ventilation air and potentially recover useful energy. Carothers et al. [2] reviewed most of ventilation air methane utilisation technologies in terms of technical and economic feasibilities. Generally, utilisation technologies of methane in ventilation air divide into two basic categories: (1) Ancillary uses involve substituting the ventilation air for ambient air in combustion processes. This has the advantage that methane in the ventilation air acts as a supplementary fuel in the combustion process. Suitable combustion processes include gas turbines, internal combustion engines and coal-fired power stations; (2) Principal uses involve combustion of the methane in ventilation air as a primary fuel without reliance on another source of combustion. For example, thermal flow-reversal reactors (TFRR) can sustain operation by maintaining the core temperature just above the auto-ignition temperature of methane and can operate with a methane concentration as low as 0.3%. Catalytic versions of these systems, known as catalytic flow-reversal reactors (CFRR), can operate with methane concentration as low as 0.1 percent. The TFRR and CFRR can cope with variability of methane in ventilation air due to the thermal inertia of the systems. The main limitation of the systems is that it is difficult to extract useful energy, so they generally provide only mitigation by preventing release of the methane. Heat can be recovered from the systems, but variations in methane concentration are likely to cause instability in the system, as it is difficult to maintain the working fluid that recovers the heat at a constant temperature and flow rate. The ventilation air methane catalytic combustion gas turbine technology that CSIRO is developing can be used to mitigate methane from the ventilation air by catalytic oxidation and to generate electricity. This gas turbine system is simple and reliable compared to other systems in terms of operation and recovering heat. Bench-scale ventilation air methane catalytic combustion tests were used to obtain the design parameters of a pilot-scale demonstration plant. Four catalysts were tested at different temperature, pressure and CH4 concentrations. This paper presents the CH4 catalytic combustion experimental results along with a brief description of CH4 catalytic combustion basics and a conceptual design of the ventilation air methane catalytic combustion gas turbine system.

METHANE CATALYTIC COMBUSTION Mechanism and Kinetics

The combustion mechanism of methane can be represented in a simple form with Eqn. 1, however, this is a gross simplification since the true reaction mechanism involves many free radical chain reactions [5].

CH4 + 202 = CO2 + 2H20

/~-I(298 ) =

-802.7 kJ/mol

(1)

Studies of the kinetic mechanisms of methane catalytic combustion can become quite involved when multistep surface reactions are considered. Chou et al. [6] used 23 different reactions in their numerical study of methane catalytic combustion in a monolith honeycomb reactor. The situation becomes even more complicated when considering heterogeneous reactions and the use of surfaces as reaction sites. Figure 1 shows a possible mechanism for methane catalytic oxidation proposed b y O h et al. [7]. Methane catalytic combustion is a multi-step process involving diffusion of methane and oxygen to the catalyst surface, adsorption onto the catalyst, reaction, and then desorption of the product species from the surface and diffusion back into the bulk [8]. Most kinetic investigations have been performed under conditions where oxygen is present in excess of the stoichiometric ratio. Resulting from this has been the finding that the reaction is independent of the oxygen concentration. The reaction order with respect to methane is generally found to be between 0.5 and 1 [5]. No definitive agreement has been reached on the kinetic mechanism of methane catalytic oxidation.

1289 CH4(g)

HCHO(g)

;T-H CH4(a)

CO(g)

H2(g)

CH3.(a)+O ~T decomp. ~T ~T ~ or ~ HCHO(a) • CO(a)+2H(a) CH2"(a) direct oxidation

+O

CO2(g)+H20(g)

Figure 1: A possible mechanism for methane catalytic oxidation [7] (a) adsorbed and (g) gas phase R e a c t o r Types

A number of different reactor types have been used for catalytic combustion. Generally, these can be classified into three types of reactors: honeycomb monolith, packed bed, and fluidised bed. Characteristics of the different types make them suitable for different types of processes. For example, the CFRR process uses packed bed reactors [2], as these have a high thermal inertia that suits the process. However, the honeycomb monolithic type reactor has better characteristics for power generation applications due to its very low pressure drop at elevated mass throughputs, high geometrical area, and high mechanical strength [9]. Monoliths consist of a structure of parallel channels with walls coated by a porous support with catalytically active particles, as shown in Figure 2. The monolith structure is normally ceramic, but may also be metallic, and acts as a substrate for a washcoat slurry of base metals (such as alumina) on which catalytic material (typically noble metals such as palladium or platinum) are placed [8].

Ceramic Monolith

~

vidual nel Cross

Section

Channel

8llb~ CH4+Ai~

SupportedCatalyst Laser

~uudCe~,

Pallmllm or

Rhmltwm

Figure 2: Illustration of a monolith reactor [8, 10] EXPERIMENTAL RIG AND CATALYSTS An experimental rig was constructed to test coalmine methane catalytic combustion performance by using different catalysts at different operating conditions, as shown in Figure 3. The experimental rig consists of two air heaters, a mixer, a catalytic combustion chamber, a cooler, fuel supplier, power supply, and sampling system. The mixer is used to dilute concentrated methane (99.99%) into air to produce a dispersed low concentration methane and air mixture that simulates coalmine ventilation air. Two water-cooling probes are used in the gas sampling system, and installed before and after the combustor respectively, are used to quench reactions at the sampling points. Two dryers are used to dry the sampling gases taken by the probes to ensure that no water vapour goes into a gas chromatography (GC). The GC determines CO, CO2, CH4, 02 and N2 of the dried gas stream. Ledwich et al. [11] and Lee et al. [5] carried out the surveys on methane catalytic combustion and determined that platinum and palladium are generally found to be the most active catalysts for low temperature oxidation. Therefore, four different honeycomb monolith catalysts, each consisting of a ceramic support with washcoats containing different concentrations of Pd and Pt, were selected for this study. Table 1 summarises the properties of the four catalysts. Catalysts 1 to 3 have an acceptable maximum catalyst bed

1290 temperature for short periods of 850-920°C, while catalyst 4 has a higher peak operating temperature of 1050°C.

Figure 3: Ventilation air methane catalytic combustion experimental rig

TABLE 1 BASIC PROPERTIESOF THE CATALYSTS Number

No. 1 No.2 No.3 No.4

Catalyst/ Substrate

Cell density, cells/cm2

Pd/A1203 Pt/AI203 Pt/AI203 Pd/A1203

62 62 62 62

Surface area, Loading, Precious metal, g/monolith m2/cm3 g/m3 Pt Pd Rh SubWashstrate coat 0 0.9217 0.1843 0.0155 30.5 649.4 0.0155 30.5 1765.7 2.6515 0 0.5303 1.4463 0 0.1446 0.0155 30.5 882.9 0 2.0534 0.4107 0.0155 30.5 1765.7

Max

continuous catalyst bed temp., °C 750 750 750 950

The experimental procedure was to preheat the catalyst to the test temperature using heated air before introducing methane into the air to produce the desired concentration. Changes in the temperature of the air leaving the catalytic reactor with time were used as an indication of catalyst performance. The variation in gas composition from inlet to outlet of the catalytic reactor were used to determine the efficiency of the catalytic process according to Eqn. 2, where, r/cH, is the CH4 conversion rate as a percentage, (CHn)in,m is the measured CH4 concentration in the reactant stream and (CHa)out,m is the measured CH4 concentration in the product stream. (cn4) . . . . x ( 5 0 - ( f n 4 ) i n m ) ) x

lO 0

(2)

E X P E R I M E N T A L RESULTS Catalyst tests were conducted at different preheated air temperature, pressure, space velocity and CH4 concentrations to determine the operational parameters at which CH4 can be fully oxidised into CO2 and H20 for each of the catalysts. Figure 4 shows some typical experimental results on CH4 catalytic combustion performance. Related operating parameters are shown for each run individually in the figure. As a general observation, higher operating pressures typically result in higher conversion of methane. This is due to that the combustion intensity is higher and the relative heat loss from the reactor is lower when the operating pressure is higher and the space velocity is kept constant. The results shown in Figures 4b and 4c

1291 can identify this effect for catalyst 1, as at 6.2atm almost total combustion of methane can be achieved for a methane concentration of 0.3325% while at 1.3atm a methane concentration of 0.601% is required for the catalyst to achieve near complete combustion. Figure 4c shows the results for an extended test where the temperature of the air entering the catalytic reactor was varied during operation. This shows that, for catalyst 1 and an operating pressure of 1.3atm, it is difficult to maintain combustion when the inlet temperature is less than 475°C, even with the relatively high methane concentration of approximately 1.07% and a catalyst temperature in excess of 600°C at the time the inlet temperature was changed. However, combustion can be initiated with a concentration of only 0.6% with an inlet gas temperature of 525°C.

7007 °li.......... / !

750 ~ 700 ! Stop CHim/~c~ion Test on 04/09/01 Catalyst 1, ff 650 at 6.2atm 600 !~_ ~ ~ ...... Inlet ,.~ 550 . . . . . Outlet 500 . . . . . 450 ~ S t a ~ n~0.3325% 0.03% 400 4 injectio C _ . ~ ~ 4

~Ii 650 / // Catalyst I, /_~L at6.2alm 600 ] St~p CH4 injection ] , I [ - - - Inlet 550 [ ~ ~1 .......... Outlet 500 ] ~S~-~CH--ml-ecilon 0.7085~ 0000% 450 4 t-I I CH4 o ~H 4 o 400 o ~ g g ........ oo oo tr~ o¢ ~ .--., CAT- 100102-N6 ,., ~.., 6< ,.. ~,., Time

........ Ai ....,

Ai ,.. Ai ,... Tim~

~..,

(a) 750

(b)

__/ ...... I /" ,i N I I//" N I1~[ N2 " // Increase CH4 ----- ~ // / concedatration ~------a_

700 650 600

~ 550 500

j'-Stop'~H4 injection I "., . / I N - vi " " "~ I Extinguished[t I due to lower inlet I temperature '

/ Start CH4 injecti ..... Reduce inlet te'~'mperature - I/-'''~

450 400

CAT-040901 -E4

.

~ g . ~S ~;

~ ~

g ~.

,..

,.,

,.,

,.,

,.,

~ ~;

~ ~ . ~ ~5

~ ~ g ~5 ~5 ~

~ ~

~ ~

Test on 10/01/02 Catalyst 1, at 1.3atm Inlet Outlet

CH4 N l: 0.601% Nlb: 1.071% N2: 1.071% N3: 1.063%

Time

CH4 NI 0.034°A Nlb: 0.000% N2: 0.000% N3: 1.510%

CAT- 100102-N 1-3

(c) 750 700

Stop CH4/.._inj~n .....

~650

TeStcatalystOn 01/10/012,

at 4.46arm

I~-,~600550

/

Inlet

~ 500

Outlet

~450 ~ tio~n 0.867% 0.0025% 400 Start CH 4 injec C ~ ............ ,~ ,~ ,~ ,~ ,~ t-- CAT-011001-I5 Time

(d)

900 [ . 800 700

r """. . . . . . -¢"~i Test on 30/01/02 Catalyst 4, St lap CH 4 injection at 6.2atm i i ~ Inlet Slart CH 4 injectk~n Outlet

t

z l

6°°1i/

I~'~ 500

400~

~. . . ~. . . ~. . ,eq m Ai ~,., Ai .., _., Time

CH 4

000% CH 4

~ >

~ * CH 4 at the inlet ,n- is estimated by Ai ,_, calculation CAT-300102-P2

(e)

Figure 4: Performances of CH4 catalytic combustion From analysis of the experimental results it has been possible to establish guidelines as to the minimum gas concentration and temperatures at which each of the catalysts will function adequately. The catalysts with higher loadings of precious metals typically perform better than those with lower loadings, in particular by functioning at lower temperature. It was also determined that the palladium-based catalysts functioned over a greater range of conditions than those containing platinum, as also concluded by Ledwich et al. [ 11 ] and Lee et al. [5]. Catalyst 4 is the preferred option due to its higher operating temperature and high catalyst

1292 loading, that allows for a greater range of operating conditions. For example, to achieve a methane conversion rate of over 90%, the air containing methane needs to be preheated to just over 450°C at 6.2atm, depending on methane concentration. When using this catalyst, it should be possible to maintain near complete combustion of methane for streams containing concentrations of methane greater than 0.6% as long as the temperature ofthe streams is above 500°C and the pressure over 1.3atm.

D E M O N S T R A T I O N SYSTEM DESIGN

Methane is contained in the ventilation air from gassy coalmines at all times, however concentrations and flow rates vary. The use of this air for combustion dilution and cooling of the turbine inlet scroll and first stage in normal industrial gas turbines will result in a significant fraction of the methane passing through the turbine without combusting. This results in a more complex turbine system that requires compressed air from other sources, as well as compressed ventilation air, if all methane is to be combusted. The demonstration system design is therefore constrained by several criteria such as performance of the catalyst to minimise methane emissions. From these criteria, potential arrangements of gas turbine systems were proposed and analysis was performed using a commercial process analysis package (HYSYS) to select and optimise a system design. This analysis determined that it was possible to arrange a system that could not only efficiently combust methane streams with concentration of approximately 1%, but also produce a net electrical output. A conceptual design of the system has been completed and the major operating parameters finalised, however, final design details and operating parameters are subject to modification in consultation with the turbine designer and manufacturer.

ACKNOWLEDGEMENTS

The authors wish to acknowledge the ACARP funding for this project. We would like to thank Mr Dominic Foran from Delphi Automotive Systems, Mr Jeff Condren, Mr Patrick Glynn, Mr Ian Hutchinson and Dr David Harris from CSIRO for their help in a construction and operation of the experimental rig.

REFERENCES

.

10.

11.

USA EPA (2001). Non-C02 Greenhouse Gas Emissions from Developed Countries: 1990-2010. U. S. Environmental Protection Agency, Office of Air and Radiation, Sept. 2001. Carothers, P., and Deo, M. (2000). Technical and Economic Assessment: Mitigation of Methane Emissions from Coal Mine Ventilation Air. Coalbed Methane Outreach Program, Climate Protection Division, U. S. Environmental Protection Agency, EPA-430-R-001, February 2000. http ://www.epa.gov/coalbed/vam/index.htm. Wendt, M. N., and Mallett, C. et al. (2000). Methane Capture and Utilisation, final report. ACARP Project C8058. CSIRO Exploration and Mining, Brisbane, May 2000. Lee, J. H., and Trimm, D. L. (1995). Fuel Processing Technology 42, 339. Chou, C. P., and Chen, J. Y., Evans, G. H., and Winters, W. S. (2000). Combustion Science and Technology 150, 27. Oh, S. H., Mitchell, P. J. and Siewert, R. M. (1991). In: Catalytic Control of Air Pollution: Mobile and Stationary Sources, pp. 12-25, Silver, J. E. (Eds). 202 nd National Meeting of the American Chemical Society, 25-30 August 1991, ACS Series, Vol. 495. Foran, D. (2001). Personal Communication: Catalytic Converter- Production Specifications. Delphi Automotive Systems, Australia. Cimino, S., Pirone, R., and Russo, G. (2001). Industrial Chemical Research 40, 80. Geus, J. W., and van Giez-en, J. C. (1999). Catalysis Today 47, 169. Ledwich, J., and Su, S. (2001). Catalytic Combustion of Coal Mine Ventilation Air: Literature Review and Experimental Preparation. CSIRO Exploration and Mining, May 2001, Australia.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1293

THE E F F E C T I V E M A N A G E M E N T OF M E T H A N E EMISSIONS FROM N A T U R A L GAS PIPELINES S. Venugopal Department of Community, Safety and Environment TransCanada PipeLines Ltd. Calgary, Alberta, T2P 5H1, Canada

ABSTRACT Methane emissions from TransCanada can be categorized into fugitive losses and vented emissions. There are a number of facets to TransCanada's methane emissions management program: source identification, quantification, tracking system, mitigative actions, pilot program, full scale implementation, monitoring progress, and continuous through research and development. In 2001, TransCanada's methane emissions management program avoided 1.3 millions tonnes of carbon dioxide equivalent from being emitted to the atmosphere. This paper documents TransCanada's methane emissions management strategy and its implementation from source identification to research and development.

INTRODUCTION TransCanada PipeLines Ltd. (TransCanada) is Canada's largest natural gas pipeline company. TransCanada owns and operates a 37000 kilometer pipeline system that contains more than 110 gas compression facilities, 1200 gas metering facilities and over 5000 valve sites. The gas compression facilities have a combined capacity of nearly 4000 megawatts. TransCanada's Canadian facilities emit nearly 8 million tonnes of carbon dioxide equivalent. Based on 2001 data, approximately 13 per cent of TransCanada's greenhouse gas emissions originate from methane losses along its pipeline network. Without the methane emissions management program in place TransCanada's greenhouse gas emissions would be 16 per cent higher (equal to 29 per cent of total greenhouse gas emissions). Carbon dioxide (84 per cent) and nitrous oxide (1 per cent), result from combustion processes that take place at the compression facilities contribute to the remaining of 85 per cent of greenhouse gas emissions.

A METHANE EMISSIONS MANAGEMENT MODEL The management of methane emissions at TransCanada is part of TransCanada's overall strategy towards Climate Change. The Climate Change strategy is guided by several principles developed by TransCanada, of which one principle is dedicated towards the development and implementation of a greenhouse gas emissions reduction program. The methane emissions management model (Figure 1) at TransCanada can be broken down into three tiers: i) Tier 1 -

1294 Senior Leadership Support, ii) Tier 2 - Program Management, and iii) Tier 3 - Execution and Monitoring. This model is based on TransCanada's experience in the development and implementation of a methane emissions management program. It was developed in order to assist and maintain future methane emissions management programs on natural gas pipeline system. I Tier

1 - Senior

Leadership Support

provide resources approve management p l a n

-

Tier 2

-

I

w i t h business needs performance management

- alignment -

Program Management

]

l

Development - source identification - quantification - tracking system - mitigative actions

-

I

1

pilot program

- trouble shooting

- metric

- annual

- s e t t i n g targets - measuring progress

- communtca

I n

Tier 3

I

i ~i,o,~ro~.~ I

1

roliout

-

Execution and Monitoring

t

I~o,, s.,o,m~, .... ,a,,oo I

I

I Continuous Improvement - research and development

I , i

I

i

I ~°ni'°r~n~ I

Figure 1: A Three Tier model for methane emissions management from natural gas pipeline. Tier 1 provides the necessary leadership and resources needed to carry out the management program. There are two key elements to Tier 1, sponsorship and accountability. One senior level leader within the firm is assigned the role of championing the program. This champions role is to obtain support from leaders of the various departments that influence decision making with respect to methane emissions and control strategies. The other key role for this champion is to provide accountability for the program. That is, making sure that the program is aligned with business needs and that it becomes a measure of business performance. This alignment demonstrates to all parties that management of methane emissions is an important part of the business cycle. Tier 2 and Tier 3 are carried out by a multi stakeholder team from the various interested departments across the firm. There are several components within Tier 2; development of an emissions management program is the first step and it involves identification of emissions sources, quantification of emissions, development of a system to track emissions and take mitigative actions. The identification emissions sources leads to the development of techniques for emissions quantification. In some cases, quantification means the use of standard engineering calculations to quantify emissions. While in other cases, it may involve research and development work to develop procedures and protocols to quantify emissions. In order to control and effectively manage methane emissions mitigative actions need to be investigated and implemented. The next step in the management plan is it's "Implementation." There are two components to this stage, development of a pilot program and a communication plan. The pilot program should be a focused effort that attempts to address possible issues that will arise in the full scale implementation of the management program. Some considerations for the pilot program are, geographical area, audience, sites for field testing the quantification and tracking systems, and evaluating mitigation options. This communication needs to be focused on all levels of management and employees involved with the program. The management program will require ongoing "Maintenance." This maintenance needs to be carried out with a mechanism for trouble shooting during the annual roll out of the program. The annual roll out is an opportunity for communicating messages and addressing issues that arise in

1295 the previous year. Performance measurement is an important component in the overall management plan. The first step is to determine a metric for the performance, the next is establishing both short term and long term targets and then establishing a periodical system of measuring progress. Continuous improvement is a business value as well as an environmental ideal. Research and development is an important tool for achieving this ideal. Special effort needs to be put forth so that new and innovative ideas for emissions quantification, mitigation and management are continually sought after. The final stage of the model, Tier 3, is Execution and Monitoring. There are three components to be considered at this point: implementing a pilot program, full scale implementation and ongoing monitoring. The pilot program phase is really the opportunity to assess the program and its effectiveness on a small scale. A comprehensive pilot program is needed before full scale system implementation. Another important element is monitoring, where a process is put in place to asses the program on continuous basis.

THE TRANSCANADA EXPERIENCE Methane is emitted to atmosphere during the construction and operation of gas metering stations, gas compressor stations, valve sites and from the pipeline itself. There are two categories of methane emissions arising from TransCanada's operations; fugitive losses and vented emissions. Fugitive losses are either engineered emissions of methane or leakages that occur on equipment such as valves and flanges. Vented emissions of methane arise from the evacuation of natural gas (which is mainly composed of methane) from pipelines, losses from compressor starts to purging of pipelines. The methane emissions management effort is facilitated by the Department of Community, Safety and Environment. However, it is not a completely integrated system of methane emissions management. This is shown in Figure 2. Fugitive losses from TransCanada's pipeline network are managed by a multi stakeholder team, known as the Fugitive Emissions Management team (FEMT) and the vented emissions are managed by the Blowdown Emissions Committee. I

I

Methane Emissions Management

- facilitated by Community, Safety & Environment I

I Meter Stations + Compressor Stations + Valve Sites + Pipeline ] - assets that contributeto methane emissions

I

.... - Fugitive Emissions Management Team

/

I

I

1

,

- Engineered Emissions I Equipment Leakage I Pipeline Leakage

I I ve.

I

- Blowdown Emissions Committee

1

/ - Venting fi'om Pipelines I Compressor Starts Purging of Pipelines

I

Figure 2: The methane emissions management structure at TransCanada is divided into managing fugitive losses and vented emissions.

Management of Fugitive Losses The FEMT is comprised of management and personnel from engineering, representatives maintenance regions across TransCanada and the environment department. The team is sponsored by a senior management representative. There are three major areas of program development and management for the FEMT. This is shown in Figure 3.

1296 ~

FugitiveEmissionsManagement Team - all aspectsof Tier I, Tier 2 and Tier 3

Research and Development

Leak Detection and Repair - aligned with maintenance program

- engineeredemissions - biofiltration - re-injectiontechnology

- aerial surveyof system - systemto track LDARand emissions savings

Figure 3: The fugitive emissions management team has three major areas of management responsibilities, research and development, fugitive emissions measurement and implementing a leak detection and repair program. The key element behind the measurement program is the device High Flow Sampler, which was developed through collaborative research with government and industry groups. This technology has allowed TransCanada to accurately measure fugitive losses. Approximately 20 per cent of the facilities are subjected to High Flow Sampler measurements annually. The data collected from these measurements are used to develop emission factors for TransCanada facilities and are used to report emissions internally within TransCanada and externally. It also provides the basis for setting annual targets for fugitive emissions reductions. In parallel with the measurement program, is the Leak Detection and Repair (LDAR) program. This program is closely aligned with TransCanada's preventive maintenance program and is administered through this process. The LDAR program is an annual activity for selected facilities across Canada. A system has been implemented using the FEMT to track the LDAR progress and resultant savings in emissions from mitigation activity. There are two research initiatives underway to address engineered emissions. One is a biofiltration project, where methane is oxidized in a biofilter cell into carbon dioxide. This reduces global warming impacts by 85 per cent. The other major initiative is research into the reinjection of engineered emissions into the pipeline system. In 2001, approximately 487 kilo tonnes of carbon dioxide equivalent of fugitive losses were avoided from being emitted to the atmosphere.

Management of Vented Methane The management of vented methane is a shared responsibility between the engineering and operations departing. The Blowdown Emissions Committee monitors and facilitates the management of the vented emissions. This committee is sponsored by a senior management representative and a variety of stakeholders are represented on this committee. Tier 1 and Tier 2 levels of the methane management models are monitored by this committee (Figure 4).

1297

- monitors only Tier I and T i ~ 2

O u t a g e Declslom Model - decision making tool - integrated with societal

~

~

,

~

- field input through forms - as ,'lccountin - g:onthly r = g r t s

- transfer compression - air powered expellers - risk planning options - pipeline inspection tools - butlcnng and hot tapping - StOl~.le plugs - repair sleeves

Figure 4: Venting of methane emissions to atmosphere is monitored by the Blowdown Emissions Committee. A tool called the Outage Decision Model (ODM) is the crucial element in minimizing vented methane emissions. This tool has been developed by TransCanada's operations planning group to facilitate how pipeline and system outages are addressed. Construction and maintenance activity along the pipeline facilities often require the system to come off line. In the past, this has been synonymous with the venting of methane. Outages along the system also have a financial impact to TransCanada in the form of the value of natural gas that is vented and lost revenue during the outage time. Tracking of methane fall into two categories, actual emissions emitted to atmosphere and the emissions saved by implementing mitigative measures. The volume of methane emissions saved is captured by the emissions tracking system that is managed by the operations planning group. The methane vented is captured in TransCanada gas accounting system. When an outage is required, a request in put forth to the operations planning group. The ODM is used to determine the best course of action for the outage, which includes mitigation techniques that are employed to reduce the venting of methane. During the outage itself, field personnel are required to fill out forms that provide detailed operations information that allow the gas accounting system and the emissions tracking system to determine the volume of methane vented and saved. There are a number of mitigative actions that TransCanada uses to reduce the volume of methane emitted to atmosphere. Many of these have been a result of research and development projects. Some of the mitigative actions are summarized below: i) Transfer Compression - When a section of pipe is isolated or shut down for maintenance, one or more transfer compressors are used to pump natural gas from the isolated section of line into another section that is still in operation. In 2000, 635 kilo tonnes of carbon dioxide equivalent were avoided from being vented to atmosphere. ii) Inline Inspection - TransCanada is now testing a pipeline inspection tool, known as a pig, that uses electro-magnetic acoustic transducers to reliably detect stress corrosion cracking (SCC.) If successful, this technology would further reduce the need for venting methane. Detection of SCC in a gas pipeline has previously required the use of ultrasound and has resulted in the venting of methane. iii) Buttering and Hot Tapping - Buttering and hot tapping procedures allow a new section of pipe to be welded to an operating pipeline without the need for natural gas flow to be shut off or vented to the atmosphere. In 2001, 160 kilo tonnes of carbon dioxide equivalent was avoided from being emitted to atmosphere.

1298 iv) Stopple Plugs - Large, portable pipeline plugs are called "stopples." These are used to isolate a short length of pipe and avoid large volumes of methane from being emitted to atmosphere. Emissions savings of 13 kilo tonnes of carbon dioxide equivalent resulted in 2001. v) Repair Sleeves - Fibre or steel reinforcement sleeves are used to permanently repair corrosion in pipeline sections without shutting down service or venting methane to the atmosphere. Emissions savings of 64 kilo tonnes of carbon dioxide equivalent resulted in 2001.

CONCLUSIONS There are a number of facets to TransCanada's methane emissions management program: source identification, quantification, tracking system, mitigative actions, pilot program, full scale implementation, monitoring progress, and continuous through research and development. The management of methane emissions is coordinated through a multi stakeholder team that consists of personnel from engineering, field operations, environmental protection and system operations. REFERENCES 1. Howard, T., Lott, R.A., and Webb, M. (1995). New Techniques Developed for Measuring Fugitive Emissions. Pipeline and Gas Industry. pp. 33-38.. 2. McBrien, R., Jones, B. and Venugopal, S. (1997). Effective Management of Fugitive Emissions from Natural Gas Transmission Facilities, Proceedings of the Air & Waste Management Association Speciality Conference - Emerging Air Issues for the 21 st Century: The Need for Multidisciplinary Management. Calgary, Alberta. September 22-24.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1299

NITROUS OXIDE EMISSION FROM PURIFICATION OF LIQUID PORTION OF SWINE WASTEWATER Takashi Osada

Dept. of Livestock Industry Environment National Institute of Livestock and Grassland Science, National Agricultural Research Organization, Japan 2 Ikenodai, Kukizaki, Ibaraki 305-0901, JAPAN

ABSTRACT

N20 is an essential greenhouse gas involved in world climate changes [ 1]. A large amount of nitrogen in livestock wastewater is treated with an activated sludge system to prevent public water pollution. In Japan, about 3% of CH4 and about 17% of N20 anthropogenic generation sources are presumed to be of livestock excrement origin [2], and its curtailment is necessary. To reduce N20 emissions from fill-and-draw type activated sludge units treating swine wastewater, N20 emissions were compared between the continuous aeration process (conventional process) and the intermittent aeration process. About 5% of the influent nitrogen was emitted as N20 gas using the conventional process under 0.5 kg m -3 d -I BOD loading and a temperature of 20°C. Most of the N20 was emitted during the first hours of aeration, beginning just after daily charging. Less than 0.05% of the influent nitrogen was emitted as N20 gas during the intermittent aeration process under two temperatures used (5°C and 20°C). The total emission of other harmful gases (NH3 and CH4) was negligible.

INTRODUCTION

Suitable processing and adequate usage of livestock excrement are serious on-going issues that affect livestock farming [3]. In areas where the livestock density per unit area is especially high, for example, parts of Europe and Japan, this is a serious problem. In Japan, the annual nitrogen amount (753Gt) contained in livestock waste was nearly equal to the annual consumption of nitrogen (600Gt) on cropland where chemical fertilizer had been spread (Table 1, [4]). This means that a large part of the nitrogen currently available in Japan is superfluous; it is difficult to apply and use all the livestock wastes on cropland. Surplus animal waste, especially wastewater handling, also poses a problem and must be carefully treated to protect public water [5]. To prevent surface and underground water pollution, a large amount of the nitrogen in livestock wastewater is purified with an activated sludge system. The activated sludge process with an intermittent aeration process (IAP) is reportedly effective for swine wastewater [6]. High removal efficiencies for biochemical oxygen demand (BOD), total organic carbon (TOC), total nitrogen (TN) and total phosphorus (TP) were achieved with the lAP. But, no attention has been paid to the fate of nitrogen gasses lost by this treatment system. In recent research, livestock manure has been suspected of contributing significantly to the emission of methane (CH4) and nitrous oxide (N20), both important greenhouse gases. Some efforts have been made to quantify the emissions from livestock manure stores [7][8] and from treatment systems [9][10][11]. The

1300 data collected have been limited, and therefore, it has not been possible to define the emission rates from wastewater purification. In the present study, bench-scale activated sludge units were operated with two types of aeration programs. The N20 gas concentrations during swine wastewater treatment were obtained to estimate total emission and to profile its release. TABLE 1 THE NUMBER OF LIVESTOCK AND ANNUAL PRODUCT OF THEIR WASTE NITROGEN AND PHOSPHATES IN JAPAN

(Tsuiki and Harada [4])

Type

Number LivestockWaste (Thousand tons) (Thousand) Feces Urine Total

Daily Cattle Beef Cattle Pig Layer Broiler Total

1,898 2,852 9,824 183,765 114,314

24,039 19,308 7,971 8,065 5,424 64,807

7,103 7,103 14,802

N and P in Waste(Thousand tons) Nitrogen Phosphorus

31 ,I 42 26,411 22,773 8,065 5,424 93,816

29,008

158.7 144.7 128.8 196.1 109.3 737.6

22.1 15.8 33.7 33.8 12.1 117.6

MATERIALS AND METHODS

Experimental design At 5 and 20°C conditions, the conventional and the intermittent aeration methods of wastewater purification were conducted with the bench-scale activated sludge unit (Fig. 1, 3 L operational volumes) under 0.5 kg m -3 d -1 of BOD loading condition, over 9 weeks. For the conventional process, a continuous aeration for 21 hours was adopted (ordinary method), while intermittent aeration was used at one-hour intervals. The units were set for a 24-hour cycle. The aeration periods started just after daily charging (0 time in Fig. 2). After the end of the aeration periods, the sludge in the mixed liquor was allowed to settle for two hours, and then the supernatant was discharged (Fig. 2). A mixture of swine feces and urine was used as influent wastewaters. The contents are shown in Table 2. Similar operational conditions for each run are as follows: 3 days of hydraulic retention time (HRT); 15-17 days of sludge retention time (SRT); 7000---9000 mg L 1 of mixed liquor suspended solid (MLSS); 0.5 kg m 3 d -1 of BOD loading; 1.2L min -1 3 L 4 aeration rate.

Discharge/Cha"cje ~..~a.s.~mple

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NEAP (Ordinaly)

Figure 2: Time chart of experimental operation

1301

TABLE 2 CHARACTERISTICSOF INFLUENTWASTEWATERAND EFFLUENTOF BOTHTREATMENTS (Average)

Items

Unit

Influent

BOD T-N

mgEl21L mglL refilL mg/L

1500.0 207.0 not detect 127.0

NOx-N

T-P

Effluent IAP NLAP(Ordinal.q) 2 El"C 5 "C 2 0 "C 5"C 19.5 12.7 9.6 30.g 94.5 54.5 32.0 100.4 19.6 6.5 6.5 16.7 43.0 48.3 46.3 41.7

Each unit was operated for a period longer than two SRTs (about 30 days) to obtain a steady-state condition. Also, the performance of each unit was evaluated for an additional two SRTs. Table 2 shows the average of the treatment data. The exhaust gases from the units were evaluated several days of wastewater treatment in the steady-state condition. These gases were collected from each head space (3 L) of the units opened (aeration periods) or closed (non-aeration periods) for 5-minute intervals during 24 hours (one treatment cycle).

Analysis The water qualities of the influent and effluent were analyzed twice a week for pH, TN, TP, NOx-N, and weekly for BOD. All analyses were conducted in accordance with the procedures of APHA [ 12]. Gas from each sampling point was automatically carried to the analysis apparatus through a Teflon tube (4 mm diameter). NH3, CH4 and N20 concentrations in the air samples were measured by Infrared Photoacoustic Detector (IPD, multi gas monitor type 1312, INNOVA, Copenhagen DK [ 10]) at 5-min. intervals (Fig. 1). Gas dried by electric cooler was used for the measurement of CH4 and N20 to improve the accuracy.

Method for calculating emission rate of each substances The rate of emission (E) for each substance (NH3, CH4 and N20) was computed from the concentration differences of each substance between inlet and outlet (background) air samples and the amount of flow-rate (0.0012 m 3 min -1, aeration periods) or headspace volume (3 L, non-aeration periods, sediment periods and discharge/charge periods). At the aeration periods: E (mg/5 min.) = (Cone. of outlet air (mg m -3) - Cone. of inlet air (rag/m-3)) x 5 x Flow-rate (m 3 hour 1)

...(1) Other periods: E (mg/5 min.) = (Cone. of outlet air (mg m -3) - Cone. of inlet air (mg m3)) x 5/60 x 0.003 (m 3 hour l )

...(2) * The 3 liters ofheadspace gas was completely replaced in one hour during which there were 12 gas samplings.

RESULTS AND DISCUSSION

Removal efficiencies of wastewater and CH4 and NzO emissions by both processes The average values of effluent characteristics in the processes are shown in Table 1. When the processes were rather high in MLSS concentration, high removal efficiencies (97.9 - 99.4%) for BOD were attained with both IAP and NLAP in all runs. While large differences in the removal of nitrogen between IAP and NLAP were observed at 20°C, the removal efflciencies for TN in IAP and NLAP were 84.5 and 54.8%, respectively. However, those removal efflciencies decreased with the decline of temperature (5°C). Removal

1302 efficiencies of IAP could solely satisfy the governmental effluent standard for BOD (120 mgL l daily average) and nitrogen (60 mgL 1 daily average). During steady-state conditions of wastewater treatment, exhaust gases from the units were evaluated. NH3, CH4 and N20 concentrations were measured at 5-min intervals by IPD throughout each treatment process (24 hrs) and emissions of each gas were totaled. The NH3 concentration in most of the exhaust gas in both processes was under 0.1 mg m -3, and the total emission of NH3 was considered negligible. The total emissions of CH4 from both processes were also low; for example, at the 20°C condition, NLAP and lAP exhaust was 1.33 and 2.05 mgCH4-C of CH4 throughout each process, respectively. These emission levels are equivalent to 0.14 and 0.22% of TOC in treated (influent) wastewater. This generation rate is kept to less than one-tenth the rate of emissions (2.6 %) generated from the stocked pig slurry rate earlier reported by Husted [8], compared to the organic matter base. N20 emissions during the NLAP treatment were 10.6 and 3.0 mg N20-N under the 20 and 5°C condition, respectively. In this experiment, the wastewater contained 207 mg of nitrogen. Thus, no less than 5% and 1.5% of the influent nitrogen was emitted as N20 gas using the conventional process under 0.5 kg m 3 d 1 BOD loading at each temperature. Less than 0.05% of the influent nitrogen was emitted as N20 gas IAP at both temperatures. Tsuruta [13] estimated around 0.92% of the nitrogen put in soil was lost as N20 in Japanese upland fields. At this level of N20 discharge, the conventional wastewater purification clearly has a serious impact on grovel warming when compared to agricultural usage.

GWPs of Swine wastewater treatment According to this experimental result, the GWPs [ 1] of swine waste treatment could be calculated as shown in Fig. 3. During one cubic meter of swine wastewater purification by the conventional process, about 1400 gCO2- 5000 gCO2 may generate as CH4 and N20 directly. These emissions could be reduced significantly about 77.1 gCO2 - 98.3 gCO2 by adequate manure contribution, and the adaptation of the intermittent aeration process for wastewater treatment.

(g C 0 2 eq) 4943.2

5000 4000 3000 2000 100C ~o(co2 ~ r4 (co2 ~¢~

C . . . . . . lAP/ LAP/ /20"C/ 5 "C 20"C 5°C

Figure 3: Grovel warming potentials generated directly from 1 m 3 of swine wastewater purification except CO2. (*1 m 3 of swine wastewater contain 950 g of total organic materials and 207 g of nitrogen.) N 2 0 emission pattern during both wastewater purification processes Significant differences were noted in the removal rate of nitrogen (Table 1) and N20 emission between NLAP (conventional process) and lAP for the same nitrogen loading (207 mg L l ) both at 20 and 5°C. Fig. 4 shows N20 concentration changes in exhaust gases from both processes.

1303 Sediment Discharge/Charge

Aeration

-,,. E

---

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Time (hrs) Figure 4 : N 2 0 concentration in the exhaust gases and background air during wastewater treatment under Non Limited Aeration Process (4a, upper) and Intermittent Aeration Process (4b, under) In NLAP, a large amount of N20 was emitted during the initial stage of the aeration periods (0 to 3 hrs), which corresponded with the NOx-N decrease in the treated wastewater at low D.O. (0-0.5 mg 02 Ll). N20-N emission was stable at a relatively low level (9 mg m -3 at 20°C, Fig. 4 a). These data suggest that the emitted N20 mainly derived from a denitrification process. Zheng et al. [14], however, reported a high concentration of N20-N production during both the nitrification and the denitrification process at low D.O. (under 0.2 mg 02 L l ) conditions. During lAP, a high N 2 0 concentration was measured mainly during the non-aeration periods, and was relatively low (around 10 mg m -3 at 20°C, Fig. 4 b). The total emission of N20 was reduced by approximately 1/50 of the conventional process. Hanaki et al. [ 15] pointed out that a low COD/NOx-N ratio enhanced the N20 production. The incorporation of the intermittent low D.O. (non-aeration) periods in IAP

1304 might enhance denitrification and therefore avoid the accumulation of NOx-N. This seems to create a condition with a high ratio of organic substrate and NOx-N.

CONCLUSIONS

The results of the present study may be summarized as follows. 1) About 5% of the influent nitrogen was emitted as N20 gas using the conventional process under 0.5 kg m -3 d -l BOD loading and a 20°C condition. Most of the N20 was emitted during the first hours of aeration started just aider daily charging. 2) The emissions could be reduced by using the intermittent aeration process for wastewater treatment. Only Less than 0.05 % of the influent nitrogen was emitted as N20 gas during the intermittent aeration process under either temperature condition (5°C and 20°C). 3) The total emission of other harmful gases (NH3 and CH4) was negligible.

REFERENCES 1. 2.

Intergovernmental Panel on Climate Change (IPCC) (2001) Climate Change 2001 - Mitigation-, Section 3.6 Agriculture and Energy cropping, Cambridge University Press, UK Haga,K (1998a) Generation and regulation of methane and nitrous oxide from livestock waste. In: Emission control of the greenhouse gas in livestock farming, Report of investigation examination

enterprise for greenhouse-gas control technology concerning animal industry in Heisei 10 fiscal year, 3. 4. 5. 6. 7. 8. 9. 10.

11. 12. 13.

14. 15.

(1999) Japan Livestock Technology Association, 82-107 (Japanese) Law concerning the Appropriate Treatment and Promotion of Utilization of Livestock manure (Law No. 112 of July28, 1999), Japan Tsuiki M. and Harada Y. (1997) A Computer Program for Estimating the Amount of Livestock Wastes. The Journal of the Japanese Agricultural Systems Society 13(1) 17-23 Haga,K (1998b) Animal waste problems and their solution from the technological point of view in Japan. Jpn. Agric.Res.Q.,32 (3) 203-210 Osada T., Haga K. and Harada Y. (1991) Removal of nitrogen and phosphorus from swine wastewater by the activated sludge units with the intermittent aeration process, Water Research 25:1377-1388 Safley, L.M. Jr. and Westerman, P.W.,(1988) Biogas production from anaerobic lagoons. Biol. Wastes 23, 181-193. Husted S. (1994) Seasonal variation in methane emission from stored slurry and solid wastes. J. of Environ. Quality 23,585-592. Burton C.H., Sneath R.W. and Farrent J.W.(1993) Emission of nitrogen oxide gases during aerobic treatment of animal slurries Bioresource Technology 45,233-235 Osada T., Hans Benny Rom and Preben Dahl (1998) Continuous Measurement of Nitrous Oxide and Methane Emission in Pig Units by Infrared Photoacoustic Detection, Transaction of the ASAE. Vol 41, ppl109-1114. Osada T., Kuroda K., and Yonaga M. (2000) Nitrous oxide, Methane and ammonia emissions from composting process of swine waste. The Japanese Society of Waste Management Experts 2,51-56 APHA (1985) Standard Methods for the Examination of Water and Wastewater, 16th edition. American Public Health Association, Washington D.C. Tsuruta H. (1997) Emission rate of methane from rice fields and nitrous oxide from fertilized upland fields estimated from intensive field measurement for three years all over Japan, Res.Rep.Div.Environ. Planning. National Institute of Agro-Environmental Sciences Japan 13, 101-130 Zheng H., Hanaki K. and Matuo T.(1994) Production of nitrous oxide gas during nitrification of wastewater, Water Science and Technology, 30:133-141 Hanaki, K., Hong, Z. and Matuo, T.(1992) Production of nitrous oxide gas during denitrification of wastewater, Water Science and Technology, Vol. 26,No.5/6, 1027-1036

FUEL CELLS

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1307

HIGH EFFICIENCY CARBON AND H Y D R O G E N FUEL CELLS* FOR CO2 MITIGATED P O W E R M. Steinberg1, j. F. Cooper2 and N. Cherepy2 ~Brookhaven National Laboratory, Upton, NY 11973-5000 2Lawrence Livermore National Laboratory Livermore, CA 94551

ABSTRACT Hydrogen fuel cells have been under development for a number of years and are now nearing commercial applications. Direct carbon fuel cells, heretofore, have not reached practical stages of development because of problems in fuel reactivity and cell configuration. The carbon/air fuel cell reaction (C + 02 = CO2) has the advantage of having a nearly zero entropy change. This allows a theoretical efficiency of 100% at 700-800°C. The activities of the C fuel and CO2 product do not change during consumption of the fuel. Consequently, the EMF is invariant; this raises the possibility of 100% fuel utilization in a single pass. In contrast, the high-temperature hydrogen fuel has a theoretical efficiency of <70%, and changes in fuel activity limit practical utilizations to 7585%. A direct carbon fuel cell is currently being developed that utilizes reactive carbon particulates wetted by a molten carbonate electrolyte. Pure CO2 is evolved at the anode and oxygen from air is consumed at the cathode. Electrochemical data is reported here for the carbon/air cell utilizing carbons derived from fuel oil pyrolysis, purified bio-char and petroleum coke. At 800°C, a voltage efficiency of 80% was measured at power densities of 0.5-1 kW/m2. Carbon and hydrogen fuels may be produced simultaneously at high efficiency from: (1) natural gas, by thermal decomposition, (2) petroleum, by coking or pyrolysis of distillates, (3) coal, by sequential hydrogasification to methane and thermal pyrolysis of the methane, with recycle of the hydrogen, and (4) biomass, similarly by sequential hydrogenation and thermal pyrolysis. Fuel production data may be combined with direct C and H2 fuel cell operating data for power cycle estimates. Thermal to electric efficiencies indicate 80% HHV [85% LHV] for petroleum, 75.5% HHV [83.4% LHV] for natural gas and 68.3% HHV [70.8% LHV] for lignite coal. Possible benefits of integrated carbon and hydrogen fuel cell power generation cycles are: (1) increased efficiency by a factor of up to 2 over many conventional fossil fuel steam plants, (2) reduced power generation cost, especially for increasing fossil fuel cost, (3) reduced CO2 emissions per kWh, and (4) direct sequestration or reuse (e.g., in enhanced oil or NG recovery) of the CO2 product. *Based on report by Steinberg, M., Cooper, J.F., and Cherepy, N., UCRL-JC-146774 Lawrence Livermore National Laboratory, Livermore, CA (Jan. 2, 2002)

1308 INTRODUCTION Fossil fuels especially coal make up 85% of the vs. energy supply. Attempts at directly converting coal to electricity in an electrochemical fuel cell dates back to the 19th century. ~1) Further attempts were made sporadically during the 20 th century with the latest by Weaver of SRI International. ~2) The main barriers of these attempts to develop a practical carbon/air fuel cell were: (1) buildup of ash in the molten carbonate electrolyte, (2) very low anode reaction rates, and (3) the high cost of carbon electrode manufacture and the logistics of distribution to the cells. The Direct Carbon Fuel Cell The current approach at LLNL to overcome the historical failures is to employ a low ash, high surface area (turbostratic) elemental carbon fuel produced by pyrolysis of hydrocarbons derived from the processing of fossil fuels (coal, oil, gas) and biomass. This carbon particulate fuel, once wetted with molten salt, acts like a rigid anode when in contact with an inert metal screen. The anode reaction takes place between the carbon and the carbonate ion from the electrolyte, releasing CO2 and electrons. At the cathode, oxygen (from air), CO2 and electrons returning from the anode produce the carbonate ion. A porous ceramic membrane allows the carbonate ion to migrate between the two electrode compartments. Nickel (with a coating of lithiated nickel oxide) is typically used at the cathode, and the CO2 for the cathode reaction may be provided by the anodic reaction. The fine particulate carbon may be distributed to the anode compartment by entrainment in a CO2 stream. A schematic of the components of a typical fuel cell is shown in Figure 1.~5)

For the reaction of carbon and oxygen to form carbon dioxide, the entropy of reaction is positive but nearly zero. O) As a result, the thermodynamic efficiency (~G/~H°298) is calculated to be 100.3% and is nearly independent of temperature. The standard cell voltage calculated on the basis of the free energy change (E°=eG(T)/4F) is 1.03 V for graphite. By comparison the thermodynamic efficiency at 1000°K for a hydrogen/oxygen fuel cell is 70% and for methane (intemally reformed to hydrogen in a fuel cell) it is 89% (Table 1). Another unique feature of the direct carbon cell is that the activity of carbon (a pure substance in its elemental state) is unity and invariant. This allows the possibility of 100% utilization of the carbon fuel in a single pass. Also the CO2 produced is undiluted and its activity is also variant. This is not true for gaseous fuels that are continuously diluted with reaction products (for example, H2, is diluted by H20). The utilization efficiency for hydrogen and methane as electrochemical fuels decreases to 75-85% (4) at practical current densities. A further important feature of the carbon fuel cell is that the reaction product, CO2 is exhausted from the anode compartment as a pure substance. This allows for recovery and disposal or utilization of CO2 without the need for further collection or separation that adds cost and energy consumption. Table 1 compares the net efficiencies (product of 3 terms shown) for the 3 major fuels.

E X P E R I M E N T A L RESULTS Based on the experimental cell design constructed at LLNL, cell potentials as a function of current density were determined for a number of different types of carbon particulates in a molten salt cell at (5) , a temperature of 800°C, and is shown in Figure 2. The cell power density is a function of the type of carbon fuel. At 0.8 V, current densities in the 60-120 mA/cm 2 range are obtained with the highest current densities for the most "turbostratic" carbons. For the carbon fuels presented in Figure 2, the bio-char has the most disordered crystallographic structure, with deconvoluted domains of crystallinity of-2.5 nm in the plane of the graphene layers and -1 nm perpendicular to the graphene layers. The green needle petroleum coke sample, by contrast, has somewhat larger crystallinity domains o f - 5 nm by 4 nm, and correspondingly lower reactivity. These results indicate that efficiencies of 80% HHV can be obtained at reasonable power densities for power production. Practical hydrogen powered solid oxide fuel cells operate in the range of 1 kW/m 2 at 0.8 volts, (6) which is the same as achieved for the most active carbon shown in Figure 2. As in the hydrogen cell, the major loss is due to the oxygen over-voltage at the cathode. Further work with the carbon fuel

1309 cell employing state-of-the-art molten carbonate fuel cell cathodes has already shown a reduction in oxygen over-voltage. C7)

Fuel Processing Over the past several decades, a number of processes, some that are industrial and some that have been under development, have the potential of providing the carbon fuel material suitable for direct carbon fuel cells. The major process operations which could yield highly active carbon particulates involve pyrolysis, hydropyrolysis, and thermal decomposition or cracking of natural fossil fuels. Based on the thermodynamics of these operations, power cycles were designed and efficiencies were determined for the major fossil fuel feedstocks including biomass. ~8'9~ Natural Gas For the thermal processes, at pressures below 5 arm and temperatures in the range of 800 - 1000°C, thermodynamic equilibrium indicates that 90% of the methane can be dissociated to carbon and hydrogen. Both the carbon and the hydrogen can be used in respective fuel cells for electric power production. There are three industrial processes for production of carbon black, used mainly for reinforcement of automobile tires. The thermal black process uses tandem firebrick furnaces, alternately reheated, and methane is pyrolyzed in the absence of air. The furnace black process partially combusts methane or furnace oil in a rich flame and the carbon fines are collected as product. These processes can be made highly efficient if the hydrogen is used in an integrated power plant. The third and most recently practiced process is the plasma black process that uses an electric discharge to crack the methane. Both the carbon and hydrogen are recovered. The process is claimed to be 90% efficient. Coal There has been much effort to produce synthetic gaseous and liquid hydrocarbon fuels by gasification and liquefaction processes, however, there is no industrial process for production of a clean carbon fuel from coals. A two-step process has been developed which has the potential of producing a clean carbon and hydrogen co-products from coal. By hydropyrolysis at high temperature and high pressure (800 - 900°C and 70 - 100 atm) most of the carbon in coal can be converted to methane. (8~ The hydrogenation reaction is also exothermic, thus making the process energy efficient. The methane can then be cracked to C and H2. Part of the hydrogen is then recycled to hydrogenate the coal and the remainder becomes a product of the process. Both the carbon and the hydrogen can be used in fuel cells. Hydropyrolysis has been used experimentally in Germany by the Rheinbraun Co. to generate methane from brown coal. This twostage reversible hydrogenation process also known as the Hydrocarb process can be used for processing of coal for integrated fuel cell power cycles.

High Efficiency Power Generation Cycles The high efficiency direct carbon fuel cell (DCC) and the solid oxide hydrogen fuel cell (SOFC) integrated with fuel processing to carbon and hydrogen in a combined cycle and using a back-end Rankine steam plant, maximizes the power generation efficiently. ~8'9) Figures 3 and 4 show respectively schematics of the components for natural gas and coal integrated fuel cell, combined cycle power plants. The hot H20 and CO2 effluents from the fuel cells are used in back-end steam cycles. For natural gas, only a thermal decomposition reactor is needed for fuel processing. For coal (lignite) fuel a two-reactor system, a hydropyrolyzer and a methane decomposer is needed to produce the C and H2. Similar cycles can be shown for petroleum coke oil, and biomass fuel feedstocks. ~8'9) Economic and Environmental Assessment of Integrated Carbon Fuel Cell Plants Based on current and projected costs of fossil fuels and estimates of unit capital investment of fuel cells and conventional power plants, estimates of the cost of power generation for each of the

1310 integrated fuel cell plants and for typical current and advanced conventional plants are made including CO2 emissions. The cost assumptions include a fixed charge of 20% on capital investment taking into account depreciation and taxes and a 15% charge for operation and maintenance of the fixed charge amount. Table 2 gives a summary comparison of the economic and environmental parameters for the fuel cell plants with conventional coal and gas plants. The coal integrated carbon fuel cell (ICFC) plant is 80% more efficient than a conventional Rankine pulverized coal (PV) steam plant and 37% more efficient than a combined cycle gasification plant. At $1/MMBTU, the lignite ICFC plants yield the lowest electricity production cost even when the unit capital cost is about the same for all three of these plants. The CO2 emissions for an ICFC plant are a significant 44% lower than a PV steam plant. Furthermore, the CO2 effluent is undiluted and ready for sequestration or utilization without further separation as is required by conventional plants. The natural gas fired ICFC plant is over 90% more efficient than a conventional natural gas fired plant. The ICFC is also 26% more efficient than the current most efficient NG combined cycle plant, which currently reaches 60%. The historical NG cost has been $2/MMBTU. It has gone up as high as $10/MMBTU and has recently decreased to a little over $3/MMBTU. At $2 and $4/MMBTU, the ICFC plant would produce electricity at a slightly higher cost than the NGCC plants available today but lower cost than a conventional natural gas fired steam plant. However, at $6/MMBTU for natural gas, the ICFC plant becomes more economical. However, in all cases, the CO2 emission is reduced by 47% and 73% lower than conventional gas and coal fired plants, respectively. The cost of obtaining the CO2 reduction amounts to $23/ton at the $4/MMBTU NG cost which is two to three times lower than estimates for removal and disposal of CO2 from conventional plants. In the case of biomass as a fuel, the CO/ reductions is 100% and assuming biomass can be obtained for $2/MMBTU the cost of power can be about 13% lower than a conventional steam plant.

CONCLUSIONS The more efficient carbon fuel cell power plants can generate electric power more economically from fossil fuels (10-33% lower than conventional steam plants), and can significantly reduce CO2 emissions by 44-73%. The direct carbon fuel cell provides the following advantages: (1) a significant increase in thermal efficiency of combined cycle direct carbon fuel cell power plants, (2) a significant decrease in CO2 emissions, (3) a pure CO2 stream which can be directly sequestered or utilized, and (4) a lower production cost than conventional plants.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1311

MULTI-CRITERIA OPTIMIZATION OF ON-SITE HEATING, COOLING AND POWER GENERATION WITH SOLID OXIDE FUEL C E L L - GAS TURBINECOMBINED CYCLE UNITS K. Tanaka l, M. Burer 2, D. Favrat 2 and K. Yamada 3 1 Tyndall Centre for Climate Change Research, UMIST, PO Box 88, UMIST, Manchester, M60 1QD, UK, Email: [email protected] 2 Swiss Federal Institute of Technology, Laboratory of Industrial Energy Systems, 1015 Lausanne, Switzerland, Email: [email protected] 3 Shinshu University, Department of Fine Materials Engineering, 3-15-1 Tokida, Ueda, Nagano 386-8567, Japan, Email: [email protected]

ABSTRACT

The implementation of integrated energy systems within urban areas is a promising CO2 emissions abatement measure. In this paper on-site heating, cooling and power generation based on a solid oxide fuel cell and gas turbine (SOFC-GT) combined cycle unit associated with a compression chiller and additional boilers has been considered from the viewpoints of cost and CO2 emissions. Physical and costing modelling of such a unit has been integrated within a new multi-criteria evolutionary algorithm for an assessment of the economic and environmental performances associated with optimal design and operation, for typical requirements of large office buildings in Tokyo. INTRODUCTION

Urban areas characterized by a high density of energy demand offer a significant potential for GHG emissions reduction, especially CO2 emissions resulting from fossil fuel consumption. The introduction of decentralized and advanced energy supply systems is among the most promising options [ 1]. Solid oxide fuel cells (SOFC) can provide highly effective energy conversion systems when their high temperature and high pressure exhaust gases are expanded within a gas turbine (GT), the exhaust heat of the latter being possibly recovered for pre-heating purposes. SOFCs also emit significantly less atmospheric pollutants compared with current generation units and retain high performance at small-scale. These characteristics make them particularly suitable for decentralized units located close to the users. Higher efficiencies can be achieved when considering cogeneration with the use of the exhaust heat to meet part of the heating requirements, he unit can be operated all along the year in association with a chiller when both heating and cooling are necessary. Previous work has been assessing such a technology together with heat pumps and chillers within district plants associated with heating and cooling networks for the supply of building clusters [2,3]. In this paper onsite heating, cooling and power based on SOFC-GT combined cycle units has been investigated for large office buildings in Tokyo. A new multi-criteria evolutionary algorithm [4] has been used to derive the Pareto frontier associated which such systems when considering the trade-off between economic and environmental performances. Based on local grid power and natural gas prices, local grid average CO2 emissions factors, and local climatic conditions, the results provided are specific to the city of Tokyo or to similar contexts. Further work will extend the analysis to other locations. Sensitivity analysis regarding the investment cost of SOFC-GT systems has been undertaken in order to identify the critical specific investment cost required to be competitive with the business as usual.

1312 MODELING The system considered is illustrated in figure 1. It is assumed to be covering air heating and hot water demands all along the year, as well as cooling in summer and mid-season for air conditioning requirements. Part of the heat can be supplied by recovering heat from the exhaust gases of the cogeneration unit. Two additional boilers supply the complement. Their total capacity is set to match the total heating demand in case of unexpected outage of the SOFC-GT unit, or during maintenance periods. One of the two boilers is designed as the leader, while the second one - further referred as peak boiler - is used for peaking demand only. Cooling requirements are met using a compression chiller, the condenser of which being associated with a cooling tower. "

I

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Figure 1" Superstructure considered for the power, heating and cooling unit installed within a large office building. Boilers and the SOFC-GT combined cycle are natural gas-fired. After compression, air must be pre-heated to maintain the working temperature prior to injection into the fuel cell module, with the high-temperature exhaust gases from the module and lower temperature waste gases from the exhaust of the gas turbine providing the sources for pre-heating. Exhaust gases of the gas turbine are given priority for the air preheating in order to extract more work. To increase the amount of work performed, and in turn the amount of electricity generated, fuel cell exhaust gases may undergo additional combustion with fuel after entering the combustion chamber directly or after preheating the air supplied to the cathode of the SOFC. Since such a technology is not commercialised yet, a methodology based on materials and weights has been considered here to allow an estimation of the future SOFC-GT systems investment cost. During the total lifetime of the plant (chosen to be 20 years) provision is made for SOFC cells and catalyst to be replaced every 5 years. More details on the SOFC-GT modelling can be found in [5]. A fuel cell is characterized by a high efficiency at part-load, but its association with a gas turbine does not benefit from the same advantage, unless variable speed operation is considered. Reducing the anode fuel flow influences the overall efficiency due to a decreased current density, a lower Nernst potential and lower voltage losses [5]. At constant rotation speed, the air mass-flow and pressure ratio need to be adapted to changing conditions at the entrance of the turbine. These considerations will be published elsewhere. In this study, the building is connected to the grid, and importation or exportation of power is authorized at all time at prices established within contracts with the grid owner. Prices can be found in table 1, fluctuating along the day according to local power demand conditions in Tokyo. The SOFC-GT unit is therefore either operated at nominal load or shut-down, its capacity and on-off hourly schedule being both optimized. Typical heating,

1313 cooling and power 1 specific demand patterns (see figure 2) have been considered for typical days in winter, summer and mid-season to derive the yearly requirements of an 80'000 m 2 office building. Seasonal and hourly fluctuations of the CO2 emissions rate of power supplied by the grid with the global demand in Tokyo are also considered [7], [8] (figure 3). Emissions related to importation and exportation of power have therefore both been taken into account, so that whenever the specific emission rate of the new unit is lower than the one of the grid, emissions savings result from the substitution of power from more emitting existing units. 0.5 1

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F i g u r e 3" Hourly CO2 emissions rate of power supplied by the grid in Tokyo.

F i g u r e 2" Heating, cooling and power demand patterns for typical days in summer, winter and mid-season of large office buildings in Tokyo.

TABLE 1 POWER IMPORTATIONAND EXPORTATIONPRICES,AND NATURALGAS PRICES(Unit: UScst/KWh) Season

Winter and Mid Season Daytime Night

Summer Daytime

Peak time

Night

Power Importation Prices

11.5

5.0

12.5

13.5

5.0

Power Exportation Prices

6.0

3.0

6.5

6.5

3.0

Natural Gas Price

3.5

OPTIMIZATION PROCESS Two objectives have been simultaneously optimized: the annual total levelized cost of power, heating and cooling generation z for the office building considered, and the annual CO2 emissions rate resulting from the installation of the new unit. Three cases corresponding to different investment costs for the SOFC-GT unit have been investigated with discounting rate and fuel escalation price chosen to be respectively 12% and 0%. Pareto-optimal frontiers have been derived, which define in each case the minimum cost required to achieve any level of CO2 emissions with this new unit, or inversely the maximum CO2 emissions abatement achievable for a given budget. A recently developed multi-criteria evolutionary algorithm has been used as the optimizer, a detailed description of which can be found in [4]. Decision variables have been chosen to be 1) the amount of natural gas driven to the SOFC, 2) the amount of additional natural gas driven directly to the GT, 3) the cell working temperature, 4) the working pressure of the system, 5) the pinch at the final heat recovery device, 6) 7) and 8) the minimal power generation under which the unit is shut down in respectively winter, summer and mid-season, and 9) the share of the leader boiler in the total boilers heating capacity. Both first and second decision variables are directly related to the capacity of the SOFC-GT system, the additional fuel driven to the GT introducing more flexibility since it 1 Here power refers to ventilation, appliances and light, but does not include the power required by the chiller and the cooling tower system which is calculated separately; heating and cooling demand patterns have been assumed based on [6] which has been originally published as a manual for designing cogeneration in Japan. 2 The total levelized cost is the discounted sum of annual capital, operation, maintenance and depreciation costs over the lifetime of the unit, converted into a uniform series of annual payments.

1314 allows a control of the exhaust gases thermal characteristics independently from the SOFC operating. When operating at nominal load, this higher degree of freedom induces however a lower electric efficiency since part of the fuel is converted into power only through the single gas turbine cycle and its low efficiency energy conversion. On-going work investigating further the benefits of such flexibility for part-load operating of the SOFC-GT will be published elsewhere. A minimum capacity has been required in this case study so that when the fuel flow driven to the SOFC is lower than 3 mol/sec, the combined cycle power output is set to zero, which means that all the power required has to be imported. The effects of working pressure and working temperature on systems' thermal efficiency and investment cost have been described in detail in [5]. The fuel utilization ratio, the air utilization ratio and the steam to carbon ratio were respectively set to 0.8, 0.3 and 1.2. The optimal pinch of the heat recovery device has to be the result of a good compromise between an efficient heat transfer process and a heat exchange area with a reasonable cost. The hourly operating schedules in winter, summer and mid-season are optimized by deriving optimal lower power demand threshold under which importation power is either more economic or environmental, considering grids' CO2 emissions and power prices. Finally, the capacity of both leader and peak boilers is optimized through the relative share of the leader boiler. The set of decision variables chosen for this study is given in table 2 together with their lower and upper boundaries. TABLE 2 DECISIONVARIABLESANDTHEIRLOWERAND UPPERBOUNDARIES. Decisionvariables SOFC fuel flow GT fuel flow Pinch Heat Recovery Device Working temperature of the S O F C Working pressure of the S O F C / G T Min S O F C - G T winter Min S O F C - G T summer Min S O F C - G T mid-season Share of the leader Boiler

type

unit

lowerbound

real real real integer integer real real real real

mol/sec moUsec K

3.0 0 2.0

K

5.0 30.0

873 - 973 - 1073- 1173- 1273

MPa -

upper bound 10.0

0.4 - 0.6 - 0.8 - 1.0 0.0 0.0 0.0 0.0

1.0 1.0 1.0 1.0

RESULTS AND DISCUSSION Figure 4 shows the Pareto fronts obtained for the three optimization processes, the low SOFC-GT investment cost case 3, and the medium and the high cost cases corresponding to investment costs respectively increased by 30% and 100 % compared to the low cost case. When considering the high investment cost scenario, the most economic but most emitting option is to import all the power required from the grid (individual hc-A). This option can be referred as the business as usual. The introduction of a 2.4 [MWe] SOFC-GT unit allows a reduction of the yearly CO2 emissions rate by about 14% at the expense of a yearly total levelized cost of heating, cooling and power generation increased by about 10% (ind. hc-B). As can be seen in figure 6, the SOFC-GT unit is then operated at low temperature - 700 [°C] - and high pressure- 1.0 [MPa] -, and with a ratio between the GT additional fuel mass-flow and the total fuel mass-flow of 0.4, resulting in a 59.7% electric efficiency. The unit is then characterized by a specific investment cost and a specific COa emissions rate of respectively 1665 [US$/KWe] and 0.357 [kgCO2/KWh~]. However, within such a high investment cost scenario, the implementation of a CO2 tax of about 100 [US$/tonCOa] would be necessary to force the shift from the current business as usual to such a configuration, which is politically hardly conceivable. R&D must therefore reduce the SOFC-GT systems investment cost even with the introduction of policies that would consider an internalization of the pollution cost. Currently, the movement for commercialization of single fuel cell systems has gained force. Specific costs in the range of 1,000 to 3,000 [US$/kW] are targeted [9]. Current R&D stages cost is about ten times higher. As regards to SOFC-GT systems, Siemens Westinghouse Power Corporation is developing a pilot 1 [MWe] plant, and commercialization is expected around the year of 2004. Electric Power Development Company in Japan announced to realize FC-GT 3 This case corresponds to the cost derived using the methodologycited above based on materials and weights for commercialized equipments (hypothesis of mass-produced fuel cells).

1315 combined system of 2,500 [US$/kW] by the early 2010s. Results show that a reduction by 70% of the SOFC-GT investment cost (medium cost case) would make the option of a-decentralized unit competitive, with a 1080 [US$/KWe] specific investment cost. The low cost case (half the high cost case) offers a comfortable margin of about 200,000 US$ per year. Most of the investment cost reduction would have to be reach regarding the fuel cell component and a specific price of about 600 [US$/KWe] should be reached for the latter to achieve the low cost scenario. 6000

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Figure 4: Pareto frontiers obtained for respectively hypothesis of a high, medium and low SOFC-GT investment cost.

In the high cost scenario, the marginal cost of CO2 emissions reduction associated with the incremental improvement of the efficiency of the SOFC-GT unit is especially high as can be measured from the slope of the Pareto front. This is explained by an investment cost increasing at a much higher rate than the rate of operating cost reduction resulting from the corresponding efficiency improvement (see figure 5). The SOFCGT unit is of course the dominant component in the total investment cost (see figure 5), and the additional

cost resulting from systems operating at higher temperature and lower pressure is not compensated by economies of scale linked with an increase of the capacity along the Pareto curve (figures 6 and 7). Economics will drive the development of such systems towards low temperature and high pressure operating

conditions. A significant reduction of the investment cost allows lower marginal cost of emissions abatement due to a lower weight of the capital cost in the total levelized cost of heating, cooling and power generation. In the mean-term, a similar effect could be obtained with lower discounting rates that would be obtained in the framework of public owned projects. Under a low cost scenario, a reduction by half of the CO2 emissions annual rate compared to the business as usual using a SOFC-GT unit would be achieved at the expense of a yearly budget increased by 50% 4 compared to the most economic design, or increased by about 30% compared to the business as usual (ind. hc-A). Figure 8 provides the optimal hourly schedule associated with individual hc-B. It can be seen that the unit covers the power requirements in winter, and that the unit is shut down at night due to low corresponding heating requirements. Summer is mainly a power importation period. This indicates that for such a case, economics require the unit to be designed according to the heating demand with a heat recovery device providing about 45% of the power demand at peak heating load, and 48% of the total winter heating energy demand. On a yearly basis, the SOFC-GT unit is operated for 4,925 hours. The consideration of other types of buildings possibly more suitable for cogeneration may drive to higher yearly operating factors for a similar capacity. Increasing the power capacity allows emissions savings by substitution of more emitting power 4 However, this corresponds to a 8 [MWe] unit which is much more than the building peak power demand of about 5 [MWd; this option would be hardly conceivable in practice since the unit turns more into an independent power generation unit than an on-site cogeneration unit.

1316

from existing units in the grid, but the power internally used for the chiller is generated at a higher cost than the grid power price. .................................... __~ [ ] i ; ~ Inve~cnent Cost ~ ................... Immm Yearly Operating Cost

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Figure 5: Total Investment Cost [millionsUS$/year], Yearly Operating Cost [millionsUS$/year] and Yearly CO2 Emissions Rate [tonsCO2/year] (left side), and share of all components in the total investment cost (right side), associated with selected individuals of the high cost hypothesis Pareto frontier.

0.7

Electrical Efficiency [-] Specific CO2 Emissions Rate [ k g C O 2 / K W h ]

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7

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Figure 6: Electrical Efficiency [-], specific CO2 Emissions Rate and Specific Investment Cost associated with the SOFC-GT unit of selected individuals from the high cost hypothesis Pareto curve. In:t B W t l e r ao

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Figure 7: Working Pressure and Working Temperature of the SOFC-GT unit for selected individuals from the high cost hypothesis Pareto curve.

25 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Figure 8: Optimal hourly schedule associated with individual hc-B of the high cost hypothesis Pareto curve.

CONCLUSIONS AND FUTURE W O R K In this paper, on-site heating, cooling and power generation based on a solid oxide fuel cell and gas turbine (SOFC-GT) combined cycle has been investigated from the viewpoints of cost and C02 emissions using a multi-criteria optimization methodology. The system is assumed to be covering typical requirements of large

1317 office buildings in the city of Tokyo. A specific investment cost of the SOFC-GT unit of about 1000 [US$/KWe] is shown to make such a decentralized unit competitive for the local energy price conditions, together with a 14% CO2 emissions reduction compared to the business as usual. A low investment cost hypothesis for the SOFC-GT unit would allow the same level of CO2 emissions abatement while reducing in the same time the yearly total cost of heating, cooling and power generation by about 10%. Further reduction is achievable by increasing the capacity (substitution effect) and improving the performance (efficiency effect) of the system but the marginal cost associated is shown to be relatively high, starting at about 120 [US$/tonCOz] for the low SOFC-GT investment cost hypothesis. Future work will consider the introduction of such units within other types of buildings and other cities with different contexts. A situation where exportation of power to the grid would be limited or even not authorized will also be evaluated, requiring the modelling of part-load performances of the SOFC-GT unit.

ACKNOWLEGEMENT Authors are grateful for the help offered by Dr. K. Tokimatsu, Research Institute of Innovative Technology for the Earth, who provided useful information on the preparation of this research. They specially thank the Swiss National Science Foundation for its financial support. REFERENCES

International Energy Agency (2002), Distributed Generation in Liberalised Electricity Markets Burer M., Tanaka K., Favrat D., and Yamada K. (2002) Future Energy Systems and Technologyfor C02 abatement, Antwerpen. (forthcoming) Burer M., Tanaka K., Favrat D., and Yamada K. (2002) submitted to Energy, the International

Journal Leyland G.(2002) Multi-objective Optimisation applied to industrial problems, PhD thesis, EPFL, Switzerland Tanaka K., Wen C., and Yamada K. (2000) Fuel 79, 1493-1507. The Society of Heating, Air-Conditioning and Sanitary Engineers of Japan (1994) Toshi Gas niyoru

Cogeneration System Keikaku Sekkei to Hyouka (in Japanese) New Energy and Industrial Technology Development Organization (2000) Energy Shiyou Hyoka

System ni Kansuru Chosa (No. O10017085) (in Japanese, Abstract in English) Tokyo Electric Power Company, TEPCO Database (2002) Power Generating Capacity by Primary Energy Source, http ://www.tepco.co.jp/corp-com/db/ Hydrogen & Fuel Cell Letter (1999), VoI.XIV/No.8, p8-9

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Shell International Exploration and Production B.V. Published by Elsevier Science Ltd. All rights reserved

1319

OPTIMISED CO2 AVOIDANCE THROUGH INTEGRATION OF ENHANCED OIL AND GAS RECOVERY WITH SOLID OXIDE FUEL CELLS T. Clemens l, M. Haines 2", W. Heidug 2 Rohoel Aufsuchung AG, 1015 Vienna, Austria, ZShell Global Solutions, Rijswijk, The Netherlands *Now with IEA, Glos GL52 7RZ, UK

ABSTRACT Reducing CO2 emissions to control the level of greenhouse gases in the atmosphere is seen as an important goal by a number of countries. Due to the fact that power generation contributes significantly to the emission of CO2, this sector offers opportunities for reducing these emissions. Newly constructed power plants are, for a large percentage, gasfired power plants. Reduction of CO2 emissions from the flue gases of these power plants by capture is difficult due to the low concentration of CO2. In the last couple of years, fuel cell technology has been developed at high pace. Fuel cell power plants can be used to generate electricity at high overall efficiencies. Also, solid oxide fuel cells produce a stream of CO2 and water which can easily be separated. Combining electricity generation with solid oxide fuel cells and CO2 separation with injection of CO2 in oil and gas reservoirs might lead to enhanced oil and gas recovery. C02 enhanced oil recovery resulted for numerous reservoirs in additional oil recovery of about 5 - 15 % of oil initially in place. CO2 enhanced gas recovery is discussed in this paper. Due to lower tubing head pressures than in conventional gas production, gas production could be accelerated by using a solid oxide fuel cell power plant. After CO2 breakthrough in the production well, the CO2 containing produced gas can be fed into the fuel cells without separation of the CO2. If the costs for fuel cells are decrease sufficiently, the integrated power production, CO2 enhanced oil or gas recovery and CO2 sequestration projects could be economically very attractive.

INTRODUCTION

In the wake of the Kyoto protocol, C02 emissions reduction to control the level of CO2 in the atmosphere has become an important goal. Due to the lack of suitable alternatives for large-scale energy generation in the short- and medium-term, solutions for reducing CO2 emissions from burning hydrocarbons are

1320 intensively investigated. About 30 % of CO2 emissions of the EU countries come from power generation. Hence, the power generation sector offers opportunities to significantly reduce greenhouse gas emissions. Power generation using wind and solar energy is still up to a factor of ten more expensive than conventional power generation. Another possibility to reduce CO2 emissions is to install so-called Zero Emission Power Plants (ZEPPs). In this concept, natural gas is burned to generate electricity but at the same time, CO2 is separated and injected into oil or gas reservoirs. Oil and gas reservoirs have been trapping hydrocarbons for millions of years and are therefore potentially suitable for sequestration of CO2. Conventional separation of CO2 from gas-fired power plants leads to reduced overall efficiencies of these power plants by 6 - 15 %. Another way of generating electricity from natural gas is by using solid oxide fuel cells. These fuel cells are fed with natural gas and produce electricity, water and COz. Water and CO2 can be easily separated and injected into oil or gas fields. The high efficiency of fuel cells and easiness of CO2 separation lead to increased overall efficiencies of fuel cells in comparison with conventional combined cycle power plants. On the subsurface side, CO2 injections may lead to enhanced oil and gas recovery dependent on the reservoir and fluid characteristics. For a number of oil reservoirs, increased oil recovery by 5 - 15 % of Stock Tank Oil Originally in Place (STOm a) have been achieved. CO2 enhanced gas recovery has not been studied as extensively as COz enhanced oil recovery and will be addressed here. The fuel cell power plant concept is presented and the synergies of CO2 enhanced gas recovery and fuel cell power plants will be explored.

FUEL C E L L P O W E R PLANT A fuel cell works similar to a battery. In a battery there are two electrodes which are separated by an electrolyte. At least one of the electrodes is generally made of a solid metal. This metal is converted to another chemical compound during the production of electricity in the battery. The energy that the battery can produce in one cycle is limited by the amount of this solid metal that can be converted. In the fuel cell the solid metal is replaced by an electrode that is not consumed and a fuel that continuously replenishes the fuel cell. This fuel reacts with an oxidant such as oxygen from the other electrode. A fuel cell can produce electricity as long as more fuel and oxidant is pumped through it (Fig. 1).

Fuel cell section Air In

_.~

Air out

~-~

Pre-

After-bumlng section

•

,

reformed gas

Figure 1: Design of a fuel cell with after-burning section.

1321 On the anode side of the fuel cell, methane is first injected into a reforming chamber where it draws waste thermal-energy from the fuel cell stack. Here the methane is converted into hydrogen and carbon monoxide. It then flows into the anode manifold where most of the hydrogen and carbon monoxide is oxidised into water and carbon dioxide. This gas stream is then partly recycled to the reforming chamber where the water is used in the reforming chamber. Steam and carbon dioxide can easily be separated and injected into reservoirs. On the cathode side, air is first blown into a heat exchanger where it reaches near to the operating temperature. The air is brought up to the operating temperature of 800°C by removing the waste heat from the electrochemical oxidation of the hydrogen and carbon monoxide gas at the anode. The oxygen in the cathode manifold is converted into an oxygen ion which travels across the electrolyte to the anode. This technology is modular in structure and can be used to produce a stream of pure CO2 and pure water. The overall efficiency of fuel cells can reach as high as 63 % which is much better than the efficiency of gas fired power plants. For a more detailed description of the fuel cell concept see [ 1] and [2].

CO2 ENHANCED GAS R E C O V E R Y The effect of CO2 injection on gas recovery was studied by performing simulations on an existing example reservoir. The example gas reservoir contained 7.4 * 109 m 3 of Gas Initially In Place (GI]P). The reservoir depth is about 2500 m, initial reservoir pressure 272 bar. The reservoir is split into two compartments. In one of the compartments, a semi-sealing fault is present as indicated in Fig. 2 of the simulation model. For more details of the model see Clemens & Wit [3]. Each compartment has one CO2 injection and one production well.

Figure 2: Gas-water saturation of the example reservoir plan view.

The gas production and injection for one of the compartments and for one injection scenario is shown in Fig.

1322 3. The base case methane production is shown in light green. Until 2000, the gas production history was used. From 2000 to 2004, methane production was simulated using a tubing head pressure of 85 bar which is required for the gas distribution grid. In 2004, a compressor will be installed in the base case. This allows the tubing head pressure to be reduced to 35 bar. Hence, the methane production is increased in the base case, followed by further pressure depletion. The economic limit of the well was reached in 2042. Installation of a fuel cell power plant in 2004 enables reducing the tubing head pressure to 6 bar. The reduced tubing head pressure leads to even higher methane production rates than the methane production rates in the base case aider installation of a compressor (Fig. 3). Due to injection of CO2, the reservoir pressure is decreasing slower than for the base case depletion. Although the methane production rates are decreasing, a constant CO2 injection rate was used. The reason is that shortfalls in methane production from the gas field were assumed to be compensated by methane supplied by the gas distribution grid to keep the electricity output of the ZEPP and therefore the CO2 output constant. In about 2008, CO2 is breaking through at the production well. This leads to faster decrease in methane production rates from the field than before CO2 breakthrough. The extra CO2 that is produced from the field has to be injected as well, leading to increasing CO2 injection rates as shown in Fig. 3.

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(302 - injection w ell 1

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I

,

= 'ooo lH JI

,0 0 llllllllb|l | llllllllllllllll " llllllllglllllllllll

0.0E~00 . 1978

. 1988

. 1998

2008

2018

202

Figure 3: Comparison of gas production for the base case (light green) with CO2 enhanced gas recovery (dark green). The cumulative methane production for the base case and CO2 injection is depicted in Fig. 4. CO2 injection results in incremental methane recovery and accelerated methane production for the example reservoir.

1323

1.4E+09 1.2E+09

C02 injection case .=_. 1.0E+09

I

/

f

c

~ 8.0E+08

!

~ a.o~a base case "N 4.0B-08 E

2.0E+08 O.OE+O0 2004

2014

2024

2034

2044

Figure 4: Comparison of cumulative gas production from the base - case and for the case of installation of fuel cells.

The following incremental costs and savings are incurred with CO2 injection: (1) CAPEX costs: Drilling of extra wells for CO2 injection, CAPEX savings: No compression on the production side (2) OPEX costs: OPEX related to the injection wells, OPEX savings: No gas processing plant and gas compression OPEX on the production side.

EFFECT OF CO2 B R E A K T H R O U G H ON FUEL C E L L P O W E R PLANT Methane production from the field is declining from the start of installation of a fuel cell power plant due to depletion of the reservoir. To achieve constant power output of the power plant, gas is supplemented from the gas distribution grid. That means the total methane delivered to the power plant stays about constant over the whole lifetime of the power plant. In year 9, CO2 is breaking through in the production well. Hence, methane production from the field is decreasing more steeply and more and more gas has to be supplemented by the gas distribution grid (Fig. 5).

1324

600,000

-~-----------

.............

i

i 500,000

t~

400,000

I

E

•--- 300,000 200,000 100,000

o

,

;o

emy

2:,,

20

Figure 5 Gas production rates fed into the power plants. Gas production from the field is continuously declining. Gas from the gas distribution grid is supplemented to achieve an almost constant power output of the power plant. CO2 is breaking through at the production well. Due to the fact that the gas production decrease from the gas field is supplemented by gas from the gas distribution grid, the CO2 content of the fed gas into the fuel cell power plant does not decrease below 50 %. Fuel cells can easily be operated with this amount of CO2. Hence, no additional investment to separate CO2 prior to feeding the gas into the fuel cell power plant is required.

DISCUSSION AND CONCLUSIONS Fuel cell power plant with CO2 separation has significant advantages to conventional gas-fired combined cycle power plants. The overall efficiency of fuel cell power plants is higher leading to improved usage of natural resources and less production of CO2 which has to be sequestered than conventional gas-fired power plants. For relatively homogeneous gas fields, installation of fuel cell power plants could lead to accelerated gas production due to the lower tubing head pressure that might be achieved compared with conventional gas production. One key prerequisite for enhanced gas recovery is that gas production can be continued after breakthrough of CO2. Fuel cell power plants can be fed with gas containing more than 80 % of CO2. Hence, no costly separation of CO2 and methane prior to feeding the gas stream in the fuel cell power plant is required. ACKNOWLEDGMENTS Thanks to NAM and NOVEM for sponsoring this study. REFERENCES 1. 2. 3.

Haines, M.R., Heidug, W.K., Froning, D., Lokurlu, A. (1999) Electrochemical Society Proceedings, 99-19, 101-106. Haines, M.R., Heidug, W.K., Li, K.J. (2000) SPE 61027, 5th SPE HSE Conference. Clemens, T.G., Wit, K. (2002) SPE 77348, Annual SPE Conference.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1325

AN EXPERIMENTAL INVESTIGATION INTO THE USE OF MOLTEN CARBONATE FUEL CELLS TO CAPTURE CO2 FROM GAS TURBINE EXHAUST GASES A. Amorelli 1, M. B. Wilkinson1, P. Bedont 2, P. Capobianco 2, B. Marcenaro 2, F. Parodi 2, A. Torazza 2, 1BP Exploration, Chertsey Road, Sunbury-on-Thames, TW16 7LN, UK 2Ansaldo Fuel Cells S.p.A., Corso Perrone 25, 16161, Genova, Italy

ABSTRACT

As part of its climate change mitigation initiative, BP is evaluating technologies for the separation and capture of CO2 from combustion sources, for subsequent geologic storage. Ansaldo Fuel Cells S.pA. is developing Molten Carbonate Fuel Cell (MCFC) technology targeted at industrial applications from 50 kW to 10MW. This paper describes the conceptual design of a hybrid MCFC system to generate power and simultaneously capture CO2 from small (<10MW) gas turbine exhaust streams. Initial modeling studies indicated that a 1.6MW MCFC could reduce the CO2 emissions from a 4.6MW gas turbine by 50% on a per kWh basis. Experimental studies are in progress to understand the system behaviour, operating envelope and impact of contaminants. Initial data from these investigations are presented, which confirm that the fuel cell can operate at sub-optimal CO2 levels with limited loss in power and efficiency.

INTRODUCTION

BP is seeking solutions to the climate change challenge. This includes controlling emissions, conserving energy and introducing new energy-efficient technologies. One such technology, hydrogen fuel cells, offers the potential for highly efficient power generation at a scale (<10MW) widely employed in the oil and gas industries. This could replace today's technology including small gas turbines and large diesel or gas fired reciprocating engines, often operating at part load efficiencies below 30%. In addition, as part of our CO2 mitigation initiative, BP is evaluating technologies for the separation and capture of CO2 from combustion sources for subsequent storage. At present, commercially viable technologies are not available at scale. A portfolio of innovative options is needed, which include technologies that allow us to take constructive action in the medium term (next 5-10 years). One such innovative idea is to exploit the ability of molten carbonate fuel cells to transport CO2 across the electrolyte. In the medium term, we can envisage that many facilities will still possess a considerable number of conventional power generating technologies operating in parallel with fuel cells. Ansaldo Fuel Cell S.p.A. is considering the possibility of hybridizing their molten carbonate fuel cell technology with gas turbines to capture CO2 from the exhaust streams of such conventional technologies by feeding the CO2 to the cathode, while still generating power at high efficiency [ 1]. Although this innovative concept is feasible

1326 in principle and confirmed by system modeling, BP and Ansaldo have embarked on an extensive experimental study to determine the system behaviour, operating envelope and the impact of contaminants. This paper presents the latest results and insights from this work.

DISCUSSION OF THE TECHNOLOGY Ansaldo's Molten Carbonate Fuel Cell Technology

Ansaldo Fuel Cell S.p.A. (formerly part of Ansaldo Ricerche) has been developing Molten Carbonate Fuel Cell (MCFC) technology since the early 1980's. The next generation, "Series 500" power plant represents the latest step in the development of this MCFC technology. The plant will generate power at high efficiency, with low environmental impact and rapid response to load changes. The target market is on-site dispersed energy production for small to medium scale, commercial & industrial customers (circa 50KW to several MW). Fuel Cells are devices that directly convert the chemical energy of a fuel, typically hydrogen, into electrical energy, by electrochemical reactions. Molten Carbonate Fuel Cells (MCFC) are high temperature systems (Tm~ 650 °C) suitable for power generation at commercial/industrial scale (>50 kW). Figure 1 is a simple schematic of the technology.

2e-

2ev41

Air + CO2(from

H20 + CO 2

anode)

Hz + C O 32- ~ Hz O + C O z + 2 e " 1/2 0 2 + C O z + 2 e - --) C O 3 "" Overall: H 2 + 1/2 02 --~ 11120

Figure 1: Molten Carbonate Fuel Cell Scheme When H2 is fed to the anode side, it combines with the carbonate ions of the electrolyte to form steam and carbon dioxide and provides electrons as DC current. This DC current is normally inverted, using solid-state electronics, to produce AC for an external load. Simultaneously, the oxygen from the air and carbon dioxide (a slipstream from the anode reactions) are fed to the cathode, and react to replenish the carbonate ions consumed at the anode. The H2 is produced by the steam reforming of methane (natural gas). This reaction together with the shift reaction ultimately generates CO2 via CO. To ensure optimization of system efficiency, Ansaldo has heat

1327 integrated this process with the fuel cell reactions. Consequently, the fuel cell can generate electricity at high overall efficiencies, well above 40% for the complete system, methane to electricity. It is this characteristic that we wish to exploit. Another environmentally beneficial characteristic of the MCFC technology is its ability to transport carbon dioxide across the electrolyte, from the cathode side to the anode side of the fuel cell. Present on the anode side are typically H2, CO, CO2 and HzO. At the anode exit the gas composition includes un-reacted H2, steam and concentrated CO2 (from the cathode transfer and the reformate). The steam can be readily condensed, H2 can be separated and the residual CO1 is therefore available as a relatively pure stream for sequestration

The Hybrid Fuel Cell Scheme far C02 Capture The innovative scheme being proposed is a fuel cell hybrid based around Ansaldo's molten carbonate technology and a typical gas turbine. The aim of this integration is to maintain power generation on an existing gas turbine but ultimately with much reduced CO2 emission to the atmosphere. The use of MCFC will provide not only additional power generation capability at an increased level of efficiency, but also the means for concentrating and separating the COz from the conventional gas turbine. The exhaust from such a turbine would typically contain between 3 and 4%vol CO2. Overall, we believe that circa 50-60% of the CO2 emissions of conventional power plants could be separated with this scheme. In this study we have chosen to focus on a typical natural gas fired, small industrial gas turbine of nominal power output of 4.6 MW at standard operating conditions (15 degC, normal pressure at sea level). At this scale a single turbine would be generating over 3 tonnes per hour of CO2 (i.e. over 25000 tonnes per annum). We will also be investigating both an atmospheric and pressurized fuel cell system. A pressurized system can offer performance benefits in the fuel cell, notably increased power output that may generate additional value for the overall scheme. However, for the purposes of describing the concept, it suffices to focus on the atmospheric scheme (Figure 2). This hybrid concept has been modeled using Ansaldo's in-house expertise, based on several years of MCFC technology development and optimization. This includes not only the electrochemical processes of the cell, but also the engineering parameters such as pressure drop and heat integration. In our hybrid scheme, we have determined that the exhaust from a conventional 4.6 MW gas turbine can be fed to the cathode of a 1.6 MW atmospheric MCFC system. We believe that this ratio of between 2:1 and 3:1 in the relative power outputs of the two technologies in the hybrid scheme is scaleable e.g. a 10 MW gas turbine could be coupled with a fuel cell system in the 3 to 5 MW range. At the cathode, as a result of the electrochemical reaction with exhaust oxygen, the CO2 reacts to form carbonate ions and the resulting content of CO2 in the turbine exhaust stream is reduced from 4.7%wt (---3%vol) down to 2.3 wt% (~1.5%vol) i.e. a reduction of 50% across the fuel cell. Following transport of the carbonate ions across the electrolyte to the anode, the CO2 is released and mixed with the components from the reforming process (H2, CO and a small quantity of unconverted CH4). At the anode, the CO2 content of the reformate is increased from-25%wt at the inlet to -55%wt at the outlet. On a dry basis, this corresponds to a concentration of CO2 of about 85%wt. This anode exhaust, composed mainly of H20 and CO2, with some CH4, H2 and CO, is directed to a CO2 separation unit; the steam is condensed and the CO2 is separated for subsequent storage. The residual gas (CO, H2, and CH4) from this CO2 separation process is then recombined with the cathode off-gas in the catalytic burner, before release to the atmosphere. The combustion of CO in the catalytic burner generates additional CO2 in this exhaust stream, which obviously diminishes the overall reduction of the emissions. Nevertheless, in this un-optimized scheme, the CO2 released to the atmosphere can be reduced by circa 40% (i.e. from 3.2 tonnes per hour to 2.0 tonnes per hour, equivalent to a reduction of circa

1328 10500 tonnes per annum). If we then consider that the MCFC is also generating 1.6MW of power in addition to the gas turbine's 4.6 MW, then the CO2 emission per kWh produced is reduced by over 50%. These initial results gave us confidence that the MCFC hybrid system can act as a carbon dioxide concentrator [2].

Natural Gas

Water

1

I [ Evaporator

Gas Turbine 4.6MW

I GT/Cathode Exhaust

I Air

H2+ CO + CH 4

I

1 MCF~-1.6MW

~~wCO~r CO2 SEPARATION

F i g u r e 2: Hybrid Atmospheric Pressure MCFC Scheme for CO2 Capture

E X P E R I M E N T A L STUDIES Work Programme Objectives

The experimental investigation is being carried out at Ansaldo Fuel Cell S.p.A.'s test facilities in Genova, Italy. The work programme will confirm the accuracy of the above analysis and will seek to quantify: • • • •

The effect on the baseline fuel cell performance of varying CO2 and Impact of operating pressure on the system The optimal combination of conditions to maximize CO2 transport The effect of contaminants on performance and lifetime

02

concentrations at the cathode

The experiments are performed on single cells. The results can then be readily and reliably extrapolated to a large-scale fuel cell system.

Initial Experimental Results Any exhaust from a conventional combustion process can be considered as a source of CO2 for this tirol cell hybrid. However, the concentration of CO2 at the cathode is critical to the performance of the fuel cell,

1329 particularly if levels fall too low. Consequently, we have been quantifying the effect of varying CO2 levels on the fuel cell power output and CO2 transport across the electrolyte. In the above scheme, such gas turbines are fuelled either by natural gas (methane) or by No.2 fuel oil (diesel), and often employ dry low NOx burners to reduce emissions. The major constituents of the exhaust from such a turbine are Nitrogen (N2) 75%, Oxygen (02) 14%, Water (H20) 4 to 7% and Carbon Dioxide (CO2) 3 to 4% by volume. The initial results from these single atmospheric cell studies are illustrated in Figure 3. For a stand-alone molten carbonate fuel cell, CO2 levels at the cathode are typically maintained at circa 7-8%vol. At this concentration, the power density for a single cell was measured at circa 740 W/m 2 and the voltage at around 800 mV. This would correspond to an overall power output of 1.6MW for the MCFC unit alone (i.e. excluding the gas turbine power generation). Concentrations of CO2 above 7%vol were found to deliver only limited improvements in power density. 900 850

.....................................

"E 800 750

ii

= 700 °

1,47 MW

........................................................................................

. m

650

a. 600 550 .......

500 3

4

6

8

10

%mol C02 in Gas Turbine Exhaust

Figure 3" Single Cell Experimental Results At the lower, sub-optimal concentrations (<7%vol CO2) typical of gas turbine exhaust streams, the power density of the cell was found to decline. At 4%vol CO2, the power density was approximately 690W/m2, which can be extrapolated to circa 1.47 MW for the MCFC system. At 3%vol CO2, the power density declined towards 610 W/m2, equivalent to around 1.3MW. These experimental results confirm the concept's feasibility and that, under these conditions, it would be possible to reduce the CO2 emission per kWh produced by circa 45% at the 4%vol CO2 and by circa 50% at the 3%vol CO2. Only at CO2 levels of 2%vol did the power density fall away dramatically and therefore have a significant and deleterious effect on overall performance. Future Work The presence in the exhaust gas streams of any contaminants for the fuel cells is a cause for concern as they have the potential to degrade both performance and lifetime. In this study, we plan to focus on the effect that the presence of both SOx and NOx will have on the operation of the MCFC.

The harmful effects of nitrogen oxides has been identified in the past but not quantified. In contrast as the MCFC can act as a sulphur scrubber, SO2 is known to accumulate in the electrolyte as sulphate, and readily transferred to the anode where it can react with the hydrogen to form HzS. This in turn has a strong

1330 poisoning effect on the nickel based anodes. However, we believe this issue can be managed with suitable pretreatment if needed.

CONCLUSIONS Our study suggests that MCFC technology in a combined power generation and CO2 concentrator hybrid offers an innovative route to help meet aspirations of reduced CO2 emissions to the atmosphere for small to medium scale power generation, typical of oil and gas operations. Extensive experimental work is being performed and initial results confirm the technical feasibility of this concept, particularly the operation of the molten carbonate fuel cell at sub-optimal CO2 levels. Further experimental work and final conclusions will be reported in a future paper.

REFERENCES 1. K.Kobayashi, T. Shimizu, T. Watanabe & M. Lio: (1998) Development of MCFC and Gas Turbine Combined System. Fuel Cell Seminar Abstracts; p. 372. 2. A. Amorelli , P. Bedont , P. Capobianco, B. Marcenaro, D. Parnell, F. Parodi, A. Torazza, M. B. Wilkinson (2002) Molten Carbonate Fuel cells as a Route to CO2 Capture, paper presented at 14th Worm Hydrogen Conference, Montreal Canada.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1331

HIGH EFFICENCY CO2 SEPARATION AND CONCENTRATION SYSTEM BY USING MOLTEN CARBONATE Kazuhiko Itou, Hidehisa Tani, Yu Ono, Hidekazu Kasail, Ken-ichiro Ota 2 1 Energy Solution Department Ishikawajima-Harima Heavy Industries Co., Ltd., 2-16, TOYOSU 3-CHOME, Koto-ku, Tokyo, 135-8733, JP [email protected] 2 Department. Energy and Safety Engineering, 79-5, Tokiwadai, Hodogaya-ku.Yokohama,240-8501,JAPAN Yokohama National University

ABSTRACT

Carbonate is indicated as MxCO3 in chemical formulae. From the viewpoint of elements of composition, CO2 occupies half the weight of this material. At high temperatures, this substance is used as an electrolyte in high temperature fuel cells. It can be used for electrochemical CO2 separation systems. This mechanism has three steps as follows:

(1) C02, 02 create a carbonate ion (CO32+) at the cathode of the cell. (2) Carbonate ion diffuses to anode side. (3) Carbonate decomposition to CO2, 02 at anode. In the case of Molten Carbonate Fuel Cells, this carbonate ion reacts with H2; it produces H20 and CO2 (1:1). These systems can separate 0.42 litres of CO2 from the cathode to the anode, per 1 A current per hour. These systems have high selectivity for CO2 in the gas. Furthermore, the system is superior to other capture systems, according to its suitability for application to exhaust gas, as the system operates under very high temperature (900K - 1000K) and an oxidizing atmosphere. Therefore, carbon ash or other remaining fuel is burned and removed in the cell. Then, the system can treat the exhaust gas directly. We had attempted to prove the availability of collection of CO2 using this system. We fabricated actual cells and measured their performance. The composition of the gas used was CO2 67% and 02 33%; this ratio is equal to the chemical composition of the carbonate ion. We used gas containing various CO2 concentrations in air. By this cell test, it was confirmed that CO2 can be collected from the gas, even when present at less than 1% CO2. From these results, it is clear that this carbonate system is very suitable system for CO2 collection. IINTRODUCTION

Generally, CO2 capture systems have some problems. One of the most important problems is that systems require significant amounts of electrical or thermal energy. In particular, it is difficult to collect CO2 from gases that contain low CO2 concentrations. Another problem is that exhaust gases have high temperatures. In addition, such gases contain many impurities and fly ash, such as carbon.

1332 Carbonate is expressed as MxCO3 in chemical formulae. From the viewpoint of elemental composition, CO2 occupies half the weight in this substance. At high temperatures, Molten Carbonate is used as an electrolyte in fuel cell (MCFC). Furthermore, this material can be used for electrochemical CO2 separation systems. Characteristically, for other capture systems, the temperature of the process is very high. Then, the effect of contamination or vapour present in the exhaust gas remains low. Electrochemical processes have high selectivity for target substances, meaning that the efficiency of the separation is high.

PROCESS OF CO2 SEPARATION Fig.1 shows the schematic figure of reaction of CO2 and Molten Carbonate. Carbonate absorbed and discharge by electrochemical process. Under the high temperature, this electrolyte indicates high electric conductivity and high chemical reactivity.

Electrolyte High electric conductor at high temperature

OK)

ICrb 0 gl

( generation

of carbonate ion )

( decomposition of

carbonate ion )

Figure 1" C02 absorption and discharge

(1) Electrolysis cell system, In the case of electrolyte cell system, the reaction is followers Cathode " C O 2 d- 1/202 + 2 e - - ~ CO3 2" Anode • CO3 2" ---) CO2 + 1/202 + 2e

(1) (2)

From this reaction, the composition of Anode gas is CO2/O2=2/1.(PC02=0.67) The cell voltage (V) for this electrochemical process was calculated by equation (3). [-2] V=(RT/2F)In(Pco2(a)P02(a) 0"5/pcO2(c)PO2(c)°5) (R:gas consatant, T:temperature, F:Faraday constant)

(3)

1333 The symbols (a) and (c) indicate the anode and cathode, respectively. The calculated result is shown in Fig.2 from this equation. This system has the ability to collect very low concentrations of CO2.

0.35

I!

0.30

IT.~-~--; i •

'

~i]!!

',

,~~!

i

I

~

u I i I

ILl_L, i i o.~

0.20

i ' .. ~ i

I i

lI '1 Mi_kk ............!/ '~

~

' !1,

,

.... t ...... T

..........

!-t¢~--.f- ....t.... ~ - ~ /IIl___._.l i I

O.la I¢i~-~

-~'~,'.

........ d.

I--

k.....

J

OlO i

0.05

....

o.oo lii II

.....t ......... ...... ]iT!T-!T'-T .... Li 10

1oo

0.01

01

Concentmtbn ofC 0 2 la process ia]et gas ~) Figure 2: Energy of C02 separation from cathode to anode(CO2=67%)

Fig.3 shows C02 separation system of the electrolysis cell. This system separates 0.42 litre of C02 from the cathode to the anode, per 1 A current per hour. In this system, the additional anode gas contains no impurities. These gases (CO2 and O2) can be used for commercial applications.

A n o d e outlet: Pco2/PO2 = 67/33

Cathode

A n o d e

(LowConc.CO2)

( H i g h Conc.CO2)

source

Figure 3" Schematic figure of C02 Separate Cell system (2) Fuel cell system, In the case of a fuel cell, the reaction shown occur (4), (5). This system generates electrical power at the same time. Cathode • C02 -t- 1/202 + 2 e ~ C 0 3 2

(4)

Anode • C032" +H2--* C02 -k- H20 + 2 e

(5)

Figure 4 shows C02 separation system of the fuel cell. This system also separates 0.42 litre of CO2 from the cathode to anode, per 1 A current per hour.

1334

;!iii ~ iiii i;i;!;iiii!;i;ii--3 3 ' 3"" 333:::::::::::::::::::::::::::::: !~~i~~i.:!::.~,:¢~iiiiiiiii!i!ii!~:!i:;i ,-'-----; electron

'

Anode outlet: Pco2=85~90%(drybase)

:::::::::::::::::::::: 20

~;i~:~:ii~...... " ":

ANODE (-

CATHODE

(+

Figure 4: Schematic figure of fuel cell system The cell voltage at no-load condition is calculated from equation (6) (Open circuit voltage). This is high efficiency power generation system from hydrogen.

E = E 0 + ( R T / 2 F ) (PmPo2'/2Pcco2/PH~oPaco2)

(6)

(E0=I.02V at 923K) In this equation Px~ shows partial pressure of the process gas. Pcco~ and Paco2 show partial pressure of CO2 in the cathode and anode gas. The value of Paco2 is much higher that of Pcco~ in MCFC. Generally, the concentration of CO2 in anode gas is 80 - 90% at dry base composition. From the viewpoint of CO2 concentration, MCFC condensed CO/ without additional energy. Furthermore, MCFC is very high efficiency power generating system. Thus, MCFC is a very highly efficiency system for CO2 capture.

OTHER VARIATIONS The molten carbonate system has various abilities for other CO2 processes. Under non-oxygen atmosphere, these reaction occurs: 2CO2 +2e- --~ CO+CO3 2" CO32 ---> CO2+1/202

(Cathode side reaction) (Anode side reaction)

In this process, the CO2 condensation and 02, CO production occur in the same time. This is one of the CO2 direct electrolysis process. CONCLUSIONS It was confirmed that CO2 separation and concentration using Molten Carbonate occurred in a high temperature electrolysis cell. Current efficiency was almost 100 % and stoichiometric gas composition at the anode outlet was obtained. These systems are applicable to CO2 capture from various exhaust gases. REFERENCES 1. Weaver,J.L and Winnick,J.,(1983) J.Electrochem.Soc., 130, 20. 2. Kasai, H., Matsuo,T., Hosaka, M., Motohira,N., Kamiya,N., Ota,K.,(1998) DENKKI KAGAKU,66,635640 3. Kasai, H., (2002), ACS NATIONAL MEETING, Fuel Chemistry 0078, Orlando.

RENEWABLE ENERGY

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1337

R E N E W A B L E ENERGY: PROSPECTS FOR S U P P L Y I N G E L E C T R I C I T Y IN THE D E R E G U L A T E D M A R K E T IN THE PHILIPPINES Jude Anthony N. Estiva 1 and Ma. Aileen Leah G. Guzman 2 INational Economic Development Authority (NEDA), NEDA sa Pasig Bldg., Ortigas, Pasig City, Philippines ZCenter for Environmental Geomatics (CEG), Manila Observatory, Ateneo de Manila University, Loyola Hts., Q.C., Philippines

ABSTRACT

The paper aims to assess the competitiveness of renewable energy in the Philippine spot market. The competitiveness of renewable energy was assessed in terms of its generation cost as compared to nonrenewable energy. The paper attempts to establish the general scenario by looking into the production cost of government owned and contracted power plants from 1990 to 2001. It looks into specific cases of renewable energy to demonstrate emerging trend considering incentives and constraints of actual and proposed projects. The paper found that renewable energy could hardly compete with non-renewable energy. However, conditions like stringent air regulation and possible additional financing from emission savings increases the competitiveness of renewable energy. The renewable energy continues to be favorable in sparsely populated areas.

INTRODUCTION

The electricity supply industry in the Philippines was purely a private sector business until 1935. The government's entry into the industry began with the creation of the state-owned National Power Corporation (NPC) in 1936. The major thrust of the government then was to develop the country's hydro potential in order to reduce fuel importation since all power plants at that time were oil-fired [ 1]. The government's takeover of the distribution utilities in the 70s resulted in full control by the government (1972-1986). Incidentally, there was also a significant geothermal and solar development in this period. Besieged by budgetary deficits and a lack of funds for infrastructure in the mid-80s, the government re-allowed the entry of the private sector in the generation business (1987-2001). At present, the Philippine Government is restructuring the electric industry through Republic Act (RA) 9136 or the Electric Power Industry Reform Act of 2001 (enacted on 8 June 2001). The reform intends to liberalize the market by privatizing the state-owned NPC and introducing wholesale and retail competition. RA 9136 also mandates all electric generating companies to sell a minimum of 10% of its output to spot market and a maximum of 90% through bilateral contract [2]. This compels prospective renewable energy producers to compete with conventional energy sources when wholesale electricity spot market operates.

1338 THE MACRO PICTURE OF RENEWABLE ENERGY a.

Renewable Energy at Present: Generation Share and Resource Potential

As of end 2000, a total of 13,264 MW generation capacity was installed nationwide and the distribution is shown in Figure 1. In the same year, the power generated was 45,290 GWh and the mix is shown in Figure 2

[3]. Installed Capaity in MW (year 2000)

Generation Mix in GWh (year 2000)

17%

28.8%

~--~~37%

17.4%

20%~ ~'~14.6 39.2%

~

% 26% mcoal [] geo [] oil-based[] hydroJ

Boil-based==coalE3hydroIlgeo

Figure 2: Generation Mix (2000)

Figure 1: Capacity Percent Distribution

In 2011, the installed capacity is expected to increase to 23,929 MW for a base case scenario and energy generation will increase to 116.2 TWh for high indigenous scenario. The generation mix is shown in Figure 3 [3]. Please note that ~er Philippine Department of Energy (DOE), new and renewable energy (NRE) category excludes hydro (except micro) and geothermal. Generation Mix in TWh (year 2011)

39% 1% 22% 16% • NRE • others [] oil-based [] coal • hydro • geo • nat gas Figure 3: Generation Mix (2011) The country has an estimated hydropower potential of 13,000 MW. It is forecasted that an additional 1,299 MW hydro will be put up for both main and island grid for the period 2002-2011 that will bring the total hydro capacity to 3,820. The country has an estimated geothermal resource potential from 35 areas of 4,537 MW with existing capacity of 1,931 MW. It is expected that a cumulative capacity of 3,484 MW will be meet by 201113]. There is a total of 417 MW wind power lined up until 2011 from an estimated potential of 76,600 MW214]. There are 68 units of micro-hydro with aggregate capacity of 233 kW. It is estimated that the potential micro-hydro in 46 remote areas has a potential of 28 MW [5]. The ricehull produced in Regions 3, 6 & 12 has an estimated potential capacity of 361 MW. Details ofbiomass potential is shown in Table 1.

=Hydro in the Philippines is classified as follow: large hydro - greater than 50 MW; small hydro greater than 10 MW but equal to or less than 50 MW; mini-hydro- 101 kw but less than 10 MW; micro hydro less than 100 kw. 2Figure represents wind potential for good to excellentwind resource scale only.

1339 TABLE 1 BIOMASS SUPPLY POTENTIAL (in Million Barrels of Fuel Oil)

2001 8.1 23.9 18.9 87.7 12.5 108.6 259.7

Biomass Rice residues Cococnut Residues Bagasse Wood/Woodwaste Animal Waste Municipal Waste Total

b.

2011 10.3 27.2 22.8 101.8 13.8 142.7 318.5

The Production Cost o f NPC

The state-owned NPC is considered the dominant entity in power generation accounting for approximately 85% of the total installed capacity in 2001 [3,6]. It has its own generation power plant and it also entered into contracts with independent power producers (IPP). The production cost of NPC indicates NPC's cost (in PhP/kW'h3). It also includes other corporate operational cost that is allocated to all other plants. The figures below indicate average production cost per plant type at 1990 constant prices. IPP Power Rant

NPC Power Plants .E

3.00

~o =

2.50

:~=~ ~ ,,~.-~,~

.........

--II--dl

~,.

8.00

0

2.00

.--/~-- Geo

o

6.00

--x- ~,

~ Q. ~.®

'2" 1.50

~ ~-°~

~:~-~~, ~ ~ .~ ~

hydro

1.00

"~ 0.50 ~"

g~

"o

Z00

a.

0.00 .

2

o.oo

--w--Oil

.

.

.

.

.

N-" PX-" N-" N-" ~-"

.

.

.

~,,-" N-" N-" P',-" rk" Year

Year

Figure 4: NPC Production Cost for Its Own Plants

.

--~--GT ~Goal --.'Nr- C~o

Figure 5: NPC Production Cost for Its IPP Plants

From Figure 4, hydro and geothermal plants are relatively competitive. Gas turbine (GT) plants are usually used for peaking thus, its high cost. NPC plants are funded mostly through concessional loans that offer lower interest rates. In Figure 5, geothermal improves its position among IPP plants. The hydro however started to soar up in 2001. This is due to the commissioning of new IPP hydro plants. Prior to 2001, all IPP operated hydro plants are old NPC plants rehabilitated by IPP. The IPP plants are usually funded through commercial sources. This may explain why IPP plants are usually more expensive than NPC plants. In the deregulated market, it is assumed that prices will be set at commercial market rates reflecting the true cost of generation.

CASES OF EXISTING AND PROPOSED P O W E R P R O J E C T S From the 'generalized' scenario of renewable energy, several cases from existing and proposed projects were studied to demonstrate emerging trends. This covers the three (3) main grids and areas that are not connected

3Philippine peso per kilowatt-hour

1340 to the grid. The levelized cost 4 (in PhP/kWh) was used to compare the cost. Costs are expressed in constant 1990 prices. a.

1.

Main Grid

Conventional Renewable Energy Sources

Conventional renewable energy sources included within this category are hydro and geothermal plants. They are compared with conventional non-renewable energy plants. TABLE 2 LEVELIZED COST (IN PHP/KWH) OF SELECTED IPP PLANTS PLANT TYPE Coal Diesel Large Hydro (New) Large Hydro (Rehabilitated) Mini-hydro Mindanao Geo Visayas Geo

POWER PLANT 1.089 0.788

FUEL 0.302 0.730

TOTAL 1.391 1.518 2.874 0.481 1.164 1.192 1.248

The levelized cost at 1990 constant prices based on selected IPP contracts is shown in Table 2 [7]. All fees for IPP are assumed to include profit. Only the diesel plant above includes fee for transmission line. While coal plant is expensive compared with diesel in terms of power plant cost, it has a cheaper fuel cost. The fuel cost for all NPC owned and contracted plants are tax-exempt including coal and diesel. Both however are cheaper compared with new large hydro plant. New large hydro has a high fix cost and longer gestation period and in some cases requires additional investment due to site-specific condition, e.g. long intake tunnel. Geothermal plants are mostly owned by the state-run Philippine National Oil Corporation - Energy Development Corporation (PNOC-EDC). It also utilizes Official Development Assistance (ODA) funds for its geothermal projects. The payment for royalty increases the cost of geothermal energy. The contractor is allowed to recover its cost up to 90% of the total fees. The remaining 10% will be split into 40% profit for the contractor and 60% government royalty [8]. An illustrative example is shown in Table 3.

TABLE 3 ILLUSTRATIVE EXAMPLE OF GEOTHERMAL COST (IN PHP/KWH) BREAKDOWN Plant

90% Maximum Recovery

Mindanao Geo Visayas Geo

1.0728 1.1232

10% Net Proceeds 40% Contractor 60% Gov't Royalty 0.07152 0.04768 0.04992 0.07488

Total

1.192 1.248

The government royalty is higher that the net proceeds of the contractor. This raises concerns to all potential geothermal investors. The tax equalization seeks to attain tax equalization between indigenous energy and imported fuel [2]. This ensures that indigenous and imported energy have proportional levels of taxes. In instances where geothermal royalty is higher than other sources, a portion of the geothermal cost due to taxes/royalty will be passed on to universal levy thus, increasing its competitiveness in the market. 4 Levelizedcost is defined as the equivalentuniform rate computedacross the life of the project consideringtime value of money. For IPP contracts, levelizedcost was computed across contractduration.

1341 The stringent measures on air quality will increase generation cost especially for coal and oil-based power plants [9]. Geothermal plants are also the subject of this measure. The Philippine Department of Energy estimated that the compliance cost will be PhP 0.623/kWh at 1990 constant prices or US$ 0.0318/kWh at 2002 current prices. This estimate however is an average across various plant types and may vary depending on the specific condition of particular plants. 2.

Non-Conventional Renewable Energy Sources

New renewable energy projects are coming into the grid including wind and bagasse. Ricehull as a source of energy is also being thought-of. The government's 42 MW Wind Project has an estimated levelized cost of PhP 1.635/kWh at 1990 constant prices [10]. Unlike the levelized cost of the IPP plants discussed earlier, the levelized cost of wind does not include cost of financing and profit margin. However, it includes cost of associated transmission line. The plant factor used in this analysis is 30%. A benefit of US$ 5/ton from carbon savings in 2002, will translate to cost reduction of PhP 0.145/kWh at 1990 constant prices, yielding a levelized cost (with carbon benefits) of PhP 1.49/kWh. This makes wind power more competitive. However, it has to contend with technical considerations regarding availability and dispatch. It should also be noted that the cost of energy generated through wind power is affected by the low cost of capital attributed to the use of ODA sources. Financing wind generation power projects through purely commercial sources may increase the cost and may affect the financial viability. Victorias Bioenergy Inc (VBI) is establishing a new 55MW bagasse cogeneration station at the Victorias Milling Company (VMC) sugar mill in Victorias City, Negros Occidental, Philippines. The plant will be located in the existing sugar mill and refinery complex of VMC. It is designed to provide VMC with all their process steam and electrical power requirements and to export surplus electricity[11]. It claims to sell its excess power to Central Negros Cooperative (CENECO) through a bilateral contract at a price lower than NPC prices. It was estimated that the cost, using standard costing for a bagasse project [ 12] is around PhP 4 billion [ 13] (US$ 80 million) 5. The levelized cost was estimated at PhP 0.633/kWh at 1990 constant prices. The estimate excluded cost of financing the 110,000 tons of woods to be used during off-season and the profit margin. Transport cost was not added in the cost stream as it was assumed that all bagasse will be supplied by VMC and the plant is located within the VMC compound. In cases where in bagasse will be sourced outside of VMC, the cost of transportation will be even higher than the cost of the materials [12]. Furthermore, the scenario assumed here is a full utilization of the power plant for electricity alone. A ricehull project was also proposed in 1996 but government deferred its approval at that time. In 1996, US$ 1.00 is equivalent to PhP 26.00. Today the exchange rate is US$1.00:PhP 53.00. The levelized cost of the proposed project was recalculated and found to be PhP 1.560/kWh at 1990 constant prices. This still excludes the cost of financing and profit margin. However, it shows that as the Philippine peso devaluates, indigenous energy like ricehull becomes more competitive. b. Areas Not Connected on the Grid

The Government through the Department of Energy (DOE) in keeping up its 100% electrification target by 2006, has already electrified 35,459 barangays out of 41,995 barangays. Most of these barangays are remote (located far away from the grid) and sparsely populated thus, there is low demand and involves high cost of distribution. Those barangays without electricity are areas that are not connected to the grid. These areas can be characterized by a low level of demand and a sparsely distributed population. Conventional energy used in the main grids can hardly fit in these areas because (1) the low demand will result to the under-utilization of a plant's installed capacity; (2) the sparsely distributed population will result 5Uses an exchange rate of PhP 50.00: US$1.00.

1342 to a high cost of transmission and distribution line; and (3) areas not connected to the grid are usually very hard to access thus, transporting the fuel becomes very expensive. In this type of situation, harnessing the locality's renewable energy resource/s becomes the best option. In this type of scenario, the Government utilizes solar and micro-hydro. For instance, 1,044 units of solar home systems were utilized in 204 barangays. Micro-hydro with capacities of 5.8 kw to 65 kw were also utilized to energize several barangays with 83-300 households. While micro-hydro is a flexible altemative, a typical micro-hydro project will have a levelized cost of around PhP 2.017/kWh to PhP 4.034/kWh. This already includes limited transmission line but excludes cost of financing. Given the range of micro-hydro generation cost, it can hardly compete with other sources if it will be located in the main grid. Solar energy can hardly compete in the main grid but it can be utilized in areas not connected to the grid. Two government solar projects approved in 2002 have costs ofUS$11.4/watt-peak and US$19.2/watt-peak at current 2002 prices. The former is financed through a 60% grant component and the cost includes panels only. The latter is financed through a mixed credit facility and the cost already includes cost of installation, social preparation, site preparation, local transportation and other costs. Wind energy is another promising technology that can be harnessed in the Philippines. Other new and renewable energy may be utilized depending on the condition of the areas. Cost still remains as one of the major factors for the utilization of these alternative sources.

CONCLUSIONS

Given the level of technological development in the Philippines, non-conventional renewable energy can hardly compete in the Philippine market, essentially in the main grids of Luzon, Visayas and Mindanao. This is primarily because of a very high cost of imported equipment. However, solar and micro-hydro is favorable for sparsely populated ares. While wind has a very good prospect in the main grid, it still needs to demonstrate its full potential especially in the spot market. Hydropower on the other end has to contend with its very high fix cost and long gestation period. The competitiveness of geothermal may be increased by tax equalization. REFERENCES 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

11.

12. 13.

Madamba, S. (2001). A Review of the Electricity Industry Regulation: The Philippine Case. An Unpublished Graduate Report at the Graduate School of Engineering, University of Technology, Sydney, Australia. Republic of the Philippines. (2001). Electric Power Industry Reform Act (RA 9136). Section 34 par. C. Manila, Philippines. Philippine Department of Energy. 2002. Philippine Energy Plan, 2002-2011, pp. 14-46. Fort Bonifacio, Manila, Philippines. National Renewable Energy Laboratory. 2001. Renewable Energy Atlas of the Philippines. A Report Prepared for Philippine DOE. Taguig, Metro Manila, Philippines. Philippine Department of Energy. 2002. New and Renewable Energy Resource Development. In http://www.doe.gov.ph. National Power Corporation. 2002.2001 Annual Report. Quezon City, Philippines. Various contracts between National Power Corporation and Independent Power Producers. Presidential Decree 1442. Manila, Philippines. Republic of the Philippines. 1999. The Philippine Clean Air Act of 1999 (RA 8749). Manila, Philippines. National Economic and Development Authority (NEDA) Secretariat. 2002.42 MWProject Evaluation Report. An Unpublished Report of Infrastructure Staff to the Investment Coordination Committee (ICC) of the NEDA Board. Pasig City, Philippines. In http://www.bronzeoak.com/BronzeoakAboutusVictoriasBioenergylncorporated.htm (30 June 2002). Philippine Biomass Energy Laboratory. 2000. Biomass Energy Resource Atlas of the Philippines. A Report Prepared for Philippine DOE, US DOE and US Agency for International Deveopment. In http://www.visayandailystar.com/2001/December/06/topstory2.htm

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1343

TECHNOLOGICAL OPTIONS FOR COST-EFFECTIVE AND ECO-FRIENDLY POWER GENERATION FOR DEVELOPMENT OF REMOTE AND RURAL AREAS IN INDIA R. Prasad, Scientist and Prof D.D. Misra ,Director Central Mining Research Institute, Dhanbad-826001 (India)

ABSTRACT

In the Indian scenario, coal-fired conventional power generation systems are not economical and eco-friendly in meeting targeted energy demand for the development of remote and rural areas due to costlier fuel transportation and atmospheric pollution. It is well known that 75 % to 80% of the Indian population resides in a large number of villages where that require basic amenities such as drinking water, power for energizing pumps for irrigation, fuel for cooking and lighting for houses etc. Centralized power generating system will not be able to meet the energy demand due to inadequate funds for transmission systems and staggered population in above areas. In such cases, renewable energy developments will be ideal and provide a more suitable approach for power/power generation in a decentralized manner for remote and rural electrification and related community developments. Here, an attempt has been made by the authors to have technological options by tapping renewable energy sources which may ensure cost-effective and pollution free power generation for bridging the gap between demand and supply among such communities. Subsequently, it may have better scope for commercialization for decentralized technologies to promote reconstruction and development at grass root level, for gainful employment and improved lifestyles of the people in remote and rural areas of developing nations such as India.

INTRODUCTION

It is well known that 75% to 80% of the Indian population lives in a very large number of villages that require basic amenities such as drinking water, fuel for cooking, power for energizing pumps for irrigation and lighting for houses. Conventional centralized coal firedpower generation systems will not be able to satisfy energy demand in rural and remote areas due to costlier fuel transportation for power generation and difficult T&D installation, as well as staggered population. Despite impressive capacity addition in the country over the past four decades, and planned capacity increases through conventional centralized power sources such as coal, hydro-electric

1344 and nuclear power plants, a wide gap continues to exist between supply and demand, expected to about 21000 MW by the turn of the century. While resources for mobilization of power generation in strengthening the grid, improving end use efficiency and energy conservation are the imperative needs, there is an important potential role to be played by renewable energy sources such as solar/wind/bio-mass/small and micro hydro power in reducing energy shortages. The scheme/project based upon renewable energy sources such as solar, wind, biomass and small hydropower capacity have low gestation periods, are close to load centres; this reduces T&D requirements. Because of this, India has placed sufficient importance on the utilization of these resources. Therefore, renewable energy sources are ideal and more suited to remote and rural electrification, providing integrated energy systems, due to comparable capital costs and running costs, as well as the absence of adverse impact on pollution and preservation of the ecology. The commercialization of several decentralized technologies may have improved scope with the creation of infrastructural O&M in the villages which will lead to local self reliance in respect of renewable energy and rural reconstruction, as well as the development of grass root level for gainful employment and enhanced lifestyles of communities in remote and rural areas; these are under different conditions in terms of agro-climatic condition, socio-cultural settings, and varying resource endowment regions. The present scenario aims to view the technological options through the potential role to be played by solar/wind//bio-mass and small hydro power-based technologies in improving the economic conditions of agricultural production, employment, development of small scale industries, drinking water, health, education and power for irrigation, for obtaining optimal performance in Indian condition.

T E C H N O L O G I C A L OPTIONS FOR ECONOMICAL P O W E R IN REMOTE AND RURAL AREAS

AND

POLLUTION

FREE

Renewable energy sources such as solar, bio-mass, wind, micro hydro and energy from wastes as multi-mode technological options may ensure an improved performance and cost-effective route for research leading to significant advancement of communities in remote and rural areas; this will improve lifestyles and social conditions. Commercialization of decentralized technologies for the above areas may be feasible by tapping into the solar, wind, bio-mass and small hydro power categories. However, efforts have been made for over two decades to harness renewable energy sources to meet low level needs such as improved Chulahas, Bio-gas plants, water pumping, and wind mills for power generation in the area of grid connected from 10 KW to 2 M W .

Solar Energy The enormous potential for solar energy intensification can be visualized from the simplified; a total of 3.9 million exa joules (an ext joule is one billion joules of energy, approximately the amount of heat released during the combustion of 2.2 million tons of oil) of solar radiation falls on the earth's surface. However, the engineering design of solar processes presents unique problems due to the intermittent and defused nature of the resource and the capital intensive nature of feasible schemes. The only method of minimizing this limitation is through storage of the energy and its transmission to different locations. In India, an average 5 KW hr/m 2 of solar

1345 energy falls for 300 days a year, with potential savings of 20 millions tons of coal through the use of solar cookers, solar water heating, solar stills and refrigeration. The conversion of solar energy to electricity has two technologies: (1) Solar Thermal and (2) Solar Photovoltaic. A demonstration of a small and autonomous solar thermal power plant has been made by BHEL as a decentralized power generation system of 20 MW, using a point focusing dish concentrator and 50 MW of line focusing parabolic trough. Another method of generating power through high temperature dish concentration is by using an external fired engine such as a Sterling engine. The Sterling engine is used mainly because of its high thermodynamic efficiency. The dish Sterling engine project requires extensive R&D efforts within the country before commercialization. On the other hand, photovoltaic power generation systems are pollution free, noiseless, easy to install and render maintenance-free operation. This is most suitable for application in remote areas for lighting, pumping, rural telephones, battery charging (for off-sun hours lighting) and telephone exchanges. The estimated energy from a 1 KW peak photovoltaic array works out at 1650 Kwh, based on 4.5 peak hours of sunshine per day under average Indian conditions, and it is more economical than that of grid power for consumers of remote & rural areas.

Wind Energy Wind energy is a conversion of 2 % sunlight falling on earth's surface as kinetic energy, which is a most abundant, easily usable form of renewable energy. The estimated potential is about 25000 MW. The large grid connected wind farms based on wind turbines of generating capacity of 50 KW to 300 KW are indigenous in the country, with average annual wind speed higher than 18 kmph. which may be projected throughout the country (in Tamilnadu, Lakshdeep, Gujrat, Maharastra, Rajasthan, Karnataka, Kernataka and Andhra Pradesh for having annual wind speed from 20 kmph to 30 kmph). Autonomous wind generators and small wind generators based on battery charging have much wider application for annual energy demand than the grid connected units. Wind battery chargers appear economically viable in inaccessible areas for small power applications where an extension of the grid or a supply of fuel oil is difficult and costly. The Government of India has installed 120 imported small wind battery chargers in the capacityrange 50 KW to 4 KW, plus about 10 standing wind generators of 10-25 KW capacity. The performance of these systems is very encouraging and economical for all round progress in remote and rural areas, where wind is available in the range of threshold speed for operation.

Bio-mass Energy Bio-mass energy resources are available from three routes as; (i) Agro-Industrial residues (ii) Agricultural crop residues & (iii) Energy Plantations. Agricultural residues like bagasse, rice husk, coffee husk, molasses, groundnut cell, saw dust, cotton gin, etc. amount to 50 million tons of production. The Agricultural crop residue is mainly wheat, straw, paddy straw, maize stocks, sugarcane frash, groundnut holmes, etc; these account for 80% of crop residues that are estimated to amount to about 325 million tons. These products may be used as combustion fuel, although efficiency of utilization is lower. Gasification can increase conversion efficiency

1346 significantly. The potential amount for energy plantations is estimated to be 62.5 million tons, of which, 70% of the area is covered by Indian states such as Madhya Pradesh, Andhra Pradesh, Rajasthan, Gujrat, Maharastra and Uttar Pradesh. Typical energy plantation yields range from 5-20 tons per annum per hectare. About 80 fuel wood species are reported to be under experimentation. Some promising ones are Trema, Orientalis (3 yrs, 54 tons per hectare), Cassia Siamea (5 years, 90 tons per hectare) Leucaena Leucocephala (3 years 110 tons per hactareSonania Sauran and Erythrina Indica (3yrs, 80 tones per hectare) Proposis Juliflora and Acacia Nilotica have been found to be unsuitable for saline-alkaline soil. Comprehensive bio-mass energy programmes are linked to bio-mass resources, especially to energy plantations; the likely exploitation of power generation capacity from bio-mass is estimated at more than 40000 MW (up to year 2000). The associated social benefits from the energy plantation activity are; (i) employment generation in economically backward areas (ii) favorable rainfall patterns (iii) prevention of soil erosion (iv) enrichment of ground water (v) lower particulates and reduction of CO2- etc.

Micro-Hydro Energy Micro-hydro electric power has good scope for power generation energy conservation as well as cost-effective and pollution-free power generation. Up to now, only about 15% of the worldwide potential of low head hydraulic energy has been utilized. The Ministry of NonConventional sources of energy, a partnership between state government and entrepreneurs, has launched a major programme to harness the vast potential available in our rivers, streams and canals to provide socio-economic development in remote and rural areas where the cost of transporting fuel to use in small diesel generators and where the electricity from country's main grid are prohibitive; for example, in the Darjeeling area, a tea company has installed 15 micro hydro power systems for emergency application. These measures cost both money and time, but form cost-effective, eco-friendly power generating systems.

TECHNOECONOMICS OF INTEGRATED P O W E R GENERATION INTERFACED W I T H RENEWABLE ENERGY RESOURCES The economic viability of the proposed integrated energy system greatly depends upon the initial cost, as well as the potential of suitable diesel fuel in DG sets. It is recognized that the cost of a DG set of given capacity is many times lower than the initial cost of an integrated system with a battery bank. However, the advantages realized in terms of saving in fuel are considered highly significant in the Indian scenario. Several methods are followed to judge the economic viability of projects such as: (i)Return on investment (ROI) (ii) Life Cycle Costing, (LCC), (iii) Net present value (NPV), which takes into account both costs and benefits. The integrated systems contribute significantly to reduction in the unit cost of energy. The factors are diesel savings owing to DG set operation for shorter durations near peak load, reduced size battery bank, and smaller DG sets; in this order, this is seen that up to a 30% reduction in the unit cost of energy is possible by using wind/diesel integrated sets and in the case of solar/diesel, the reduction in annual fuel costs is good. In the case of a bio-mass wood gasifier, diesel replacement is up to 80%. The techno-economics of the integrated energy system minimises the energy cost for inhabitants of rural and remote areas; these are given in Table 1.

1347 TABLE 1 COMPARATIVE COST-EFFECTIVE OPTIONS OF ENERGY SYSTEMS S1 No.

Energy System

Initial Cost in lakhs Dual DG Set 0.70 Bio-mass Gassifier-sterling 1.30 engine with DG Set Solar PV with dual mode 10.6 of DG Set Solat PV with Gasifier 11.2 Sterlin[~& DG Set Wind generator with dual 6.1 mode DG Set Wind generator with 6.7 ~asifier sterlin~ & DG Set Micro hydel with dual 3.0 mode DG Set

Total present cost of fuel & maint cost for 25 ),ears 15.5 12.2

UnitCost Rs/Kwh

Pay period

2.4 2.03

1.1 2.6

5.1

2.33

16.9

5.1

2.31

17.5

5.7

1.75

9.8

5.0

1.73

10.3

6.0

1.25

3.5

back

CONCLUSIONS The energy scenario in India for renewables is an important route for bridging the energy gap between supply and demand, especially for rural and remote areas. Comprehensive bio-energy programmes linked with energy plantations are considerably to be highly beneficial from the viewpoints of energy, environment and economy, as well as having a positive social impact in providing gainful employment, for technological options of integrated energy systems using renewables and diesel generating systems; the latter are provided with an inverter and battery bank supply, giving an uninterrupted energy supply to rural communities in an efficient manner characterized by a low pollution level. It is possible to optimally size the renewable energy source, battery bank and diesel generator size for site specific condition to achieve lower running cost and unit operating cost. The future developments in the area of solar, thermal, low cost PV pumps, long life batteries, and higher technology bio-gasification would lead to more efficient and cost-effective integrated energy systems for the all round development of rural and remote areas of developing countries such as India. ACKNOWLEDGEMENT The Authors of the paper are thankful to the Director, Central Mining Research, Dhanbad, for his kind permission for the oral presentation of this paper during "6th International Conference on Greenhouse Gas Control Technologies (GHGT-6) in Kyoto, Japan, lst-4th October'2002. REFERENCES Ramamoorthy Dr M."Integrated energy systems for Remote Area Application: An optimal strategy" (January 1994), Journal of Irrigation & Power (India) M.K. Deb," Prospects for Power Generationthrough wind" (1992) IREDA Vol.3 No.2 Pg11-21,1992.

1348

.

5.

S. Pisutello, et.al " Bio-mass power in USA" GEC-Alsthom'Power Generation Technology (1993), Sterling Publishers, UK. TEDDY (TERY Energy Data Directory & Year book) (2000-2001) Mike Welch" Bio-mass derived fuel gases for power generation" (January 2001) Electrical India, Vol No. 41 No. 02.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1349

G R E E N I N G E L E C T R I C I T Y G E N E R A T I O N IN SOUTH AFRICA T H R O U G H WIND E N E R G Y Joe Asamoah EnerWise Africa, P.O.Box 101847, Moreleta Plaza 0167, Pretoria, South Africa

ABSTRACT Globally, the electricity supply industry is undergoing marked changes. The quest for "green" power is a motivating factor for the use of New and Renewable Sources of Energy (NRSE) that are relatively more environmentally benign, for the generation of electricity. The conventional components of the electricity supply industry, forming the core of electricity utilities; generation, transmission and distribution are gradually being fragmented into separate entities, in some cases, to promote efficiency, effectiveness, enhance profitability and to boost corporate governance. Wind Energy is expected to make enormous contributions to the global electricity generation market, hitherto dominated by fossil fuels. A report jointly commissioned by Greenpeace International et al has indicated that wind energy is capable of supplying 10% of global power in 2020 - requiting a wind power capacity of about 150 TW per annum. In South Africa, the coastal areas and the Drakensburg Escarpment show the greatest potential for wind energy. Several windmills have been installed in the more arid and commercial farming areas in South Africa mainly for pumping water. A prominent role-player in the generation of electric power is the Darling Wind Demonstration Farm. This farm has planned to generate about 5.2 MW of power initially, increasing to 10 MW eventually, for sale to the local municipality. This paper examines the status of the project, and its potential contribution to cleaner and sustainable environment in South Africa. INTRODUCTION

Whereas wind generation is a novel technology in South Africa, it is already well established throughout the world. For a country like South Africa with significant adverse environmental impacts from several coal-fired power stations, the generation of power from more environmentally benign energy carriers, in particular, wind and solar energy is very desirable. Due to the predominance of the power generation landscape by coal-fired power stations, devoid of flue gas desulphurisation mechanisms that result in cheap electricity, generation using new and renewable sources of energy is perceived to be expensive, and as such faces several barriers: institutional, policy, structural and fiscal. By 1993, some 30 000 windmills had been installed in the more commercial farming and arid areas of South Africa to provide water for both domestic use and livestock (SANEA [1]). The development of wind energy has largely been aided by the development of a wind map, for the country, as well as the entrepreneurial drive of private capital.

1350 However, the nascent interest shown by the Department of Minerals and Energy (DME) has added the much-needed fillip to the promotion of wind energy as a source of power. The DME has recently released a draft White Paper on the promotion of renewable energy and clean energy development, in which the development of wind energy features prominently. Additionally, it is the intention of the department to follow the approval of the draft White Paper with a Strategy that will translate the goals, objectives and deliverables that have been set out into a practical implementation plan (DME [2]). Wind energy is bound to play a significant role in hybrid remote area power systems that are intended to assist the attainment of the goal of universal access to electricity by 2010. THE DARLING WIND DEMONSTRATION FARM PROJECT The Darling Wind Demonstration Farm (an Independent Power Producer [IPP]) is meant to introduce wind technology into South Africa, and is planning an initial 5.2 MW Wind Farm in the area of Darling, 70 km north of Cape Town. Subsequently, the output will be increased to 10 MW. Wind measurements that were carried out showed an excellent wind regime, with a potential speed in excess of 7 m/s. This project will create a new industry with a potentially new market, create jobs and result in environmentally friendly power production. Financial analysis, that was conducted, indicates that the selling price of the generated electricity will be of the magnitude of 38 c/kWh, at a modest Internal Rate of Return (IRR) of 8,0% for the shareholders/investors of the wind farm. This is much higher than the 19 c/kWh the Darling/Yzerfontein municipality is prepared to pay. Substantial grant funding is therefore required to lower the generation price to an acceptable selling price of 19 c/kWh for the municipality. The innovation of the project is to act as the first Independent Power Producer of bulk generation of electricity from renewable energy sources in South Africa. In addition, the Darling Demonstration Project has been declared a project of national importance by the South African Government, through the Department of Minerals and Energy (DME), and will be used to identify, develop and update the necessary strategies and regulations on how to deal in general with IPP issues. The aim of the project is to showcase the removal of obstacles for future applicants to obtain an Independent Power Producer' generation licence for "green" power generation. The successful application for international grant funding is essential for the project, and knowledge of these application processes could be used for future projects (Asamoah [3]). It is noteworthy that a number of institutions have shown tremendous interest in the project, including the Global Environment Facility (GEF) that is providing grant funding to aid the development of the project. Being the first of its kind to be developed in the country, numerous research studies have been carried out on the project, resulting in abundant knowledge on the technical and financial aspects, as well as its contribution to sustainable development. TECHNICAL ISSUES With a capacity factor of 34%, the 5.2 MW-capacity installation will produce a conservative 13.5 GWh output per annum. After consultation with numerous major wind turbine suppliers, Darling IPP has selected the Bonus Energy A/S latest 1 MW turbine as the generation plant for the wind farm. Five turbines will initially be erected on the site. The Bonus 1 MW turbine is microprocessor controlled. A Windows-based remote monitoring system will be the interface of the link between the Darling IPP Head Office in Darling and the turbine, with remote access to the monitoring equipment. The turbine is mounted on a tubular steel tower that has internal platforms to facilitate safe ascent without additional safety harnesses. According to Oelsner [4], seventeen months of wind measurements using two monitoring systems in parallel and correlated with 10 years of historical data in the Cape Town area indicate wind speeds in excess of 7.5 m/s at 50-metre hub height, depending on the location on the hill. It is observed that the pattern of electricity generation

1351 will match the demand pattern of the area, by being higher in the late afternoon when local demand starts to peak. NATIONAL BENEFITS Wind generation will be a new technology in South Africa, notwithstanding the fact that it is already well established throughout the world, especially in Europe, India and the United States. One of the reasons for the globally fast growing market is the trend to generate "green" electricity from renewables. The demand for environmentally clean energy in South Africa is a major objective of the Department of Minerals and Energy (DME), and the implementation of the Darling Wind Farm will introduce this new technology into the South African energy market. This will definitely transfer knowledge from overseas into the country, forming the basis for a new industry in the country. Worldwide experience demonstrates that wind energy has a very high job creation effect thanks to its decentralised electricity generation. It is observed that the installation of 1 MW of wind power creates between 15 and 19 jobs. However, in more labour intensive parts of the world, like South Africa, this may double. In addition, jobs will be created in maintenance and service. Wind energy creates 10 times more jobs than nuclear, and 4 times more than coal-fired power stations. Being the first of its kind in the country, it is envisaged that the Darling project will attract about 30 000 visitors per year, thereby boosting the tourism industry of the area. ENVIRONMENTAL AND H E A L T H BENEFITS The environmental and health benefits of the Darling Wind project are provided below for the planned maximum output of 10 MW per annum (producing 27 GWh of electricity), replacing coalfired power generation. The major benefits stem from the avoided anthropogenic emission of green house gases, noxious gases, particulate emissions and savings in water consumption, due to the savings in the combustion of coal. The health benefits are very important, considering the expenditure that the Government incurs in the purchase of medication to combat acute respiratory infection that results from the combustion of coal, particularly, in poorly ventilated households. TABLE 1 AVOIDED EMISSIONS AND SAVINGS OF RESOURCES BY THE DARLING WIND FARM

Wind generated electricity replaces coal generated electricity Resource/Emission

Annual savings

Life time saving (25 years)

Coal

13 939 tons

348 476 tons

Water

35 million litres

868 million litres

C02

26 117 tons

652 912 tons

S02

214 tons

5 339 tons

Nitrogen Oxide

106 tons

2 658 tons

Particulate Emission

12 tons

322 tons

Source: ESI Africa 2, 2002

1352 The electricity produced by the Darling Demo Project will contribute implicitly to the health of South Africans by displacing the above-mentioned gases that emanate from coal-fired power generation of electricity in the country. Most of the emissions from the combustion of coal contribute to acid rain, cause respiratory infection and impair visibility, whilst carbon dioxide is the biggest contributor to global climate change. The wind farm will act as a model of an environmentally friendly sustainable development. Research estimates that the environmental external costs in coal-fired power generation are: Research in Europe Preliminary local research in South Africa

R 1,17 / kWh R 0,14/kWh

At the present stage, these external costs are paid by the health of the people. However, they have to be paid in future by the generator/provider. The environmental impacts of wind turbines are very minimal, compared to other electricity generation options. Among these impacts are noise, endangering the lives of birds and visual intrusion. However, to increase the benefits, sheep will be allowed to graze on the farm. CLEAN DEVELOPMENT MECHANISM

Due to the high fossil fuel content of its power generation, South Africa is a very attractive destination of massive anthropogenic emission of greenhouse gases, whose abatement could lead to the procurement of certified emission reduction units (CERs) under the Clean Development Mechanism (CDM) of the Kyoto Protocol. The value of these credits, computed as avoided emission of greenhouse gases, is estimated to cover up to 20 % of the total capital cost of the Darling project. South Africa has already acceded to the Kyoto Protocol; and is expected that the Conference of Parties (COP) would ratify the latter by the end of 2002. CONCLUSIONS The Darling Wind Demonstration Farm project, arguably the first of its kind to be developed in the country for the generation of "green" power has political backing; and is expected to pioneer bulk "green" electricity generation, using renewable energy in the country. Considering the adverse environmental and health impact of coal-fired power generation in South Africa, this project is very important to sustainable development, as it will address environmental, health and social issues. Over the 25-year life span of the project, it is expected to generate certified emission reduction units (CERs), the value of which equals 20% of the capital cost required for the project.

REFERENCES

1. 2. 3. 4.

SANEA. (1998). In South African Energy Profile, p 35. DME. (2002). In Draft White Paper on Renewable Energy and Clean Energy Development, p38. Asamoah, J. (2000). African Energy Journal, vol 2 no 4, pp 32-35 Hermann, F.W. (2002). ESIAfrica. 2, 42.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1353

G R E E N H O U S E GAS M I T I G A T I O N O P P O R T U N I T I E S T H R O U G H THE A P P L I C A T I O N OF S O L A R E N E R G Y IN BANGLADESH Ahsan Uddin Ahmed Bangladesh Unnayan Parishad (BUP) Dhaka, Bangladesh E-mail:

ABSTRACT

There is a consensus that Bangladesh will suffer the most under climate change despite the fact that it is one of the least contributors to the annual load of greenhouse gases to the atmosphere. High susceptibility of physical systems to climate change-induced extreme weather events will cause devastating impacts on the livelihood of the poor population of the country. Recognising the importance of mitigation towards reduction of vulnerability, the country has committed to implement projects on energy efficiency, particularly those involving renewable energy technologies. Initially, a remote area has been chosen to provide solar electricity at household levels. Poor families are asked to share initial capital investment costs, that are collected in instalments. Dissemination of such technologies will not only enable a large number of families to get basic form of electricity services, but also contribute to the reduction of greenhouse gas emission from the country. This article discusses a few options concerning solar-powered technologies with particular emphasis on solar home systems. However, given the high initial investments for solar photovoltaic technologies and poor socio-economic conditions of the majority of the population, it appears that the feasibility of large-scale GHG mitigation by use of solar photovoltaic systems is low in Bangladesh.

INTRODUCTION

The global scientific community has now given ample justification to their earlier consensus: the world is destined to face significant changes in its climate systems [ 1] leading to adverse impacts in many countries. The Third Assessment Report of the Inter-governmental Panel on Climate Change (IPCC) highlighted the areas where the adverse impacts of global warming and sea level change would be significant. As a lowlying delta burdened with 129 million people in an area of 14.7 million hectare land, Bangladesh is likely to face the worst kind of impacts in the form of increased floods, droughts, salinity ingress etc. Since the country has poor financial, institutional, and technological capacity to adapt, its vulnerability will be extremely high in a warmer world [2,3,4]. It is ironical that the country, which is known to be one of the worst victims of climate variability and change, contributes very little to the main cause of global warming anthropogenic emission of greenhouse gases (GHGs) to the atmosphere. As a signatory to the UNFCCC and the Kyoto Protocol the country is not particularly obligated to reduce its minuscule load of GHG emissions. In order to show its willingness to voluntarily participate in GHG mitigation, in recent years the country has began to take steps towards reducing its GHG emission load in various sectors. The Energy Policy of Bangladesh gave emphasis on utilisation of renewable energy including solar energy to meet future demand [5]. Application of solar-based appliances in the country has taken place only at a very slow rate. There exist a number of opportunities where solar energy may be utilised in future to get

1354 GHG-free (zero-emission) energy services. This article examines such opportunities and highlights the factors that might limit the full potential of application of solar energy in future. BANGLADESH'S CONTRIBUTION TO GLOBAL LOAD OF GHG EMISSIONS According to the first Emissions Inventory conducted in 1997, the average per capita GHG emission for Bangladesh was about 655 Kg of CO2 equivalent with respect to the UNFCCC base year 1990 [6]. It was mush less compared to those for USA, Australia, Canada and other industrialised countries. The total emission was 72,000 Gg of CO2 equivalent, which was about 0.04 percent of the global GHG emissions of 1990 [7]. From the above analysis one may infer that Bangladesh' overall contribution has been very low. Since the economy has been growing at a rate of about 5 percent per annum during the 1990s and increasing amounts of commercial fuels are now being consumed instead of traditional fuels, it is expected that the country's overall future emissions load will significantly change. Given that the population of the country is likely to increase significantly in the coming decades, it is also expected that the average per capita GHG emissions will remain low in near future. IMPLICATIONS OF CLIMATE CHANGE FOR BANGLADESH Since time immemorial, the country has been subject to natural disasters. The country is situated at the end of the natural drainage system of the Eastern Himalayan rivers comprising the Ganges, the Brahmaputra and the Meghna (GBM), where it has very limited control over a huge quantity of available surface water. Moreover, due to continued sedimentation, the discharge capacity of these rivers has deteriorated, resulting into deceleration of flows when the outfall is approached. The inter-seasonal distribution of water is also precarious: over 80 per cent occurring between June and October and the volume available in August is about 30 times higher than that in March. These two phenomena occurring simultaneously in each annual hydrological cycle makes the country highly vulnerable to water availability and its distribution patterns. Under normal circumstances, the people frequently suffer from either flood or drought. Low flows in the dry season and increased withdrawal in the upstream of the boundaries of Bangladesh cause salinity ingress in the coastal areas. The country is frequently devastated by high intensity cyclonic storm surges. Such events will be far more damaging due to increasing density of both coastal population and infrastructure. Climate change will increasingly threaten sea-facing polders due to increasing surge heights caused by a rise in sealevel. It is found from a number of model-simulation studies that the country's overall vulnerability to disaster with respect to water resources would increase significantly due to climate change [4, 8, 9]. The overall impacts of climate change in Bangladesh will have far reaching consequences, not only on the physical features, also on the socio-economic aspects of the country. Anticipated adverse impacts of climate change are likely to affect agriculture severely. Under climate change scenarios it will be extremely difficult even to maintain the present level of agricultural production. A combination of increased food demands (due to increase in population and expected economic progress) and possibility of having somewhat reduced or same levels of agricultural production will challenge the national goal of maintaining food-self sufficiency. Loss of both agricultural land and production will adversely affect livelihoods of the rural poor. Loss of income and unemployment will further complicate poverty situation of the country. Loss of livelihoods of a large segment of the population will not only increase the risk of large-scale migration, but will also lead to increased competition for access to the reduced natural resources. All these result in further acceleration in the exploitation of natural resources and further degradation of the natural resource base - both causing a negative impact on sustainable resource management. Appropriate adaptation measures would enhance the resilience of physical and social systems and/or reduce the risk of adverse impacts of climate change. Unfortunately, there are inherent weaknesses with regard to adaptive capability of the country, owing to high incidence of poverty, lack of institutional strength, weaknesses in legal and governance mechanisms, and disaster proneness to climate change. It is expected that a comprehensive climate change strategy will soon be formulated with a view to reduce the anticipated adverse impacts and strengthen people's resilience toward facing climate-related adversities.

1355 NATIONAL VIEWS T O W A R D S ADAPTATION AND M I T I G A T I O N Bangladesh is yet to have a policy on climate change. It is in the process of developing its first National Communication to the UNFCCC [2]. In absence of a specific policy it is difficult to predict whether the country would concentrate on adaptation or mitigation - both being emphasised as response measures in the UNFCCC and subsequently, in the Kyoto Protocol (KP). According to the TAR of IPCC [ 1] it is clear that even if the KP enters into force early, the adverse impacts cannot be fully offset. Compliance to the Protocol, at the best, could only slow down the process of global warming. Under such circumstances, it is expected that Bangladesh would only like to concentrate on long-term anticipatory adaptations, especially those targeted at reducing water resources vulnerability to climate change. Simultaneously, it would try to enhance the existing social resilience in order to make its 'reactive adaptations' more useful while facing future adversities. It is also expected that mitigation would not get high priority, especially when it has very limited capacity to facilitate the reduction of overall global GHG emissions. Despite the threats posed by global warming, Bangladesh should try to achieve sustainable development by all possible means. One of the modalities of development is to achieve higher efficiency in production and utilisation of energy. Discarding wasteful technologies and demand side management are two options which can pay high dividend in this context. In the process of achieving higher energy efficiency, opportunities for abatement of GHGs should also be carefully examined while selecting appropriate technologies. P O T E N T I A L F O R M I T I G A T I O N : SECTOR-BASED ASSESSMENT The per capita GHG emission for 1990 was about 655 kg, about 41% of which were due to agricultural and waste management practices. Energy sector contributed to about 31% emissions while forestry sector and land use change contributed to about 27.4% for the same year. For the same base year the average commercial energy consumption per capita was about 56 kg of oil equivalent. A detailed technology based estimate revealed that a total of 12.09 Tg CO2 was released from fuel combustion and fugitive emissions that included 4.39 Tg from energy production and transformation, 2.42 Tg from industry sector, 1.88 Tg from transport sector and the remaining emission from small combustion and fugitive sources. In addition, 2.2 Gg of N20 and 163 Gg of CH4 were also released in 1990 from the formal energy sector. An inventory of emissions from the forestry sector (including land use change) revealed that there was a net emission of about 19.74 Tg of CO2 equivalent in 1990 [6]. Biomass (straw, dung, fuel wood, jute sticks etc.) is the major source of energy in Bangladesh. CO2 emission from biomass burning is believed to be recycled through photosynthesis in the following cropping season and therefore, it does not cause GHG forcing. In the contrary, emissions from fossil fuel sources contribute to GHG forcing. Since consumption of fossil fuel energy is still very low in Bangladesh, there exists little opportunity for GHG mitigation in terms of absolute quantity likely to be abated per annum. But Bangladesh' GHG emissions will increase significantly as the country takes stride for economic development through industrialisation [6]. It is expected that fossil fuel will be increasingly used instead of biomass fuels and a corresponding growth in emissions from fossil fuel burning will be observed in near future. In order to maximise energy output it is also expected that Bangladesh will try to mitigate GHG emissions from fossil fuel burning. Economic efficiency is likely to become a major factor guiding the choice of technologies and GHG mitigation will then become an important criterion. It is, therefore, necessary to examine the available GHG mitigation options. Under the current economic considerations and policy regimes, a few mitigation options offer good economic alternatives now in terms of costs per tonnes of CO2-eqivalent abated [6]. A few such options offer additional benefits such as increased energy intensity, improved production and services, reduction of energy demand, and making provision of services where conventional services could not be extended. Two types of supply side mitigation options are available: (i) efficient power generation and (ii) reduction of loss in transmission and distribution. Since Bangladesh is endowed with a significant reserve of natural gas, a clean-fuel, a fuel switch from diesel to natural gas for power generation is already a potential mitigation option. Fortunately, natural gas has been considered as the baseline fuel for power generation [5]. Choice of

1356 technology can also help reduce GHG emissions. In recent past, opting for combined cycle power plants in lieu of either combustion turbine or steam turbine plants have resulted in an increase in power production efficiency from a mere 35% to as high as 55%. The country has been enabled to save about 484 Gg of CO2eqivalent from one power plant, established in 2000-01. Despite the high initial investment cost of such options, combined cycle technology is likely to become the baseline electricity generation technology in near future. Although hydro-electricity production does not cause GHG emission, its future potential is low. There may be a number of GHG mitigation options by means of Demand Side Management. In the transport sector, efficiency improvement may be achieved by means of replacing highly polluting two-stroke engines, used mainly in motorised three wheelers, with four-stroke engines having a potential of 25 to 35% increased fuel-efficiency. A recently imposed ban on two-stroke three-wheelers will enable the country to save 90 Gg of CO2-eqivalent annually. Introduction of new cars and buses instead of reconditioned ones could increase fuel-efficiency by 10-15%. Recent introduction of about 300 new buses in Dhaka alone is saving some 204 Gg of CO2-eqivalent per annum. Mitigation concerning an intra-modal transport shift from reconditioned cars to fuel-efficient motorcycles, especially suitable for city dwellers, appears to be another good option. Maintenance of vehicles could also increase fuel-efficiency quite considerably with a potential reduction of about 54 Gg of CO2-equivalent per annum. Such mitigation can only be materialised through personal care of the users with an intention to save fuel. Another option is to replace gasoline by condensed natural gas for cars that may provide up to 75 per cent fuel savings with a potential reduction of about 135 Gg of CO2equivalent per annum. The present government has attached high priority to such a win-win option. But the progress has been really slow. A number of mitigation opportunities also exist in the industrial sector. Retrofitting of leaking boilers and inefficient motors does not only save fuel, also enhances working conditions. Mitigation potential, however, is low - in the order of 20 Gg of CO2-equivalent per annum. Brick making and paddy parboiling are the two energy-intensive large-scale industrial activities, where mitigation is possible in addition to maximising other environmental and socio-economic benefits. The potential mitigation in these industries can be as high as 14,000 Gg of CO2-equivalent per annum. Industrial co-generation has already been practising in a number of sugar industries in Bangladesh. The experience may be extended in some of the heavy and energyintensive industries. Co-generation is also possible in large commercial complexes and big hotels where, in addition to supply electricity for lighting and other purposes, the exhaust heat energy may be used for air conditioning and for supply of hot water. Such an option is highly feasible in the upcoming large commercial-cum-residential complexes in the major urban areas. Co-generation offers a potential of about 80 Gg of CO2-equivalent per annum. Increase in efficiency of appliances in the domestic sector provides a number of GHG mitigation options. Introduction of efficient air conditioners, switching from incandescent light bulbs to either fluorescent or compact fluorescent light (CFL) bulbs, use of improved kerosene lamps and biomass stoves in rural households - all are attractive mitigation options. In addition, CFLs provide higher lumen and do not attract insects, thereby enhance quality of life of the users. The cost of a CFL unit is much higher than an incandescent bulb making it less attractive in the short-run. However, in the longer term its economic returns are higher. Efficient biomass cooking stoves offer major environmental benefits by reducing in-house air pollution, thereby reducing health-risk, and rate of fuel wood consumption by 40-50%. The annual potential GHG mitigation from improved biomass stoves can be as high as 14,000 Gg of CO2-equivalent. Theoretically, GHG mitigation from agriculture is possible by changing (i) traditional wet rice cultivation practices, (ii) feeding practices involving ruminant livestock, (iii) management practices for livestock manure, and (iv) land use pattern by planting trees for increased sequestration. The options under i and iii have very limited scope, while option ii and iv could be extremely useful. The government has been encouraging fattening of cattle. Use of molasses-urea blocks as improved feed, alternative to traditional straw based feed, is gaining popularity. Sink enhancement by means of tree plantation has become a nationwide annual social event. The early drive of the government for Social Afforestation has been highly successful. Afforestation programme enabled the country not only to revert high rate of deforestation prevailing in 1990, it has also helped it re-establish itself as a net sink instead of being a source of GHG.

1357 GHG M I T I G A T I O N T H R O U G H THE APPLICATION OF SOLAR ENERGY In addition to the above mentioned GHG mitigation options several other renewable energy based options are perceived to have prospect in Bangladesh. At present, the Bangladesh Rural Electrification Board is supplying electricity to just over 10% of about 21 million rural households. Unfortunately, the supply is inadequate and erratic. Despite having indigenous raw material (natural gas) and plans for extension coverage of reliable power, the Bangladesh Power Development Board has been facing acute problems in meeting increasing demand for electricity, largely due to shortage of financial resources. It is almost certain that majority of the rural families could not be brought under electricity coverage in near future. PV systems offer limited-scale household- and/or community-based electricity without causing any GHG emissions. The energy may primarily be used for lighting, especially in remote areas outside the reach of national electric grid system, and also for (a) recreational purposes such as viewing television and (b) extending working hours to increase household income. These systems are particularly useful in areas that are not connected to the national electric grid. In the backdrop of current shortcomings in relation to further expansion of capacity for generation-transmission-distribution of electricity, solar PV technology offers an alternative source of energy. Given the weak economic base of majority of the rural households, there is, however a serious impediment concerning the high initial investment cost for PV technology. If the total cost of expanding grid electricity coverage is weighed against the cost of PV systems the overall economic and environmental cost-benefit analysis does not look pessimistic. In Bangladesh, the efficiency of conventional power generation is about 30-35% and transmission and distribution loss is about 25%. Considering these factors, a simple arithmetic suggests that the potential annual savings of GHG would be between 0.045 and 0.05 tons of carbon per household. If a household accepts solar PV technology at a cost of about US $700-$950 and assuming that the average lifetime of each set of gadget is about 15 years; it is estimated that the annual cost of enjoying electricity per household would be about US$25. This is about 1.1% of per capita income of an average household. In recent years, a Pilot Project has been successfully implemented in an area that has been non-accessible by the electric grid. Early experience showed promising results for extending the 'zero-emission' alternative in other remote areas. Local Government Engineering Department and a voluntary non-governmental agency (NGO) are now engaged in disseminating PV technology under financial assistance from the UNDP. It is expected that solar home systems will offset about 367 Gg of CO2-equivalent annually by the year 2005. Solar powered lanterns not only provide zero-emission lighting option, the units are also transferable. Such devices are handy in rural areas, especially at night where the sanitary latrines are located outside the household and people need light to access those. A typical PV lantern unit costs about US$450 to$700 for about 30 to 43 Watt output. The estimated GHG savings potential is about 730 Kg CO2 per unit per annum. In urban areas solar technology can be used for non-lighting purposes such as water heating. In many of the urban households belonging to higher socio-economic classes, natural gas is used for heating water to serve various purposes. A domestic water heater with a capacity of 20-30 gallons consumes about 25 gigajoules of natural gas per year. A solar water heater costs in the range of US$600 to $800 in comparison to about US$300 to $360 for an electric water heater. If regularly used, each solar water heater could save about 750 Kg of CO2 per annum in addition to saving about US$37 - the cost of saved natural gas. Bangladesh is a poverty stricken country. Electricity is regarded as luxury to about 50% of its population who fall below poverty line. But these poor people have demand for various energy services (lumen for lighting etc.), often met by traditional energy sources. Since the initial investment for the solar technologies are quite high, many rural poor families cannot afford such technologies. Moreover, people hesitate to accept an exotic technology, even given free of cost, until they become fully aware of its effects. Given the economic and cultural background, it is almost certain that people would not opt for a solar lantern, since the alternative technological option is so cheap (battery operated 'torch'). On the other hand, since electricity supply is relatively better in urban areas than in rural areas it is likely that the urban people

1358 would tend to afford electric water heater instead of solar powered alternative. Examining the solar technologies mentioned above it seems that only the solar PV system has some potential, especially in areas where it would be difficult to extend electricity grid in near future. But the technology is not likely to penetrate easily because of the financial barrier: the high initial investment cost. If poor rural households are offered a sizeable proportion of the initial investment cost of a Solar Home system as a loan, repayable by easy instalments, then many household would be willing to accept the technology. Use of such technology could also improve the quality of life for millions of rural people. In rural Bangladesh many voluntary NGOs are working. Their activities are predominantly focused on (a) helping the poor in income generation and (b) facilitating towards improving quality of life through health care and education. The government should set aside an adequate fund, channelled through the NGOs, to offer appropriate credit schemes to the people enabling them to install PV technologies. The government could further facilitate dissemination of the technology by providing market incentives such as waiving off tariff and other applicable taxes, which would in turn reduce the burden of high initial investment cost. It is expected that, any 'incremental cost' necessary to promote such technology will be borne by the Global Environmental Facility (GEF) considering the fact that it is environment friendly with considerable potential for emission reduction. It is the responsibility of the concerned government agency, the Ministry of Energy and Mineral Resources who should apply to GEF for adequate funds. Traditional Bangladeshi rural people lack proper education and, therefore, they are somewhat passive towards accepting 'new' and 'improved' technologies. It would be necessary to build their confidence first by demonstrating the technology in electronic media. In the past, demonstration on other technologies helped overcome the barrier of lack of knowledge. Lessons may be leamt from earlier experiences. CONCLUSIONS The total GHG emissions from different anthropogenic activities in Bangladesh are small in global scale. Even then it is possible to reduce emissions by introducing some technologies and management practices. Solar energy based technologies could be useful in mitigating GHG emissions, but the overall impact would not be substantial in global scale. It is found among the solar energy based mitigation options that photovoltaic units, that can provide electricity from household based point sources, might have relatively large potential. However, one must consider the high cost of initial investment and provide financial incentives by introducing cost-sharing partnership in order to enable the poor to enjoy electricity at the grassroots. NGOs could be instrumental towards disseminating the technology and popularising it. REFERENCES 1. 2. 3. 4. 5. 6. 7. 8. 9.

McCarthy, J.J., Canziani, O.F., Leary, N.A., Dokken, D.J., and White, K.S. (Eds) (2001). Impacts, Adaptation, and Vulnerability, Published for IPCC by Cambridge University Press, Cambridge. Ahmed, A.U. and Rahman, A. (2000). In: Asia LoolcingAhead, pp. 49-67, K. Ramakrishna, B. Bamberger and L. Jacobsen (Eds), The Woods Hole Research Center, Massachusetts. Ahmed, A.U., Alam, M. and Rahman, A.A. (1998). In: Vulnerability and Adaptation to Climate Change for Bangladesh, pp. 125-143, Huq, S., Karim, Z., Asaduzzaman, M. and Mahtab, F.U. (Eds), Kluwer Academic Publishers, Dordrecht. WB (2000). Bangladesh: Climate Change and Sustainable Development, World Bank report No. 21104-BD, 138 p., Rural Development Unit - South Asia Region, Dhaka. GOB (1995). National Energy Policy, Government of the People's Republic of Bangladesh, Dhaka. ADB (1998). Asia Least-Cost Greenhouse Gas Abatement Strategy -Bangladesh, Summary Report, Asian Development Bank, Manila. Asaduzzaman, M., Reazuddin, M. and Ahmed, A.U. (Eds), (1997). Global Climate Change: Bangladesh Episode, 40 pp, The Department of Environment, Government of Bangladesh, Dhaka. Warrick, R.A. and Ahmad, Q.K. (Eds) (1994). The Implications of Climate and Sea-Level Change for Bangladesh, 415 p., Kluwer Academic Publishers, Dordrecht. Huq, S., Karim, Z., Asaduzzaman, M. and Mahtab, F.U. (Eds) (1998). Vulnerability and Adaptation to Climate Changefor Bangladesh, 143 p., Kluwer Academic Publishers, Dordrecht.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1359

C O R P O R A T E E N V I R O N M E N T A L I S M IN INDIA: SOCIAL AND C O M M U N I T Y ISSUES RK Khullar General Manager (Works), Siel Ltd., Rajpura- 140 401, Punjab, India

ABSTRACT

The economic issues, related to environment misuses are very significant in the concept of globalization/liberalization especially for developing and underdeveloped countries. "Masses continue to live far below the minimum levels of human existence on Earth. They are deprived of adequate shelter and education, water and lighting, food and clothing, health and sanitation. In nut shell, the developing countries must concentrate their efforts to development bearing in mind their priorities and the need to safeguard and improve the environment". Due to non-availability of the above facilities, the environment is at stake and under a lot of stress and strain as mankind misuse the various natural resources available in the surrounding areas. Due to the shortage of resources and availability of the latest CDM, the gap between developing and developed countries is increasing day by day. Indirectly, the environment is getting spoiled/misused/damaged beyond recoverable limits, i.e. increase in the release of CO2 by the burning of wood/cowdung/cutting of forest cover/spoiling of water resources, without any knowledge of the havoc caused by them. The paper deals with the challenges for Control of Climate Change Sustainable Energy and Greenhouse Gas Emissions. For the same purpose, the industries of developed countries should make efforts between themselves and the developing countries to save the mankind. Who is going to lose or what is their loss? Developed and developing countries alike are heading towards the same destination. INTRODUCTION

SIEL Ltd. is a major producer of chemicals, sugar, compressors and household products such as vanaspati and soap. Siel Food & Fertiliser Industries (SFFI) is a flagship company of Siel Limited and has a food processing and chemical manufacturing industry employing 1400 people. It has four major plants and has an installed capacity to produce 49,500 MT of Caustic Soda, 43,500 MT of Liquid Chlorine, 33,000 MT of HCL, 30,000 MT of Stable Bleaching Powder and 83,585 MT of Vegetable Oils, and a captive thermal power plant of 27.5 MW capacity. It has an annual turnover of Rs. 375 Crores. SFFI is a unit of Siel Ltd. and was instituted in 1941; the major thrust was on production and quality. It made efforts to meet pollution standards, however, it had potentially hazardous installations such as Oleum and chlorine gas units. Environmentally-sound industrialization requires sustained effort on the part of corporate management, government and public interested groups. Industries are increasingly realizing that continued mismanagement of resources/materials could affect the long term viability of production, whereas environmentally sound production practices pay dividends in terms of corporate image and product acceptance. With the two subsequent accidents happening in industry in India in two consecutive years, i.e the Bhopal gas leak and the Oleum gas leak (in the Shriram factory) in Delhi, the corporate world became very weak in their defence as far as

1360 environmental protection and controls were concerned. This resulted in stringent measures being suggested by the Expert Committees for the running of the hazardous chemical factories their storage and manufacture. The Bhopal factory was closed but the Shriram factory, which has storage and manufacture of two chemicals, chlorine and Oleum, re-opened again aider five months with the management becoming more proactive and paying a great deal of attention to environmental issues. According to top managers, the starting point of the transformation "was the strong management commitment to protecting environment". The result was that the management and workforce became one, and worked together to implement the various suggestions in the shortest time (considering it as their only survival). The management soon realized that Sustainable Environmental protection is possible only through participation of all employees and it is not a one-time policy but an on-going process. I belong to this company, M/S Siel Ltd., Delhi, India, and would like to share the thinking and methodology adopted, actions carried out and the results achieved in the improvement of the environment, reduction in water and air pollution, as well as reduction in the greenhouse effect by improvement of energy efficiency and reduction in discharge of carbon dioxide into the atmosphere. All this improved the working conditions, resulted in more revenue by utilizing the waste for useful saleable products and reduction in energy cost/unit of product produced. However, the management of SFFI, realizing the company's responsibility towards society chose to go beyond the measures suggested by the expert committees. It adopted an agenda of Sustainable Environmental Management accounting for all stakeholders. The vision and the efforts made by management enabled SFFI to institutionalize environmental care systems in all their production activities. CORPORATE PRIORITY Environment and energy efficiency and safety are accorded top priority in the business ethos of the company. A clear corporate philosophy was enunciated to identify, incorporate and implement key determinants to sustainable development. SIEL CORPORATE PHILOSOPHY Salient parameters of Siel group philosophy also enunciate: Openness and trust; - Pursuit of knowledge; Encouraging development of corporate leadership through continuous education, challenging assignments and greater interactions in the socio-economic and cultural spheres. In addition, SIEL is committed to improving the quality of life in and around its units through community development programmes that focus on drive on literacy, plantation, sanitation and health. -

-

S F F r S CORPORATE ENVIRONMENTAL STRATEGY SFFI sought to inculcate the concept of environmental protection in all their operations and at all levels of interaction between Nature and SFFI's people and machines. The strategy encompassed: - Corporate level management measures - Work-force related measures In-plant measures - Stake holder related measures -

1361 CORPORA TE L E V E L M A N A G E M E N T M E A S U R E S

The corporate philosophy squarely places environmental concerns in the centre of their production activities. The management believes that the following measures will enable them to achieve environmentally compatible production techniques: Conservative attitude towards energy and resources Proactive approaches to wastes and hazard produce in the plant operations High degree of responsibility towards consumers, the general public and other stake holders to ensure their safety and quality of life The management's commitment to environmental concern and their positive efforts to act upon these have created a new work culture. This culture has even gone beyond the factory door's, finding reflection in the personal lives of SFFI's employees. -

-

-

WORK FOR CE R E L A TED M E A S U R E S

Many of the steps initiated by SFFI are aimed at improving the work climate in the industry. These have goals of: improving labour-management relations ensuring safety, health and literacy creating a sense of self-esteem and personal responsibility SFFI's employee relations are not limited to factory premises. The management has initiated certain welfare programmes for worker's families. A sense of belonging has been created by arranging family get together and giving conducted plant tours for family members, and involving them in tree plantation and ongoing care of saplings. As the corporation demonstrates its care for their well being, the employee respond by contributing as much as possible, and accepting personal responsibility for safety and productivity in the plant. Taking one step beyond what is required, SFFI has tried to make environmental considerations a way of life for each employee. They offer general awareness programmes on down to earth methods of energy conservation, wild life conservations and danger of smoking, among others. -

-

-

IN-PLANT STRATEGIES

Strategies adopted at plant level addressed: - safety and preparedness - energy and material conservation preventive maintenance - recycle and reuse - regulatory compliance - research and development -

S TAKE H O L D E R - R E L A TED S TRA TE GIES

The main stake holder outside the business premises is the general public, in particular the community right outside its doors that is directly affected by corporate activities. Consumers are the important stake holders. Keeping in view the fact that concerns and priorities of different share holder are not always similar, SFFI has tried to integrate and respect these different expectations. While giving due respect to the expectations of the consumer regarding product quality and comfort in handling, SFFI also tries to extend its vision of environmental protection to the common people by sponsoring activities such as 'Marathon Race' to help Save the Earth and by arranging Eco Tours for school children. With regard to the safety of nearby communities, public address systems are in place that will give clear instructions on what to do in the event of gas leaks, so there will be no panic. Public servants, Police and Fire Brigade personnel are trained and well informed about the plan of action they are to adopt to minimize impacts arising out of ignorance and panic. Doctors in the hospitals nearby have been informed of the possible causes of mishaps, so that they can prescribe correct antidotes.

1362 CLEAN TECHNOLOGY Starting from raw material exploration stage, SIEL has adopted a concept of preventive techniques. This concept envisages minimizing emissions and maximizing recycling/reuse of effluents. In our Chlor-Alkali operations, we have developed systems for recycling and reuse in such a manner that there is neither liquid effluents nor gaseous emission from the plant. The plant has 100% utilization of chlorine. In other plants also the same technique was applied to reduce wastages. ENVIRONMENTAL CONTROL MEASURES The control measures for environment are broadly classed as follows:

1) ENVIRONMENT PROTECTION : Under this, significant measures taken are a) ZERO-EFF PROJECT: Under the zero-eft project, effort is made to reuse/recycle gaseous and liquid effluents. Thus, the caustic chlorine plant has achieved zero-liquid effluent and gaseous emissions, where chlorine utilization is 100%. The Stable Bleaching Powder Plant also achieved a landmark in recycling/reuse of liquid effluent in plant operations and gainful utilization of waste chlorine in the manufacture of saleable product. b) BIOLOGICAL T REAT M EN T P L A N T After recycling/reuse and in-plant measures in the chemical plant, the combined effluent is subjected to biological treatment in a polishing unit. The treatment plant works on the principle of oil recovery, physico-chemical. An activated sludge process and dissolved air flotation process is used to render treated liquid effluent fit for use in plantation. c) ECO PARK, BIO/NATURAL MONITORS: In SFFI, we believe that conventional methods of monitoring should be retained, yet we have introduced the concept of Bio/Natural monitors. SFFI was the first Industry in the country to develop an Eco Park in its premises using Bio-Monitors/Natural Monitors as sensitive indices to check hazardous operations of the industry. This development, which has plants, fish, micro-organism, ducks, geese, pigeons, rabbits as Bio-Natural Monitors has been well acclaimed nationally and internationally. 2) DISSEMINATION OF INFORMATION, IMPROVING COMMUNICATION AND TRAINING AVENUES Training on chlorine emergency handling is imparted regularly through refresher courses for employees, Delhi fire service, Home guards and consumers. The training comprises mock drills, audio-visuals and classroom lectures. Drivers and cleaners transporting hazardous chemicals have been given exhaustive audio-visual training before taking the consignment for delivery. All around the periphery of the premises, loudspeakers have been installed to communicate to the population in the vicinity on any malfunctioning of operations and recommend steps to be taken by them. We have also started a gradual dissemination of information on our chemical products to people in our vicinity through our out-reach programmes. 3) ENERGY CONSERVATION IN THE COMPANY Energy conservation was an important component of the management philosophy in the company, right from its inception. SFFI improved its energy consumption by introducing dual concepts: a) Improvement in the thermal and thermodynamic cycle efficiency of steam and power generation

1363 b) The energy consumption efficiency in the bulk energy consuming plants like the caustic soda and vegetable oil plant. Other significant focus acres include cogeneration of steam and power, reduction of auxiliary power consumption, improving the heat transfer efficiency, waste heat recovery etc. A central energy conservation department identifies energy conservation opportunities in the various plants and each Operating Manager takes up responsibility of executing it as his thrust area. Monthly budgeting and review of energy consumption in all manufacturing operations is done and a computerized cumulative data on coal, steam and power per unit of production is circulated to the top management, thus saving fuel (as per annexure attached). The unique feature of SFFI's approach has been its policy of promoting active participation of the entire work force in energy conservation. Employees are made aware of energy significance via Quality Circles, TQM programmes, etc. The significant efforts undertaken in energy conservation have resulted in SFFI winning the first prize in the "National Energy Conservation Award" scheme of the Ministry of Power, in the chemical sub-sector in 1990, 1993, and 1995. The unit has also won the Jawahar Lal Nehru Memorial Award for excellence in Energy Conservation for the year 1994. The unit received FICCI Award for 1992 for "Environment Conservation and Pollution Control" from the Prime Minister of India. PROPOSAL IMPLEMENTED Reduction in unburnt carbon losses The two parameters to control carbon losses are proper coal sizing and blending to have uniform heating value. With almost static load conditions and for best results from traveling grate stoker type boilers, sizing of coal is of paramount importance. With improvement in crushing unit and strict monitoring of coal size, before feeding it to boiler bunkers, unburnt carbon losses are reduced by 2 - 3%. SFFI has linkage with Eastern coal Fields and central coalfields to meet its coal requirements. Both these coals when burnt separately behave differently and boiler parameters are to be changed frequently. U n b u r n t c a r b o n in refuse

This used to result in lower combustion efficiency. In order to overcome this difficulty, the company has resorted to blending of different grades of coal in a predetermined ratio so as to have ash content in the coal fed to the boilers in the range of 22+- 2%. This gave following benefits: • Uniform boiler loads

• Reduced problem of ash clinkering and protection to boiler arch refractory. These two steps of sizing and blending of coal have improved steam raising from 4.75Kg steam per Kg coal to 5.1Kg i.e 6.8% efficiency increased in boilers with an annual saving of Rs. 2.96 Crores.

Improved Combustion by Micro-Processor Based Control (MICON) To optimize combustion, it is necessary to control air fuel ratio. A programmable micro processror based system was installed with the following benefits: • Extremely flexible

1364 • Programmable control strategy • Interactive • User friendliness • Rate sensing Apart from the related advantages, the maximum benefits are derived from the coal circuit. This could be sent to: • maintain pre-set air fuel ratio • Further trimming from CO2 and 02 • Self trimming For good combustion, besides uniform coal bed thickness on boiler grate, air flow must vary along the bed. This is accomplished by dividing the grate area into a series of zones. Air from the plenum chamber below the grate is admitted to each zone through rectangular port and exact amount of air is being controlled by the dampers. With the above combustion system, the company is able to improve efficiency of boilers by about 1.3%, resulting in annual saving of the order of Rs. 55 lacs. Reduction in radiation heat losses in boilers A portable heat flow meter (called Emissimeter) is used for checking the heat loss from furnace walls, boiler walls, steam pipes etc. Before shut-down of boilers all the walls are thoroughly examined and refractory repair is undertaken accordingly. By proper maintenance of refractory, annual saving of Rs. 15 lacs were achieved. Reduction in auxiliary power load By optimizing F.D. air through auto control, its excess capacity could be utilized for providing secondary air required for over grate firing. With minor modification of ducting system the plant is able to stop four secondary air fans (2 nos. x 40KW for each boiler) with a resulting power saving of 7.20 lac KWH/annum. With decreased air input into the system, the I.D fan impellers of the boilers have been modified. With this instead of a 250 H.P motor, the plant could install a 145 H.P motor only. The above two measures have resulted in annual savings of Rs. 52 lacs. Installation of 5 MW topping turbine SFFI was earlier a pressure reducing valve (PRV) for reducing pressure from 35Kg/cm2 to 19Kg/cm2 for supply steam to Hitachi make 10 MW TG set, and another PRV to supply steam to process plant at 8.5 Kg/cm2. This has resulted in wastage of energy. SFFI installed a 5MW toppling TG set with suitable extractions which eliminated all reducing stations. The capacity of topping set was calculated considering process requirements, parameters of existing boilers and turbine manufacturers standards. An electronic governor was incorporated for control of load sharing and steam pressure. The installation of above topping TG set has resulted in an annual saving of 20,000 MT of coal, thereby a total annual saving of Rs.3.7 crores. lnlprovement

ill g e n e r a H o n i~f T G

~,ets

,t

Plate type heat exchanger for blow down heat recovery The efficiency of the generation system has been further enhanced by replacing cell and tube heat exchanger with a plate type heat exchanger for boiler blow down heat recovery. The exit

1365 temperature has been brought down from 65 - 70 deg.C to 35 - 40 deg.C. Saving on this account for a blow down flow of 18 TPH are about 1400 tonnes of coal per year which amounts to Rs.19 lacs per annum. Total condensate recovery as feed water In caustic soda plant at SFFI, a triple effect evaporation system exists, in which steam at 8.5Kg is fed to the first body of the evaporators and is recovered as hot condensate at 100deg.C. The vapours from the first body are utilized for heating in the second body and recovered as second effect condensate. Similarly vapours from the second body are utilized in the third body and recovered as third effect condensate. The first effect condensate is equivalent to the quantity of steam used and is at a temperature of 95 - 100 deg.C. This being very much consistent in its quality, was considered suitable for use as boiler feed water after conditioning with SodiumHexameta Phosphate and Hydrazine Hydrate. The first effect condensate from evaporator house is recovered in boiler feed system and used after conditioning. On-line conductivity meter with an alarm installed in water treatment plant ensures the quality. This has resulted in an annual saving of Rs. 45 lacs. Gland steam recovery from turbines The gland steam particularly from the high pressure and large sets constitute enormous heat losses. This steam is utilized for heating the condensate recovered from turbo sets through an ejector system thereby resulting an annual savings of the Rs. 22 lacs. Improvement in vacuum of turbo sets Vacuum plays a major role in the condensing turbo sets. With improvement in vacuum, the exhaust steam temperatures have reduced. The vacuum is reduced by continuously scheduling cleaning of condenser tubes, by use of a high-pressure pump, which has resulted an annual saving of Rs. 55 lacs. TABLE I SUMMARY OF MAJOR ENERGY CONSERVATION MEASURES Project Description Reduction in unbumt carbon losses Improvement in boiler combustion Improvement in boiler roof insulation Stoppage of secondary air fans and I.D fan modification Installation of 5MW topping turbo set •Plate type heat exchanger for blow down heat recovery Recovering of condensate Gland steam recovery from turbines Vacuum improvement of turbo sets

Investment (Rs. In lacs) 6 5 4 6 150

4 6

Annual Savings ( Rs. In lacs ) 296 55 15 52 370 19 45 22 55

CONCLUSIONS Corporate environmentalism in Siel has been promoted in a big way (environmentally sustainable development) in its industries. The result has been highly encouraging in improvement of quality of life within and around its units besides achieving tangible results in environment preservation and reduction in greenhouse gases. Climate change and greenhouse effects, however, are global environmental problems of gigantic dimensions and all efforts should be to solve these in a time bond programme. Attempts at Siel are a humble beginning in that direction, i.e. saving 119,000 mt of fossil fuel coal per annum, thus reducing carbon dioxide gas generation by 115,000 mt annually, a drop in the ocean.

1366 REFERENCES

1. Energy Audit Manual for Vanaspati Serial No. 2 National Productivity Council (1998). 2. Energy Management Bulletin Issue - 14 vol. IV (January- March 1993). 3. Industry Initiatives for Environmental Compatibility. A case study of Shriram Foods & Fertilisers Industries by Development- Alternatives New Delhi (March 1994). 4. Chemical Energy digest Third Quarter (1992 Sept.) Energy Awards. 5. Energy Management Bulletin Issue (July- Sept. 1996). 6. KHULLAR R.K. - Energy Conservation through efficiency improvements in Boilers and Steam Systems in a Chemical Industry. Paper presented at PHD Chamber of Commerce and Industry in (Sept. 95). 7. KHULLAR R.K. - Case studies of Innovative Practices at Siel, Delhi. Paper presented during the proceeding of Fourth Himer Symposium (1996). 8. KHULLAR R.K. - Paper presented at top level management awareness workshop under Indo EC Energy Cooperation Programme organized by EMC.

1367 ANNEXURE

SAVING OF FOSSIL FUELS IN Siel LIMITED

S, NO

9 10

11 12 13

14

PROPOSALS IMPLEMENTED

SAVING OF FOSSIL FUELS PER ANNUM (MT)

Strict monitoring of Coal size and proper blending Micro processor based air fuel control in boiler Reduction in radiation heat losses in boilers Reduction in auxiliary power load Installation of 5MW topping turbo set for substituting PR valves Installation of plate type heat exchanger for blow down heat recovery Recovery of total condensate as feed water Recovery of gland steam from turbosets Improvement in vacuum of turboset Installation of continuous/semicontinuous Deodouriser in vanaspati plant Installation of triple effect evaporator system in Caustic Soda Conversion of Diaphragm cells to Membrane cells in Caustic Soda Conversion of F.O fired boiler to F.Oil cum Hydrogen gas fired system Equivalent Coal Saved / less carbondioxide generated.

16000

REDUCTION OF CARBON DI-OXIDE GENERATION PER ANNUM(MT) 29280

3000

5490

800

1464

2800 20000

5124 36600

1400

2562

2500

4575

1200

2196

3000 8400

5490 15372

3000

5490

54000

98820

4500

8200

119000

115000

This Page Intentionally Left Blank

BIOMASS

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1371

BIOMASS ENERGY WITH GEOLOGICAL SEQUESTRATION OF CO2: TWO FOR THE PRICE OF ONE? James S. Rhodes and David W. Keith Department of Engineering and Public Policy, Carnegie Mellon University, Pittsburgh, PA, 15213, USA

ABSTRACT We explore the technical feasibility and economic implications of combining biomass energy systems with carbon capture and sequestration technology, resulting in energy products with negative net atmospheric carbon emissions. This represents an efficient strategy for biomass-based carbon mitigation and a mechanism for offsetting emissions sources elsewhere in the economy, fundamentally changing the role of biomass in achieving deep emissions reductions. We develop crude engineering-economic models of two potential systems based on IGCC and bio-ethanol technologies. The results of these models provide a basis for comparison with more conventional mitigation technologies. This comparison suggests that, depending on biomass feedstock costs, biomass technologies with carbon capture may be competitive with other mitigation options in the electric sector. Regardless of this intra-sector attractiveness, however, emissions offsets generated by biomass energy systems with CO2 sequestration are likely to be more cost effective than many direct mitigation options outside the electric sector.

INTRODUCTION Biomass has long been investigated both as a (nearly) CO2 neutral substitute for fossil fuels and as a means of offsetting industrial emissions by sequestering carbon in terrestrial ecosystems [1]. More recently the possibility of using fossil fuels without carbon emissions by CO2 capture and sequestration (CCS) has emerged as an important alternative for mitigating atmospheric emissions. Combining CCS technologies with biomass energy systems (biomass-CCS) would generate useful energy products and effectively remove CO2 from the natural carbon cycle for geologic timescales. The primary focus of CCS technology development has been to provide a mechanism to substantially reduce atmospheric carbon emissions from the current mix of fossil energy resources. This strategy's attractiveness stems from its compatibility with existing energy infrastructures. In addition, however, CCS could be integrated with biomass energy systems. In this application, atmospheric carbon- fixed in biomass during production- is captured and sequestered away from the atmosphere, resulting in a net carbon sink or negative net emissions. While it remains largely unexplored, several factors make biomass-CCS an attractive option within a portfolio of carbon mitigation strategies: (i) The net reduction in atmospheric CO2 from biomass-CCS systems provides a mechanism to offset emissions anywhere in the economy; (ii) the system would efficiently utilize limited land and water resources relative to other biomass strategies [2]; and, (iii) all of the components necessary for biomass-CCS either currently exist at large scales or are in the late stages of development for such applications.

1372 We developed a crude bottom-up engineering-economic model of one feasible, though non-optimal, biomass integrated gasification combined cycle system with CCS (BIGCC-CCS). The model is based on pre-existing component cost estimates and ASPEN simulation results [3,4,5]. In addition, we modeled capture and sequestration of CO2 fermentation off-gases (Ethanol-CCS) in a pre-existing engineering-economic model ofbio-ethanol production [6]. To compare the economics of these systems with other mitigation options, we developed a top-down energy cost model for electricity and liquid fuels as a function of carbon price.

BIOMASS-CCS MODELS The BIGCC-CCS design includes biomass gasification, syngas conditioning, carbon capture, and a gas turbine combined cycle power system. As the model is intended to illustrate near term potential rather than the current state-of-the-art, technology cost and performance assumptions are based on an 'n th' plant design and a 10-year time horizon. The model is developed from previously published ASPEN simulation results and associated component cost estimates; our efforts are restricted to integration of the component technologies. The results represent reasonable estimates of cost and performance for one feasible design. A number of design alternatives and alternative component technologies exist, but no optimization has been performed. The Battelle Columbus Laboratory / Future Energy Resource Company (BCL/FERCO) technology was selected for the biomass gasifier [3,4]. It uses steam-blown gasification and provides heat for gasification by burning residual char in a separate reaction vessel. Circulating sand provides heat transfer between the char combustion and gasification reaction vessels. Steam-blown gasification with indirect heating avoids dilution of the syngas by atmospheric nitrogen, simplifying carbon separation relative to air-blown gasification technologies. However, roughly 30% of the fuel carbon is released from the char combustor, reducing net carbon capture efficiency. This compromise might be avoided by adapting oxygen-blown gasification technologies currently used for coal. Beyond its ability to produce undiluted syngas, the BCL/FERCO system appears to have several design benefits including relatively high throughput, high energy efficiency, and low capital costs. While the technology is still in development for large-scale applications, it should be available within the time horizon of this analysis. The gasification and syngas conditioning components of the BIGCC-CCS model are based on a study of hydrogen production by Margaret Mann [3]. Modifications to the original design include: substitution of a steam dryer assembly for the rotary dryer, elimination of the PSA system, redefinition of the heat source for steam reforming, and addition of supplemental power generation from available process steam. A more recent study of the BCL/FERCO technology by Weyerhaeuser provided cost and performance parameters for the steam dryer assembly and an update for syngas composition and production rates [4]. Note that there are several alternatives to the design choices made in the current model. For example, steam reforming of higher hydrocarbons could be eliminated to reduce electricity costs (due to lower capital costs and higher net plant efficiency). However, this would reduce the carbon capture efficiency of the system, as the higher hydrocarbons pass through the system and are burned in the gas turbine. Such trade-offs between cost of electricity and net carbon emissions illustrate how carbon capture technologies will likely be determined by complex economic optimizations rather than binary choices of available technologies. The carbon capture component of the model was incorporated without modification from the study a ~" Doctor et al [5]. The core technology of this system is a wet CO2 scrubber with a glycol (Selexol ) solvent. Solvent regeneration - and CO2 de-sorption - occurs via depressurization into a series of flash tanks. The resulting CO2 streams are compressed for pipeline transport and the regenerated solvent is compressed, refrigerated and recycled to the scrubber. The process streams for integration between syngas conditioning and CO2 capture have nearly identical compositions. An additional compressor is incorporated to account for pressure differences, and a higher heat rate is assumed for the pre-scrubber heat exchanger. Finally, the gasifier and syngas conditioning systems are scaled up by a factor of two over the systems in the original study to equalize flow rate with that of the carbon capture system.

1373 The gas turbine combined cycle system is based on GE's H-class technology with performance modifications reflecting the hydrogen rich fuel gas. While this technology is currently only available at 400 MWe scale, we assume that a comparable technology will be available at 100 MW~ scale within the time horizon of this analysis [7]. The fuel gas composition is modeled by adjusting the conditioned syngas composition to reflect fractional changes in the CO2 capture system's process flow components. We include fuel gas humidification of 0.6 kg steam per kg fuel and assume net power plant conversion efficiency of 60% (LHV) [7,8]. Our economic modeling efforts include converting the component cost estimates in the original literature to year 2000 dollars, developing capital cost estimates for additional equipment, scaling the biomass gasifier and syngas conditioning costs up by a factor of 2, and estimating annual O&M costs. The installed cost of the gas turbine combined cycle system is assumed to be 550 S/kW. Transport and geological sequestration of pressurized CO2 is assumed to cost $10/tonne CO2 at the plant gate.

Bio-ethanol with CCS

We model a bio-ethanol production system with CCS based on the work by Wooley et al. [6]. The only significant modification is to incorporate compression of CO2 off-gases from the fermentation tanks. This stream represents 11% of the feedstock carbon in the baseline model. However, the content of this stream is assumed to scale with ethanol production, so more efficient processing will lead to higher carbon capture rates. We assume 13.3% carbon capture will be achievable in ten years based on published efficiency projections in the literature [6]. The net conversion efficiency of the system is not penalized for the energy requirement for COz compression because the baseline facility generates surplus electricity. Instead, the economic credit from electricity sales over the fence are reduced, though the resulting net increase in O&M costs are not significant at the level of this model. Finally, we assume a 15% energy efficiency benefit for bio-ethanol production due to potential advantages for ethanol use in spark ignition engines relative to gasoline [9]. The cost and performance results for baseline and capture models of both systems are detailed in Table 1. TABLE 1 TECHNO-ECONOMIC RESULTS FOR BASELINE AND CCS MODELS BIGCCEthanol Parameter BIGCC CCS Total Capacity (bone dr), tons / day) 1,814 1,814 2,000 141 MWe 235 ML/yr 108 MWe Total output (MWel 10° L/yr) 34% 26% 40% Net Conversion efficiency (HHV) 53% Carbon capture rate (% input carbon) $87 $200 $234 Total Capital Requirement ($M) $81 $113 $7.3 Non-Fuel O&M ($/kW-yr I $M/yr) + 0.35 ($1.33/gal) 5.87 8.88 Product Cost (c/kWh I S/L)* $128 $99 $333 Carbon Mitigation Cost ($/tC)* + Not including cost of sequestration. *Based on the energy cost model parameters defined below.

Ethanol-CCS 2,000 235 ML/yr 40% 13.3% $236 $7.3 0.36 ($1.36/gal) $243

Top-down energy cost model

We develop an energy cost model to evaluate these biomass-CCS technologies within the context of other mitigation technologies. The model evaluates the producer cost of electricity and liquid fuels for various technologies as a function of carbon price. Such a price may result from a carbon tax, a tradable permit system, or some hybrid. Mitigation costs are defined by the carbon prices where energy costs from the mitigation technologies equal those from a specific baseline technology. Pulverized coal and gasoline are

1374 defined as the baselines for the electric and transportation fuel sectors, respectively. The model includes coal and natural gas technologies with and without CCS as well as more conventional biomass IGCC and bio-ethanol technologies. Results from a single deterministic case are illustrated in Figure 1, given the fuel and technology parameters defined in Table 2 and below. Capital costs are amortized over twenty years at 10% interest. Annual O&M is defined as a fraction of total capital cost, 5% for electric sector fossil technologies, 6% for electric sector biomass technologies, and 2.75% for bio-ethanol technologies. Annual utilization is assumed to be 0.65 and 0.95 in the electric and liquid fuels sectors, respectively. Fuel costs are fixed at 1.0, 3.7, 2.7, and 7 dollars per gigajoule for coal, natural gas, biomass and gasoline, respectively. 'PC' represents pulverized coal technology, 'CIGCC' represents coal integrated gasification combined cycle technology, and 'NGCC' represents natural gas combined cycle technology. '-CCS' indicates inclusion of carbon capture technology.

TABLE 2 ENERGY COST MODEL TECHNOLOGY PARAMETERS Capital cost Technology PC CIGCC-CCS NGCC NGCC-CCS BIGCC BIGCC-CCS BioEthanol BioEthanol-CCS

($/kW) 1,200 1,560 500 1,020 1,212 1,845 1,270 1,280

Efficiency (HHV) 40% 35% 55% 47% 34% 26% 40% 40%

Carbon Capture Rate (% input Carbon) 98% 98% 53% 13%

RESULTS AND DISCUSSION According to the energy cost model results in Figure 1, natural gas without CCS dominates electric sector technologies until carbon prices near 200 dollars per ton carbon ($/tC) (note: the curve for NGCC-CCS coincides with that for CIGCC-CCS). While this is an important result, there are several reasons why the electric sector may not experience wholesale conversion to natural gas with carbon prices up to 200 $/tC. Natural gas prices may rise with increasing demand, improving the competitiveness of alternate technologies. Natural gas price uncertainty and volatility may result in technology diversification even if long-term average natural gas prices don't rise. And finally, alternate technologies may enter due to carbon emission targets below that achievable with non-CCS natural gas technology alone. While the cost of electricity from our model of BIGCC-CCS in Figure 1 is high under zero carbon price, the system's negative net emissions cause the cost of electricity to decrease with increasing carbon price. This could result from a carbon tax credit or the sale of internally generated emissions offsets, depending on the regulatory framework. The result is that the mitigation cost associated with this model is generally competitive with other electric sector technologies (128 $/tC compared to 87 $/tC for CIGCC-CCS). As carbon prices rise, BIGCC-CCS becomes the least cost electricity producer in the sector. In the extreme case, with high enough carbon prices, electricity could be generated as a free byproduct of sequestering CO2.

1375

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Carbon price ($/tC) Figure 2: Liquid fuel sector energy costs as a function of carbon price While mitigation costs in the transportation fuels sector, illustrated in Figure 2, are much higher overall than in the electric sector, adding CCS substantially reduces the mitigation cost associated with bio-ethanol. This is particularly relevant given the number of existing bio-ethanol facilitieswith CO2 vents that could easily be captured and redirected for geological sequestration. These facilities could quickly benefit from any carbon price system that recognizes the potential for negative emissions. Potentially more important than the competitive mitigation costs of either biomass-CCS system within their own sectors is their potential to generate emissions offsets for other sectors at the same costs. Top-down economic analyses suggest marginal mitigation costs rising above 1,000 $/TC to stabilize atmospheric CO2 concentrations at an equivalent doubling of pre-industrial levels [ 10]. By crediting negative emissions from biomass-CCS technologies to sources that are expensive to mitigate directly, mitigation costs could be capped across the economy, given sufficient biomass supply. While the dollar value of this mitigation cost cap cannot be determined with confidence--because it will scale with the cost of biomass--the ability to offset emissions anywhere in the economy fundamentally changes the potential role of biomass for achieving deep carbon emissions reductions.

1376 ACKNOWLEDGEMENTS

We gratefully acknowledge thoughtful comments on this work from Michael Griffin, Gregg Marland, Allen Robinson, and Edward Rubin. This research was made possible through support from the Center for Integrated Study of the Human Dimensions of Global Change. This Center has been created through a cooperative agreement between the National Science Foundation (SBR-9521914) and Carnegie Mellon University, and has been generously supported by additional grants from the Electric Power Research Institute, the ExxonMobil Corporation, and the American Petroleum Institute.

REFERENCES

1.

Kheshgi, H.S., Price, R.C. and Marland, G. (2000). The Potential of Biomass Fuels in the Context of Global Climate Change: Focus on Transportation Fuels. Annual Review of Energy and the Environment. 25: pp. 199-244. 2. Keith, D.W., (2001). Sinks, Energy Crops, and Land Use: Coherent Climate Policy Demands an Integrated Analysis of Biomass. Climatic Change. 49: p. 1-10. 3. Mann, M.K. (1995). Technical and Economic Assessment of Producing Hydrogen by Reforming Syngas from the Battelle Indirectly Heated Biomass Gasifier. National Renewable Energy Laboratory. 4. Weyerhaeuser, (2000). Biomass Gasification Combined Cycle DE-FC36-96G010173. United States Department of Energy. 5. Doctor, R.D., J.C. Molburg and Thimmapuam, P.R., (1996). KRW Oxygen-Blown Gasification Combined Cycle: Carbon Dioxide Recovery, Transport, and Disposal. United States Department of Energy. 6. Wooley, R., Ruth, M., Sheehan, J., Ibsen, K., Majdeski, H., and Galvez, A. (1999). Lignocellulosic Biomass to Ethanol Process Design and Economics Utilizing Co-Current Dilute Acid Prehydrolysis and Enzymatic Hydrolysis Current and Future Scenarios. National Renewable Energy Laboratory. 7. Matta, R.K., Mercer, G.D., and Tuthill, R.S. (2000). Power systems for the 21st Century- "H" Gas Turbine Combined-Cycles. GE Power Systems. Schenectady, NY. 8. Audus, H., and Jackson, A.J.B. (2001). C02 Abatement by the Combustion of H2-Rich Fuels in Gas Turbines. In: Proceedings of the 5th International Conference on Greenhouse Gas Control Technologies. Williams, D., et al. (Eds). CSIRO Publishing: Collingwood, Australia. 9. Wymann, C.E. (1996). Handbook on Bioethanol: Production and Utilization. Taylor and Francis: Washington, D.C. 10. Metz, B., et al., (Eds). Climate Change 2001: Mitigation: Contribution of Working Group III to the Third Assessment Report of the IPCC. 2001, Cambridge University Press: Cambridge, UK.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1377

MODELLING BIO-ENERGY WITH CARBON STORAGE (BECS) IN A MULTI-REGION VERSION OF FLAMES P. Read ~, J. Lermit ~ and P. Kathirgamanathan 2 1Sustainable Resource Use Modelling Project, Victoria University, Wellington, NZ. 2Institute of Fundamental Sciences, Massey University, Palmerston North, NZ.

ABSTRACT

Global FLAMES [ 1,2] demonstrates the potential of the combined evolution of the stock and flow effects from temporary sequestration and subsequent fossil fuel displacement due to plantation based bio-energy, in reducing greenhouse gas levels below those widely thought to be feasible [3]. This surprising effectiveness can be further enhanced by linking plantation bio-energy to carbon capture and storage [4]. Such 'BECS' technology yields, potentially, a negative emissions energy system and control of CO2 levels on a few decade time-scale. The effect of BECS is illustrated using global FLAMES. To provide relevance to country level scenario building and decision taking, FLAMES has been developed [5] into a multi-region dynamic market model simulating trade in fossil fuel, biofuel, and timber products. Results are illustrated in the case of three notional regions, 'rich', 'landed' and 'popet' (populous with petroleum)- broadly equivalent to the 'North', South Sahara Africa with Southern America, and Asia plus OPEC Introduction

This paper reports on work in progress in a model that simulates the main market impacts that arise from policy driven land allocations to two plantation activities. These are long rotations, which initially sequestrate carbon prior to later use of woody biomass as joint product timber and bio-energy raw material, and short rotations that lead to a larger proportion of bio-energy raw material in the joint product, with minimal sequestration over the short rotation. A key role is played by exogenous representation of technological advances, including with plantation productivity. This work builds on the previous development of the FLAMES model that simulates global (1-region) interactions in the markets for land, fuel and timber under the impact of model-user-selected allocations of land to the two activities. This paper explains the motivation for the further development of FLAMES and reports preliminary results. Motivation

The long rotation activity creates a 'buffer stock' of carbon that can be used to decouple reductions of carbon in atmosphere (Cat) from change in the energy sector, cutting premature obsolescence c o s t s "stranded assets"- inherent in other urgent programmes of Cat reductions (whilst not diminishing the role of cost effective progress with renewable energy and energy efficiency). The potency of this low cost approach enables a return towards pre-industrial levels of Cat over half a century in a way that remains compatible with existing carbon-fuel-based infrastructure. A n d - should science eventually demonstrate that there is no need for concern in relation to Cat- it carries the option of maximising timber output (with bio-diversity benefits in terms of reduced 'mining' of natural forest timber reserves). To provide policy relevant output to facilitate the realisation of this potential, the earlier global FLAMES model has been developed to a multi-region version with trade, generating world and regional prices for fossil and biofuels and timber to support land allocation decisions at the national level. Urgency arises potentially on account of concern for Abrupt Climate Change [6] the possibility of which "haunts the problem" [7] and provides the economic rationale for action by the developed countries - which are largely sheltered from the economic impacts of gradual climate change [8]. Obersteiner et al [4] suggest

1378 that BECS technology can provide a 'real option' in a risk management approach to such climate threats. Accordingly, FLAMES has been applied to a preliminary analysis of the potential for rapid response to a few decade time-scale Abrupt Climate Change. Furthermore it is argued [9] that a low cost 'buffer stock' approach to the FCCC Art 3.3 commitment to early action in response to threats of severe or irreversible damage may provide a basis for rapprochement between Kyoto Protocol Parties and other Annex 1 Parties.

Order of magnitude Assuming 500GJ/Ha is produced over 500mHa globally by 2030, i.e. using half of the usable land described by the FAO as surplus to agricultural needs, then there is a supply of 250EJ annually which, with 50per cent efficient conversion, can displace 200EJ of crude oil (assumed five eighths transportation fuel fractions) annually. By 2100 14,000EJ of oil is displaced, equivalent to about 2.4 billions of millions of barrels, more than twice global proved reserves and renewable each century- plausibly sufficient to keep pace with rising demands for transportation fuels given continuing increases in plantation productivity and vehicle efficiency (e.g. with fuel cells and bio-methanol as hydrogen carrier). Regardless of Cat considerations, there would seem to be a significant case on security of supply grounds for growing fuel as well as drilling for it. Caveats The results generated by the FLAMES model are the direct outcome of the assumptions made in the baseline or reference scenarios and of the quantities of land allocated to policy-desired uses. Three baselines have been simulated: first, 'business as usual' (b.a.u., reflecting a median IS92 no policy scenario); second, 'fossil free energy scenario' (f.f.e.s., reflecting the Tellus Institute's 1993 study funded by Greenpeace ); and third, 'Kyoto' (broadly half way between the first two). Both the first two embody rather little land use change or bio-energy and the third reflects the view that the Kyoto Protocol approach to gradual climate change is unlikely to achieve Cat stability - let alone reductions - during this century. It should be noted that, although the focus of the FLAMES model is on the additional impact of policy driven land allocations, the surprisingly low Cat levels noted previously (see above) that result from large scale land allocations are only reached with the simultaneous application of the low and zero emissions energy technologies involved in the f.f.e.s.: in other words, the large scale policy-driven land use allocations illustrated in this paper are a necessary but not sufficient condition for the achievement of the low Cat levels mentioned above. By the same token, for the below pre-industrial Cat levels illustrated in this paper, large scale negative emissions, through widespread application of BECS technology, is a necessary but not sufficient condition. Additionally, it should be noted that the very large land allocations that have been used in the FLAMES model are taken to be 'maximal'. No decision taken this decade can finally determine land allocations some decades ahead and the implication of modelling large allocations at such a time is that the initial phases of the programme are successful in meeting socio-economic and environmental constraints and hence stimulating - or at least not inhibiting - the sequence of decisions that is represented by such a maximal programme. Thus such maximal allocations are a representation of the maximum amount of land that might be used for policy-desirable activities if the appropriate incentives were put in place, and sustained, to reward current landlords and land users so as to ensure they engage continuingly in such policy-desirable land use. Implicitly it is assumed that they desist from current land-profligate slash and burn subsistence, nomadic herding, forest clearance, etc., investing their rewards so as to meet their food and other land based needs better than at present, and more sustainably. Conceptually the modelled allocations are intended to represent the maximum possible policy-induced effect, constituting a 'flip' in the trend of land use change and the following of a new path, starting from a near-future bifurcation in the evolution of land use policy and technology towards stewardship rather than exploitation. And, implicitly, no degree of policy urgency can accelerate land use allocations defined as maximal: if pushed too fast ~then disaffected communities will simply set fire to the plantations. This is not to claim that the land allocations modelled here are empirically maximal in this sense: if a better estimate of what is maximal can be made, then that estimate should replace the pattern modelled here.

Methodology of FLAMES and N-region FLAMES Investigation of market impacts in the context of ongoing technological transition (which is inconsistent with competitive general equilibrium) is most transparent within a demand and supply framework. Three

1379 markets - for fuel (with perfectly substitutable bio-fuel and fossil fuel), for timber products and for land are simulated at a high level of aggregation, as three simultaneous equations in four variables, producer prices for fossil fuel, bio-fuel, and timber, and the opportunity cost of land (rent). Output from the two policy-driven plantation activities is determined by plantings one rotation earlier and allocated to jointproducts timber and bio-fuel as a function of their relative price and of the rotation length, with a rapid transition from maximum timber to nil timber near a price difference that represents the cost of processing to timber products. Closure is by a fourth equation for a tax on fossil fuel CO2 emissions (equal to the difference in producer prices for fossil and bio-fuel) that is dedicated to financing the excess cost of biofuel over fossil fuel (including rent). In the multi-region (N-region) case, additional export demands arise for fossil and bio-fuel, and for timber products, proportional to differences between regional and world prices, with the latter determined in a set of trade balance equations setting total exports equal to total imports. A fossil fuel tax is set globally to cover global policy costs and a transfer equation for each region determines the additional subsidy from importing to exporting countries needed to compensate for 'profit taking at sea' (the 'law of one price' does not apply). A final equation, currently independent but capable of including CO2 fertilisation effects and, if so, requiring simultaneous solution with the other 4N+41, simulates the impact on Cat, under the chosen reference scenario, of emission and absorption in the energy, forest product and land use sectors, and in the oceans, as the consequence of user selected (or policy-driven) land allocations to the two activities. In the market equations, per capita demands for fuel, timber products and farmland grow exponentially (but could be driven by an economic growth model) and are inhibited by the fossil fuel tax. Under b.a.u., supplies of fossil fuel grow to match demand but emissions grow more slowly in order to represent increased energy efficiency and use of non-fuel energy sources. Under f.f.e.s., there is accelerated technological progress (TP) in these a r e a s - and correspondingly slower TP with 'discouraged' fossil fuel. Reference case supplies of woody biomass are derived from harvesting an area of managed forest that is distinguished from conservation forest, which is treated as unavailable for exploitation. Both these supplies and supplies from policy driven land allocations provide timber and bio-fuel raw material as joint products, with the proportions dependant on relative prices at the time of felling, and on rotation length. Long rotation forestry technology is treated as 'mature', with zero TP, while short rotation productivity rises threefold over 70 years, eventually reaching current achieved results in experimental plots in Brazil. Supplies of exploitable land represent all land that is not barren or conservation forest and rents rise as the reciprocal of the area left to wilderness, after meeting demands for farming, for managed forest and for policy-driven activities. For a detailed description of the 1-region model, see Read (1999). Parameters in the market equations are initialised to a broad representation of current conditions and then shifted over time at user-selected rates to achieve a broad match with the time-path of Cat in the chosen reference scenario. Then the impact of user-selected land allocations (see Figure 1, top panel) to, first, a time-path of short rotation plantations and, second, the same pattern of short rotation plantations but preceded by a time-path of long rotation plantations, is superposed on the reference case (with a userspecified responsive reduction in conventional forestry). Model outputs are generated as the time-paths for Cat (see Figure 1, bottom panel) and for the various prices in the model (see Fig 2).

BECS and precautionary policy It is envisaged that BECS technology would be mobilised in response to bad scientific news regarding near term risks of precipitating an Abrupt Climate Change event as a consequence of continued elevated Cat levels. Global-FLAMES may be used to assess the effectiveness of BECS (with other measures- see caveat above) under a 'game with nature' framework in which policy is assumed to be either 'Kyoto' or 'Precautionary' and nature to be 'Nice or Horrid' hence yielding a regret matrix [KN, KH; PN, PH] 2. 'H' is taken to correspond to bad news in, say, 20 years time (i.e. 15 years after the initiation of globally coordinated precautionary policy) and 'P' to measures extra to 'K', taken prior to the bad news, specifically, t Three market equations plus a transfer equation for each region, three world price equations plus the global tax equation. 2Unfortunatelythe lap-top on which that work was done was stolen during preparation of this paper. Graphicalresults that had been transmitted to a colleague and are displayed in Fig 1 cannot at present be reproduced, as the coding was not transmitted at the same time. At the time of the theft, the KH case had yet to be modelled.

1380 a learning-by-doing programme with carbon capture and storage technology (CCS) applied to fossil fuels, and a human capital development-cum-plantation programme in line with the short plus long rotation plantations described above. Under PH, the decade after bad news is devoted to a crash programme of converting long rotations land to short rotations, accelerating technological progress with non-fuel energy and efficiency in line with the f.f.e.s, scenario, and applying CCS to both fossil fuels and to bio-fuels. Under KH the same crash programme is attempted but without the benefit of experience with CCS technology from 2005 to 2020, or of low cost pre 2020 Cat reductions, or of ready availability of plantation land in 2020, all arising from the precautionary policy measures.

Technical Progress All scenarios are developed from the same initial conditions, with 300EJ of final global demand for fuel supplied by raw fossil fuel at 2$/GJ, 2.5Gtons timber supplied at 1505 per ton and 1.9Gha of food-land having an opportunity cost of 10S/Ha 3. Different scenarios arise as the consequence of different exogenously imposed rates of technological progress that yield neutral price shifts over the time horizon under b.a.u., (in line with broad historic experience save for the 1970's oil price hikes). Thus technological progress embodied in capacity expansion broadly keeps pace with demand growth under b.a.u., for which final per capita fuel demand is assumed to grow at 3.5%p.a. and emissions at 1.5%p.a. (where the difference represents decarbonisation of energy due to increased end use efficiency, renewables and fuel switching). Under f.f.e.s., policy signals induce two effects on TP: firstly investment in fossil fuel R&D is discouraged so that fossil fuel expansion falls to 2%p.a. and secondly accelerated technological progress in decarbonisation occurs over the second and third decades modelled. Consequently fossil fuel prices initially rise due to reduced supply but eventually fall due to more-reduced demand. Over the remaining four decades modelled TP with decarbonisation slows so that aggregate TP at the time horizon is the same as under b.a.u.- this represents an assumed physical limit in TP in relation to, for instance, thermal efficiency. In relation to land use, where policy induced change occurs, the productivity of long rotations (an old technology) is assumed constant at 6 oven dry tons/Ha-yr while the productivity of short rotations rises from 12 o.d.t/Ha-yr to 36 o.d.t/Ha-yr over the 70 year time horizon.

Results Outcomes are illustrated in Figures 1 and 2. Figure 1 shows land allocations proposed and the resulting Cat effects, for three reference scenarios (b.a.u., f.f.e.s, and 'Kyoto' and for the 'Precautionary' scenario first with no ACC and second with response to bad news in 2020 (i.e. the PH scenario). Figure 2 illustrates market price movements in fossil and bio-fuel prices, in timber prices and land rents under policy-driven land allocations to both biofuel and a long rotation buffer stock (i.e. the PH scenario).

Comments and further research The outcome of the PH scenario, as illustrated in Figure 1 suggests that a return to below pre-industrial Cat levels by 2050 is, if necessary, feasible given that appropriate precautionary measures are undertaken. Clearly there is a need to model the KH case (i.e. the consequences of maximal land use change and other aspects of the precautionary policy initiated only after news of ACC becomes available) and the costs of policy under the alternative scenarios, along with recoding of the PH case to enable repetition of current results (and estimation of policy costs). Prior to this work there is a need to achieve more realistic analysis of landowner behaviour in response to price expectations illustrated in Figure 2: clearly the prospect of sharp price drops as the long rotation approaches maturity will induce a profit maximising land-owner to fell early. Whatever policy may induce the establishment of these plantations can hardly determine the behaviour of landowners exposed to commercial discount rates a generation later. Thus an incentive-compatible version of FLAMES is currently under development to provide a more realistic picture of the long-term Cat impacts of policy driven land 3 In the 3-regionmodel, these initial values are the worldprices, with regionalprices for Rich, Landed and Popet [2.5, 3, 1.5] and exports [, , ] for fossil fuel and [0,0,0] for biofuel, and with regionalprices [180, 150, 1??] and exports [ , 0, ] for timber. These initial values yield trade coefficientsfor fuels and for timber in the three regions as exports/(world- regionalprice), with the coefficients for fossil and bio-fuel assumed equal.

1381

allocations. In the long run it is envisaged this model m a y reveal the optimal p a t t e m o f land allocations in relation to a risk-averse precautionary policy criterion focused on ACC. REFERENCES 1. IPCC, 2000a. "Land Use, Land Use Change and Forestry", C.U.P., 277-280 2. Read, 1998. "Dynamic Interaction of Short Rotation Forestry and Conventional Forestry in Meeting Demand for Bioenergy", Biomass and Bioenergy, 15. 3. IPCC, 2000. "Special Report on Emissions Scenarios (SRES): A Special Report of Working Group III of the Intergovernmental Panel on Climate Change", C.U.P. 4. Obersteiner, M., C. Azar, P. Kauppi, M. Mollerstem, J. Moreira, S. Nilsson, P. Read, K. Riahi, B. Schlamadinger, Y. Yamagata, J.Yan, and J.-P. van Ypersele, 2001. "Managing Climate Risk", Science 294, (5543): 786b. 5. Korobeinikov, A., P. Read, J. Lermit, A. Parshotam and P.Kathirgamanathan, 2001. "Market dynamics of allocating land to biofuel and forest sinks", in Proc. International Congress on Modelling and Simulation MODSIM, 2001, Volume 3, 1079-1084, Canberra, 2001. 6. National Academy of Science, 2001. "Abrupt Climate Change:Inevitable Surprises", N.A.Press, DC. 7. IPCC, 200 l_"Third Assessment Report, Contribution of Working Group III." C.U.P. (Sec. 10.1.2.4.) 8. Schelling. T.C., 1992. "Some Economics of Global Warming", AER, 1-14. 9. Read, P., 1999. "The Role of Biomass in Meeting Greenhouse Gas Reduction Targts: Land Allocation Modeling of Key Market Impacts". Discussion Paper 99.16, Department of Applied and International Economics, Massey University, Palmerston North. 10. Read, P., 2002. "Precautionary climate policy and the somewhat flawed protocol: linking sinks to biofuel and the CDM to the Convention", Climate Policy 2/1, 89-95. Figure 1" C a r b o n in a t m o s p h e r e u n d e r p o l i c y r e s p o n s e to state o f n a t u r e

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1383

A LIFE CYCLE ANALYSIS OF BIOMASS E N E R G Y SYSTEM TAKING SUSTAINABLE FOREST M A N A G E M E N T INTO CONSIDERATION Kiyoshi Dowaki I Shunsuke Moril, Hitofumi Abe 2, Pauline F. Grierson 2, Mark A. Adams 2, ' Nalish Sam 3 and Patrick Nimiago 3 1 Department of Industrial Administration, Faculty of Science and Technology, Tokyo University of Science, Yamazaki 2641, Noda-shi, Chiba 278-8510, Japan 2 Ecosystem Research Group, Department of Botany, The University of Western Australia, Nedlands, WA 6907, Australia 3 Papua New Guinea Forest Research Institute, P. O. Box 314, Lae, Papua New Guinea

ABSTRACT

In this paper, we evaluated life cycle C02 (LCCO2) emissions by comparing biomass power plants with a coal power plant of the CO2 removal system. For the concrete investigation of the biomass life cycle analysis (LCA), we selected the reforestation sites in Eastern Highland Province and Madang Province in Papua New Guinea (PNG) as model areas. Then, Casuarina oligodon (C. oligodon) and Eucalyptus deglupta (E. deglupta), which are fast growing trees, were adopted as biomass materials. Especially, C. oligodon has the characteristics of nitrogen fixation from air. As the result, nitrogen fixation to soils is expected to mitigate LCCO2 emissions and direct and indirect energy input in the biomass LCA. The biomass energy system consists of two subsystems, the cultivation process and the energy conversion process. In the cultivation process, we constructed the nutrient circulation model in reforestation area. Nutrients losses by soil erosion are evaluated in this process. In this study, it is assumed that their nutrients are newly supplemented for the purpose of considering the sustainable forest management, and that they are equivalent to chemical fertilizer. In the energy conversion process, we design the Biomass Integrated Gasification Combined Cycle (BIGCC) in PNG In this study, it is assumed that the plant scale is approximately 59 or 110 MW. Especially, using the basic experimental chemical data, we calculate the performance of gasification. Consequently, we estimated that LCCO2 emissions of BIGCC are 4.4 to 107.2 g-COJkWh (E. deglupta) and 2.1 to 63.5 g-COz/kW~h(C. oligodon), while that of Coal-IGCC with CO2 removal equipment is 50.5 g-COz/kWh. INTRODUCTION

This article aims at estimating energy balance ratio (E.B.R.) and LCCO2 from a biomass energy system. Although there have been many analyses conceming the biomass LCA [1,2,3], this analysis has following differences from previous studies: • • •

In recent studies, the biomass potentialities of timber volume in the world are being estimated by using the data of the Food and Agriculture Organization (FAO). However in this study, energy balance ratio and LCCO2 emissions are evaluated by data that are surveyed in PNG~ The basic experiments concerning the biomass gasification are carried out by using the biomass in PNG. Then using the data of each experiment, we design the BIGCC plant and simulated the plant efficiency. Finally, the biomass LCA in this study estimated E.B.R. and LCCO2 emissions with consideration of nutrients circulation and basic chemical experiments concerning the local materials. Furthermore, we acquired the local data concerning nutrients concentration in soil etc. that are measured respectively in PNG

CONCEPT OF THE BIOMASS LCA

Firstly, we have to determine the system boundary in the biomass LCA. The definition of the system boundary follows a definition ofDowaki et al [8].

1384 The biomass energy system consists of the two subsystems, the cultivation process (Process 1) and the energy conversion process (Process 2). In the cultivation process, we investigated the characteristics of E. deglupta and the feasibility of the sustainable reforestation management with Western University of Australia and PNG Forest Research Institute. On the other hand, the characteristics of C. oligodon referred to the related papers [ 16,17,18]. Then energy input and LCCO2 emissions concerning establishment, harvesting, transportation and machines are estimated in this process. Furthermore, nutrients losses by soil erosion are also taken into consideration. Namely, it is assumed that they are newly supplemented and that they are equivalent to fertilizer. Next, it is assumed that the case of both E. deglupta and C. oligodon of a reforestation area, is 20,160 ha, that is, the cultivation area per year is 2,880 haJy and that the terrain gradient is from 0 to 10 degrees. By taking the present circumstances in PNG into consideration, we can presume that the maximum reforestation area come to be approximately 20,000 ha. In the energy conversion process, we design the IGCC for E. deglupta or C. oligodon in PNG The plant scale is approximately 59 or 110 MW. The gasifier is an air-blown pressurized fluidized-bed type. The gas turbine such as LM2500PH made by General Electric Company (GE), which permit the operation on low calorific fuel such as biogas [4]. Then, a curie point pyrolizer (Japan Analytical Ind., Model JHP-22) and a thermogravimetric analyzer (Shimadzu, Model TGA-51) acquire the basic data of the gasification. Using the basic data of each experiment respectively, we calculate the performance of gasification. Finally, we evaluate energy input and LCCO2 emissions of the biomass energy system, using input-output analysis [5]. CULTIVATION PROCESS (PROCESS 1) Surveying Biomass in PNG In the cultivation process, energy input and LCCO2 emissions of a biomass are estimated with consideration of sustainable management in the plantation. Firstly, some field works are implemented at the trial site. In the field survey, the characteristics of climate, soil and E. deglupta are monitored. This study was based at Wasab forest plantation, about 40km north of Madang town (4052 , S, 145°44'E). the PNG Forest Authority manage the plantation but the land is owned by local people. The total plantation area at Wasab is about 300 ha and supplies logs for sawn timber and wood chips. E. deglupta and Acacia mangium (A. mangium) are the main planted species. Because of an increased demand for wood chips in recent years, plantations have been predominantly A. mangium but it is planned that E. deglupta be planted more widely in 2002 (Binensis, personal communication). The plantation is 40-100 m above sea level and several kilometres from the coast. Climatic data is available for Madang township where the mean annual rainfall is 3518 mm, with at least >128 mm falling in the driest month. The mean temperature is 26.5 °C and the difference between the average temperature of the coolest and warmest month is only 0.5 °C. The soil of the area is loam at the surface but with heavy clay at depth (Cambisol). The pH range is 6.0-7.0. If we assume that cultivation period is 7 years, the average yields of E. deglupta and C. oligodon are estimated approximately 9.2 t/ha.y and 29.5 t/ha. y by taking timber volume, spacing and survival rate into consideration [6,7]. Nutrients Circulation Model In this biomass LCA, we should take nutrients circulation into account in evaluating energy balance ratio and LCCO2 emissions. In order to actualize the sustainable forest management by reforesting, it is necessary to make up for the lost nutrients. This is reason we must think over energy input and LCCO2 emissions concerning the lost nutrients in the biomass LCA. In particular, the main nutrients such as N, P2Os and K20 are essential for growing. In this study, the balance of these elements is estimated, based on the nutrients circulation model (Figure 1). In this case, the quantity of soil loss is determined by the next Eqn. 1 of Universal Soil Loss Equation (USLE) [8,9,10,11].

A=RKLSC A: Soil erosion per hectare ~t/ha] R: Rainfall runoff factor [m • tf/ha, h] K: Soil eroding factor [t" h / m 2" tf] L: Slope length factor [-] S: Incline factor [-] C: Cover and management factor [-] P: Support practice factor [-]

(1)

1385

|

Ferti]izatbn at seedliag [ |

Soilat seedling Raw ~! ateri~ls Liru N ittogen Fixatbn

P hntatbn Soil ~arget depth ~"-lOcm ) ~> c=~

~qutr~nt 0 utput ~ utri~nt hput F vaporatbn

Soilerosbn River runoff

Figure l" Nutrients circulation model The each factor has already been determined experimentally (Table 1). TABLE 1 SET-VALUES OF EACH COEFFICIENT OF USE R [m2" tf/ha" h] K [t" h/m :" tf] LS[-]

Set-values E. deglupta: 147.2, C. oligodon:82.2 0.37 0.09-6.84

P[-]

0.5-0.8

C[-]

E. deglupta:0.00-0.92,C, oligodon:0.00-0.98

From the results, we can estimate that soil loss during one cycle (7 years) is 4.7 to 486.7 t/ha in the case of E. deglupta, and is 3.8 to 399.6 t/ha in the case of C. oligodon. In this study, by multiplying nutrients concentrations by the values (soil loss, timber loss and evaporation etc.) in each section, net nutrients loss in the whole system can be evaluated [ 12,13]. Judging from the above estimations, the following results can be obtained. At the beginning, Table 2 shows direct and indirect energy input and LCCO2 emissions in each chemical fertilizer. Furthermore, the forestry work in the plantation are taken in consideration in consists of establishment, cultural management activities (fertilizers, pesticides, equipment), harvesting and transportation. The design of each work in the plantation should be determined from the energy resource supply conditions in the site. TABLE 2 LCA INDEX IN CHEMICAL FERTILIZER N P205 K20

Energy Input [MJ/kg] 121.6 16.3 25.5

LCCO2 [kg-CO2/kg] 5.67 0.88 1.85

In this study, it is assumed that the working hour of the machines on each task in the plantation is 8 h/d and the working day per year is 180 d/y [13]. Finally, undergrowth and other species will fix carbon directly during a planting period [ 19]. We can estimate that direct COE emissions are 21.7 t-CO2/ha in the case of E. deglupta and 25.7 t-CO2/ha in the case of C. ologodon, respectively. As a result, direct and indirect energy input and LCCOE emissions can be evaluated, and it is 66.1 to 435.7 GJ/ha'y and 0.4 to 17.5 t-CO2daa'y in the case of E. deglupta, and is 78.0 to 372.2 GJ/ha" y and 0.1 to 14.1 t-CO2/ha" y in the case of C. ologodon, respectively. However, fixation of air nitrogen (116 kg-N/ha- y) is taken into consideration in the case of C. oligodon [ 18].

1386

ENERGY CONVERSION PROCESS (PROCESS 2)

Summary of BIGCC Integrated Gasification Combined Cycles (IGCC) have been developed and demonstrated for fossil fuels as feedstock. Furthermore, the BIGCC in Europe have been developed since 1991 [14]. Based on the Europe circumstances, we design BIGCC in this study as Figure 2. A higher electrical efficiency can be expected in BIGCC system than the direct combustion system. In this study, we examine two subjects as follows: • Performance of an air-blown pressurized fluidized-bed gasifier. The performance of an air-blown pressurized bed-bed gasifier is simulated using the basic experiments concerning gasification. • Calculation of the system efficiency in BIGCC. We calculate the system efficiency, using the performance data concerning the gasifier, the gas turbine, the steam turbine and so on.

FuelGa~ __--W-~-Gas-~Stick

ProductGas

[__~~ pressurized[ Feed stock i Gasifire I

.... ~IHeatRecovery

I "I ,

I,[ He'atRecovery ~s ~-~SteamGenerator ~me I I (HRSG)

clone

Wet-type Scrubber

E1 ieity I

l

NHa Figure 2: Image of BIGCC Plant

Drying the chipped materials In this study, it is assumed that the lkg dryness capability of E. deglupta and C. oligodon in the outdoors is the same each. Namely, the feed material ofE. deglupta is dried from 62.6 % (wet-base) to 38.9 % (wet-base) and that of C.oligodon is dried from 43.7 % to 20.0 %. Of course the drying period on the material depends on the air temperature and the relative humidity in PNCt If we will design this system in detail, we need to examine the drying velocity experimentally on basis of the climatic condition. Thus, in the case that the cultivation area per year is 2,880 ha/y, and that the operation hour in the plant is 6,000 h/y, the feed weight become 35.6 t/h by the case ofE. deglupta, and become 69.6 t/h by case of C. oligodon.

Performance of an Air-blown Pressurized Fluidized-bed Gasifier In general, it is assumed that pyrolysis, combustion and gasification occur in the gasifier. Furthermore, in this study, shift, CH4 reforming and NH3 synthesis reactions are also taken into consideration. The data on the pyrolysis and the gasification are acquired by the basic experiments. The products of pyrolysis are gases, liquids (tars) and solids (char). These yields depend on the experimental conditions, especially temperature and heating rate [15]. The experiment on the pyrolysis is carried out by a curie point pyrolizer (Japan Analytical Ind., Model JHP-22) and a gas chromatograph (Shimadzu, Model GC-8A). The primary pyrolysis reactions occur in a curie point pyrolizer and the yields of gases are analyzed by a gas chromatograph. One to two mg of the samples are heated rapidly (heating rate >1,000 K/s) from 596 to 1,040-°C in an argon atmosphere and are kept at the temperature for 10-20 s in the pyrolizer. Table 3 shows the physico-chemical characteristics of E. deglupta and C.oligodon. If tar is not produced and oxygen is consumed completely by combustion in the gasifier, the only three components of H2, CO and CH4 are estimated by the first order model [14]. Next, the experiment on the gasification is carried out by a thermogravimetric analyzer (Shimadzu, Model TGA-51). The char gasification using H20 and CO2 is the slowest reaction velocity among reactions in the gasifier. Thus, we examine the reaction velocity concerning the gasification. Firstly, a sample of about 20 mg is heated in a nitrogen atmosphere at a design temperature. Then char is produced in the furnace. Each design temperature in this experiment is 950, 1000, 1050 and 1100 °C. Secondly, the gasification occurs in the furnace temperature, which is in each design temperature. Char mass

1387 decreases by reacting with H20 (25vo1.%) and CO2 (65vo1.%). The variation rate X in each temperature is measured by the analyzer. The results of pyrolysis experiments and gasification experiments of char are shown in Table 4 here. Using the above experimental data, we evaluated BIGCC plant performance as Table 5. TABLE 3 PHYSICO-CHEMICAL CHARACTERISTICS

c [wt.%]" H [wt.%]*

o [wt.%]" S [wt.%]* N [wt.%]* Ash [wt.%]* Water Content [wt.%] Bulk Density [kg/m ~] Heating Value [kJ/kg]" *Dry-basis

E. deglupta 48.8 6.28 44.1 >0.1 0.16 0.63 38.9 380 25,900

C. oligodon 48.2 6.21 45.0 >0.1 0.15 0.35 20.0 780 19,600

TABLE 4 THE RESULTS OF PYROLYSIS AND GASIFICATION OF CHAR E. deglupta 1.41 3.86 0.87

H2 [mol/kg]" CO [mol/kg]* CH4 [mol/kg]* Gasification velocity IS-1]

dX= dt

1459ex/~-~-~) D-X)~

C. oligodon 2.74 2.68 1.82 dX

77701ex~-~/O-X~

*Yields of pyrolysis at 750°C TABLE 5 PERFORMANCEOF BIGCC Cold-gas eft. [%-LHV] Auxiliary[%] Net-Generating eff. [%-LHV] Annual Power [GWh/year]

E. deglupta 68.7 7.8 41.9 353.5

C. oligodon 64.0 16.3 40.0 655.1

LIFE CYCLE ANALYSIS IN A BIOMASS ENERGY SYSTEM This section deals with the above mentioned results on energy input and LCCO2 emissions in the two subsystems (Process 1 and Process 2). We evaluate energy balance ratio and LCCO2 emissions concerning the case of coal and biomass cases. Figure 3 shows the estimation results of E.B.R. and LCCO2 emissions. These results imply the following conclusions. First of all, energy balance ratio of a biomass system is lower than that of a coal power system. However LCCO2 of the biomass is smaller than the coal. Next, in the case of the biomass, energy balance ratio and LCCO2get worse as terrain degree increases. Finally, as Figure 3 indicates, an improvement of LCA index is found. For instance, about LCCOz emissions, it is 3.8 to 106.6 g-COz/kVvqain the case of E. deglupta, and on the other hand, is 1.3 to 62.8 g-COz/k'Whin the case of C. oligodon. Furthermore, although LCCO2emissions in the case of coal with CO2 removal equipment is 50.5 g-COz/k~Vh,if construction cost of the equipment is taken into consideration, that of the biomass will be superior generally.

1388 Consequently, nitrogen fixation of air, that is, selection of C. oligodon, has good influence on sustainable forest management. 20.00

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Figure 3: The estimation results of E.B.R. and LCCO2 emissions CONCLUSIONS

On the basis of this study it can be concluded that the biomass energy system, for example BIGCC system, can actualize the sequestration of CO/, that the improvement of the sequestration will be better by selecting C. oligodon, and that the system will be promising for developing countries as an environmentally friendly system or an alternative system to the fossil fuels in the future. As a future research subject, the continuous investigation about timber volume or nutrients circulation etc. in consideration of compound reforestation of C. oligodon will be important. REFERENCES Yamamoto, H., Yamaji, K. and Fujino, J. (1998) Energy Resources 19 2, 60. Thrhollow, A. E and Perlack, R. D. (1991) Biomass and Bioenergy 1 3, 129. Hanegraaf, M. C., Biewinga, E. E. and Bijl Ct V. D. (1998) Biomass and Bioenergy 15 4/5,345. Neilson, C. E. (1998) Biomass and Bioenergy 15 3,269. Ikeda, Y., Shinozaki, M., Suga, M., Hayami, H., Fujikawa, K. and Yoshioka, K. (1996) In: Input-output table for environment analysis. Keio University Economic Observation, Japan. 6. Abe, H., Niangu, M., Damas, K., Sam, N. and Kiyono, Y. (1998) PNG FRIBULLETIN 10, 53. 7. Abe, H., P. E Grierson, N. Sam, P. Nimiago, Dowaki, K. and M. A. Adams (2002) In: Basic research concerning nutrient circulation for cultivation energy crop in Papua New Guinea, RITE, Japan. 8. Nagasawa, T., Umeda, Y. and Li, L. (1993) Trans. JSIDRE 63 2, 121. 9. Hosoyamada, K. and Fujiwara, T. (1984) Trans. JSIDRE 52 4, 315. 10. Hosoyamada, K. and Fujiwara, T. (1984) Trans. JSIDRE 59 3,497. 11. Muraoka, H. and Miura, N. (1991) Trans. JSIDRE 59 3,283. 12. Smith, W. H. (1990) In: Air Pollution and Forest Second Edition. Springer Verlag, New York. 13. Dowaki, K., Ishitani, H., Matsuhashi, R. and N. Sam (2002) Technology 8, 193. 14. St~hl, K. and Neergaard, M. (1998) Biomass and Bioenergy 15 3,205. 15. Miura, K. and Mac, K. (1994) J. Chem. Eng 20 6, 733. 16. Abe, H., P. Kale and Kiyono, Y. (2000) PNG FRI BULLETIN 16, 36. 17. J. A. Duke (1983) In: Handbook of Energy Crops. http ://www.hort.purdue.edu/newcrop/duke_energy/Casuarina equisetifolia.html 18. D. Gauthier, H. G. Diem and Y. R. Dommergues (1985) Soil Biology and Biochemistry 17 3,375. 19. Philip J. Polglase, Mark A. Adams and Peter M. Attiwill. (1994) In, Measurement and Modeling Carbon Storage in A Chronosequence of Mountain Ash Forests. State Electricity Commission, Victoria

1. 2. 3. 4. 5.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1389

THE SYNTHESIS OF CLEAN FUELS FROM CO2 RICH BIOSYNGAS Kyu-Wan Lee and Jae-Sung Ryu Korea Research Institute of Chemical Technology e-mail: [email protected]

ABSTRACT In this work, the authors performed the Fischer-Tropsch reaction with biosyngas containing CO2, controlling the water gas shift reaction We carried out the reaction in a fixed bed, slurry bed and other reactor systems. However, in this paper, we report only the results from the fixed bed reactions. The reactions were carried out at both laboratory- and bench-scales. We also elucidated the causes of catalyst deactivation.

INTRODUCTION Recently, after COP 3 in Kyoto 1997, biomass was highlighted as an a sustainable energy source and an environmentally-friendly tool to reduce CO2. This is because biomass contains extremely low levels of sulfur and nitrogen, compared to coal and oil. The only way to synthesize liquid and solid paraffinic products containing alpha olefins with no sulfur and nitrogen from biomass is via FischerTrosch synthesis. Generally, for the F-T reaction, CO2 is eliminated to obtain pure syngas; however, in this work we didn't separate the CO2 and investigated the behavior of CO2 during the reaction in a fixed bed reactor. For a long time, the author(s) has investigated the catalytic hydrogenation of CO2 into hydrocarbons [1-3] and methanol/DME [4-5]. EXPERIMENTAL

Catalyst preparation [6] The catalyst was prepared in two steps, including co-precipitation and impregnation. The Fe-Cu-AI(Si) precursor was prepared by continuous co-precipitation from aqueous solution of metal nitrates with ammonium hydroxide solution, and the precipitate was impregnated with potassium carbonate by the incipient wetness method The catalyst composition was determined by ICP-AES to be 100Fe:6.6Cu: 15.7Al:K (Variable). Reaction The reaction was performed in a continuous fixed bed reactor. The catalyst (0.1-~1.0 g at the laboratory scale and 20-40 g in the bench scale reactions) was reduced in situ in hydrogen at 450°C for 24 hr. Then, the reaction was started with feed gas (variable composition) at a space velocity of 1800 ml/gcat.h under different pressures (10-30 atm) and temperatures (250-300°C). In the feed gas, Argon was added as an international standard gas for the GC analysis.

1390 The effluent gas from the reactor was periodically injected into an on-line GC by using two six-port valves. Ar, CO, CO2 and CH4 were analyzed by a thermal conductivity detector with a carbosphere column, while light hydrocarbons (C1-C8) were analyzed by flame ionization detector with a GS-Q capillary column.

Characterization of Catalysts The fresh, activated and deactivated catalysts were characterized by means of BET surface analysis, Mossbauer spectrocopy, XRD, XPS, TPR, TPDC and elemental analysis, etc.

RESULTS AND DISCUSSION

Characterization of catalysts. The catalysts were characterized by BET and adsorption of CO, CO2 and H2. The results are summarized in Table 1. Alumina addition increased the surface area and CO2 and hydrogen uptakes but in the silica supported catalyst, decreased remarkably. Alumina accelerated the K dispersion than Silica.

TABLE 1. CHARACTERIZATION OF CATALYSTS Catalyst

B E T area

CO2

CO

(p

(mZ/g)

Hz

mol/g)

FelCulAIlK(IO0/5/17/4) : Js,

95.5

209

FelCu/AIIK(IO0/6/16/4) : MW,

89.5

248

11.6

Fe/C u/SilK (100/6/16/4)

209.0

8.9

9.8

HzS exposed

47.0

4.4

The alumina supported catalyst converted CO in high levels, of >90%. Conversely, the silica supported one showed only 20% CO conversion and high methane (>45%) and low high fraction selectivities. Therefore, hereafter, we used Fe/Cu/A1/K catalyst for the reaction.

F- T Reactions It is impossible to obtain sufficient hydrogen gas by biomass gasification to react with co-produced CO and CO2 completely, because of its composition. The composition of biosyngas is variable and depends on the reaction conditions. Therefore, we tested many kinds of gases, composed of different ratios of CO/CO2/I--I2.

The effect of gas composition (hydrogen content) To test the catalytic activity for a model biosyngas (gas 1), hydrogenations of Ar/CO/COz/K/H2 (5/11/32/4/variable) were performed. From Table 2, it is clear that CO2 does not react, even at 300°C but it reacts in the presence of a stoichiometric hydrogen content, showing similar product selectivities. This means that the reaction proceeds through a reverse water gas shift (RWGS) reaction; namely, the products come from CO and not from CO2 [8].

1391 TABLE 2 COMPARISON OF BIOSYNGAS AND H2 SUPPLEMENTED GAS Conversion (%) CO

Olefin sel.(%) in C2-C4

Hydrocarbon distribution (C %) CO+CO

CO 2

CH4

C2-C4

C8+

C5-C7

2

H2-deficient feed: COTCO2 = 0.33, H2/(2CO+3CO2) = 0.44

82.78

0.26

21.18 12.62 39.19 21.89 26.31 84.92 ~ i5:33:i:i~i(2(::6¥3(~i5;) ~-i.................................................................................................................

....i3aia.,~ea-i~e-ea:-(~-(5;cr;

88.17

28.89

43.65

13.75

37.66

22.18

26.41

84.01

Reaction conditions: Fe/Cu/A1/K(100/6/16/4), 1 MPa, 300°C and 1800ml/g~t. • h. Balanced feed gas = 6.3CO/19.5CO2/5.5Ar/69.3H2.

Some representative F-T reaction results under various conditions are summarized in Table 3. From this table, we could induce following explanations (results). TABLE 3 REACTION RESULTS IN FIXED BED REACTION. c|t.

r2

e,-

cu-

F3

Fe-- C u -

AI- K (K-2) AJ- K ( K =

Co-

16 4)

*

•

69

19"59

t:~o°m~;;":022~ 2.0

1.0

2.0

1 0 : 4 0

F4

F,-

AI-

K (K=4)

10

*

69

20

F5

Fe-Cu.

AI.

K (K-$)

19

•

5i

2 0 1 0 : 4 0

F7

F,-

C,-

^I.

K (K-6)

19.

66

2.0

: I

F10

Fe-

Cu.

AI-

K (K=5)

lg

56

2.0

' 10

F11

: 4

Fe.

Cu-AI-K

4, 6 0

20

Fe-

Cu-

AI- K (K=8)

10

*

6o

2 o

: 1.0

Fe-Cu-AI-K

(K=4)

10

*

56

1 0

1.0

81

Fe-Cu-AI.K

(K-5)

.2

F.-

K (K-6)

I

50~

•

0

0 : 4.0

F12

A,

lg

0 : 4

F13

c.-

(K-S)

*

: I

: 4.0

0

20

: I

,.,m ,

P

Tim e

260

Z0

S01

94

275

1o

1oo

,,: ~

(,,,

xco

xcoz

SCH4

- 63.30

15,91

43,77

1064

9r12

-67.60

16 12

61 66

1636

.46

27

6

11

18

33

605

36

23

1661

42

! SCH6-

20

292

250

20

32

6042

• 74

61

6 62

260

20

210

96.53

-48

43

4 46

1638

4

265

20

165

96.63

-37

76

4

1650

431

-36

99

93

22

275

20

160

94

42

6.52

275

30

230

88

34

-5753

20

170

81

66

-26

20

71

95

14

• 6414

0 : 40

4

275

: 4.0

. 2

SCH2-

9621

: 25

1 0 : 4 0

o : I.o

Tern

276

s

276

20

220

31

4 29 S 09 1084

89

9

77

9 33

16

os

I

r

I

i

SCH6.

OSC.2-

29.60

45.90

1697

60.67

70.50

79

462

I 3974

78,31 79

96

74.36

60

01

76

63.26

67

7616

6454

1430

3 91

76.67

31

66

9 01

46

49

5495

30

62

26

70.26

32.79

21

46

36

18

06

39.82

7676

6076

The effect of potassium content It is well known that potassium is a good promoter in F-T reaction; thus, we also tested the effect of potassium as a promoter, focused on the aims as described in the Introduction. More than 2% of the potassium CO conversion and olefin selectivity of the C2-C4 fraction reached more than 80% and the methane selectivity decreased steadily below 10% over 4% of potassium-containing catalysts. By increasing the K content, the WGSR was suppressed and at high K content (8%) (see run F12 it did not occur below 275°C and 20 atm. This showed low methane and higher fractions produced in larger amounts, compared to the low potassium-containing catalysts (run F2). Conversely, at lower pressure, 10 atm, the WGSR proceeded significantly. Therefore, from the results, the preferred pressure is greater than 20 atm and the potassium content, above 4%.

Temperature and pressure effects At low temperature, 250°C, the CO conversion is not high, only 60.4% (run F5) and most of CO being converted to CO2; if the temperature is above 260°(2, the WGSR proceeded significantly. It is easily understood that the F-T reaction is an exothermic reaction (AH=-130--160KJ/mol). By increasing the temperature, the WGSR is suppressed (compare F5, 7, 10 and 11) but the product selectivities and olefin selectivity were very similar. At the same temperature, the high pressure prohibited the water gas shift reaction (compare F4 and F5); that means, at higher pressure, more CO is converted to longer chain products. At 30 atm, with a gas composed of CO/CO2/H2=1/1/2.5, most of CO is converted to CO2, meaning that the WGSR is prior to RWGSR, since the C8+ fraction and olefin selectivities were lower than the reactions at lower pressure (see Run 13). This may be attributable to the fact that at high pressure, the olefin is partially

1392 hydrogenated and chain propagation is prohibited by the shortage of CO, and the hydrogenation reaction proceeds to produce more methane.

Sulfur effect on catalyst An advantage ofbiosyngas is the extremely low sulfur and nitrogen contents in raw biosyngas, compared to gases from coal and oil. In catalysis, it is well known that sulfur damages the catalyst critically, and the sulfur content should be kept below 0.1ppm. Therefore, we tested the catalyst with different concentrations of HzS, namely 1, 3, and 5 ppm. The Fe/Cu/A1/K catalyst deactivated slowly, even at 1.0 ppm H2S concentration. The reason may be attributed to remarkably decreased BET surface area after exposure to H2S gas (see Table 1).

Long run test of catalyst. Our standard catalyst, Fe/Cu/A1/K=100/6/16/4, was verified as stable for more than 2,000 hr [7] in the case of CO2 hydrogenation under 300°C and 10atm. We also applied this to the F-T reaction of biosyngas. As you shown in Fig. 1, the catalyst activity was maintained for more 900 hr. We did not run beyond this because of experimental time schedule.

I0o, : :_-z _--_ : : :

:

-_:-

• :_

..:-

_- - :

:.

27oi1~

ZrOl~ • =m=o

,

~r~.

CO=

~.

,o

co,

i

co

!

i iiTi'iiiill"' ...."ii"'""

8

_

~f 0

*

"'"

. . . . . . . loo

20o

3oo

4oo

•.

:: . * * ° o

.-.? . . . . " '; , . , 5oo 6oo 7oo :: aoo

Time on s t r e a m (hr)

0 so

~0

lOOO

150

25o

o

100

2oo

300

400 soo r~oo 7oo i ~ T i m e on s t r e a m (hr) o 50

9oo 1so

~000 250

a) xeaction condition : P = 2.0 Mpa, T = 275/270 *C, SV = 1800rnl/g.h. b) reduction condition : H2 at 400 *C during 6hr c) biosyn gas composition : Ar/CO/CO2/H2= 5.83/26.53/13.27/54.36(vo1.%) d) coprecipitated catalyst composition : Fe/Cu/A1/K= 100/4.6/17.0/4 (wt. ratio)

Figure 1: Catalytic activity test for long run. Bench Scale Reactions

1)

Temperature profile

To accumulate technical data for the scaleup, we carried out bench scale reactions with different gas compositions; CO/CO2/H2=2/1/4 and 1/1/2.5 vol.%. To monitor the heat evolved during reactions, many thermocouples were installed at different heights along the fixed bed reactor.

1393 (A)

(B)

%,...,~

oa

A,.~ - .

"

E

T-T

T

z

0"70

40

SO

eO

IO0

120 ~40 1 "

leo

200

O0

.

.

Time [hr]

.

.

.

.

"~ ?'~/ ?5"" /

.

.

.

.

Temperature Profile [°C]

a) reaction condition : P = 2.0 Mpa, T = 270 °C, SV = 1800ml/g-h. b) reduction condition : H2 at 400 °C during 22hr c) biosyn gas composition : Ar/CO/CO2/H2 = 5.82/26.19/13.10/54.89(vo1.%) d) coprecipitated catalyst composition : Fe/Cu/A1/K = 100/6/17.0/4 (wt. ratio)

Figure 2: Temperature profiles at different height of the reactor and time on stream Figure 2 (A) & (B) show the temperature profiles at different heights of the reactor (A) and time on stream (B). The temperature at the inlet section increased significantly during the earlier stages. The maximum temperature difference between set and measured was about 40-50°C. To avoid the local heating of the catalyst bed, another efforts were required, for example, a more effective cooling system and/or dilution of the catalyst with quartz sand.

2)

Regeneration of deactivated catalyst

To discover the physical properties of the used catalyst, we extracted a wax covering on the surface and in the pores by extraction with light alkane, hexane, for two days, and finally oxidized at 400°C for 12 hr. However, the BET surface area was not recovered.

3)

SEM of Deactivated Catalyst

As the Author noted, catalyst deactivation [7] was examined. The causes of catalyst deactivation in biosyngas were crystallite size change and the change of elemental composition on the catalyst surface. Photo 1 supports the explanation, namely, surface morphology and crystallite size are changed from the inlet stage, compared to fresh catalyst.

3rd ~tage

Oullot stage

Photo 1. The SEM photos of catalysts of each stage and fresh

1394 CONCLUSIONS (1) We have developed the catalyst composed of Fe/Cu/A1/K for the F-T reaction ofbiosyngas which contains CO2. (2) We performed the F-T reactions under various conditions. The optimal reaction condition with gas 4, CO/CO2/H2=2/1/4 vol.%, was as follows; Temperature: 260-275°C, Pressure: 20 atm, Space velocity=1800 ml/g.h (3) We elucidated the catalyst deactivation. The causes could be attributed to composition change on the catalyst surface and change of crystalline size. (4) On the basis of laboratory-scale reactions, we carried out bench scale reactions. ACKNOWLEGEMENTS This work was supported by RITE/NEDO (Grant No: 99GP2) for 3 years. The Author is deeply appreciative for the financial support. REFERENCES

1. 2. 3. 4. 5. 6. 7. 8.

Lee, K. W., Nam S.S. et al., Appl. Organometal. Chem., 14, 794-798 (2000). Lee, K. W., Kim J.S. et al.,, Korean J. Chem. Eng., 18(4), 436-467 (2001). Lee, K. W., Kim H. et al.,, Study in Surface Sci.& Catalysis, 114, 407-410 (1998). Lee, K. W., Jun K.W. et al., Appl. Organometal. Chem., 2001, 15, 105-108. Lee, K. W., Shen W.J. et al., Korean J. Chem. Eng., 17(2), 210-216 (2000). Lee, K. W., Jun K.W. et al., Appl. Catal., A, 174, 231-238 (1998). Lee, K. W., Hong J.S. et al.,, Appl.Catal.,A, 218, (2001) 53-59. Lee, K. W., Riedel T., et al.,., Ind. Eng. Chem. Res., 2001, 40, 1355"1363.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1395

REDUCED CO2 MITIGATION COSTS BY MULTI-FUNCTIONAL BIOMASS PRODUCTION P. B6rjessonl'3 and G. Bemdes 2 1 Environmental and Energy Systems Studies, Dept. of Technology and Society Lund University, Gerdagatan 13, SE-223 62 Lund, Sweden 2 Dept. of Physical Resource Theory, Chalmers University of Technology/ Grteborg University, SE-412 96 Grteborg, Sweden 3 Author for correspondence

ABSTRACT

The CO2 mitigation cost when biomass replaces fossil fuels depends on several factors, such as the type of fossil fuel replaced, the energy systems involved, induced changes in the biospheric carbon stock, and the intensity and efficiency of the biomass production. Irrigation of energy crops, using nutrient rich municipal wastewater and drainage water, can lead to substantially improved productivity while at the same time addressing pollution of ground water and eutrophication. The cost of the biomass produced in such multifunctional biomass production systems will also be significantly reduced. Previous studies show that the COz mitigation cost when fossil fuels are replaced by biomass is often most sensitive to changes in fuel costs. Thus, a significant reduction in the biomass production cost will simultaneously lead to a substantial reduction in the CO2 mitigation cost. This paper shows that the CO2 mitigation cost could be significantly reduced, or even negative, when biomass from willow vegetation systems irrigated by nutrient-rich wastewater is utilised for replacing natural gas for heat and power production.

INTRODUCTION

The reduction of net CO2 emissions from substituting biomass for fossil fuels --and also the cost of such reductions-- depends on several factors, such as, the type of fossil fuel replaced, the energy systems involved, induced changes in the biospheric carbon stock, and the intensity and efficiency of the biomass production. Several studies have found that deficiency of water is often a growth-limiting factor in short rotation forestry, even in countries like Sweden with significant rainfall all year round [1]. Irrigation of energy crops, using nutrient rich municipal wastewater and drainage water, can lead to substantially improved productivity while at the same time addressing pollution of ground water and eutrophication of rivers, lakes and seas. Such multifunctional biomass production systems have been tested in large-scale field trials (Willow) in Sweden [2]. The cost of the biomass produced in these plantations will also be significantly reduced, or even negative [2,3]. Besides higher biomass yields, the reduced need for commercial fertilizers leads to lower cultivation costs. In addition, the cost of municipal wastewater treatment (considering nitrogen, phosphorus and sewage sludge treatment) is normally significantly lower in vegetation filters than in conventional treatment plants. Previous studies show that the CO2 mitigation cost when fossil fuels are replaced by biomass is often most sensitive to changes in fuel costs [4]. Thus, a significant reduction in the biomass production cost will simultaneously lead to a substantial reduction in the CO2 mitigation cost. This paper describes the possibilities of reducing biomass production costs by

1396 utilising willow plantations as vegetation filters for the treatment of nutrient rich wastewater, and how this cost reduction will affect the CO2 mitigation cost when natural gas is replaced, given heat and power production using various conversion technologies.

METHODOLOGY AND ASSUMPTIONS We define multi-functional biomass production systems as systems that, besides producing biomass, also generate additional environmental services. In this paper, we analyse willow plantations utilised as vegetation filters for the treatment of municipal wastewater and nitrogen polluted drainage water, located in Southwest, Southeast and Central Sweden, respectively. The economic value of the additional environmental services has been estimated by using two different methods. When there exists a relationship between an environmental service and a change in, for example, cultivation cost, this relation is used for valuation. One example is increased crop yields through irrigation of wastewater. When no such direct cost relation exists, the substitution cost method has been used. The substitution cost describes the cost of providing the same environmental service, but in another relevant and cost-efficient way [3]. One example is the cost of reducing nutrient leaching through the restoration of wetlands, which have the same purification function as willow vegetation filters in cleansing nitrogen polluted drainage water. We analyse the total reduction in CO2 emission (fuel-cycle CO2 emissions) by substituting natural gas for the cogeneration of power and heat, and for stand-alone power production, respectively. Cogeneration systems typically improve the efficiency of fuel use and reduce costs compared with the separate production of heat and power. The heat sinks available, however, limit the application of such systems. To make possible the comparison between the separate production of heat and power and cogeneration, we must consider both the energy carriers produced. This can be achieved by expanding the reference entity to include both power and heat in the analysis [4]. Here, we use the reference entity 1 MWh of power and 1 MWh of heat, since this is the highest ratio of produced power to heat for the cogeneration technology studied. For the additional power required for cogeneration plants with a power to heat ratio < 1.0, the power is assumed to be produced in condensing plants. The following systems are included:

Cogeneration of power and heat • A natural-gas-fired cogeneration plant (Cogen-NG) - Reference energy system • A natural-gas-fired condensing plant and a biomass-fired cogeneration plant with steam turbine (CogenBio-ST) • A biomass-fired cogeneration plant with integrated gasification and combined-cycle technology (CogenBio-IGCC) Stand-alone power production • A natural-gas-fired condensing plant (Condense-NG) - Reference energy system • A biomass-fired condensing plant with steam turbine (Condense-Bio-ST) • A biomass-fired condensing plant with integrated gasification and combined-cycle technology (Condense-Bio-IGCC) A more detailed description of the technologies studied, including capacities, efficiencies and the costs, is given in Gustavsson and Brrjesson [4]. The energy content of the fuels is defined as the LHV. All costs refer to 1997 when the average exchange rate was US$1 = SEK 7.64. The annual capital costs have been calculated using 6% real discount rate. The price of natural gas for cogeneration and for condensing plants is assumed to be US$ 4.7 and US$ 3.9/GJ fuel, respectively [4]. Domestic Swedish taxes have been excluded from the analyses.

1397 W I L L O W V E G E T A T I O N F I L T E R CHARACTERISTICS

Treatment efficiency The purification efficiency of willow vegetation filters has been demonstrated in several countries, e.g. Sweden, Poland, Denmark, and Estonia [5]. When wastewater percolates through the soil, the welldeveloped root system takes up 75-95% of nitrogen (N) and phosphorus (P) in the wastewater [6]. The nutrient content in municipal wastewater corresponds fairly well to the nutrient requirements in willow cultivation. An annual municipal wastewater load of 600 mm/ha, containing about 100 kg N, 20 kg P, and 65 kg K, will supply, not only the demand for water, but also the demand for nitrogen and other macronutrients [5]. The concept of using willow vegetation filters for the treatment of nitrogen-polluted drainage water has been tested in a large-scale field trial in southern Sweden since 1993 [7]. Here, a storage pond received drainage water from surrounding intensively cultivated land, which was subsequently used for irrigation of a willow plantation, using a furrow system for water distribution. Results from the field trial show that the nitrate concentration in the drainage water was significantly reduced after passing through the vegetation filter [7].

Biomass yield response A previous study by Lindroth and Bfith [1 ] shows that water deficit is often a limiting factor for high productivity in willow cultivation, even in countries like Sweden with significant rainfall all year round. The regional variation in biomass yields could be significant due to differences in water supply during the vegetation period. For example, the willow yield in conventional rain-fed plantations in the southeast of Sweden is normally around 50 to 60% of that in the southwest of Sweden, due to a lower rainfall in the summer season. Thus, the biomass yield response from wastewater irrigation will increase with a decrease in precipitation during the vegetation period. An estimation is that the biomass yield response from wastewater irrigation (compared with rain-fed) will vary from +30 to + 110% in Swedish willow plantations, due to the geographical location (Table 1) [2]. TABLE 1 ESTIMATED BIOMASS YIELD IN CONVENTIONALRAIN-FEDAND IN WASTEWATERIRRIGATEDWILLOW PLANTATIONS, RESPECTIVELY,IN DIFFERENTSWEDISH REGIONSa Region

Biomass yield Conventional rainWastewater fed plantations irrigated plantations dry Mg/ha, yr dry Mg/ha, yr 14 18

Southwest (SW) Southeast (SE) 8 Central (C) 10 a Estimationsbased on data from Lindrothand Bath [1].

Yield increase

dry Mg/ha, yr +4

+30

17

+ 9

+ 110

16

+6

+ 60

ECONOMIC VALUATION

Municipal wastewater treatment The economic value of municipal wastewater treatment in willow vegetation filters is here based on (i) reduced treatment cost compared with conventional N, P and sewage sludge treatment, and (ii) reduced cultivation costs. Results from previous studies show that the wastewater treatment cost can be reduced by, on average, 40%, or US$ 6.5/kg N, when wastewater produced during the summer months is treated in willow vegetation filters [8]. If also wastewater produced during the winter months is treated, the treatment cost will be reduced by, on average, US$ 2.6/kg N, compared with conventional treatment. This lower reduction in treatment cost in the whole year option, compared with the summer option, is due to the need for intermediate storage ponds during the non-growing season in the whole year option. The calculations

1398 include irrigation (equivalent to a N supply of 100 kg N/ha, yr) through a pump-pipe system with a maximum length of the feed pipe to the willow plantation of 5 km, and the cost of all technical equipment, labour and energy use. When also the value of the reduced generation of sewage sludge is included, the treatment costs will be reduced further by around US$ 1.6 and US$ 0.8/kg N for the whole year and the summer options, respectively [2]. Wastewater irrigation will reduce willow cultivation costs by increased biomass yields and by making commercial fertilisers superfluous. The value of these benefits, compared with conventional willow cultivation, is estimated to be from US$ 2.2/kg N in the southwest of Sweden, up to US$ 3.7/kg N in the southeast of Sweden, due to variations in crop yield response (see Table 1) [2,8].

Treatment o f poUuted drainage water The economic value of the treatment of polluted drainage water in willow vegetation filters is here based on (i) reduced cultivation costs, and (ii) the alternative treatment cost using restored wetlands. Restoration of wetlands is a cost-efficient method of reducing eutrophication and is a commonly used method in Sweden today. The marginal cost of nitrogen mitigation through restoration of wetlands has been estimated by Gren [9] to vary from US$ 2.6 to US$ 7.8/kg N, depending on local conditions (an average cost of US$ 5.2/kg N is used here). Like in the case of municipal wastewater irrigation, the reduced cultivation costs are based on increased biomass yields and reduced costs for fertilisers. Cost calculations of drainage water irrigation include irrigation through a pump-pipe system, storage pond, and the cost of all technical equipment, labour and energy use [8]. The size of the storage pond needed is estimated to vary regionally depending on the annual precipitation and the nitrogen content in the drainage water [2]. All drainage water produced during the whole year is assumed to be treated (equivalent to the "whole year option "considering municipal wastewater irrigation). In drier areas with relatively high nitrogen leaching, e.g. Southeast Sweden, smaller storage ponds are needed per hectare of willow vegetation filter in order to supply the nitrogen equivalent to 100 kg N, than in areas with higher precipitation and lower nitrogen leaching, e.g. Central Sweden. In these areas, the irrigation cost is calculated to, on average, US$ 6.9 and U S $ 1 2 / k g N, respectively.

Total biomass costs The total costs of biomass produced in willow vegetation filters, including the value of the water treatment, are summarised in Table 2. For comparison, the cost of biomass in conventional willow plantations is also shown. TABLE 2 TOTAL BIOMASS COSTS IN CONVENTIONAL WILLOW PLANTATIONS AND IN WILLOW VEGETATION FILTERS IN DIFFERENT SWEDISH REGIONS, INCLUDING THE ECONOMIC VALUE OF THE WATER TREATMENT a Region

Conventional willow plantations

Willow vegetation filters b

Municipal waste Municipal w a s t e Treatment of water treatment water treatment nitrogen polluted summer option c whole year option d drainage water e US$/GJ US$/GJ US$/GJ US$/GJ Southwest (SW) 4.7 -0.81 1.0 5.0 Southeast (SE) 5.3 -1.2 0.61 4.2 Central (C) 5.0 -0.92 0.92 7.2 a Including a transportation cost of US$ 0.8/GJ, which is equivalent to a transportation distance of 40 km [4]. b The wastewater and drainage water application corresponds to 100 kg N per ha. ¢ Summer option means treatment of wastewater produced during the vegetation period. d Whole year option means treatment of wastewater produced during the whole year and thus includes intermediate storage ponds. e Including intermediate storage ponds. The alternative cost of nitrogen mitigation is based on restoration of wetlands.

1399 CO2 MITIGATION COST

In Figure 1, the CO2 mitigation costs are shown when biomass replaces natural gas for the cogeneration of heat and power and for stand-alone power production, respectively, and how the mitigation cost varies due to changes in biomass cost. The CO2 mitigation cost is lowest for cogeneration systems using IGCC technology, followed by stand-alone power production using IGCC and stem turbine technology, respectively, when biomass from conventional willow plantations is replacing natural gas. For these three systems, the CO2 mitigation cost varies between US$170-300/t C, due to the conversion technology and the location of willow cultivation. The CO2 mitigation cost for cogeneration using stem turbine technology is significantly higher. Using nitrogen polluted drainage water for irrigation of willow plantations will lead to reduced biomass costs when applied in Southeast Sweden, resulting in a CO2 mitigation cost around US$150/t C (excluding Cogen-Bio-ST). However, in Southwest Sweden, and especially in Central Sweden, the biomass cost, as well as the CO2 mitigation costs, will be higher due to the need of larger storage ponds and thereby higher irrigation costs. When municipal wastewater is used for irrigation in willow plantations, the biomass cost, as well as the CO2 mitigation cost, will be significantly reduced. The CO2 mitigation cost turns negative when the biomass cost is below US$ 0.5-1/GJ, which will be the case when willow plantations are utilised for wastewater treatment considering both the summer and the whole year options. Considering the summer option (excluding storage ponds), the biomass cost and the CO2 mitigation cost will be reduced further, leading to negative CO2 mitigation costs (US$ -210 to -140/t C). The lowest costs refer to willow production in the southeast of Sweden where the highest biomass yield response from wastewater irrigation is achieved.

I 002 mitigation cost (US$/tC) 1000 * Conventional Willow cultivation SWCSE

800 600

/

400

.....-

/i

Co~len-Bio-ST i < / /

i

oO.O-. .

i

Cond-Bio-ST

~

""

.o <

Cond-Bio-IGCC

200

""

-'= ~ ,i

-', O

t ~~f

1114o0J

; I

~T I I I

;

1~

4//

/

1~

;

;//

I Biomass co~t

;I

I

SE SW C * Treatment of polluted drainage water

SECSW

/// * Waste water treatment / / / - Whole year option SE C SW * Waste water treatment - Summer option

Figure 1:CO2 mitigation costs when biomass replaces natural gas for cogeneration of heat and power and for stand-alone power production, respectively, as a function ofbiomass cost. The cost ofbiomass produced in various multi-functional willow plantations in different regions in Sweden, as well as in conventional plantations, is indicated by arrows.

1400 CONCLUSIONS AND DISCUSSION An introduction of multi-functional biomass production systems could lead to significant environmental benefits, on both a local and a global scale. Examples of such systems are willow vegetation filters for treatment of polluted water (described in this paper), but also willow plantations for preventing soil erosion (shelter belts), nutrient leaching (buffer strips along open streams), removal of cadmium from contaminated arable land (phytoremediation), increased soil carbon accumulation and soil fertility, etc. [2,6]. Another type of a multi-functional biomass production system is logging residue recovery and wood ash recirculation, which could generate various additional environmental benefits in a forest ecosystem [ 10]. The economic value of multi-functional production systems could be substantial, thus affecting future market conditions for biomass. Results from previous studies also show that large quantities of biomass could be produced in such systems in Sweden [2,3]. Reductions in biomass costs will simultaneously lead to reductions in CO2 mitigation costs when biomass is utilised for replacing fossil fuels. This paper shows that the CO2 mitigation cost could be significantly reduced, or even negative, when biomass produced in willow vegetation filters is utilised for replacing natural gas for heat and power production. Several data used to calculate the cost of power and heat production, and thus the cost of C02 mitigation, are uncertain. Examples are the cost of new conversion technologies, the impact on local conditions for biomass production, the discount rate, etc. A general conclusion is that energy systems, especially natural gas systems, are more sensitive to changes in the fuel price than to changes in investment cost and discount rates. Thus, policy measures to change fuel costs are more effective than measures to change investment costs in encouraging the desired changes [4]. Policy measures to reduce biomass costs by, for example, stimulating the introduction of multifunctional biomass production systems, seem to be an effective tool in reducing CO2 mitigation costs. A great challenge when creating such measures lies in the harmonization of the different policies in the energy, environmental and agricultural fields.

ACKNOWLEDGEMENTS We gratefully acknowledge the economic support provided by The Swedish Energy Agency.

REFERENCES

.

4. 5. 6. 7. 8.

9. 10.

Lindroth, A. and B~ith, A. (1999). Forest Ecology and Management 121, 57. Brrjesson, P., Berndes, G., Fredriksson, F. and K~berger, T. (2002). Multifunktionella Bioenergiodlingar. Final Report to the Swedish Energy Agency (Manuscript). Brrjesson, P. (1999). Biomass and Bioenergy 16, 155. Gustavsson, L. and Brrjesson, P. (1998). Energy Policy 26, 699. Perttu, K. (1999). Biomass and Bioenergy 16, 291. Brrjesson, P. (1999). Biomass and Bioenergy 16, 137. Elowsson, S. (1999). Biomass and Bioenergy 16, 281. Rosenqvist, H., Aronsson, P., Hasselgren, K. and Perttu, K. (1997). Biomass and Bioenergy 12, 1. Gren, I-M. (1994). Ecological Engineering 4, 153. Brrjesson, P. (2000). Biomass and Bioenergy 19, 137.

Greenhouse Gas Control Technologies, V o l u m e II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1401

NEW FUEL BCDF (BIO-CARBONIZED-DENSIFIED-FUEL)" THE EFFECT OF SEMI-CARBONIZATION T. Honjo 1, M. Fuchihata 2, T. Ida 2 and H. Sano 3 lNational Institute of Advanced Industrial Science and Technology (AIST), 1-8-31 Midorigaoka, Ikeda, Osaka 563-8577, Japan 2Kinki University, 3-4-1 Kowakae, Higashi-Osaka, Osaka 577-8502, Japan 3Laboratory of Global Energy System, 5-8-2-106 Makioti, Minou, Osaka 562-0004, Japan ABSTRACT

Woody biomass is a potential energy resource that helps to reduce greenhouse gas emissions. Japan has much forest; two-thirds of the land area is covered with forest. However, only a small amount of woody biomass is utilized for energy production. Therefore, we must reduce the labor and the costs for harvesting and transportation of woody biomass for this type of energy to be utilized in Japan. The object of our study is to improve the calorific density of woody biomass pellets, and reduce the transportation cost per unit energy. We adopted the semi-carbonizing method to achieve this [1, 2, 3]. After biomass has been completely dried, it is dehydrated further by decomposition of cellulose, hemi-cellulose and lignin during carbonization. Dehydration is accompanied by the loss of organic volatiles, and the energy yield of the carbonized wood is reduced. Therefore, semi-carbonizing conditions, under which maximum energy yield can be achieved, should exist. This study examined the optimum semi-carbonizing conditions needed for pelletizing. INTRODUCTION

In Japan, the amount of forest is large, estimated at 500Mdry-t/y [4, 6]. Nowadays, felling, collecting and transportation are labour-intensive, hence, very expensive. Consequently, it is difficult for woody biomass to compete with fossil fuels in terms of price in Japan. Therefore, we must provide the solutions to the transportability of harvesting and transportation for its utilization. The goal of our work is to improve the energy density and the energy yield of woody biomass pellets and reduce associated transport costs. An increase in energy density of bio-fuel is TABLE 1 the most important requisite in order to CHARACTERISTICS OF SEMI-CARBONIZED BM & CHARCOAL enhance transportability. We adopted the semi-carbonizing method to achieve this. Woody biomass could be dehydrated Calorific Calorific Energy yield density density further by decomposition of cellulose % GJ/m 3 MJ/kg and hemi-cellulose, and combination of 100 4"11 0.4-1 Green brush wood chemically dehydrated water in the 100 2"5 7"17 Dried wood temperature range 200 to 300°C. We, in the present study, examined the 100 10"11 17"19 Bio-pellet conditions of semi-carbonizing, and about95 Ogalight *~ 17"19 11-13 pelletizing for maximum energy density 50"90 (15-21) 25"35 Semi-carbonized BM and energy yield. Charcoal

33"34

,I Artificial firewood (commercial item in Japan)

(20"21)

18-40

1402 SEMI-CARBONIZATION The characteristics of semi-carbonized biomass and charcoal are shown in Tablel. The semi-carbonized biomass is situated between the bio-pellet and classical charcoal. Fig.1 shows a schematic of the relationship.

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Dried woody biomass consists of cellulose, hemi-cellulose and lignin. The cal. density/w, increases during the process from the green wood to the absolutely dried state, since free water, which originates in green wood, is gradually evaporated, the weight then decreasing significantly, but with no calorific loss. Concurrently, its volume slightly diminishes. Therefore, the calorific density per unit volume (cal. density/v) slightly increases. Cellulose and hemi-cellulose dehydrate between 200 to 250 °C due to thermal decomposition. Carbonization starts from this point, the color of wood then gradually turning black. We define semi-carbonization as these processes. The generation of wood-tar is a feature of the semi-carbonization process. The mechanisms of wood-tar generation are considered as the heat decomposition of lignin and that of cellulose, The wood-tar is sublimated beyond 400 °C. It is desirable for the wood-tar to remain in the char for pelletizing, as it acts as an antiseptic, lubricant and binder. Although the

1403 cal. density/w for charcoal is high, the energy yield of production is relatively low, about 20% for mass fraction, and no more than 40% for the calorific fraction [7]. Furthermore, it could not be well pelletized without the addition o f a binder. Therefore, high calorific and energy yielding pellets can be produced if the volatile components are retained, including the wood-tar. This is the concept o f semi-carbonization. The energy density o f semi-charcoal could be higher than that of charcoal, as the semi-charcoal contains more hydrogen and other organic substances, etc.

EXPERIMENTAL In this study, we used four types o f biomass: sawdust, leaves and branches o f a type o f Japanese cypress tree, and cellulose. Initially, thermo-gravimetric analyses (TG/DTA) was carried out for selected types of biomass. With a view to avoiding the loss o f energy, we required semi-charcoal that is rich in organic volatiles. Therefore, we adopted hot-pelletizing, the simultaneous processing of heating and pelletizing. Figure 2 shows the experimental apparatus. About lg of a sample was placed between the moulds in the reactor tube and a mechanical pressure applied, P= 0-250kgf/cm 2. They were then heated by an electric furnace at the rate o f 20 °C/min. up to the final temperature hold time, where they were kept for 15 -30min. T was selected as 150-340 °C. Samples were used after drying at 110 °C for 4 hours. In the case o f cellulose, experimental results are shown in Table2. Photographs o f the surface of the cellulose BCDF produced by optical metallograph are shown in Fig. 3. The semi-carbonized pellets are heated to about 200-330°C in the case of cellulose. Sawdust is white at 200-300°C, red at 200-270°C, the leaves are 200-250°C, and branches are 200-290°C. Cellulose has a wider range for pelletization compared with these biomasses. In the case o f the wood industry, wood is usually pressed at 170-200°C by steam treatment [5]. The pellets are obtained under 86-400 kgf/cm 2 pressure. The lower pressure tends to be used to perform pelletization until high temperature is applied. TABLE 2 EXAMINATION OF SEMI-CARBONIZED BIO-PELLETS Run no. 50 46 47 36 35 37 39 51 19 20 21 23 24 22 49 48 44 32 52 28

Sample

Press.

Temp.

Hold time

Weight

Pellet density

°C 270 300 340 300 320 330 340 200 275 280 290 305 310 320 270 300 200 270 200 270

min. 15 15 15 30 15 15 3 15 15 15 15 15 15 5 15 15 15 15 15 15

Loss (%) 6.6 8.8 59.7 21.0 30.5 47.8 48.2 5.2 7.1 6.7 6.9 10.3 41.6 56.6 9.4 26.7 4.2 13.7 4.6 18.3

g,/cm3

Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Sawdust Sawdust Sawdust Sawdust Sawdust Sawdust

kgf/cm2 86 86 86 130 130 130 130 250 250 250 250 250 250 250 86 86 130 130 250 250

1.04

1.02 1.15 1.20 1.24 1.31 1.16 1.22 1.18 1.20 1.21 1.32 1.21 1.10 1.13 1.27 0.97 1.23 1.12 1.27

Yield of pellet (%) 100 99.9 100 . 99,4 99.9 100 97 100 100 100 100 100 87.6 75.3 100 99.1 100 99.6 100 78.9

1404

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8

cellulose

9

cellulose

10

cellulose

130kgf/cm ~-200 °C 15min. 130kgf/cme 320 °C 15min. 130kgf/cm ~- 330 °C 15min. FIGURE 3: PHOTOGRAPHS OF SEMI-CARBONIZED PELLETS

::: :.(

.....

......

1. Cellulose 130kgf/cm 2 320 °C

L

2. Cellulose 130kgf/cm 2 330 °C

scale "50pm

FIGURE 4: PHOTOGRAPHS OF THE SURFACE OF THE SEMI-CARBONIZED PELLETS BY OPTICAL METALLOGRAPH

1405

RESULTS AND CONCLUSIONS The density of semi-carbonized cellulose-pellets is shown in Figure 5. At room temperature, to produce the bio-pellet, a pressure of about 1 or 2 tons per cm2is needed. Conversely, with the semi-carbonized bio-pellet, the pressure it may be possible to reduce a pellets using about 100kgf/cm 2. The weight loss of semi-carbonized cellulose-pellets is shown in Figure 6. The weight loss becomes large from 320 to 340°C. Weight loss is dependent on temperature, and slightly dependent on pressure.

Pressed at ] £OOI] temp.

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70 60 5O

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_= 30

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Temperature (°C) Figure 6: weight loss of semi-carbonized cellulose pellet

1406 Semi-carbonized biomass can be pelletized by compression, in order to improve its calorific density/volume by eliminating the void space, and also to improve the calorific density per unit weight by eliminating water in chemical molecules. This BCDF (Bio-carbonized densified fuel) can be made from all biomass types such as branches, brushwood, sawdust, etc. The characteristics of BCDF are shown in Table 3. The notable points on biomass fuel are: (1) Water content is closely connected with calorific density/weight. Free water can be easily removed by drying. Conversely, dehydrated water that is chemically compounded in organic molecules should be removed simply by thermal decomposition. (2) Void space is closely connected with calorific density/volume. The void space can be decreased by pelletizing, but it is very difficult for water-rich biomass, such as raw brush wood, to be pellitized. TABLE 3 COMPARISON OF CHARACTERISTICS OF BIO-FUEL Bulk density (g/cm 3)

0.9-0.95 0.8-1.0

Decomposed. water .2 55 55

0.5-0.7 0.4-0.8

1.0-1.1 0.8-1.1

5-15 0-10

55 10-30

0.6-0.8

0.6-1.1

0-10

2

Maximum* 1

0.1 0.3

Bio pellet BCDF Charcoal ,1. without void

Green brushwood Dry brushwood

Water contents (%) Free water 40-50 15-30

commercial

,2. water derived from organics after thermal decomposition Charcoal is also difficult to pelletize because of the lack of stickiness. The semi-carbonized biomass alone is suitable for pelletizing and obtaining high calorific density. ACKNOWLEDGEMENT The Authors would like to acknowledge the members of Dr. K Miura's laboratory at Kyoto University for carrying out experimental work and providing useful advice. Mr. Y Nakata at Kinki University is acknowledged for his assistance with the experiments. REFERENCES

1. Honjo T, Ida T, Fuchihata M, Sano H. Improvement of energy density of fuel-woods, the way for BCDF, Proceedings of the 2 lth Annual Meeting of Japan Soc of Energy and Resources, Japan, 2001. p. 429-434. 2. Honjo T, Sano H, Ida T, Fuchihata M. Prospect of BCDF: Utilization of semi-carbonized biomass, Proceedings of the 18th Conference on Energy, Economy and Environment, Japan, 2002. p. 257-262. 3. Honjo T, Fuchihata M, Ida T, Sano H. Prospect on new fuel BCDF(bio carbonized densified fuel): The effect of semi-carbonization, Proceedings of the first world conference on pellets, Stockholm, Sweden, 2002. p. 159-163. 4. Report of RITE, Development of prevention of global warming by carbonization of woods. Kyoto: RITE (Research Institute of Innovative Technology for Earth), 2001. p. 80. 5. Inoue M. Consolidation technology, now and future. Mokuzai-kougyou (Japan), 2001.56(5), p. 245-249. 6. Yokoyama N. Expectation for bio-energy, J of Japan Energy Institute, 2002, .81 (4), p. 236-248. 7. Kishimoto S. Carbon.: Soushin-sya, Tokyo, Japan, 1998. p. 208-210.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1407

N E W R E N E W A B L E E N E R G Y I N N O V A T I O N PARTNERSHIPS: E L E M E N T S OF A C O N S T R U C T I V E C A R B O N S T R A T E G Y FOR N O R W A Y ' S INDUSTRY AND G O V E R N M E N T J. Buen, Research Fellow, Centre for Technology and Society, Norwegian University of Science and Technology E-mail: [email protected], Tel." +47 7359 8115, Fax: +47 7359 1327

ABsTRAcT Norway has two major problems. First, an enormous budget surplus, resulting from petroleum exports, which economists say could overheat the Norwegian economy if it were to be reinvested on the Norwegian mainland. Second, the dependence on the petroleum sector for continued economic growth. There is consensus that new industry needs to be developed in order to maintain Norwegians' standard of living when the petroleum revenues start dwindling. This paper argues that these problems might be ameliorated through solving a third problem, namely Norwegian industry's need to meet its obligations under the Kyoto Protocol. This, it argues, could be done in a manner that would stimulate creativity and new strategies among both greenhouse gas (GHG) emitters; the financial community; and new renewable energy (NRE) companies in Norway and key non-Annex 1 countries alike.

INTRODUCTION The central argument of this paper is that Norwegian government and business should consider joining their counterparts in key non-Annex-1 countries in NRE innovation partnerships to cocommercialise small-scale NRE technologies I in order to meet Norway's Kyoto commitments. The partnership projects could be financed through a new public-private carbon fund whose liquidity would be ensured by i) stimulating Norwegian companies to diversify the risk related to their emissions reductions efforts through investing in this fund to obtain necessary credits, and ii) reinvesting parts of the Petroleum Fund. The paper suggests the organisational setup of such NRE innovation partnerships. It also presents a number of arguments for why such partnerships could stimulate GHG emissions, innovation and economic development both in host countries and Norway.

1

This paper follows the guidelines of the CDM Executive Board (EB), which includes renewable energy project

activities with maximum output capacity of
1408 A BRIDGE O V E R T R O U B L E D OIL

There are a number of attractive features of NRE innovation partnerships between Norway and selected non-Annex 1 countries. Such partnerships may contribute towards solving the problem of building new, clean, energy-efficient and knowledge-intensive Norwegian export industry while not overheating the Norwegian economy. Mainly because it is the second largest oil and gas exporter in the World, Norway has had substantial budget surpluses since the mid-1990s. Fearing the Norwegian economy would be overheated if the revenues were invested domestically, the Norwegian Parliament has decided that the bulk of this money be transferred to a Petroleum Fund that can only invest outside Norway. This fund was currently about 85 billion USD in April, but is set to more than double in a few years' time. Critics of this solution have highlighted the need to build new Norwegian industry that can secure continued economic growth after the petroleum era. They say the Petroleum Fund bereaves emerging Norwegian industry of necessary capital to grow internationally, and funds its competitors in other countries. This, they argue, slows the development towards a Norwegian industrial structure that is more knowledge-intensive and less energy-intensive. A public-private carbon fund can help bridge these differences, by making it possible to strengthen existing as well as emerging Norwegian industries by investing petroleum revenues outside Norway. This could be done by channelling a certain percentage of the Petroleum Fund's profits to a new fund that invests in innovation partnerships involving new renewable energy companies in Non-Annex-1 countries as well as their counterparts from Norway and other Annex 1 countries (the private part of the funding will be discussed below). The volume of such a fund would be too limited to satisfy requirements for the diversion of risk if it were only to concentrate on Norwegian companies. Furthermore, relatively few Norwegian companies operate in this field so far, and their capacity for international operations is limited. Allowing non-Norwegian companies to participate would probably also improve the fund's legitimacy. Finally, the European Free Trade Agreement's (EFTA) Surveillance Authority (ESA) could easily interpret this as giving special privileges to Norwegian industry. Although the carbon fund cannot be directed at Norwegian investments only, a carbon fund established in Norway would make it much simpler for Norwegian NRE industry to obtain financing for projects it conducts in co-operation with partners in non-Annex 1 countries. If Norwegian companies whose projects are financed by the fund invest their project profits in Norway, this would contribute to the overheating of the Norwegian economy. However, this problem might partly be solved through a strategy inspired by the one Norwegian authorities used towards foreign petroleum companies investing in projects on the Norwegian continental shelf in the period 1979-1991 (the so-called "Technology Agreements", or "Goodwill Agreements", see e.g. [ 1, 2]). Companies participating in projects financed by the carbon fund would have to agree to invest a certain percentage (at least 50 per cent) of both initial carbon funding and subsequent sales revenue in R&D in the host country, in return for very low taxes and fees and no extra costs placed on exports to Norway. This would not only secure the transfer of Norwegian companies' competencies to their host country counterparts - and vice v e r s a - but also minimise the risk of overheating the Norwegian economy. This could be further secured by demanding that the local operations be registered in the host country. Then, investment in production facilities, labour etc. would be under host country rather than Norwegian economic jurisdiction.

1409 THE CASE FOR A C A R B O N FUND: O T H E R A R G U M E N T S

Apart from building an environmentally friendly, knowledge-based Norwegian export industry without overheating the Norwegian economy, the NRE innovation partnership strategy also provides a number of other significant benefits - both for Annex 1 countries like Norway, host countries, and the global combat against climate change.

Supporting existing Norwegian industry NRE innovation partnerships may provide a legitimate, low-risk and low-cost way for Norwegian and other Annex 1 companies of meeting their emissions reductions obligations. In mid-June 2002, the Norwegian Parliament accepted the Government's proposal to establish a domestic GHG emissions trading scheme in the period 2005-2007 in sectors that are currently not charged for their CO2 emissions, equalling about a third of Norway's GHG emissions [see e.g. 3,4,5,6,7]. In 2008, the domestic cap-and-trade system is to be extended to the sectors that are currently subject to a CO2 tax, and the cap of the system will be decided by Norway's Kyoto commitment (Norway is allowed to increase its GHG emissions by 1% from 1990 levels). As opposed to the proposal for an EU emissions trading scheme, companies can also use credits from e.g. the Clean Development Mechanism (CDM) to offset emissions. Norway's industry consumes more energy and raw materials than most other Annex 1 countries' industries. However, the operations of the companies likely to be targeted under the abovementioned GHG trading system are often less harmful for the climate than their competitors', and the costs of in-house emissions reductions subsequently higher. These companies could therefore be interested in using the Kyoto mechanisms to fulfil their emissions reductions obligations while staying competitive. They will probably also be looking to diversify risk and minimise transaction costs associated with reducing emissions. One way of achieving this could be that these companies transfer capital to the public-private carbon fund, which invests in projects yielding GHG emissions reductions. The fund will be financially solid, as it is partly governmentfinanced. It will build up competence on the project types in which it invests, and it will invest in several different projects to diversify risk. The fund rather than the fundraisers will have the direct contact with project developers. The abatement costs will probably be low as well. The fight to emit 1 tonne of CO2 equivalent emissions (tCO2e) can be bought for 2-4,5 USD/tCO2e in existing international carbon markets. This is lower than projected costs for Norwegian companies wishing to reduce emissions domestically. International carbon prices might drop further towards 2008. Furthermore, GHG-intensive Norwegian industry - notably the processing industry - may have more trouble locating cheap domestic emissions reductions opportunities than many of its competitors. Possibilities for reducing emissions from its own operations so far seem rather limited [3]. Electric power is produced from cheap, clean hydropower. 2 Thus, GHG-intensive Norwegian industry cannot invest in cheap incremental reductions in coal power plants. As a growing number of sectors have been charged for their emissions of CO2 since 1991, many cheap abatement measures in these sectors are therefore already implemented.

Making legitimate emissions reductions The processing i n d u s t r y - joined by the Labour party, now experiencing a rare period in opposition- has questioned the environmental integrity of investing in cheap CDM projects 2The construction of large dams entails considerable GHG emissions, for example due to all the cement used, but this developmentphase is over in Norway.

1410 abroad to reduce GHG emissions. Admittedly, some might raise their eyebrows if the industry were to insist on obtaining all its reductions through buying "hot air" (excess allowances) from Russia or Ukraine. However, let us say the processing industry makes all its reductions through investments in the proposed carbon fund. The chance that such initiatives are not sustainable is probably smaller than what would be the case for voluntary initiatives in the Norwegian processing industry. Climate projects in non-Annex 1 countries stimulate cleaner development. They reduce no less emissions as the same measures conducted in Norway. As the climate problem is global, reducing emissions has the same effect in Harare as in Helsinki. It is hard to see why it is problematic that projects in non-Annex 1 countries yield cheap reductions. If so, it means that such projects can compete with investments in emissions reductions in Annex 1 countries. Nothing is better. Thus, through the CDM, industry could make its reductions in a very legitimate manner, for a lower price: 2-4,5 USD/tCO2e.

Developing clean, knowledge-intensive Norwegian industries NRE innovation partnerships may stimulate the development of Norwegian competence on carbon funds and on the development and commercialisation of selected new renewable energy technologies; both would be valuable contributions to the global efforts to reduce greenhouse gas emissions as well. Much of the NRE competence could be gained from the non-Annex 1 countries selected; they might have more experience in technology development and diffusion than do the Norwegians.

Creating technological niches NRE partnerships would create technological niches with predictable and long-term framework conditions for Norwegian and host country companies co-commercialising new renewable energy technology, e.g. the period to 2012 (and possibly beyond). While Norway contributes a larger share of its GDP to development aid than almost any other country in the World, the use of these funds has not been guided by any particular energy innovation strategy. Developing NRE innovation partnerships may be a step towards utilising development aid as a technological niche where selected technologies are allowed to develop in relative protection from market pressures, often at locations where the willingness to pay for NRE technology solutions is high, while maintaining the key objectives of such aid. Consequently, producers can cut costs, due to organisational learning and economies of scale.

Enabling market access in host countries NRE partnerships could help NRE companies from Annex 1 countries gain a foothold in nonAnnex 1 countries' growing markets. Planning procedures and local opposition slows the deployment of such technologies in Annex 1 countries. Furthermore, markets for such technologies are projected to rise in non-Annex 1 countries, as they are currently on the verge of an explosive development of energy infrastructure. As many key non-Annex 1 countries have considerable experience in the production of NRE equipment, and their labour costs are much lower than countries like Norway, there are good reasons for establishing production facilities there instead of for example in Norway. Nevertheless, knowledge-intensive employment (administration, marketing, strategy etc.) related to the partnership would most probably grow in Norway as well, especially because the funding would come from Norway.

1411

Stimulating commercialisation in host country NRE partnerships would stimulate NRE commercialisation in the non-Annex 1 countries selected. As mentioned above, many such countries have an existing R&D community and industrial base. However, they may lack the capital and knowledge of export markets necessary to gain market shares outside their home market. When this is the case, NRE innovation partnership could provide a channel to new markets.

Signalling moral responsibility, improving legitimacy Reinvesting parts of Norway's Petroleum Fund in a fund investing in NRE partnership projects would signal that Norway acknowledges its particular moral responsibility in reducing greenhouse gas emissions, due to the fact that the economic welfare of its citizens is based on a result of indirect exports of greenhouse gases to other countries. Norway not only gets the revenue from extracting and exporting these natural resources, but also avoids most of the environmental hazards (other than global warming) occurring through their lifecycle, as its own energy consumption is mainly based on electricity from hydropower. Establishing such a new fund would also improve the domestic legitimacy of the Petroleum Fund. Apart from the moral aspects mentioned above, the fund has also spurred a lot of critical press coverage due to its investments in nuclear power technology companies, weapons industries, and tobacco companies.

Improving further climate negotiations with non-Annex I countries Related to the preceding argument, the innovation partnership strategy could potentially stimulate even more constructive negotiations with non-Annex 1 countries on the participation in a possible global GHG reduction regime from the second commitment period under the Kyoto Protocol (2013 onwards). The need for transfer of climate-friendly technologies has been a key requirement from non-Annex 1 countries in the climate negotiations so far. While this claim is legitimate, the requirement that Annex 1 countries let go of their patents is unrealistic. The closest one could get towards accommodating arguments that do not take private ownership into account, may be an innovation partnership strategy resembling the one suggested in this paper.

Supporting small-scale NRE CDM projects A carbon fund supporting NRE partnership will strengthen the role of small-scale new renewable energy projects in the CDM. The project-based Kyoto mechanisms require the project developer to document that the project actually reduces emissions more than what would have been the case if the project had not been implemented. This is much more demanding for NRE technology companies than, say, coal power companies. The latter has considerable administrative capacity, and has few difficulties documenting that emissions from its own coal-fired power plant go down when an inefficient boiler is replaced with a more efficient one. A solar energy company typically has few, overworked employees. They have limited capacity to engage in trying to convince an independent auditors and the CDM EB that people in the village that has invested in their project will actually replace their kerosene, diesel aggregates and paraffin with power from solar PV panels.

1412 CONCLUDING REMARKS

The Petroleum Fund currently operates according to financial, and not political, objectives. There are several examples of unsuccessful petroleum funds where financial and political objectives are not clearly separated. If the fund proposed in this paper is established, it should have clear political objectives that should be given more emphasis than the financial ones. The Petroleum Fund, on the other hand, should maintain its strictly financial focus. This paper has proposed that parts of the profits from Norway's Petroleum Fund be invested in a new public-private carbon fund with the clear political objective of financing small-scale new renewable energy projects in non-Annex 1 countries. Similarly, Norwegian companies that need to reduce their GHG emissions under Norway's domestic emissions trading regime could do so by contributing to this fund. This would improve the Petroleum Fund's image, stimulate Norway's emerging energy technology companies, and give established Norwegian industry a low-risk, low-cost and legitimate way of reducing their emissions. The Norwegian economy would not be less overheated- and so would the globe. REFERENCES

1. Blichner, L. (1995). Radical Change and Experimental Learning. PhD thesis. University of Bergen: Department of Administration and Organisational Science. Report 37. 2. Warhurst, A. (1988). Comparative Study of UK and Norwegian Science and Technology Policy for the Offshore Oil Industry, Science Policy Research Unit, Sussex University. 3. Norwegian Ministry of the Environment (2002). Norway's third national communication under the Framework Convention on Climate Change (12 July). URL:

http://odin.dep.no/md/engelsk/publ/rapporter/022021-220010/index-dok000-b-n-a.html [accessed 30 July 2002]. 4. Norwegian Ministry of the Environment (2002). Summary in English: Report No. 15 to the Storting (2001-2002) - Amendment to Report No. 54 to the Storting (2000-2001) "Norwegian climate policy". URL: http://odin.dep.no/md/engelsk/publ/stmeld/022051-040013/indexdok000-b-n-a.html [accessed 30 July 2002]. 5. Norwegian Ministry of the Environment (2001). Summary in English: Report No. 54 to the Storting (2000-2001) -"Norwegian climate policy" (previous Labour Government). URL: http://odin.dep.no/md/engelsk/publ/stmeld/022001-040012/index-dok000-b-n-a.html [accessed 30 July 2002]. 6. Norwegian Ministry of the Environment (1999). A Quota System for Greenhouse Gases: A policy instrument for fulfilling Norway's emission reduction commitments under the Kyoto Protocol (summary of study) (17 December). URL: http://odin.dep.no/md/engelsk/publ/rapporter/022021-020006/index-dok000-b-n-a.html [accessed 30 July 2002]. 7. Point Carbon (2002). GHG emissions trading in Norway: Preparing for the global Kyoto market. URL: .http://www.pointcarbon.corn/article_view.php?id=1889 [accessed 30 July 2002]. 8. Norwegian Ministry of the Environment (2001). Agreement on the reduction of greenhouse gas emissions between the Ministry of Environment and the Aluminium Industry (1 http://odin.dep.no/md/engelsk/topics/climate/022051-990069/indexNovember). URL: dok000-b-n-a.html [accessed 30 July 2002].

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1413

CARBON SEQUESTRATION IN PLANTATIONS AND THE ECONOMICS OF ENERGY CROP PRODUCTION: THE CASE OF SALIX PRODUCTION IN SWEDEN. Berndes, G. 1'3 B6rjesson, p.2 and Azar, C. l 1

Dept. of Physical Resource Theory, Chalmers University of Technology/ Grteborg University, SE-412 96, Sweden 2 Environmental and Energy Systems Studies, Dept. of Technology and Society Lund University, Gerdagatan 13, SE-223 62 Lund, Sweden 3 Corresponding author

ABSTRACT

The establishment of bioenergy plantations on previously unforested land will generally involve carbon accumulation in aboveground biomass for some period before final use of the biomass for energy. The equilibrium level of aboveground carbon stock may be substantially larger than the level prior to the plantation establishment. Soil carbon may increase, decrease or remain approximately constant depending on plantation characteristics, climate, soil type and land use history. Thus, besides fossil fuel substitution, also changes in the carbon stock influence the climate change mitigation potential of bioenergy plantations. The Bonn agreement (COP6) opens up for the linking of biomass plantations with the crediting of plantation-induced carbon sinks. Our analysis of the case of Salix production in Sweden indicates that the revenues from such carbon credits could be substantial. Thus, the new opportunity for crediting of the carbon sink component of plantations can have implications for the economics of biomass energy. It will also favor longer rotation periods and some types of crops over others, with annually harvested crops such as energy grasses having less incentive than short rotation forests.

INTRODUCTION

This paper reports results from a 2-year project funded by the Swedish Energy Agency [ 1]. The scope of the project was to explore how biomass cultivations in Sweden can be located and managed in order to obtain environmental benefits additional to those associated with the fossil fuel substitution. The potential volumes ofbiomass that could be produced under such schemes where assessed and the economic value of the environmental benefits where estimated. Examples of benefits are reduced nutrient leaching and soil erosion, carbon sequestration and improved soil quality, cadmium removal from arable land, and improved treatment efficiency of polluted wastewater. Brrjesson & Berndes [2] provide a project overview, and Fredriksson et al. [3] discusses the specific case of Salix-based cadmium management on arable land in Sweden. This

1414 paper focuses on another potential environmental benefit of biomass plantations, namely the associated sequestration of carbon in soil and aboveground biomass.

BIOENERGY AND CARBON SINKS Biomass is rarely a climate neutral energy source. Different bioenergy systems differ greatly what regards the stocks and flows of carbon, and hence the net climate benefits. The fossil carbon displacement value of biomass varies depending on fossil fuel substitution pattern. Figure l a and l b, showing the carbon flows when plantation-derived biomass replace coal for heat (1 a) and natural gas in electricity generation (lb), clearly illustrates this point. As can be seen, the carbon abatement differs substantially between the two applications. ~o.oooLloo,,p,.~ ~o,,~,, ~"

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Figure 1: Carbon flows associated with the use ofbiomass to replace: (a) coal for heat (left), and (b) natural gas in electricity generation (fight). Based on a biomass growth rate at 7.5 tC/ha/yr and 6 year harvest interval. 10 tC/ha is sequestered in litter per 12 years and the same amount is sequestered in soils per 30 years. Coal and biomass are used for heat at 90% efficiency. Natural gas and biomass are used in electricity generatiori at 50% and 35% efficiency respectively. See [4]. Besides fossil fuel substitution pattern, the choice of biomass supply source also influences the net carbon abatement of different bioenergy systems. In addition to fossil carbon emissions in biomass production and conversion, changes in the biospheric carbon stock can be important. The extraction of biomass from existing forests tend to somewhat reduce the carbon stocks and can therefore, temporarily, constitute a net source of greenhouse gases. Conversely, projects that involve establishing new bioenergy plantations on previously unforested land can induce carbon accumulation in soils and aboveground biomass (Figure 1). Carbon s t o c k c h a n g e s a s s o c i a t e d with biomass p l a n t a t i o n s

The carbon stock changes associated with biomass plantations will mainly depend on (i) soil type, (ii) land use history, (iii) plantation productivity, and (iv) harvest interval. Soil type and land use history determine the soil carbon stock changes associated with biomass plantations. The establishment of biomass plantations on agricultural land previously used for annual food crop production will result in reduced carbon losses from organic soils, and can induce carbon accumulation in mineral soils. If the land was previously used for grazing or ley crops, the induced changes in soil carbon stock can be positive, negative or neutral. Plantation productivity and harvest interval determine the standing stock of aboveground carbon, w h i c h - averaged over large areas--can be calculated as (Eqn. 1): Y • T Harvest ~ . 1 0 0 . C Bi. . . . .

Y= average yield level [Mg DM ha -1 yrl], DM = dry matter harvest interval [Yr] cBi . . . . . - - c a r b o n content of the biomass [%] T Harvest =

(1)

1415 Thus, sink crediting would tend to favor high yielding longer rotations over shorter rotations and annually harvested crops. However, this does not mean that longer rotations will always be preferred, economically, to shorter ones. Depending on local conditions, crops cultivated with shorter harvest interval may be preferred to those with longer intervals since the yield advantage (or economics in production) more than outweighs the disadvantage of less carbon sink creation.

Crediting of carbon sinks associated with biomass plantations The Bonn agreement (COP6) opens up for the linking of biomass plantations with the crediting of plantation-induced carbon sinks. Provided that they fulfill the definition of a "forest" and have been established on former non-forested land, post-1990 biomass plantations are eligible for crediting of sinks under Article 3.3 of the Kyoto Protocol. Herbaceous crops on former cropland, such as miscanthus and switchgrass are eligible for crediting of sinks under Article 3.4 (Non-forest activities) --given that their cultivation induces soil carbon stock increases. Crediting of carbon sinks associated with biomass plantations is also possible under Article 6 and 12. In the case of Article 12 (CDM), incentives are somewhat greater due to the banking of credits starting in 2000. There might be tradeoffs between maximizing fossil carbon substitution and maximizing eligible emission-reduction credits. The relative price of biofuels vs. the price of CO2 credits, and the fossil carbon displacement value of the harvested biomass, will determine the optimal strategy. It is beyond the scope of this paper to give a full account of the net climate benefits - - a n d contribution to nearterm national emissions commitments-- of different bioenergy and carbon sequestration options (see, e.g., [5] for a discussion of fossil fuel substitution vs. carbon sequestration considerations, [6, 7] for a discussion about the carbon abatement efficiency of different bioenergy options, and [4] for a more thorough account of bioenergy-sinks issues in the context of Kyoto Protocol agreements and mechanisms). It is clear, however, that fossil carbon substitution will outweigh the carbon sequestration effects of plantation establishment in the long run (Figure 1).

SALIX CULTIVATION AND ASSOCIATED SINKS IN SWEDEN Given typical harvest intervals and yield levels, and a net fossil carbon displacement value at 0.7, Salix production on one percent of the Swedish agricultural land (about 33,000 hectares) can contribute to emissions reductions corresponding to roughly one percent of the Swedish net 1990 emissions (excl. LULUCF) [4]. Given the expectations about future land availability for energy crops in Sweden~, it is clear that the contribution from Salix production and associated carbon sinks to future Swedish emissions commitments could become substantial, and will not likely be constrained by lack of land during the coming decades. Other factors (e.g., economic, structural and institutional) will mainly influence the expansion rate ofbiomass plantations. Below, it is examined to what extent the crediting of plantation-induced carbon sinks can improve the economic viability of Salix, and thereby provide a stimulus for such plantations in Sweden.

Contribution of carbon sink credits to the economic viability of Salix cultivation Salix coppice systems are typically harvested every fourth year and extends about 25 years. Estimated county-average annual yield levels --which mainly are limited by water availability-- range from 7 Mg DM per hectare to almost the double under favorable conditions [1]. Table 1 presents some characteristics of the two Salix plantation models that are used in the evaluation of the importance of sink credits for the economics of Salix cultivation in Sweden.

i For example, the Swedish EPA vision for a sustainable agriculture in 2021 [8] included energy crops production on about 450,000-650,000 hectares, and in a scenario for 2020 presented by the Swedish Farmers Association in 1995 [9], about 400,000 hectares were used for energycrops production.

1416

TABLE 1 SOME CHARACTERISTICSOF THE SALIX PLANTATIONMODELS USED IN THIS PAPERa. Model Plantation lifetime [yr] Harvest interval [yr] Agricultural subsidies [E/ha/yr] Establishment subsidy [E/ha] Proceeds of biomass sales [E/Mg DM] First harvest [Mg DM/ha] Subsequent harvests [Mg DM/ha] Average aboveground carbon stock [tC/ha] Soil carbon accumulation [tC/ha/yr]

1

2

24 4 256 542 16 27 32 7.8 0.5

24 4 256 542 16 40 48 11.7 0.5

aBased on budget for a 6 ha Salix field (www.agrobransle.se).Agricultural subsidies differ among regions in Sweden (present range is about 168-3776/ha). Proceeds of biomass sales depend on field design, standing biomass volume at harvest vs. optimal volume for harvest operations, and distance to energyplant. First harvest is about 80-85% of subsequent harvests. The carbon content of the biomass is about 50% (DM basis). Soil carbon accumulation is set to a level correspondingto what is expected when Salix replaces annual crops on mineral soils. Based on the data in Table 1, the revenues from the crediting of associated carbon sinks can be calculated for different carbon prices. Table 2 presents the results for the two Salix plantation models and three different carbon prices (reflecting estimated costs corresponding to varying near and longerterm carbon abatement ambitions). The credit for soil carbon accumulation is assumed to be paid annually, while credits for aboveground carbon stock increases is assumed to be paid year 1, based on the expected average aboveground carbon stock o f the Salix plantation (Table 1). The value o f carbon in average aboveground biomass, given in Table 2, somewhat overestimates the potential credit for aboveground carbon stock increases. Unless the plantations are established on land with very sparse vegetation, the net increase in aboveground carbon s t o c k - - a n d hence the carbon c r e d i t s - - would be lower. The net discounted annual carbon sink revenue in Table 2 is calculated for two different cases. In the case o f plantation termination after the plantation lifetime (Termination case), it is assumed that the farmer returns to the pre-plantation land use. The transition cost associated with the resulting decrease in aboveground carbon stock is set to equal the payment year 1. In the case of plantation reestablishment (Re-establishment case), transition costs associated with aboveground carbon stock changes is assumed to be zero. No cost is assumed to arise due to soil carbon losses during termination/re-establishment.

TABLE 2 VALUE OF CARBON IN AVERAGE ABOVEGROUNDBIOMASS, AND THE NET DISCOUNTED ANNUAL CARBON Carbon price

[E/tC] 10 50 100 10 50 100

SINK REVENUES AT THREE DIFFERENTCARBON PRICESa. Value of carbon in average Net discounted annual carbon sink revenue over above-ground biomass plantation lifetime Termination Re-establishment [E/hal [E/hal [E/ha] Salix model 1 78 9 11 389 47 54 778 93 108 Salix model 2 117 11 14 583 57 69 1167 115 138

a 6% discount rate and fixed carbon price over plantation lifetime.

1417 Figure 2 shows the share of discounted total annual revenues that comes from carbon sink credits at different carbon prices. The contribution from the establishment subsidy is included for comparison. Figure 2 presents only data for Salix model 1. However, the difference between Salix model 1 and 2 is small. For example, the share of discounted total annual revenues that comes from carbon sink credits at 100 C/tC carbon price is about 21% and 23% for Salix model 1 and 2 respectively (reestablishment case). As noted above, the approach here somewhat overestimates the potential carbon sink credits since it implicitly sets the average aboveground carbon stock of pre-plantation vegetation equal to zero. Nevertheless, based on Figure 3 and a comparison of the value of carbon in average aboveground biomass (Table 2) with the present establishment subsidy in Sweden (Table 1), it can be concluded that at high carbon prices, the credits for carbon stock increases would be a substantial incentive to plantation establishment. .....

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100

1418 CONCLUSIONS AND DISCUSSION Salix plantations could contribute significantly to meeting carbon abatement requirements in Sweden; through fossil fuel displacement and carbon sink creation. The Bonn agreement (COP6) opens up for the crediting of carbon sinks associated with biomass plantations. In the case of Salix cultivation in Sweden, such crediting could significantly improve the economic viability of Salix, and thereby provide a stimulus for such plantations in Sweden. Rising carbon prices increases the competitiveness of biomass over fossil fuels. With high enough carbon prices there would be substantial profits in the bioenergy sector and farmers would have incentives to cultivate energy crops rather than food. Under these conditions biomass plantations might successfully compete for land resources in several regions of the world. Sink crediting would further improve the competitiveness of plantations, and costs for carbon stock decreases under plantation termination tend to conserve the plantation state. Land use competition between food and energy uses has long been an issue. The implications of a linkage between biomass plantations and credits/costs of associated carbon stock changes further underlines the importance of paying close attention to food-bioenergy interactions under the emerging carbon trade regime.

ACKNOWLEDGEMENTS This project has benefited from cooperation with Bernhard Schlamadinger, Joanneum Research, Austria, and Michael Grubb and Ausilio Bauen, Imperial College, UK. Financial support from the Swedish Energy Agency and the Adlerbertska Research Foundation is gratefully acknowledged.

REFERENCES

1. Brrjesson P., Bemdes, G., Fredriksson, F. and Khberger, T. (2002). Multifunktionella bioenergiodlingar. (Multifunctional bioenergy plantations, in Swedish). Final report to The Swedish Energy Agency. 2. Fredriksson, F., Berndes, G. and Brrjesson, P. (2002). Bioenergy production as a tool for phytoextraction in agriculture -the case of Salix-based cadmium management on arable land in Sweden. In: 12th European Conference and Technology Exhibition on Biomass for Energy, Industry and Climate Protection. Amsterdam, 17-21 June 2002. 3. B6rjesson, P. and Berndes, G. (2002). Multi-functional biomass production systems. In: 12th European Conference and Technology Exhibition on Biomass for Energy, Industry and Climate Protection. Amsterdam, 17-21 June 2002. 4. Schlamadinger, B., Grubb, M., Azar, C., Bauen, A. and Berndes, G. (2001). Carbon sinks and biomass energy production: A study of linkages, options and implications. Climate Strategies: International Network for Climate Policy Analysis. 5. Marland, G. and Schlamadinger, B. (1997). Forests for Carbon Sequestration or Fossil Fuel Substitution? A Sensitivity Analysis. Biomass and Bioenergy 13, 389. 6. Azar, C., Lindgren, K. and Andersson, B.A. (2002). Global energy scenarios meeting stringent C02 constraints -cost-effective fuel choices in the transportation sector. To appear in Energy Policy. 7. Gustavsson, L., Brrjesson, P., Johansson, B. and Svenningsson, P. (1995). Reducing C02 emissions by substituting biomass for fossil fuels. Energy 20, 1097. 8. Swedish Environmental Protection Agency (1997). Det framtida jordbruket-slutrapport fr&n systemstudien frr ett miljranpassat och uth&llitjordbruk (Agriculture in the future -final report from the system study of an environmental sound and sustainable production in agriculture). Stockholm, Sweden. 9. Swedish Farmers Association (1995). Biobr~slenas roll i ett uthhlligt energisystem (The role of biofuels in a sustainable energy system).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1419

G R E E N H O U S E GAS EMISSIONS F R O M BIOE T H A N O L AND BIO-DIESEL FUEL S U P P L Y SYSTEMS Haroon S. Kheshgi 1 and David J. Rickeard 2 1ExxonMobil Research and Engineering Company, Route 22 East, Annandale, New Jersey 08801, USA aExxonMobil Petroleum & Chemical, Hermeslaan 2, B-1831 Machelen, Belgium

ABSTRACT Analyses of the yield, energy consumption and GHG emissions for current systems to produce ethanol and bio-diesel are reviewed in the context of European Union (EU-15) application. Energy consumption and net GHG emissions are compared on a per unit fuel and per unit land basis for various systems: corn, sugar cane, wheat, and sugar beet to ethanol; and rapeseed to rape methyl ester (RME). Gross yield of RME is approximately 1 toe ha 1, ethanol from wheat 1.2 toe ha 1, and ethanol from sugar beet 3.4 toe ha -1 limiting the quantity of gasoline or diesel fuel use that could be replaced by biofuels using set-aside land available in the EU-15. Energy consumption for crop production and processing to make ethanol or RME in current processes account for about 58-106% of the produced RME or ethanol fuel energy content. Avoided GHG emissions resulting from gasoline or diesel fuel use replaced by biofuels, accounting for fuel system energy use, and crediting GHG offsets for animal feed byproducts, result in 0.4 tCeq ha 1 for ethanol from wheat, 1.3 tCeq ha ~ for ethanol from sugar beet, 0.6 tCeq ha -! for RME with a wide range of uncertainty stemming from, e.g., uncertainty in agricultural N20 emissions and byproduct credits. Fluxes of avoided GHG emissions from these biofuel production systems are found to be much less than those from afforestation or reforestation in temperate regions.

R E V I E W OF C U R R E N T B I O F U E L S

Biofuel Yields Per Hectare Systems produce bio-diesel by the extraction of oils from crops (e.g. rapeseed or soybean), transesterifation with, e.g., methanol to make fatty acid esters and glycerol, followed by removal of glycerol [ 1]. Systems produce fuel ethanol by the extraction of starch or sugar from crops (e.g. corn, sugar cane, sugar beet, or wheat), fermentation to make a dilute ethanol solution, and distillation to make anhydrous ethanol [2]. Yields of biofuels from commercial systems are determined by the yield of sugar, starch or plant oils extracted from harvested crops and the conversion efficiency to ethanol or bio-diesel. Yields of rapeseed methyl esther (RME) and ethanol are shown in Figure 1. Yield of RME per unit land is lower than ethanol from corn or wheat, which is lower than ethanol from sugar cane or sugar beet. Yields of plant oils are typically lower than yields of sugars and starches [3].

1420 Prospects for improving yields for these biofuel systems by improvements in conversion efficiency are limited; conversion efficiency for ethanol, for example, is approaching the theoretical maximum [3]. Increases in crop yields have been achieved; USA corn yield, for example, has exhibited a 2% annual increase in yield over the last decade, and EU-15 wheat and sugar beet yields each have exhibited a 1% annual increase in yield over the last decade, all with considerable interannual variation [4]. t o e h a "1 y r "1

0

Com Ethanol

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Figure 1" Yield of ethanol and RME per unit cropland given on an energy basis (lower heating value; 1 toe = 42 GJ). Com ethanol yield is typical for the USA [5]. Wheat and sugar beet ethanol yields are typical for EU-15 [6]. Sugar cane ethanol yield is the average for Brazil in 1995/96 [7]. RME yield is the average for Northem France [6]. Error bars represent the range of yields spanned by studies reviewed by CONCAWE [8].

Net Energy Produced with Biofuels Increased use of biofuels (ethanol and bio-diesel) is being considered for a variety of reasons including the reduction of GHG emissions. The production of biofuels from plants would lead to no GHG emissions if they did not consume fossil fuels, lead to other GHG emissions such as N20 emissions from fertilizer use, or lead to loss of plant and soil carbon stocks. It is well known, however, that the production of biofuels requires significant energy to convert chemical components of crops to ethanol or bio-diesel, and to produce and deliver the crop that is consumed in the process. The energy inputs to produce ethanol or RME can be comparable to the energy contained in the fuels as was found in the studies summarized in Figure 2 and reviewed in detail in other reports [8, 9]. Agriculture energy inputs from fertilizer production, planting and harvesting, crop transport, etc, are lower for sugar cane or sugar beet than for wheat, corn, or rapeseed per unit fuel produced. Energy required for processing is higher for the production of ethanol (e.g. milling, fermentation and distillation) than for RME. In the EU15, estimated energy inputs range from 58% of energy in RME produced [10, 11] to 106% of energy in wheat-ethanol produced [12]. Some processing energy can potentially be supplied by bioenergy. In the Brazil sugar cane-ethanol system, process energy (see Figure 2) is supplied by ample supplies of bagasse (crushed cane stems) that would otherwise require disposal. For most crops, the supply of agricultural byproducts or residues (e.g. wheat straw) is limited in relation to the energy needs for processing the crops into, for example, ethanol and could, in theory, supply a fraction of the processing energy [8, 9]. Fossil energy consumption avoided by the replacement gasoline or diesel fuels with ethanol or RME is represented by the somewhat lower bar heights for biofuels than for gasoline or diesel in Figure 2. Furthermore, results summarized in Figure 2 do not include energy credits for byproducts such as animal feed or biomass residues. CONCAWE [8] estimates that, in the European context, the percent of fossil fuel energy saved by replacing gasoline with ethanol increases from 17% to 31% of fuel replaced when animal feed credits are included, and fossil fuel energy saved by replacing diesel fuel with RME increases from 47% to 56% of fuel replaced when animal feed credits are included.

1421 MJIGJ fuel 1200

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Figure 2: Energy consumed for agriculture (i.e. production of crops) and processing of crops to make biofuels per GJ biofuel produced (lower heating value). Corn-ethanol energy use is typical for good practice in the USA circa 1990 [5]. Wheat-ethanol energy use is estimated for the UK [12]. Sugar beet-ethanol energy use is estimated for France [13]. Sugar cane -ethanol energy use is for Brazil in 1995/96 with the extended bar indicating the additional energy from burning bagasse used to fuel the cane to ethanol process [ 14]. Two bars for rapeseed to RME energy use are from studies carried out for Germany [ 10, 11 ] and the UK [12]. Energy required to produce, refine and deliver gasoline and diesel fuel in Europe is shown [8] along with the energy consumed by end use combustion in vehicles (1 GJ; not shown for biofuels). Avoided GHG Emissions with Biofuels GHG emissions incurred producing biofuels subtract from the GHG emissions not emitted by the gasoline or diesel consumption that biofuels might replace. GHG emissions resulting from, and offsets assigned to, byproducts produced along with biofuels further modify net GHG emission estimates. Figure 3 summarizes the net GHG (studies focus on CO2 and some consider N20 emissions) emissions avoided per unit cropland for biofuel systems. While the yield of RME per unit land is lower than ethanol from corn or wheat, the energy consumption for ethanol production is higher leading to lower CO2 emissions avoided for these sources of ethanol than for RME. High sugar yields of sugar cane and beet lead to higher CO2 emissions avoided per unit cropland. Sugar cane ethanol as produced in Brazil, which makes use of the large quantities of byproduct bagasse (crushed cane stems) as an energy source for the conversion of sugar cane to ethanol, has the highest rate of CO2 emissions avoided of the biofuels shown in Figure 3. Fertilizer use for some crops, for example rapeseed, can add not only to CO2 emissions for fertilizer production, but also, and perhaps more significantly, additional N20 emissions leading to decreased net GHG avoided from biofuels. While N20 emission factors remain uncertain, application of IPCC [15] emission factors for N20 cuts the estimate of CO2 equivalent emissions avoided by RME shown in Figure 3 by more than a factor of two [8] leading to a fundamental uncertainty in estimates of GHG emission. Land use required to produce RME at a scale sufficient to avoid a fraction of EU-15 GHG emissions is compared to EU-15 land areas in Figure 4. Given the current area of EU-15 set-aside land of 5.6 Mha [16], CONCAWE [8] calculated that if all set-aside land were to produce a mix of RME and wheat- and sugar beet-ethanol then this would avoid about 0.3% of EU-15's GHG emissions. Available land is clearly a key limitation to large-scale production of biofuels. Studies of net GHG emissions from biofuel systems usually neglect consideration of changes in plant and soil carbon stocks over harvesting cycles. Soil management practices can add to soil carbon stocks at rates comparable to the rates of emissions avoided shown in Figure 3; of course, such practices could be applied more broadly to agricultural lands [ 17]. But if biofuel systems lead to deforestation or the establishment of additional cropland, then emissions associated with land use change would far surpass the annual avoided emissions from biofuels; for example, the IPCC [ 18] lists temperate forest deforestation to cause an emission of about 60 tC ha 1.

1422 Accumulation of carbon stocks is observed in temperate forests. Increases in total carbon stocks -vegetation and soils -- have been assessed by direct determination of net sources and sinks (i.e. net ecosystem productivity) over periods of 1 or more years; increases in total carbon stocks have been found in temperate forest stands (predominantly mature) to range from 2.5 to 7 tC ha -1 yr -~ [19]. The IPCC [18] assessed that afforestation and reforestation in temperate regions could be accounted to offset GHG emissions at a rate of 1.5 to 4.5 tC ha l yr1. As shown in Figure 3, these rates are larger than estimated emissions avoided by biofuel systems. The common assumption [20] that forest sinks and bioenergy result in similar reductions in net GHG emissions is found to be false for the biofuel systems considered here. tC.,

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Figure 3: Net GHG emissions avoided by the replacement of gasoline or diesel fuel by ethanol or RME is compared with carbon sinks from temperate forests on a per unit cropland or forestland basis. Emissions avoided shown for the European context (wheat- and sugar beet-ethanol, and RME) are the average and range of studies summarized by CONCAWE [8] including credits for animal feed byproducts but assuming no bioenergy used for processing energy. The CO2 emissions estimate for the ongoing USA corn-ethanol system includes credits for animal feed byproducts with no bioenergy used for processing energy, while that for the ongoing Brazilian cane-ethanol system accounts for bioenergy use but does not produce animal feed byproducts [3]. For temperate forests, the range of observation-based estimates of CO2 sinks [19] and the additional sinks that would be expected to be generated by reforestation or afforestation [ 18] are shown. Alternative Uses of Biomass The production of ethanol by the fermentation of cellulose and hemicellulose in biomass (e.g. wood, grass and crop residues) has been proposed as an effective process to avoid GHG emissions [21, 22], although not currently commercial. However, the energy required to make ethanol in this way is greater than the energy of the produced ethanol -- i.e. greater than the energy required for ethanol from any of the systems considered in Figure 2 [8]. The process relies on efficient use of waste biomass (e.g. lignin) to power the system [23]. Of course, biomass could alternatively be used directly for energy (e.g. heat and power) rather than as an energy supply for an energy-inefficient and expensive biofuel system. The cost of producing ethanol from cellulose has yet to match the targets set for this technology [24]. The cost of bio-ethanol in the USA has been estimated to currently be about $1.20 per gallon higher than the cost of gasoline [22]; if this added cost were assigned to avoiding gasoline CO2 emissions, it would equate to about 440 $ tC 1. CO2 emissions avoided by the use of ethanol or RME produced in the EU-15 has been assessed to be even more costly [9]. The high cost of biofuels in the EU-15 and the USA relative to gasoline and diesel fuel put biofuels far down the list of options [25] to reduce GHG emissions based on cost effectiveness.

1423

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Figure 4" Proportional relationship (diagonal line) between the extent of land required to produce RME and the GHG emissions that would be avoided by using RME as a diesel fuel substitute. GHG avoided per ha for RME follows the value shown in Figure 3 and includes byproduct credits. EU-15 RME production in 1998 [ 16] at the average yield of Northern France (see Figure 1) is marked by the square symbol. EU-15 land areas and GHG emissions are marked along the axes. Note that the axes are logarithmic.

CONCLUSIONS Yields of biofuels per unit land area limit their scope as a replacement for gasoline or diesel fuel in the EU15 context. Analyses show the yield of RME to be less than that of ethanol from wheat or sugar beet. The processing needed for RME, however, is less energy intensive. If fossil energy is used to process biofuels, the rate at which COz emissions may be avoided per unit land becomes higher for RME than for wheatethanol, although sugar beet-ethanol remains still higher. Emissions of the GHG N20 from fertilizer management in crop production adds uncertainty to estimates of GHG emissions avoided as do prospective uses of byproducts. In spite of these uncertainties, emissions avoided with biofuels are significantly lower than observed carbon sinks of temperate forests. The oft-assumed equivalence between rates of forest sinks and emissions avoided with bioenergy does not hold for the biofuels ethanol and RME. Use of bioenergy for heat and power could prove a more effective way to avoid GHG emissions. The costs and prospects of bioenergy systems relative to other alternatives, however, indicate that there is a need for broader portfolios of approaches to address GHG emissions.

1424 REFERENCES

1. Ma, F. and Hanna, M.A. (1999) Bioresource Technology 70, 1-15. 2. Klass, D.L. (1998). Biomassfor Renewable Energy, Fuels, and Chemicals. Academic Press, San Diego. 3. Kheshgi, H.S., Prince, R.C. and Marland, G. (2000) Annual Review of Energy and the Environment 25, 199-244. 4. FAO (2002). FAOSTAT. Food and Agriculture Organization of the United Nations, http://apps.fao.org. 5. Marland, G. and Turhollow, A.F. (1991) Energy 16, 1307-1316. 6. Levy, R.H. (1993). Les biocarburants. Report to the French government based on figures from the Commission Consultative pour la Production des Carburants de Substitution, 1991. 7. Moreira, J.R. and Goldemberg, J. (1999) Energy Policy 27, 229-245. 8. CONCAWE (2002). Energy and Greenhouse Gas Balance of Biofuels for Europe -- an Update. CONCAWE, Brussels. 9. Rickeard, D.J. and Kheshgi, H.S. (2002) In: Procedings of the 29th FISITA World Automotive Congress, paper F02E 199, http://www.fisita2002.com/fisita.html, FISITA, Helsinki. 10. Reinhardt, G.A. and Zemanek, G. (2000). Okobilanz Bioenergietrager-- Basisdaten, Ergebnisse, Bewertungen. IFEU-Institut, Heidelberg. 11. Reinhardt, G.A. and Jungk, N. (2001) In: Proceedings of the International Colloquium on Fuels, pp. 247-256, Esslingen. 12. Grover, M.P., Collings, S.A., Hitchcock, G.S., Moon, D.P. and Wilkins, G.T. (1996). Alternative Road Transport Fuels -- A Preliminary Life-cycle Study for the UK. Energy Technology Support Unit, Oxford. 13. ECOBILAN (1996). ECOBILAN de I'ETBE de betterave (Eco-balance fro ETBE from sugar beet). ECOBILAN, France. 14. Macedo, I.C. (1998) Biomass and Bioenergy 14, 77-81. 15. IPCC (1997). Revised 1996 1PCC Guidelines for National Greenhouse Gas Inventories. Reference Manual. Intergovemmental Panel on Climate Change, Geneva. 16. EU (2001). Communication from the Commission to the European Parliament, the Council the Economic and Social Committee and the Committee of the Regions on alternative fuels for road transportation and on a set of measures to promote the use of biofuels. Commission of the European Communities, COM(2001)547, Brussels. 17. Smith, P., Powlson, D.S., Smith, J.U., Falloon, P. and Coleman, K. (2000) Global Change Biology 6, 525-539. 18. IPCC (2000). Land Use, Land-Use Change, and Forestry: A Special Report of the Intergovernmental Panel on Climate Change. Cambridge University Press, New York. 19. Bolin, B., Sukumar, R., Ciais, P., Cramer, W., Jarvis, P., Kheshgi, H., Nobre, C., Semenov, S. and Steffen, W. (2000) In: Land Use, Land-Use Change, and Forestry: A Special Report of the Intergovernmental Panel on Climate Change, pp. 23-51, Watson, R.T., Noble, I.R., Bolin, B., Ravindranath, N.H., Verardo, and D.J. Dokken, D.J. (Eds). Cambridge University Press, New York. 20. Royal Society (2001). The role of land carbon sinks in mitigating global climate change. The Royal Society, London. 21. Lynd, L.R. (1996) Annual Reviews of Energy and Environment 21,403-465. 22. Lave, L.B., Griffin, W.M. and MacLean, H. (2001) Issues in Science and Technology online Winter 2001, hhtp://www.nap.edu/issues/18.12/lave.html. 23. Wang, M. (2001). Well-to-wheel energy use and greenhouse gas emissions of advanced fuel/vehicle Argonne National Laboratory, systems -North American Analysis. http ://www.ipd. anl.gov/anlpubs/2001/04/39097.pdf. 24. National Research Council (1999). Review of the Research Strategy for biomass-derived transportation fuels. National Academy Press, Washington D. C. 25. IPCC (2001). Climate Change 2001: Mitigation: Contribution of WGII1 to the Third Assessment Report of the IPCC. Cambridge University Press, New York.

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1427

THE P O T E N T I A L ROLE OF B I O T E C H N O L O G Y IN A D D R E S S I N G THE L O N G - T E R M P R O B L E M OF C L I M A T E C H A N G E IN THE C O N T E X T OF G L O B A L E N E R G Y AND E C O N O M I C SYSTEMS James A. Edmonds, John Clarke, James Dooley, Son H. Kim, R Izaurralde, N Rosenberg, and GM Stokes 1 Joint Global Change Research Institute, Pacific Northwest National Laboratory 8400 Baltimore Ave, College Park, MD, 20740, [email protected]

ABSTRACT Commercial biomass is a technology that is of interest in the context of the formulation of a response to the issue of climate change, because it is a potential source of modem commercial fuels in which the carbon content of the fuel was originally obtained from the air. Thus, biomass has no net emissions of carbon dioxide (CO2), the most prominent greenhouse gas. Biomass must compete with well established energy forms, in addition to other, emerging energy technologies, for market share. To win a significant market share, biomass technology must continue to improve. The degree of improvement will have a major influence on the role ofbiotechnology in addressing climate change. This paper examines the competition among technologies in a variety of markets, and explores conditions under which new markets for modem commercial biologically derived fuels could emerge. Important interactions with agricultural markets and land use and land cover are considered. The successful application of biotechnology to crop, pasture, and forest productivities is shown to be important. The availability of a complimentary energy technology like carbon capture and disposal technologies is shown to dramatically reduce the cost of stabilizing the concentration of greenhouse gases, as well as to open up the possibility of negative-emission energy production from biomass. INTRODUCTION

Dramatic advances have occurred in understanding biological processes and in applying that technology to important problems. While much attention has been placed on the applications of biological sciences to medicine and health, the biological sciences have substantial potential to affect global energy systems. Potential applications include improvements in the productivity of crops that could be employed as feedstocks to produce modem commercial fuels, direct microbial based production of hydrogen (H2) from water, and a variety of biological processes to directly capture and sequester carbon. In addition, biotechnology could improve productivity in traditional crops, pastures, and forests, needed in order to free up land from food production so that it can be devoted to growing energy crops. In this paper we focus on technologies to produce modem commercial fuels and the other major anthropogenic land-use technologies.

The research reported in this paper was made possible in part by support from the Integrated Assessment program in the Office of Science, U.S. Departmentof Energy and by EPRI. The authors are further indebted to many people, whose comments and suggestions have served to improve the paper, including Rich Richels, John Weyant, Ron Sands, and Ken Humphreys. The authors retain responsibilityfor any remaining errors of opinion or fact.

1428 Commercial biomass is a technology that has attracted interest in the context of the climate change issue. It is a potential source of modern commercial fuels in which the carbon content of the fuel was originally obtained from the air. Thus, biomass has no net emissions of carbon dioxide (CO2), the most prominent greenhouse gas 2. We explore the potential of biotechnology to address climate change using the MiniCAM version 2001.02. 3 The MiniCAM 2001.02 is a long-term, global model of energy, economy, land use, and greenhouse gas emissions to examine a reference case and three alternatives. Biomass production is modeled explicitly in the MiniCAM. There are several types of biomass production, including traditional biomass such as wood, dung, and detritus, modern commercial biomass produced from recycled biological materials and crop residues, and modern commercial biomass crops grown primarily for the energy content of the crop. Modern commercial biomass solids are combusted directly to provide electricity and other energy services and converted into synfuels and hydrogen. In the MiniCAM agriculture and biomass energy are modeled within the context of the determination of land-use. Land is allocated to competing uses based on relative profitability of competing activities. As an activity become more profitable its share of land use increases. Alternatively, as an activity becomes less profitable its share of land use declines. Similarly, as the application of land to anthropogenic activities increases in value, the extent of managed lands increases, expanding into unmanaged ecosystems. Conversely, declines in the overall rate of profitability of land management leads to the abandonment of land to an unmanaged state. Land-use carbon emissions are determined by simple stock model of biological resources (Edmonds et al., 1996). The relative carbon intensity of land-uses depends on the land use as well as dynamic adjustments. The replacement of high carbon intensity uses, such as forests, with low-carbon intensity uses, such as food crops, results in a net flux of carbon to the atmosphere. THE R E F E R E N C E CASE The reference case is modeled on the IPCC B2 scenario (Nakicenovic, 2001). The B2 world is one in which both population and economic activity grow steadily. The gap between rich and poor nations is reduced and there are substantial improvements in energy technologies. The MiniCAM embodiment of the B2 scenario, MiniCAM B2, is described in Edmonds, et al. (2002). In addition to the MiniCAM B2 scenario the effects of limiting the concentration of CO2 to 550 ppmv will be examined. Table 1 displays assumptions used to describe key technologies in the examination of four cases. Several technology options are available in the MiniCAM B2 scenario that differ from the case reported in Edmonds et al. (2002). These include hydrogen production and hydrogen fuel cells. TABLE 1 TECHNOLOGY ASSUMPTIONS

Technology US Automobiles Land-based Solar Electricity Nuclear Power Biomass Energy Hydrogen Production (CH4 feedstock) Fuel Cell

Units Mpg 1990 c/kWh 1990 c/kWh 19905/gj 19905/gj

1990 Base 18 61 5.8 $7.70 $6.00

Year 2095 60 5.0 5.7 $6.30 $4.00

. mpg(equiv) ........... 43 . . . . . . . . . . . . . . 98 . . . . . . . .

2Associated fuel production activities could have net CO2 emissions, as would changes in the net stock of biomass in the field. 3 The model is described in greater detail in Edmonds et al. (2002).

1429 Against each of these backgrounds, we examine implications of three altemative rates of technological change for agricultural products and commercial biomass: • • •

No productivity improvement--0.0 percent per year, Reference technology improvement--asymptotic convergence to 0.5 percent per year, High productivity--asymptotic convergence to 1.5 percent per year.

We note that the high productivity growth assumption reflects a slower rate of improvement in the 21 st century than historical rates achieved in the 20 th century. Carbon capture and disposal (CC&D) is not included in the reference technology cases. This technology has a potentially powerful influence on the degree of deployment of modern commercial biomass and its development and large-scale deployment are discussed later in this paper. The stabilization cases examine the implications of limiting global emissions so that they never exceed 550 ppmv employing the trajectory prescribed by Wigley et al. (1996). The choice of the concentration 550 ppmv is arbitrary. No scientific basis exists yet for defining a concentration that would "prevent dangerous anthropogenic interference with the climate system"--the goal of the Framework Convention on Climate Change (United Nations, 1992). The level at which the CO2 concentration is ultimately stabilized could also turn out to be 450 ppmv or 1000 ppmv. The available technologies for stabilizing at alternative concentrations, and thus the cost to achieve that end, along with the rate, magnitude, timing, and regional dispersion, of impacts of realized climate change will likely play roles in determining the ultimate stabilization concentration. It is also important to point out that this study reports the minimum cost of a globally coordinated effort. All nations and economic agents are assumed to behave in an economically efficient. Cost minimizing manner so as to achieve the concentration limitation at minimum cost to society. This assumption is obviously unrealistic. Real world institutions and implementation will certainly be economically inefficient. Inefficiencies will raise costs of meeting any emissions limitation objective. Costs here are therefore reported to provide a basis of comparison between two alternative technology regimes. A G R I C U L T U R A L P R O D U C T I V I T Y AND S T A B I L I Z A T I O N In the MiniCAM B2 reference case commercial biomass remains a relatively small-scale technology, Figure 1. Traditional biomass fuels are employed in low-efficiency applications and their per capita use declines with income. Economic growth over the century reduces reliance on traditional biomass, though its use is not extinguished. In the second half of the century modern commercial biomass begins to account for a noticeable share of the global energy system in the reference case, MiniCAM B2 0.5% Ag Productivity, Figure 1. Additional biomass is produced in the reference case when agricultural productivities rise to 1.5%. However, commercial biomass becomes a major energy supply source when the concentration of CO2 is limited to 550 ppmv, supplying half of the world's energy. In this case the value of carbon is sufficient to dramatically increase the production and deployment of this technology. It is important to note that this result excludes the possibility of CC&D and accelerated development of other technologies such as solar, wind, and nuclear power. Since fossil fuel use implies CO2 emissions absent the carbon capture and disposal option, controlling the concentration of CO2 ultimately requires that fossil fuel use peak and then decline in a world where CC&D technologies are not successfully developed and deployed. The minimum value of a ton of carbon rises to $450 per ton of carbon in the reference productivity case by the year 2095. Increasing agricultural productivity growth to 1.5% per year reduces the value of carbon by a third ($300 per ton). If there is no increase in agricultural productivity, the value of a ton of carbon increases to $600

1430 per ton of carbon. Clearly, the ability to increase agricultural productivity is a significant lever in controlling the cost of addressing climate change. The cost of producing and utilizing hydrogen is assumed to improve over time and by the end of the century becomes a major source of final energy in all scenarios 4. While fossil fuels are the dominant source of H2 in the reference MiniCAM B2 0.5% and MiniCAM B2 1.5% productivity cases, biomass becomes the largest feedstock for H2 in the 550 ppmv concentration limitation cases. When agricultural productivity growth is 0.5% the imposition of a constraint on the concentration of CO2 results in a very substantial reduction in the use of H2 because its cost rises reflecting the value of carbon contained in the fossil fuel feedstocks. At the 1.5% agricultural productivity level, the effect is smaller reflecting a smaller value of carbon required to stabilize the concentration of CO2. MiniCAM B2 550 0.5% Ag Productivity

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Figure 1: Commercial Biomass Energy In the Global Energy The effect of modem commercial biomass on land use ranges from modest, providing farmers a new commercial crop, in the MiniCAM B2 0.5% productivity growth rate reference case, to the most important land-use activity on earth, MiniCAM B2 550 1.5% agricultural productivity growth rate, Figure 2. The MiniCAM B2 reference case scenario implies an increasing fraction of land coming under direct agricultural management. This in tum leads to emissions from deforestation. Deforestation rates depend on time and the rate of technology improvement. In the MiniCAM B2 0.5% productivity growth case, emissions rise until the middle of the century, eventually reaching four billion tons of carbon per year. Beyond the middle of the century the rate of change in land use slows and finally halts dropping deforestation emissions to zero. Against this background the imposition of a constraint on 4 Though this result requires hydrogen and fuel cell technologiesto improve relative to present technologies. As Edmonds, et al. 2002 discuss, if this progress lags, the hydrogen market may never form.

1431 emissions has the effect of expanding the demand for land to provide biomass energy. This in turn fuels the continued expansion of managed lands into the unmanaged ecosystems and sustains the rate of landuse emissions about a quarter century beyond the non-climate control case. When agricultural productivity increases to 1.5% per year, land-use emissions are significantly reduced. The maximum emissions are relatively stable through the middle of the century at which point they begin to decline and eventually enter a regime of net global reforestation. The effect of a constraint on the concentration of CO2 has a similar effect at 1.5% agricultural productivity growth to its effect at 0.5% productivity growth. That is, it delays the decline in emissions in the second half of the century. The reason that land-use emissions are relatively insensitive to the constraint in the first half of the century is the fact that carbon values are relatively low and the demand for land for commercial biomass remains small. The interaction between agricultural productivity, food prices and climate change is similarly noteworthy. In the absence of climate change, crop prices decline continuously over the course of the century. MiniCAM B2 100% 90% 8O% 70% 60% 5O% 40% 3O% 20% 10% 0%

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Figure 2: Managed and unmanaged land use--1990 to 2095 The decline goes on somewhat faster when agricultural productivity is higher, but unless productivity growth falls below 0.5% per year, crop prices end the century at a lower level than they began the century and with a 1.5% productivity growth rate are about one third lower. The imposition of a ceiling on the concentration of CO2 of 550 ppmv alters that pattern. The competition for land by commercial biomass leads to an increase in land values and land rents, reducing the extent of crops, pastures and forests, and which in turn raise crop prices. The rise in crop prices is highly sensitive to agricultural productivity growth rates. When agricultural productivity growth rates are 0.5% per year, year 2095 crop prices are double 1990 prices. When agricultural productivity growth rates are 1.5% per year, year 2095 crop prices are very near their 1990 levels.

1432 INTERACTIONS WITH CARBON CAPTURE AND DISPOSAL In the analysis reported above the ability to capture carbon from waste gas streams and dispose of it in permanent, reservoirs was not available. While issues surrounding this technology are discussed in greater detail in Edmonds, et al. (2002), some interesting interactions occur with commercial biomass. The presence of carbon capture and disposal technologies makes it possible for fossil fuels to be used while emitting carbon at dramatically lower rates 5. In addition, it opens the possibility that carbon can be removed from commercial biomass creating an energy form which effectively removes carbon from the atmosphere net. While interactions are too many and too varied to report in this brief paper, it is worth noting that the availability of carbon capture and disposal technology dramatically reduces the marginal value of a ton of carbon, cutting it by two-thirds. This reduces the extent of land area needed for commercial biomass, reducing the pressures to deforest. The upward pressure on crop prices exerted by the requirement to stabilize CO2 concentrations is also significantly reduced. Nevertheless, when the concentration of CO2 is stabilized biomass remains as attractive a feedstock for hydrogen production in the presence of carbon capture and disposal technology as without, owing to the fact that biomass derived hydrogen can be a negative-emission fuel.

FINAL THOUGHTS The value of biotechnology in stabilizing the concentration of CO2 in the atmosphere is substantial by any number of metrics. The value of a ton of carbon is reduced by a third when agricultural productivity growth rates rise from 0.5% per year to 1.5% per year, while food grain prices are reduced by almost half. The 1.5% per year productivity growth rate decreases the intrusion into unmanaged ecosystems by half compared with the 0.5% per year agricultural productivity growth rate. To the extent that biotechnology can raise agricultural productivity, including productivity in commercial biomass crops, traditional crops, pastures, and forests, the cost of stabilizing the concentration of CO2 in the atmosphere can be reduced.

REFERENCES 1. Edmonds, J., J. Clarke, J. Dooley, S. H. Kim, S. J. Smith. 2002. "Stabilization of CO2 in a B2 World: Insights on The Roles of Carbon Capture and Disposal, Hydrogen, and Transportation Technologies," submitted to Energy Policy, Special Issue, J. Weyant and R. Tol (eds.). 2. Edmonds, J., M. Wise, R. Sands, R. Brown, and H. Kheshgi. 1996. Agriculture, Land-Use, and Commercial Biomass Energy: A Preliminary Integrated Analysis of the Potential Role of Biomass Energy for Reducing Future Greenhouse Related Emissions. PNNL-11155. Pacific Northwest National Laboratories, Washington, DC. 3. Nakicenovic, N., et al. 2000. Special Report on Emissions Scenarios. Cambridge University Press, Cambridge, United Kingdom. 4. United Nations. 1992. Framework Convention on Climate Change. United Nations, New York. 5. Wigley, T.M.L., R. Richels & J. A. Edmonds. 1996. "Economic and Environmental Choices in the Stabilization of Atmospheric CO2 Concentrations," Nature. 379(6562):240-243.

5In this analysis the carbon removal efficiencyis assumed to be 90%.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1433

THE CONTROLLED EUTROPHICATION PROCESS: USING MICROALGAE FOR CO2 UTILIZATION AND AGRICULTURAL FERTILIZER RECYCLING.

J.R. Benemann l, J.C. Van Olst 2, M.J. Massingill 2, J.A. Carlberg 2, J.C. Weissman 3, and D.E. Brune 4 1Consultant, 3434 Tice Creek Dr. No. 1, Walnut Creek, California, 94595, USA 2Kent SeaTech Corp., 11125 Flintkote Ave., Suite J, San Diego, California, 92121, USA 3SeaAg, Inc., 705 27th Ave. S.W., Suite 5, Vero Beach, Florida 32968, USA 4Agficultural & Biological Engineering Dept., Clemson University, Clemson, South Carolina, 29634, USA

ABSTRACT

In 1960, Oswald and Golueke [1] presented a conceptual techno-economic analysis, "The Biological Transformation of Solar Energy", proposing the use of large-scale raceway ponds to cultivate microalgae on waste nutrients and then to ferment (anaerobic digestion) the algal biomass to methane fuel. The methane was to be converted into electricity, with the CO2-containing flue gas and the nutrient-containing digester effluents recycled to the ponds to support further algal production. Over the past forty years a great deal of research has been carried out on this and similar concepts for microalgae fuels production and CO2 utilization. However, significant technical challenges have limited the practical application of this technology: the difficulties of maintaining selected algal species in algal mass cultures, the lower-than anticipated biomass productivities and methane yields, and, in particular, the high costs of harvesting the algal biomass. These limitations could be overcome through further research and technology development and by integrating biofuel production with wastewater treatment and nutrient recovery, providing for additional economic and environmental benefits, in particular where relatively large scales are possible. One potential site for such a large-scale integrated process is the Salton Sea in Southem Califomia, a shallow (average 10 m depth) large (900 km 2) inland lake located below sea level and, thus, without an outflow. About 10,000 tons of nitrogen (mostly as nitrate) and phosphorous (as phosphates) are discharged annually into the Salton Sea by three rivers that drain wastewaters from population centers and drainage waters from large tracts of irrigated agriculture. Removal of nutrients from these inflows is required to avoid eutrophication of this large lake with resulting massive algal blooms, fish kills and other environmental impacts. Nutrient capture could, in principle, be accomplished with 1,000 hectares of algal pond systems, assuming a production of 100 tons of dry weight biomass per hectare per year (t/ha/y) and a typical 10 % N and 1% P content in the harvested algal biomass. This biomass could then be converted into biofuels with the residual sludge used in agriculture for its fertilizer value. As stated above, a major limitation of such a process is the harvesting of the algal biomass, which is expensive using current technology. The "Partitioned Aquaculture System" (PAS), developed at Clemson University, integrates microalgae production with fish aquaculture in a process that promotes a vigorous algal culture of desirable species and converts these into a sedimentable biomass through the production of fish fecal pellets. An adaptation of the PAS, the "Controlled Eutrophication Process" (CEP), has been designed and is being tested by Kent SeaTech Corp. to achieve the objective of nutrient removal from the Salton Sea influents. The CEP, by producing a combination of valuable outputs, including fuels, fertilizers and fish, could help to affordably manage the Salton Sea environmental quality while also abating substantial quantities of greenhouse gases.

1434 INTRODUCTION: MICROALGAE APPLICATIONS IN ENVIRONMENTAL PROTECTION. Microalgae ponds have been used for several decades for the treatment of municipal and other wastewaters. In these, so called "facultative ponds", the microalgae mainly provide dissolved oxygen for bacterial decomposition of the organic wastes [2]. The major limitations of this technology are the relatively large areas required and the high cost of removing the algal cells from the pond effluents, using chemical flocculation-sedimentation, centrifugation or other means. Shallow (< 0.5 m depth) raceway-type ponds, with channels and mechanical mixing ("high-rate ponds"), were introduced in the 1950's [3] allowing much higher productivities and thus higher loadings than the conventional unmixed, deeper (> 1 m deep) facultative ponds. High rate ponds also exhibit higher algal cell densities, making algae removal, that is harvesting, an even more critical requirement. Paddle wheel mixing provides a controllable and flexible mixing regime that allows management of the pond culture to promote algal cells that tend to spontaneously flocculate and settle [4]. However, it has not been possible to demonstrate such a "bioflocculation" processes with the high reliability required for algal harvesting from municipal wastewater treatment or similar applications. Thus, in current design practice, large settling or "maturation" ponds follow the high rate ponds, just as in the case of facultative ponds, though these are only partially effective in reducing algal solids in the effluents. This greatly increases the area ("footprint") of such systems and often prevents the discharge of the treated pond effluents to rivers or lakes, requiting their use in ground water recharge, irrigation or similar applications. Development of more intensive, smaller footprint, microalgal wastewater treatment processes based on high rate pond technology and low-cost algal harvesting remains a significant R&D challenge. One process that can accomplish this goal is the patented "Partitioned Aquaculture System" (PAS) [5, 6, 7], now being tested at the Salton Sea in a variation termed the "Controlled Eutrophication Process", further described below. Microalgae have also been extensively studied in other environmental applications. The removal of heavy metals from wastewaters with microalgae has been studied and commercial applications with immobilized algae were reported, though these could not compete commercially with ion exchange resins [8]. The removal of residual nutrients, specifically N and P from wastewaters, so-called "tertiary treatment", has also been investigated. A variety of processes have been proposed, from attached algal cultures to the cultivation of thermophilic species in cooling reservoirs [9]. Microalgae are excellent for nutrient removal processes, with typical contents of N and P of about 10 and 1% respectively, on a dry weight basis, several-fold higher than for higher plants. Also, microalgae cultures are able to reduce residual nutrient concentrations to vanishingly low levels and even allow for a significant variability in N:P ratios, from about 3 to 30 N for each P, on a weight basis, depending on which is the limiting nutrient. Finally, microalgae cultures have been proposed as a method for fixation of CO2 and production ofbiofuels, of interest in greenhouse gas abatement. The first conceptual development of this idea was by Oswald and Golueke in 1960 [ 1], who prosposed a very large-scale system with dozens of large (40 hectare) high rate ponds, with the biomass harvested by a simple flocculation-settling step, and the concentrated algal sludge anaerobically digested to produce biogas (CH4and CO2). The biogas was to be used to generate electricity and the flue gas CO2, along with the nutrients in the digester effluents, used to grow more algae. Make-up water and nutrients (C, N, P, etc.) would be provided from municipal wastewaters. Their conceptual cost estimates suggested electricity generation costs similar to those projected at the time for nuclear power. A more detailed, design and engineering study of this concept [ 10] concluded that with favorable assumptions, in particular availability of a low-cost harvesting process, such systems could produce biogas competitively with then projected fossil fuel prices. From 1980 to 1995 the U.S. R&D effort in microalgae biofuels production centered on the Department of Energy (U.S. DOE) sponsored "Aquatic Species Program" (ASP), which aimed at producing algal oils for production ofbiodiesel [ 11 ]. More detailed engineering design and cost analysis studies were carried out by the ASP during the 1980's [12, 13], again with many favorable assumptions, in particular the achievement of very high productivities. A 0.25 hectare pilot plant in New Mexico [ 14] demonstrated the feasibility of outdoor microalgae cultivation on saline waters and efficient CO2 capture. However, the projected long-term R&D required for development of such dedicated biofuel production processes, led, among other factors, to the wind-down of the ASP. In Japan a very large (> US$200 million) govemment-sponsored program to develop microalgae biofixation of CO2 for greenhouse gas abatement, involving many private companies, was carried out during the 1990's. That program focused on closed photobioreactors, in particular optical fiber systems, and co-production of

1435 high value products [ 15]. Similar concepts are currently being developed in the U.S. with DOE support [ 16, 17]. Also during the 1990's several electric utility companies in Japan carried out microalgae R&D projects, including cultivation of microalgae on power plant flue gases in small ponds [18]. Most Japanese R&D efforts ceased by 2000, due to the very high costs of closed photobioreactors and the minimal potential of high-value co-products, although some microalgae biofixation R&D continues [ 19, 20, 21]. Recently, an "International Network on Microalgae Biofixation of CO2 and Greenhouse Gas Abatement" was formed comprising international energy agencies and companies to foment and coordinate R&D activities in his field [see Pedroni et al., in These Proceedings]. Microalgae biofixation of CO2 for greenhouse gas abatement requires open pond systems, as closed photobioreactors are much too expensive. However, even simple open pond cultivation systems are presently too costly for dedicated biofuel production, and such processes must include other co-products or co-services, such as wastewater treatment, fertilizer production and/or feed/food production, to make them economically competitive. One specific application is the use of microalgae to remove N and P from wastewaters, as discussed next. THE SALTON SEA AND THE CONTROLLED EUTROPHICATION PROCESS. Irrigation in desert or semi-desert environments often leads to soil salinity problems, due to surface evaporation, requiring drainage of the fields, thereby producing so-called agricultural drainage waters. These are typically high in salts and nutrients, principally nitrates and inorganic and organic phosphates. In Southern California, agricultural drainage systems used in the Coachella and Imperial valleys drain into the large, about 900 km 2, Salton Sea. The current Salton Sea began with the accidental flooding of the below sea-level Salton Sink in 1904 with Colorado River water. As the Sea has no natural outlet, salinity has increased through evaporation of the runoff and drainage from agriculture and settlements, presently reaching about 46 parts per thousand (ppt). The major sources of inflow to the Sea are (% of total): the Alamo River (45%), New River (45%) and the Whitewater River (10%). Total inflow, including runoff, ranges from 1 to 1.5 billion m 3 per year. As the Sea has increased in salt content it has seen a transition of ecosystems from freshwater to brackish, now reaching the tolerance limits of most fish. These environmental problems are exacerbated by high nutrients inputs, principally nitrates and phosphates. Proposed solutions to the salinity increases include evaporative ponds, desalinization plants and pumping saline waters to the Gulf of California. Evaporative ponds would require up to 20% of the total lake area, the other options are very expensive and energy consuming. One management plan is to install dikes within the sea near the freshwater inputs, creating fresh to brackish ecological zones C ecotones", Figure 1), where fisheries and wildlife could prosper, with the center of the sea continuing to increase in salinity. However, the large present inputs of N and P into the lake, about 10,000 and 1,000 tons/year (t/yr) respectively, create hyper-eutrophic conditions resulting in severe fluctuations in dissolved oxygen concentrations, leading to massive fish kills. These problems would not be remedied by the proposed salinity control measures alone. To reduce the nutrient loads to this lake, an adaptation of the PAS, Partitioned Aquaculture Systems, developed at Clemson University by the senior author (DEB) and colleagues [5, 6, 7], is proposed to be sited near the three main inlets to the Sea (see "PAS" in Figure 1). This modified process, now called the "Control!ed Eutrophication Process" (CEP), is in concept similar to the conventional PAS, in which algae are grown in typical high-rate ponds (raceway, paddlewheel mixed), with the algal culture passed through separate zones containing planktivorous fish, such as Tilapia. The fish convert most of the algal biomass into settleable solids (feces and pseudo-feces), which can be readily removed by fast settling ("high rate sedimentation"). Residual algal solids would be processed further by Tilapia or similar fish cultures and polished by chemical flocculation. The algal and fecal solids would be recycled to agricultural land as fertilizers, preferably after anaerobic digestion to produce biogas, a mixture of CH4 and CO2. Development of this process has been initiated by Kent SeaTech Corp. with two pilot-scale 3,000 m 2 high-rate pond ASP systems located next to the Whitewater River (near the north-west end of the Salton Sea, see Figure 2). The multiple products that would be generated from such a process, in particular the relatively high value fish, in addition to payments received for nutrient removal, would make such a process economically appealing and a candidate for early implementation. To remove most nutrients flowing into the Salton Sea, about 100,000 metric tons of algal biomass containing 10% N and 1% P would need to be produced annually, requiting in the order of 1,000 hectares (ha) of algal ponds. The scale of this system suggests that additional algal processes for nutrient removal at the Salton Lake, not requiting fish culture, would also be of interest.

1436 PAS

%

INTEP,ZO NE FLOW CONTROL DIKES

g PA8

Figure 1: Salton Sea, appx. 900 km2, showing proposed dikes creating fresh/brackish ecotones and PAS units (some 1% of total surface area) for high rate pond recovery of wasted nutrients and fish production.

Conceptual CEP Flow Diagram

Algae Growth Channel il O0 to 200 gpm/ac)

High-Flow M a x .~Igae R e m o v a l Loop

Slow-Rate Settling

~'

Low-Flow"Clear" Effluent Pathway

Clear

(100 to 200 gpm/ac)

Settling

Effluent --~ Whitewater River

~

. ~.__x

'Q..)

Figure 2: Controlled Eutrophication Process (CEP) Flow Diagram. Shown are the high rate ponds ("Algal Growth Channels") receiving Whitewater River inputs containing high nutrient (N and P) levels, followed by the main Tilapia production ponds, in which the algal biomass is converted into fish biomass, fecal pellets and algal flocs, removed in the sedimentation tanks ("High Rate Settling"). (Not shown is the CO2 supplied to the culture). Much of the flow is re-circulated through the high rate ponds with a portion of the treated effluent discharged through a smaller Tilapia culture, followed by slower sedimentation and final polishing of the effluent with chemical coagulants and settling of the flocs. The output is a purified effluent low in nutrients that would be returned to the Whitewater River for discharge into the Salton Sea.

1437 MICROALGAL BIOMASS SYSTEMS FOR FUEL PRODUCTION. As discussed above, extensive R&D has been carried out in the past on microalgae biomass production systems, including conceptual applications to the Salton Sea. Indeed, pioneering work in the 1960's and 70's already anticipated the establishment of large-scale algal ponds at or even in the Salton Sea, for nutrient (nitrate) removal and salinity control, with the algal ponds serving a dual function in salt evaporation and nitrate removal [22]. This early work demonstrated the conceptual rudiments of this approach, including the ability of algal cultures to grow on drainage waters and to remove nitrates. Over the years the Salton Sea featured in several genetic engineering cost analyses [10, 12], including one that developed cost estimates for a pilot-scale facility and full-scale (400 ha) microalgae fuels production plants on the shores of this lake [13]. The latter studies [12, 13] addressed the production of algal oils for conversion to biodiesel. The relatively high cost of oil extraction and biodiesel production makes methane (biogas) generation fi'om algal biomass by anaerobic digestion for on-site power generation a more attractive alternative. An initial cost estimate, based on a recently updated study [23], for a microalgae-biogas production process applied to nutrient removal at the Salton Sea suggests that the total capital investment would be some $40,000/ha. This would be for a 400 ha system with about 50 individual earthen growth ponds of the paddle wheel mixed high-rate pond design. The overall design is essentially a scaled-up version of commercial microalgal production systems, such as the Spirulina producing Earthrise Farms, Inc. plant located near the South shore of the Salton Sea. Major differences would be the use of dilute (appx. 10%) CO2 obtained from the power plant flue gas (rather than the pure CO2 used in Spirulina production), the clay (rather than plastic) lining of the ponds, and the harvesting by spontaneous bioflocculation-sedimentation (rather than with screens), and the use of anaerobic digestion (rather than drying) for the processing of the biomass. Operating costs would be for the power consumed in the process (considered below), for labor and for minor inputs, such as, possibly, flocculating aids, for a total of some $4,000/ha-yr. With annualized capital related charges (taxes, maintenance, insurance, depreciation and cost of capital) at 20% of total investment, this would result in a total cost of $12,000/ha-yr. Assuming an average productivity of 30 g/m2/day and 90% operating capacity, or 100 t/ha-yr (a lower productivity than assumed in other recent studies), total costs would be about $120/t biomass. Net electricity production from the biogas, after deducting parasitic electricity consumption (including an allowance for generation costs), is estimated at 700 to 1,000 kWhr/t of biomass, or a current fuel value of $20 to 50/t of algal biomass. The remainder of the costs of production would be covered from the use of the digester effluents as agricultural fertilizers and the environmental credits for reducing nutrients loadings to the Salton Sea, and for greenhouse gas abatement. Although the $ value per ton of algal biomass of these benefits is not yet well defined, they do appear, in combination, to be exceed the projected biomass production costs. The CEP, through the additional production of fish, would be economically even more advantageous, even considering the additional costs of the fish component. In any event, achieving the goals of low-cost microalgae production requires improvements in algal cultivation processes, increased biomass productivities, low cost harvesting and improved processing. Indeed, the above projected cost of $120/t biomass is far below current costs of commercial algal biomass production, of at least $5,000/t (estimated plant-gate cost for producing dried Spirulina at Earthrise Farms, Inc.). This great disparity between current reality and future projections can be ascribed to several factors: economies of scale (ten-fold larger sizes for growth ponds as well as the overall plant), the greatly simplified process (e.g. no drying, no cost for the nutrients, water or CO2), and three-fold higher productivity (30 g/m2/day) than current commercial Spirulina production. Regarding the latter point, for several reasons, commercial Spirulina culture is of rather low productivity and the projected productivities are well within present experience. Even higher productivities may be achievable through genetic engineering [21, 24], though that research still has to be brought from the laboratory into outdoor pond culture. In summary, microalgae processes for fuel production and greenhouse gas mitigation must be a component of or integrated with other processes, such as nutrient removal from municipal and other wastewaters, fish aquaculture waste treatment (the PAS), a combination of both (e.g. the CEP), and/or processes with large volume co-products, such as fertilizers, chemicals or animal feeds. A potential example of the latter could be the conversion of high-starch algal biomass to ethanol and animal feeds, in analogy with current U.S. corn-to-ethanol production. Such a process could become economically competitive if similar governmental subsidies were available to microalgae as for the corn-ethanol industry. In any event, such multipurpose processes could have relatively short development times, 5 to 10 years (Pedroni et al., These Proceedings].

1438 CONCLUSIONS: MICROALGAE PROCESSES FOR GREENHOUSE GAS ABATEMENT.

Greenhouse gas abatement by microalgae processes is based on the production of renewable fuels replacing fossil fuels and on the other co-products and co-processes derived thereof. A net output of 1,000 kWhr/t of biomass represents 0.8 tons of CO2 abated, based on averaging CO2 emissions of natural gas and coal-fired power plants. The nitrogen contained in the anaerobic digestion residuals would add some 0.3 t of CO/ abated, based on the natural gas used in fertilizer production. In municipal wastewater treatment, microalgae processes would accrue abatement credits from reductions in energy consumption and CH4 and N20 emissions, compared to conventional processes (e.g. activated sludge) [25, 26]. The water resources reclaimed by microalgae waste treatment processes could add to their greenhouse gas abatement credits. Even larger greenhouse gas abatement credits could be projected for the CEP, by comparing the greenhouse gas emissions from conventional animal protein production to that of fish aquaculture systems. Even though the overall value ($/t biomass or S/ha) of greenhouse gas abatement would likely be modest, it could in many instances make the critical contribution to the economic viability of such processes. One difficulty in estimating greenhouse gas reductions is the highly site-specific nature of such systems and a complicating factor is their seasonal variability, a particular challenge in the case of wastewater treatment. These complexities and uncertainties make it difficult to assess the overall potential of microalgae processes to reduce greenhouse gas emissions nationally or globally. Nevertheless, in aggregate, microalgae systems provide many opportunities for greenhouse gas abatement and can make a significant contribution to the global efforts to abate greenhouse gases, in addition to their other environmental and economic functions. REFERENCES.

.

6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26.

Oswald, W.J., and Golueke, C.G. (1960). Adv. Appl. Microbiol., 11,223 - 242. Oswald, W.J. (1988). In M. Borowitzka, (ed.). Microalgae Biotechnology, Cambridge U. Press. Oswald, W.J. (1963). Dev. Ind. Microbiol., 4:112-125. Benemann, J.R., Koopman, B.L., Weissman, J.C., Eisenberg, D.M. and Goebel P. (1980). G. Shelef and C.J. Soeder (editors) Algae Biomass: Production and Use, Elsevier, Amsterdam, pp 457-496 Brune, D.E., Collier, J.A., Schwendler, T.E. (2001), U.S. Patent No. 6,192,833, February 27, 2001. Bnme, D. E., Collier, J.A. Schwedler, T.E., and Eversole, G.A. (1999). ASAE.Paper No. 99-5031. Brune, D.E. and Wang, J.-K. (1998). Aquaculture Magazine 24:63 - 71. Wilde, E., and Benemann, J.R., (1993). Biotechnology Advances. 11:781-812. Weissman, J.C., Radway, J.C., Wilde, E., and Benemann, J.R. (1998). Biosources Tech. 65: 87-95. Benemann, J.R., Pursoff, P., Oswald W.J. (1978). Engineering Design and Cost Analysis of a LargeScale Microalgae Biomass System, U.S. Dept. Energy, NTIS #H CP/T1605-01 UC-61. pp. 91. Sheehan, J., Dunahay, T., Benemann, J., and Roessler, P. (1998) A Look Back at the U.S. Department of Energy's Aquatic Species Program -Biodiesel from Algae". NERL/TP-580-24190. Benemann, J.R., Goebel, R.P. Weissman, J.C. Augenstein, D.C. (1982). Microalgae as a Source of Liquid Fuels, Final Report to the U.S. Department of Energy, pp. 202. Weissman, J. C. and Goebel, R.P. (1987). Design and Analysis of Pond Systems for the Purpose of Producing Fuels, Final Report, Solar Energy Res. Inst., Golden CO, SERI/STR-231-2840 (1987). Weissman, J.C. and Tillett, D.T. (1992). In Aquatic Species Project Report, FY 1989-1990, pp.32-56, NREL, Golden Co., NREL/MP-232-4174 (1992). Usui, N., and Ikenouchi, M. (1996). Energy Conserv. Mgmt. 38:$487 - $492. Bayless, D., Brown I.I., Cooksey, B., and Cooksey, K.E. (2002). 1st Cong. Intl. Phyc. Soc. pp. 201. Olaizola, M., Mazzone, E., Thisltehwaite, J., Nakamura, T., and Masutani, S. (2002). Ibid pp. 219. Ikuta, Y., J.C. Weissman, J.C., and Benemann, J.R. (2000). Technology 75:137 - 145. Hase, R., Oikawa, H., Morita, M. and Watanabe, Y. (2000). J. Biosci. & Bioeng. 89:157 -163. Nagase, H., Yoshihara, Hirata, K., and Miyamoto, K. (2001). Biochem. Eng. J., 7:241 - 246. Nakajima, Y., Fujiwara, S., and Tsuzuki, M. (2002). Abstracts, 1st Cong. Intl. Phyc. Soc. pp. 151. Brown, R.L. (1971). Removal of Nitrate by an Algal System. Dept. Water Resources, California Benemann J.R. and Oswald W.J. (1996) Systems and Economic Analysis of Microalgae Ponds for Conversion of C02 to Biomass, Final Report, Pittsburgh Energy Technology Center, pp.260. Polle, J.E., Benemann, J.R., Tanaka, A., and Melis A. (2000). Planta 211:335 -344. Benemann, J.R. (2002). Greenhouse Gas Emissions and Potential for Mitigation from Wastewater Treatment Processes. Report to the Electric Power Research Institute and U.S. Dept. of Energy. Green, F.B., Lunquist T.J., and Oswald, W.J. (1994). Wat. Sci. Tech., 30:9-20 (1994).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1439

T H E I M P R O V E M E N T OF M I C R O A L G A L P R O D U C T I V I T Y B Y REDUCING LIGHT-HARVESTING PIGMENT - A N A L Y S I S OF A P H Y C O C Y A N I N - D E F I C I E N T M U T A N T OF S Y N E C H O C Y S T I S PCC 6714 Yuji Nakajima l), Shoko Fujiwara2) and Mikio Tsuzuki 2) lAdvanced Technology Research Center, Mitsubishi Heavy Industries, Ltd. 2School of Life Science, Tokyo University of Pharmacy and Life Science

ABSTRACT

We have achieved the improvement of photosynthetic productivity in a continuous culture system at high cell density under high light intensity using a mutant with a small content of light-harvesting pigment of Synechocystis PCC 6714 (PD-1). We analyzed the sequence and the expression of the cpc operon encoding phycocyanin subunits and linker polypeptides in the wild type and PD-1. The sequences of cpc operon were identical in the wild type and PD-1. However, there was a single-base substitution (from T to C) at 5 base upstream of transcriptional initiation site of the cpc operon. The results of northern blot analysis and in vivo transcription activity of the promoter show that the phycocyanin-deficiency ofPD-1 is due to the substitution in the promoter region of cpc operon. We expect that this kind of single-base substitution will contribute to microalgal breeding for mass culture and microalgal products. These results will make a contribution of CO2 biofixation. INTRODUCTION

Microalgae have a high photosynthetic activity on a per unit surface area, so that microalgal mass cultivation has been regarded as useful for CO2 fixation. Furthermore, microalgal mass cultivation can produce algal materials such as industrial materials and food resources, so that many techniques for microalgal mass cultivation have been developed. For the photosynthetic organisms, especially in a commercial mass production, the light energy is essential, because they are mostly cultivated photo-autotrophically. Many devices and much effort have been put into improvement of culture systems using sunlight as to increase algal production. In many cases ofmicroalgal mass production, the algal cell suspension is designed to be so high to absorb the light thoroughly, because the dense microalgal culture minimizes the leakage of received light energy and also helps to reduce the cost of algal harvest. When the culture is conducted at high cell density, however, the photosynthetic productivity can never be increased in proportion to the light intensity under high light intensity, such as sunlight. In many algal species, it is well known that the light-harvesting pigment (LHP) content is changed from high to low when the light intensity is changed from low to high. The LHP content of an alga in the dense cell suspension is high even under high light intensity because of acclimation. Mutual shading in the dense suspension leads the LHP content high even under high light intensity. When the microalgal mass cultivation is conducted under high light intensity and the cells with high LHP content by the acclimation are brought to the irradiated surface by mixing under such a high light intensity, the cells at the irradiated surface can absorb more light energy than that usable for the photosynthetic reactions. The excessive light absorption would cause not only a loss of light energy but also photoinhibition of photosynthesis. The idea of reducing the LHP content is to mitigate the above unfavorable effects caused by

1440 the high LHP content which is inevitably caused by the algal adaptation in a dense culture. The idea was reviewed in detail by Benemann (1989) and was confirmed to be effective using a phycocyanin (PC)-deficient mutant (PD-1) of Synechocystis PCC 6714 (Nakajima and Ueda 1999). The PC is a major LHP in Synechocystis PCC 6714. The PC content on a cell basis was one-third in PD-1 as high as that in the wild type, although the maximum photosynthetic activity as well as the contents of photosystems and chlorophyll (Chl) in PD- 1 was almost the same as in the wild type (Nakajima and Ueda 1997). As we expected, PD- 1 showed 1.5 times higher productivity than the wild types in a continuous culture system at high cell densities under high light intensities. The same results were also with the wild type and the small LHP mutant of Chlamydomonas perigranulata (Nakajima et al. 2001). If the technique of reducing the LHP content is applicable in other strains, the improvement of photosynthetic productivity could be more realistic. Since PD-1 was obtained by nitrosoguanidine mutagenesis, there was no mutation tag. In order to obtain such a mutation tag, we had to start the research for analyzing the mechanism of the PC-deficiency in PD-1. We have considered that the mutation in PD-1 would be attributable to a defect in PC subunits and/or linker polypeptides. The PC-deficiency in PD-1 might be caused by reduction of the rate of biosynthesis or stability of the polypeptides or phycocyanobilin in PC, or the linker polypeptides. In this study, we examined sequence of cpc operon and then found a single-base substitution. Then, we introduced a DNA fragment including the mutation site into a transformable strain, Synechococcus PCC 7942. The results suggest a possibility of improvement of photosynthetic productivity by genetical mutagenesis. BODY OF PAPER

Materials & Methods

Cells and culture conditions The mutant strain, PD-1, of Synechocystis PCC 6714 was kindly supplied by Prof. Fujita of Fukui Prefectual University. The wild type and PD-1 mutant of Synechocystis PCC 6714 were cultured under white light at 25 °C in an MDM medium With a supply of air containing 1% CO2 (Nakajima and Ueda 1997). The culture was conducted in an oblong flask at 50 ~tmol photon m 2 s1. Cells in the late exponential growth phase were used for DNA and RNA extraction. In order to determine the promoter activity of the upstream region of the cpc operon, Synechococcus PCC 7942 was used as a host organism, which was cultured under white light at 30 °C in BG11 medium with a supply of air containing 3% CO2. The culture was also conducted in an oblong flask at 50 ~tmol photons m 2 s". The cells in the exponential growth phase were harvested and used for transformation.

Isolation of DNA and RNAfrom Synechocystis PCC 6714 Genomic DNA of Synechocystis PCC 6714, as a template for the PCR reaction, was isolated using a GNOME kit (Qbiogene, Carlsbad, CA, U.S.A.) or a GenomicPrepa~ (Amersham Pharmacia Biotech, Buckinghamshire, England) according to the supplier's manual. Total RNA was prepared by the hot-phenol extraction method as follows. Cells were harvested and then suspended in 3mL of 20 mM sodium acetate containing 0.5% SDS and lmM EDTA. An equal volume of buffered phenol was added to the cell suspension. After the incubated for 10 min at 60 °C, the suspension was centrifuged for obtaining the aqueous phase. The aqueous phase was treated with chloroform, and was precipitated by ethanol. The precipitate was purified by the CsC1 ultracentrifugation method.

Northern blot analysis Equal amounts of total RNA were separated by electrophoresis in formaldehyde-containing gels and then transferred to nylon membranes. The RNA separated by electrophoresis fixed on the membranes was hybridized with radio!abeled nucleic acid probes for the cpcA, cpcB, cpcC1, cpcC2, cpcD, cpcE, cpcF, cpcG1, cpcG2, apcA andpsbAI genes. These probes were prepared by means of the PCR reaction with reference to the sequence of Synechocystis PCC 6803 (Kaneko et al. 1996).

1441

Transformation ofSynechococcus PCC 7942for the promoter assay A plasmid, pAM1414 (Andersson et al. 2000), which was kindly provided by Prof. S. S. Golden of Texas A&M University, was used as a vector for the construction of promoter-reporter fusions. This plasmid carries the promoterless luxAB gene of Vibrio harveyi, two parts of the neutral site I (NSI) of Synechococcus PCC 7942, a spectinomycin-resistant gene and pBR322 replicon. The DNA fragments (763 bp, -767 - -4) of the upstream region of cpcB amplified using the wild type and PD-1 DNA were ligated into NotI / BamHIdigested pAM1414 to construct pANY 1 and pANY2, respectively (Figure 1). The Synechococcus PCC 7942 wild strain was transformed with pANY1 or pANY2, which yielded spectinomycin-resistant colonies. These transformants carried the upstream region of cpcB were the luxAB fusion at the neutral site I (NSI) of the chromosome, as a result of homologous recombination.

~

Upstream region on the cpc operon

Synechococcous PCC 9742 NS1

NS1 ~SpR Transformant ~mt Ii!!::i;::i~ Figurel: Construction of plasmids for the promoter assay. The upstream region of the cpc operon of the wild type (for pANY1) and PD-1 (for pANY2) was ligated into the cloning sites, NotI and BamHI, of pAM 1414. The plasmids have a segment of DNA from the Synechococcus PCC 7942 chromosome (NSI) that mediates homologous recombination with the chromosome.

Assaying of Bioluminescence The bioluminescence of the cell suspension was determined with a luminometer (Lumat LB9501, Germany) immediately after the addition of n-decanal. The intensity of the bioluminescence was expressed in RLU per minute per micromole of Chl. Chl was repeatedly extracted with hot acetone (80% v/v), and its content was calculated using the coefficients. RESULTS & DISCUSSION

Analysis ofcpc operon in Synechocystis PCC 6714 To clarify the mutation site in PD-1, we determined the complete sequence of the cpc genes in the wild type and PD-1 by direct sequencing of PCR products (from 822 bp upstream of the translational start codon of cpcB to 280 bp downstream from the stop codon of cpcD). The primer pair in order to obtain the DNA fragment was designed with reference to the sequence of Synechocystis PCC 6803 (Kaneko et al. 1996), which is related species of Synechocystis PCC 6714. The sequence revealed that 259 bp upstream of the predicted initiation codon of the cpcB was T in the wild type, while it was replaced by C in PD-1 (Figure 2). The recent experiment revealed that this substitution had been occurred at 5 base upstream of transcriptional initiation site of the cpcB (Imashimizu et al. Unpublished data). No other difference was observed in the upstream region of cpcB. The expression of cpc genes in both cell types was investigated. The pattern on Northern blot analysis of both types and the complete sequence of cpc operon suggested that cpcA, cpcB, cpcC1, cpcC2 and cpcD constitute an operon, in the order (Figure 3, data not shown for cpcA, cpcC1 and cpcC2). The results of

1442 Northern analysis ofPD-1 demonstrated that the levels of the cpcB, cpcA, cpcC1, cpcC2 and cpcD transcripts were one-tenth to one-sixth as high as those in the wild type (Figure3, data not shown for cpcA, cpcC1 and cpcC2). However, the mRNA levels ofpsbA1 and other phycobilisome genes were almost the same in the two cell types (Figure 3, data not shown for cpcA, cpcC1, cpcC2,, cpcE, cpcF, cpcG1 and cpcG2,). These results indicate that the PC-deficient mutation in PD-1 is due to reduction in the transcription of the cpc operon. -I0 region -300

AAGACGTAACAGACAGAAGTTGCACCAGCATT~TATAAAIGT T A A C ~ IGTGG

-250 -200 -150 -i00 -50 1

GATTGCAAAAGCATTCAAGCCTAGGCATTGAGCTGTTTGAGCGTCCCGTT GGCCCTGTGTCTGTGTCTGTAACTTTCCCTTGGGTTGAGCTGGATAACGC CTCTCATAAATTCCCTTGGTAACCAAAGAAAGTTTTATGGAGAGCAGCCA 'TAATCATTCCGGGGTCACTGCTTTGGACTCCCTCACTTAATACGAGGGAA TTGTGTTTAAGAAAATCCCAACTCATAAAGTCAAGTAGGAGATTAATTCA ~TGTTCGACGTATTCACTCGGGTT >

C

cpc B Figure 2: Nucleotide sequence of the upstream region of the cpc operon. This nucleotide sequence is presented from the translational start codon of cpcB to 300 bp upstream of cpcB. In PD-1, T is substituted for C at 5 bp upstream of the transcriptional initiation site (+1) of the cpcB, which was confirmed by primer extension. Rest part of sequences are identical in the two cell types.

nsbAl

ancA

cncB

cncD

4.4Kb ---*

iiii,ii'il!ii:i~i

2.4Kb ---*

Ii~i~i~'~ i:i<~ ~!!,iS:i:; .....

1.4Kb

WP

WP

WP

WP

Figure 3: Northern analysis of the wild type and PD-1. Northem hybridization analysis was performed on the wild type (W) and PD-1 (P) of Synechocystis PCC 6714. Total RNA was hybridized with psbAI, apcA, cpcB and cpcD as probes. The arrows indicate the transcripts probed with cpcB or cpcD.

Promoter activity of the cpc operon To confirm that the nucleotide substitution affects on the promoter activity, weconstructed vectors for the promoter assay, pANY 1 and pANY2, which contained the upstream region of the cpc operon of the wild type and PD-1, respectively. The spectinomycin-resistant transformants of Synechococcus PCC 7942 were checked by PCR (Figure 4). The bioluminescence activity of the transformant with pAM1414 was very low, as in the host cells (Table 1). However, bioluminescence was clearly detected for the transformants with pANY1 and pANY2. This indicates that the upstream region of the cpc operon of each cell type is responsible for the promoter activity. Furthermore, the bioluminescence activities of the transformants with pANY1 were 6 - 1 0 times as high as those with pANY2. This result coincided with the tendency shown by Northern analysis of the cpc operon (Figure 3). Strictly, the bioluminescence activity reflects the amount of luciferase protein, not the abundance

1443 of the luxAB mRNA. However, it can be considered that the bioluminescence activity reflects the mRNA abundance to some extent, when the activity is compared among cells which have been incubated under the same condition. Then, the result ofbioluminescence activity suggests that the mutation in the upstream region of the cpc operon in PD- 1 is a cause of reduction of the gene expression. This implies that the reduction of the mRNA levels of the cpc operon in PD-1 is due to the mutation in the cis-acting element, not in a trans-acting factor. In this study, the promoter activity was measured in Synechococcus PCC 7942 with an available vector, pAM1414. Although Synechococcus PCC 7942 has a different genetic background from Synechocystis PCC6714, the promoter assay in PCC 7942 demonstrated that the promoter activity of the PCC 6714 wild type DNA fragment was higher than that of the PD- 1 DNA fragment, as was shown for the m R N A levels ofthe cpc operon in the wild type and PD-1 of PCC 6714. This indicates that the promoter activity of the cpc operon is affected by the cis-acting sequence in both cyanobacterial species.

Primer 1

Primer 2

Transformant ~ : i [i::::::::::i~ NS1 gpR

6.3 (~bp

--.

÷ 5.5

Upstream region on the cpc operon

÷ 1.0 1

2

3

4

5

6

Figure 4: Confirmation of the transformants. The transformants were confirmed by the lengths of the PCR products. A primer pair, primers A (5'-GACGAGGCCATTGAAGAAGG-3') and B (5'-TACGCTGCAAGTCCAGAAC-3'), was designed to amplify the 1.0 kb DNA fragment at the NSI site in the Synechococcus PCC 7942 genome. Lanes 1 and 2 are the host and transformant with pAM1414, respectively. Lanes 3 and 4 are the transformants with pANY1, and lanes 5 and 6 the transformants with pANY2. The numerals at the right indicate the lengths of the DNA fragments. TABLE 1 PROMOTER ACTIVITY EXPRESSED BY luxAB. Transformant

Bioluminescence Strain

Host

1.6 +

pAM 1414(none) pANY 1(wild type)

pANY2(PD-1)

(Photon pmol Chl moF 1 min -I ) 1.2 + 0.2 0.4

1

135.9 + 16.6

2

159.9 + 19.6

1

13.3

±

2.0

2

8.8 ±

1.7

3

21.2 ±

7.6

Bioluminescence measurements were conducted to detect the promoter activity of the cpc operon. The values represent the means of triplicate experiments with the standard deviations. The mutation in PD-1 is a single-base substitution in the short spacer between the 3' end of t h e - 1 0 region and the transcriptional initiation site, which is not conserved in other cyanobacteria. We are now continuing the research to clarify the relationships between the stability of the transcriptional initiation-complex and the

1444 sequence of the short spacer by performing experiments both in vivo and in vitro. The improvement of microalgal productivity is an urgent problem for microalgal mass production. We had analyzed the wild type and PD-1 of Synechocystis PCC 6714 to evaluate the effects of the LHP content on photosynthesis and productivity, and demonstrated that a reduction of LHP is effective for this problem, especially in mid to full sunlight (Nakajima and Ueda 1999). In this study, we indicated a gene manipulation strategy for improving microalgal productivity. In most cyanobacteria, PC is the major LHP of the PSII components. Therefore, techniques for site-directed mutagenesis of the cpc promoter in other commercial strains or exchange of the promoter to that of PD- 1 will be valuable for microalgal mass production.

REFERENCES

1. Andersson et al. (2000). Methods Enzymol. 305:527-542. 2. Benemann, J.R. (1989) The future of microalgal biotechnology. In Algal and Cyanobacterial Biotechnology. Edited by Cresswell, R.C., Rees, T.A.V. and Shah, N. pp. 317-337. Longman Scientific & Technical, Harlow, UK. 3. Kaneko et al. (1996) DNA Res. 3:109-136. 4. Nakajima, Y. and Ueda, R. (1997) J. appl. Phycol. 9:503-510. 5. Nakajima, Y. and Ueda, R. (1999) J. appl. Phycol. 11 : 195-201. 6. Nakajima, Y. and Ueda, R. (2001) J. appl. Phycol.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1445

EFFECTIVE CO2 REMOVAL BY CHLORELLA SP. HA-I IN VARIOUS CULTIVATION M E T H O D S

Ji-Won Yang*, Tae-Soon Kwon and Jae-Young Lee

Environmental Remediation Engineering Lab, Dept. of Chemical & Biomolecular Engineering, KAIST, 373-1, Guseong-dong, Yuseong-gu, Daejeon 305-701, Republic of Korea,

ABSTRACT In biological CO2 fixation, high growth rate and high cell density are necessary for effective CO2 removal. But it is difficult to obtain both aspects simultaneously in the conventional cultivation methods. So, in this study, the various cultivation methods were employed: fed-batch, medium replacement, and semicontinuous cultivation method. The high cell density and the moderate growth rate were obtained by replacing old medium by new medium. For the semi-continuous method, the characteristics of microalgal growth by dilution ratio were studied. The amount of CO2 fixation in the fed-batch cultivation method was less than that in the medium replacement cultivation method. Therefore, the semi-continuous cultivation was the most effective method to remove a large amount of CO2 for practical purpose.

INTRODUCTION Biological CO2 fixation using microalgal photosynthesis has many merits such as cheap initial cost and operation cost, no pre-treatment of flue-gas, and re-use of produced biomass, etc [2-4]. Most researches on the biological CO2 fixation have focused on the enhancement of CO2 fixation efficiency through the development of effective photobioreactors such as a con-shaped helical tubular photobioreactor [5], an internally illuminated photobioreactor [6] and an optical fiber reactor [7], etc. But there is a limitation in the improvement of the amount of CO2 fixation by the development of photobioreactor. Another alternative is the improvement by the control of operation methods. In previous studies [5-9], the batch and continuous operation methods were used for the biological fixation of CO2. These methods have certain drawbacks in the maintenance of CO2 fixation rate. In a batch operation, as cell density increased, the cell growth rate decreased because of the inhibition by shelf shading effects. On the other hand, the CO2 fixation rate in a continuous operation was not high as in a batch mode, although cell productivity could be maintained continuously. Consequently, it is necessary to develop new operation methods that can maintain CO2 fixation rate continuously during operation periods. Our present research is aimed to develop new operation methods for effective CO2 fixation to overcome limitations of conventional operation methods. Three mode of operation including fed-batch, medium replacement, and semi-continuous operation were proposed. The characteristics of COz fixation in each operation method were investigated. MATERIALS AND METHODS

Strain and Culture medium Microalgae used in this experiment was Chlorella sp. HA-1 obtained from NIES (National Institute of Environmental Studies, Japan). The strain can be cultivated relatively easily without concerning about a

1446 contamination problem by other strains. It also can withstand high concentration of C O 2 , i.e., well above 20 % [ 10-12]. The standard M4N medium was used for the cultivation of the HA-1 [12].

Photobioreactor Figure 1 shows the schematic diagram of the overall system. The reactor was constructed as a tubular type of 55 cm tall with an internal diameter of 9 cm (2 L in working volume). Light from fluorescent lamps (18 W, FL20SD/18, Kumho, Korea) was illuminated from the center of the reactor. The mixed air with CO2 was injected from the bottom of the reactor. Gas flow rate was 1 VVM (volume to volume per minute) and the concentration of CO2 supplied was 10% (v/v). The medium was maintained at a temperature of 30 °C throughout the experiment and the temperature was controlled by water jacket. Gas out

1:CO2 bomb 2: Air bomb 3: Mass flow controller 4: Gas flow meter 5: Humidifier 6: Fluorescent lamp 7: Photobioreactor

Water out

water in -~(temperature control)

3

!

4

T

Figure 1: The schematic diagram of the overall system

Fed-batch operation A fed-batch operation is the method that enhances the C O 2 fixation rate by injecting certain amount of medium into the reactor once a day. Microalgae can grow without exhaustion of nutrient by addition of medium. In this experiment, 100 ml fresh medium was supplied into the reactor every day.

Medium replacement operation To solve the accumulation of wastes after exponential growth phase, medium replacement operation was proposed. In the medium replacement operation, cells were separated from cell suspension in the stationary phase and the separated cells were re-suspended into the reactor with new medium. In this study, medium were replaced at intervals of a week and two ratios, 50 % and 100%, were used. Semi-continuous operation A semi-continuous operation is the method which replaces an appropriate volume of cell suspension with fresh medium [12]. Dilution ratio is defined as:

V D = --~

v~

(1)

where D is the dilution ratio, Vr is the working volume of reactor, and Vn is the volume of newly added medium. Dilution was done once a week when the microalgal growth was in stationary phase.

Analysis Cell growth was measured by optical density (O.D.) at 660 nm using a UV spectrophotometer (8562A, Hewlett Packard, U.S.A), which was converted into dry cell weight (DCW). DCW was obtained by drying 50 ml of the cell suspension at 105 °C for a day after filtering through the pre-dried and pre-weighted 0.45 lam filter papers. Nitrate and phosphate concentration in cell culture were determined by ion chromatography (Metrohm 732 IC, USA). The used column was Shodex IC SI-90 4E and the eluent was the

1447 mixture of 1.8 mM Na2CO3 and 1.7 mM NaHCO3. RESULTS AND DISCUSSION

Fed-batch operation Figure 2A shows the cell growth curve during 4 weeks in a fed-batch operation. The cell growth rates decreased gradually and cells did not grow during last week. Because the nutrients were still remained after the decrease of cell growth rate (Figure 2B), it was proved that the decrease of cell growth rate was due to the decrease of illumination and the accumulation of wastes. 1400

4-

1000 .,-,,. ..,I ..,.. 3

0 C)

2

[Ooo

0

1

o Oo o .o o o o o o oo-o

O, 0

....

, .... 5

, ....

, . . . . -.- . . .

10

15

Ooo

o.o.o.o.o ooo

o

, ....

20

25

5

o

30

10

15

20

25

"nine (day)

"nine (Day)

Figure 2A-B: Cell growth curve (A) and nutrient consumption curve (B) in a fed-batch operation

Medium replacement operation As shown in Figure 3, the cell growth rates were 0.307, 0.213, 0.121, and 0.038 g/L/day at replacement ratio of 50 %; 0.385, 0.105, 0.181, and 0.051 g/L/day at replacement ratio of 100 %, respectively. Also the final cell density, about 5 g/L, increased as compared with that of fed-batch operation, about 4 g/L. Because the accumulated wastes which inhibit cell activities were removed through replacing old medium by fresh medium, the cell growth was enhanced and the replacement ratio of 100 % showed better than that of 50 % in both cell growth rate and cell density. In comparison with fed-batch operation, medium replacement operation was more effective in CO2 fixation. But the cell growth rate still decreased due to the decrease of light intensity within the reactor. As shown in Figure 4A-B, because the nutrient was consumed periodically during operation periods, CO2 fixation was accomplished continuously during operation periods. Nevertheless, light intensity should be considered in the development of operation methods for more effective CO2 fixation.

O

5

4

0

A

O0~

O 0

2

~

" ~

H~/°

o/

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I

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,

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,

,

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, 10

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,

,

•

,

•

•

15

i

.

,. 20

.

.

.

.

,. 25

.

.

30

Time (Day)

Figure 3" Cell growth curve in a medium replacement method

1448

o

12oo

.

~

:..

o

o

/0

~o

!0

"o

"

too.

"~o i

6oo.

/

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;.

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:: / \

o

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:/~

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o

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8

o 400,

2130

, , ,, 0

, • • • • , .... 5

, ....

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, .... 25

50

. . . . 0

3o

,

*,

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5

,

. . . .

10

,

. . . .

15

, 20

. . . .

,

. . . .

30

25

"nn-e(Day)

Figure 4A-B: Nitrate consumption curve (A) and phosphate consumption curve (B) in a medium replacement operation

Semi-continuous operation In a semi-continuous operation, the cell growth rate was maintained constantly by dilution during operation periods, because the light intensity within the reactor was maintained through dilution when the inhibition of cell growth by decrease of illumination happened [8]. The effects of dilution ratio on the cell growth rate were described in Figure 5 and Table 1. When dilution ratio was too low to increase light intensity efficiently and supply sufficient nutrients, the cell growth rate was not enhanced by dilution. So the application of higher dilution ratio was necessary. From Table 1, as cell density was lowered after dilution by high ratio, the cell growth rate increased. But the cell growth was inhibited at too high dilution ratio, because the cell activities were reduced. Consequently, in order to maintain COz fixation rate efficiently, dilution ratio should be determined appropriately by consideration of cell density after dilution.

TABLE 1 COMPARISON

1st week

OF

CELL

GROWTH

RATE

2 nd week

IN SEMI-CONTINUOUS

OPERATION

4 th week

3rd week

growth rate (g/L/day)

Cell density after dilution (g/L)

Growth rate (g/L/day)

Cell density after dilution (g/L)

Growth rate (g/L/day)

Cell density after dilution (g/L)

Growth rate (g/L/day)

20%-40%-60%

0.360

1.546

0.224

1.427

0.216

0.908

0.281

20%-50%-80%

0.332

1.946

0.193

1.637

0.226

0.620

0.346

30%-50%-70%

0.348

1.415

0.241

1.163

0.244

0.901

0.276

30%-60%-90%

0.411

1.914

0.192

1.123

,0.260

0.696

0.364

50%-70%-90%

0.323

1.213

0.252

0.874

0.282

0.387

0.314

1449

.

-

.

•i o

-

•

A

.-

.~¢

I

. . . . . . . . -

. . . . 0

0 -

....... -

--v

.....

30*1,-6[W,-90%

m

--m

m

50*/.-70°/.-90*/.

i

5

-

2001¢rz0°1,.8001,

~

--

. . . .

30"1,-50010-70"1o

i

10

.

.

.

.

.

. 15

.

. . , i , , , i ,

. ~

~

firm (day) Figure 5: cell growth curve in a semi-continuous operation

CONCLUSIONS Although the biological CO2 fixation process using conventional operational methods shows high CO2 fixation efficiency, there are some limitations to be solved for practical application. The decrease of cell growth rate in a long-term operation was a main problem. The principal causes are the decrease of illumination within the reactor and the accumulation of wastes. In this study, fed-batch, medium replacement and semi-continuous operation methods were proposed to overcome limitations in a long-term operation. As a result, medium replacement operation had a merit to maintain the high cell density during operation periods. On the other hand, semi-continuous operation could obtain the high cell growth rate. In conclusion, the semi-continuous operation method is more effective in comparison with other operation methods and the consideration of cell density after dilution is most important to maximize the cell growth rate during operation periods.

ACKNOLOWGEMENTS The authors would like to acknowledge the financial support given by KEMCO (The Korea Energy Management Corporation), Republic of Korea.

REFERENCES 1. Jae-young Lee, Hyun-Ah Kang, and Ji-Won Yang (1999). The characteristics of carbon dioxide fixation by Chlorella sp. HA-1 in semi-continuous operation, Korean J.Biotechnol. Bioeng, 14(6), pp. 742-746. 2. Ki-Don Sung, Jin-Suk Lee, Chul-Seung Shin, Mi-Sun Kim, Soon-Chul Park, and Seung-Wook Kim (1996). CO2 fixation by Chlorella HA-1 cultured in bubble columns, Kor 3". Appl. Microbiol. Biotechnol., 26(1), pp. 1-6. 3. Jang Kyu Kim, Sung Ho Won, and Nam Ki Kim (1997). Biological fixation of carbon dioxide by Synechocystis pcc 6803, Kor. 3". Biotechnol. Bioeng., 13(1), pp. 101 - 107. 4. I Karube, T. Takeuchi, D. J. Barnes (1992). Biotechnological reduction of CO2 emissions, Adv. Biochem. Eng. Biotechnol., 46, pp. 63-78. 5. Y. Watanabe, D. O. Hall (1996). Photosynthetic production of the filamentous cyanobacterium Spirulina platensis in a cone-shaped helical tubular photobioreactor, Appl. Microbiol. Biotechnol., 44, pp. 693-698. 6. James C. Ogbonna, H. Yada, H. Masui, and H. Tanaka (1996). A novel internally illuminated stirred

1450 tank photobioreactor for large-scale cultivation of photosynthetic cells, J. Ferment. Bioeng., 82(1), pp. 61-67. 7. Kei Mori (1995). Photoautotrophic bioreactor using visible solar rays condensed by fresnel lenses and transmitted through optical fibers, Biotechnol. Bioeng. Symp., 15, pp. 331-345. 8. Satoshi Hirata, Masahito Taya, Setsuiji Tone (1996). Characterization of Chlorella cell cultures in batch and continuous operations under a photoautotrophic condition, J. Chem. Eng. JaPan, 29(6), pp. 953-959. 9. Rejean Samson, Anh Leduy (1985). Multistage continuous cultivation of blue-green alga Spirulina maxima in fiat tank photobioreactors with recycle, The Canadian J. Chem. Eng., 63, pp. 105-112. 10. Y. Watanabe, N. Ohmura, H. Saiki (1992). Isolation and determination of cutural characteristics of microalgae which functions under CO2 enriched atmosphere, Energy Convers. Mgmt., 33(5-8), pp. 545-552. 11. Masaaki Negoro, Norio Shioji, Yoshiaki Ikuta, Takenori Makita, Makoto Uchiumi (1992). Growth characteristics of microalgae in high-concentration CO2 gas, effects of culture medium trace components, and impurities thereon, Appl. Biochem. Biotech., 34/35, pp. 681-692. 12. M. Yanagi, Y. Watanabe, H. Saiki (1995). CO2 fixation by Chlorella sp. HA-1 and its utilization, Energy Convers. Mgmt., 36(6-9), pp. 713-716.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1451

ENZYMATIC SYNTHESIS OF PYRUVIC ACID AND L-LACTIC ACID FROM CARBON DIOXIDE Masaya Miyazaki, Hiroyuki Nakamura, and Hideaki Maeda Micro-space Chemistry Laboratory, AIST Kyushu, National Institute of Advanced Industrial Science and Technology (AIST), 807-1 Shuku, Tosu, Saga 841-0052, Japan

ABSTRACT A new enzymatic synthesis of pyruvic acid and L-lactic acid from acetaldehyde and carbon dioxide has been developed. The reaction of pyruvic acid synthesis utilizes reverse reaction of pyruvate decarboxylase in sodium bicarbonate buffer. The reaction proceeded at high pH, and gave better yield in higher concentration of buffer. The maximum yield was obtained in 500mM sodium bicarbonate buffer at pHI 1. We also developed a one-pot, two-step enzymatic synthesis of L-lactic acid from acetaldehyde and carbon dioxide. The reaction employing reversal of pyruvate decarboxylase and hydrogenation of pyruvate by Llactic dehydrogenase. The maximum yield was obtained at pH 9.5 in 500mM sodium bicarbonate buffer.

INTRODUCTION

Because of recent global warming, the emission of carbon dioxide became serious problem. While carbon dioxide gas is not in itself a particularly strong greenhouse gas, the contribution to the atmosphere since the beginning of the industrial revolution has been very considerable. The increase in global carbon dioxide levels over the last hundred years or more have been reported. Furthermore, there is some indication of a rising global temperature. A number of meetings, particularly in Kyoto in December 1997, have recommended reducing the total emission of carbon dioxide. Several efforts to immobilize or utilize carbon dioxide have been achieved. Still, no conclusive method is available for this purpose. Recent interest in the problems of environmental pollution has forced the development of a green chemistry process for the chemical industry [1]. Several environmentally-friendly processes have been developed. Biocatalytic processes such as fermentation and enzyme reactions have attracted attention as environmentally safe chemical process [2,3]. Biodegradable polymers have also proved interesting for environmental safety [4,5]. Among the biodegradable plastics, poly(L-lactic acid) has been widely studied. Several methods have been developed to produce lactic acid from many sources [6]. However, most of them produce the racemic form and require relatively longer time and multiple steps to obtain pure L-lactic acid. These disadvantages are problematic, not only for large-scale production but also for environmental safety. Therefore, a simple method, that can produce optically pure L-lactic acid, is desired. We are interested in the development of novel enzymatic reactions and reactor systems characterised by environmentally safe chemical processes. Pyruvate decarboxylase (EC 4.1.1.1) is known as a catalyst for

1452 the decarboxylation reaction of pyruvic acid, to produce acetaldehyde, and has been utilized for C-C bond formation such as chiral Gt-hydroxy ketones, which are versatile building blocks for organic and pharmaceutical chemistry [7, 8]. The reverse reaction of this enzyme is also of interest as a catalytic procedure for carboxylation. Several studies have been performed which imitate these enzyme reactions using CO2 as the reactant. A previous study using a-lactylthiamin showed that production of pyruvate was achieved at higher pH (>10) [9]. However, these reactions require organic solvents and severe conditions. In the present study, we demonstrated the usefulness of the reverse reaction of pyruvate decarboxylase in the production of pyruvic acid from acetaldehyde and carbon dioxide. We also developed a one-reactor, twostep enzymatic synthetic procedure for L-lactic acid from acetaldehyde, by combining this reverse reaction of pyruvate decarboxylase and reduction of pyruvic acid by L-lactic dehydrogenase to produce L-lactic acid.

MATERIALS AND METHOD

General Pyruvate decarboxylase (from brewer's yeast) and L-lactic dehydrogenase (from rabbit heart) were obtained from SIGMA (St. Louis, MO, U. S.A.). Thiamine pyrophosphate and NADH were purchased from Wako Chemical Ind. (Osaka, Japan). Sodium bicarbonate buffers were prepared immediately before experiment. All experiments were performed in thermostated bioshaker (Titech Co., Tokyo Japan) with vortex shaking. The HPLC analysis was performed using Waters Alliance 2596 system equipped with Wakosil C22 analytical column (d~4.0 x hl 50 mm, Wako Chemical Ind.). IH-NMR spectra was recorded by Bruker DSX300 spectrophotometer.

Synthesis of Pyruvic Acid A typical run was performed as follows. To a solution of acetaldehyde (100 ~tM) in sodium bicarbonate buffer (1 ml) in a 1.5 ml microcentrifuge tube, pyruvate decarboxylase (1 unit) and thiamin pyrophosphate (the final concentration was 10 ~tM) were added at 4 °C. The reaction mixture was warmed to 25 °C quickly, and then shaken on a vortex mixer at room temperature. After 1 h, the reaction mixture was chilled on ice, and then subjected to RP-HPLC analysis immediately. The amount of pyruvic acid was calculated from the peak area of RP-HPLC analysis calibrated with commercially available pyruvic acid as standards. The yield was estimated based on acetaldehyde.

Synthesis of L-Lactic Acid The reaction was initiated by adding pyruvate decarboxylase (1 unit) and L-lactic dehydrogenase (1 unit) to a solution of acetaldehyde (0.1 laM), thiamine pyrophosphate (0.1 ktM), NADH (0.2 ~tM) in various concentrations and pHs of NaHCO3/Na2CO3 buffer at room temperature. The reaction was performed 1 h, and then the reaction was terminated by adding 1M HCI and analyzed by RP-HPLC. The amount of each compound was estimated by peak area calibrated by commercially available standards. The absolute configuration of lactic acid was confirmed by the optical rotation, and the yield was calculated based on acetaldehyde. For confirmation, the yielded lactic acid was subjected to the analysis. The IH-NMR spectra and optical rotation value were identical to the commercially available L-lactic acid.

RESULTS

Synthesis of Pyruvic Acid First, we tried the reverse reaction of pyruvate decarboxylase (Scheme 1). Previous organic synthesis showed that hydrolysis of lactylthiamin requires a higher pH [9]. Thus, we chose a sodium bicarbonate buffer system, because not only is this buffer suitable at higher pHs, but it also can be used as the source of carbon dioxide.

1453

H3C-,,~H O

+

Pyruvate decarboxylase > Thiamine

CO2

O HaC~o

H

O Scheme 1: Synthetic process of pyruvic acid from carbon dioxide

We firstly evaluated the effect of pH on the reaction. The reaction was performed using acetaldehyde (100 ktM), thiamin (0.1 ~tM), and pyruvate decarboxylase (1 unit) in 0.1 M NaHCO3/Na2CO3 buffer at various pHs (pH 8.5-11.5). The result is shown in Figure 1A. Higher pHs gave a better yield of pyruvic acid. The maximum yield was obtained at pH 11 (61%). The present result agreed well with a previous observation obtained from the hydrolysis of ct-lactylthiamin. In that case, the best yield from hydrolysis was obtained at pH 12. In our case, the best yield was obtained at pH 11, but the yields decreased at much higher pH. Although the hydrolysis proceeds at a maximum rate at pH 12, the enzyme might not be stable over pH 11. Therefore, the maximum yield was obtained at pH 11. Thus, we decided to perform further experiments at pHil. 100

BO

..........

: ..........

~. . . . . . . . . . .

~ ..........

,~

.o

40

..........i......................................................i...........i.........

o

i

8

;

B.5

9

9.5

10

10.5

i

i

11

11.5

12

pH

Figure l" Effect of pH on the reverse reaction of reverse reaction of pyruvate decarboxylase. The experiment was performed as described in Material and Method section.

...

60

,

~"

40

,-- '

20

.... "...................................................................................

o

, 1 o

.....................................

,

,

,

.....

~ ........................................

|

. . . . . . . .

1 oo

1 ooo

Concentration/raM

Figure 2: Effect of ionic strength of bicarbonate buffer on the reverse reaction of reverse reaction of pyruvate decarboxylase. The experiment was performed as described in Materials and Method section.

1454 Next, we examined the effects of concentration of bicarbonate buffer on the reaction (Figure 1B). Higher ionic strength of the bicarbonate buffer strongly influenced the yield, as expected. The maximum yield of the reaction was 81% at 500 mM NaHCO3/Na2CO3 buffer. This yield was sufficient to use as an organic process, and much higher than that obtained by the reaction in DMF under 20 atm of CO2 [9]. Not only does the latter reaction require multiple steps, but the use of the organic solvent DMF is problematic for environmental safety reasons. The enzymatic reaction does not require any organic solvent and gave a better yield. It has been reported that the thiamin itself could catalyze a reaction analogous to that of the enzyme, but preparation of the intermediate c~-lactylthiamin from acetaldehyde was unsuccessful. Thus, it is difficult to reverse the reaction without an enzyme, and pyruvate decarboxylase is the best catalyst for carboxylation of acetaldehyde.

Synthesis of L-lactic acid Pyruvic acid can be easily hydrogenated asymmetrically by L-lactic dehydrogenase in the biological system. Therefore, it is possible to produce L-lactic acid from acetaldehyde and carbon dioxide by combining the two enzyme reactions, reverse reaction of pyruvate decarboxylase and L-lactic dehydrogenase (Scheme 2). In the present study, we designed and evaluated a one-pot, two-step enzymatic synthetic procedure for Llactic acid from acetaldehyde as an initial experiment. Pyruvate decarboxylase

H3C',,~H CO2

L-Lactic dehydrogenase ~

O

"-

H3C

OH

O H3C

OH

0 O

OH

Scheme 2: Synthetic process of L-lactic acid from carbon dioxide First, the effect of pH (7 to 10.5) on the reaction was examined, because the reverse reaction of pyruvate decarboxylase proceeds at higher pH, the yields should become better than that of neutral pH. The results were summarized in Figure 3. In the present study, the yield of lactic acid was maximized at pH 9.5. Much higher pH gave lower yield of L-lactic "acid and gave relatively better recovery of pyruvic acid. This result can be explained as follows. The first step proceeds at higher pH, whereas the second step, hydrogenation by L-lactic dehydrogenase, gave lower yield at much higher pH, yielded decrease of production of L-lactic acid and therefore the recovery ofpyruvic acid was increased (Figure 3). 100 . . . . . . . . . . . . . . . . . .

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1455 We also examined the effect of concentration of bicarbonate buffer at pH 9.5, because the reverse reaction of pyruvate decarboxylase prefers higher concentration of bicarbonate buffer, s shown in Figure 4, higher concentration of bicarbonate gave better yield, as expected. The maximum yield was obtained at 500 mM bicarbonate buffer (51%). The reverse reaction of pyruvate decarboxylase yielded about 43% of pyruvic acid production in 500 mM bicarbonate buffer at pH 9.5. However, the combined yield of lactic acid and pyruvic acid exceeds 65%, meaning the yield of the reverse reaction of pyruvate decarboxylase was improved than that by alone. This might result from change of equilibrium condition of the reaction, namely pyruvic acid consumption by the second step might promote better yield of the first step. Further studies are required to solve the details of this mechanism. B{']

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DISCUSSION Although the effect is much weaker than methane, carbon dioxide is considered to be a greenhouse gas, and therefore its immobilization is desired. The methods currently reported are mainly catalytic or electrochemical reactions, which require much energy [10-12]. One alternative method has been reported, which utilized carbonic anhydrase for the immobilization of carbon dioxide [ 13]. This biomimetic approach needs almost no energy for the reaction. However, the carbonic anhydrase just improves the solubility of carbon dioxide in aqueous media, and further treatment of dissolved gas is required. The biodegradable polymers have also been interested for environmental safety. Among the biodegradable plastics, the poly(L-lactic acid) has been widely studied. Several methods have been developed to produce the lactic acid from many sources. However, most of them produce racemic form and require relatively longer time and multiple steps to obtain pure L-lactic acid. These disadvantages are problematic not only for large-scale production but also for the environmental safety. Therefore, a simple method, which can produce optically pure L-lactic acid, is desired. Recent interest of poly(L-lactic acid) demands the effective method to produce the material, L-lactic acid. The fermentation method has been focused as effective solution, because it can produce relatively pure L-isomer [6]. By our method, the carbon dioxide in the aqueous phase can be condensed with acetaldehyde to produce the pyruvic acid and can easily be converted into lactic acid, which is a material ofbiodegradative plastic. This

1456 method utilizes an enzymatic reaction that proceeds in shorter times and gives the product in higher purity than that by fermentation. Although further studies are required to establish efficient pilot-scale production, these features are advantageous than the classical fermentation method for lactic acid production and the carbon dioxide will be able to be immobilized into the biological cycles. In conclusion, we have demonstrated the usefulness of the reverse reaction of pyruvate decarboxylase. This reaction might become a recommendable, environmentally safe carboxylation procedure for acetaldehyde. Also, we have developed a one-pot, two-step enzymatic synthesis method of L-lactic acid from acetaldehyde and carbon dioxide. This method might become a recommendable, environmentally safe procedure for Llactic acid production. Further studies are in progress in our laboratory.

ACKNOWLEDGMENT We thank Mitsukuni Shibue and Kazuya Ogino for technical assistance. REFERENCES

10. 11. 12. 13.

Anastas, P. T. and Warner, J. C. (1998) Green Chemistry: Theory and Practice, Oxford. Koller, K. M. and Wong, C.-H. (200 l) Nature 409, 232. Schmid, A., Dordick, J. S., Hauer, B., Kiener, M., Wubbolts, M., and Witholt, B. (2001) Nature 409, 258. Amass, W., Amass, A., and Tighe, B. (1998) Polym. Int. 47, 89. Jacobsen, S., Degree, P. H., Fritz, H. G., Dubois, P. H., and Jerome, R. (1999) Polym. Eng. Sci. 39, 1311. Lunt, J. (1998) Polym. Degred. Stab. 59, 145. Sprenger, G. A. and Pohl, M. (1999) J. Mol. Catal. B: Enzym. 6, 145. Schorken, U. and Sprenger, G. A. (1998) Biochim. Biophys. Acta 1385, 229. Foppen, M.-A. E., de Lange, Y. M., van Rantwijk, F., Maat, L., and Kieboom, P. G. (1990) Recl. Tray. Chim. Pay-Bas 109, 359. Li, Y., Xu, G.-H., Liu, C.-J., Eliasson, B., and Xue, B.-Z. (2001) Energy & Fuels 15, 299. Aresta, M., Dibenedetto, A., and Tomassi, I. (2001) Energy & Fuels 15, 269. Liu, C.-J., Xu, G.-H., and Wang, T. (1999) Fuel Processing Technol. 58, 119. Bond, G. M., Stringer, J., Brandvold, D. K., Arzum Simsek, F., Medina, M.-G., and Egeland, G. (2001) Energy & Fuels 15, 309.

LAND USE AND SINKS

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1459

ANALYSIS OF AGRICULTURAL GREENHOUSE GAS MITIGATION OPTIONS WITHIN A MULTI-SECTOR ECONOMIC F R A M E W O R K R.D. Sandsl, B.A. McCarl 2, D. Gillig2 and G.J. Blanford 3 ~Joint Global Change Research Institute, Pacific Northwest National Laboratory-Battelle-University of Maryland, 8400 Baltimore Avenue, Suite 201, College Park, MD 20740, USA 2Department of Agricultural Economics, Texas A&M University, College Station, TX 77845, USA 3Department of Management Science and Engineering, Stanford University, Stanford, CA 94305-4026, USA

ABSTRACT

National-scale analysis of greenhouse gas mitigation options is generally carried out using topdown economic models with moderate energy detail but very limited detail in most other sectors including agriculture and forestry. However, a complete analysis of greenhouse gas mitigation options including sequestration requires an improved representation of agriculture and forestry within the models used. In particular, greenhouse gas mitigation options within the agricultural and forestry sectors include changes in afforestation of agricultural lands, altered crop and livestock management practices, harvesting of biomass crops for fuel, and the sequestration of carbon in agricultural soils. Analysis of such options is usually carried out in a detailed sectoral model. We report on activities to combine the bottom-up agricultural and forestry sector detail with the top-down economic and energy structure of an economy-wide computable-generalequilibrium model.

INTRODUCTION

A full analysis of greenhouse gas mitigation options should include activities that reduce emissions of carbon dioxide (CO2) and other greenhouse gases, and activities that sequester carbon. Analysis of greenhouse gas mitigation policies typically starts with an economic model that simulates national or global energy consumption in response to a carbon price, then appends marginal abatement cost curves for non-CO2 greenhouse gases, and perhaps includes simple assumptions on carbon sinks [ 1]. No single model can adequately simulate all the activities and processes that might contribute to reductions in net greenhouse gas emissions. However, detailed process models for various activities, including agriculture and forestry, can be used to inform national and global economic models. In this paper, we use results for the United States from two models: the Second Generation Model (SGM), a computable-general-equilibrium (CGE) model of energy and economy developed at Pacific Northwest National Laboratory

1460 (PNNL), and the U.S. Agricultural Sector Model (ASM), a sectoral level, price endogenous, programming model of agricultural supply and demand for 22 traditional crops, 3 biofuel crops, and 29 animal products in 63 U.S. regions. This work demonstrates the improved realism that can be obtained by using the expertise of sector specialists to inform economy-wide analysis of greenhouse gas mitigation strategies. Following sections provide brief descriptions of each model and a methodology for combining output from the two models.

SECOND G E N E R A T I O N M O D E L The SGM is designed to provide estimates of future time paths of environmentally important emissions associated with economic activity, and provide estimates of the economic cost of actions to reduce greenhouse gas emissions [2]. The SGM is actually a collection of CGE models for fourteen world regions that can be run individually, or as a group that trades carbon emissions rights. The model operates in five-year time steps from 1990 through 2050. Model output is often characterized by a set of marginal abatement cost curves that are generated by a series of constant-carbon-price experiments. Marginal abatement cost curves provide a relationship, at a point in time, between the carbon price in dollars per metric ton of carbon (tC), and the reduction in annual carbon emissions below a baseline level. 250

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Figure 1" Marginal abatement cost curves for carbon emissions from the United States energy system using PNNL Second Generation Model. Figure 1 displays several marginal abatement cost curves from the U.S. component of SGM (SGM-USA) where a carbon price was applied in 2010 and held constant thereafter. 1 Reductions in carbon emissions relative to a baseline case are plotted against the carbon price for years 2010 through 2030. Even with a constant carbon price, the marginal abatement curves shift outward, or to the right, over time for two reasons: it takes time for capital stocks to turn over in the model, and carbon emissions are steadily increasing in the baseline case. The baseline case in SGM-USA is constructed to generally follow projections from the U.S. Energy Information Administration [3] until 2020, and then continue with the same rates of change in One-half of the final carbon price was applied in 2005 to approximate a gradual introduction of a carbon policy. The 2005 time step in SGM can be thought of as covering years 2003-2007.

1461 energy and labor productivity through 2050. Several factors influence the slope of the marginal abatement cost curves, especially elasticities of technical substitution in production, and consumer income and price elasticities of demand. Another factor is the share of coal in the baseline energy system. The area under a marginal abatement cost curve is often used to approximate the cost of a carbon mitigation policy.

AGRICULTURAL SECTOR MODEL The Agricultural Sector Model [4] is a large-scale nonlinear programming model of regionalized domestic production and consumption, as well as major international trade, of the U.S. agricultural sector. Schneider [5] expanded the ASM to include greenhouse gas treatment, and the new model, hereafter called ASMGHG, was used to examine the effects of a carbon price, and other economic signals, on a broad range of agriculture and forestry management options and outcomes, including greenhouse gas emissions [6,7]. Because of the complexity of the ASMGHG, using it within a CGE model to endogenously determine land use change emissions as a result of carbon prices is not practical. However, repeated simulations of the ASMGHG can be consolidated into response functions and built into a CGE setting, allowing both models to work together to exploit the interactions between the agricultural and energy sectors. The ASMGHG produced net emission reduction responses to a discrete series of carbon prices 2 across a variety of scenarios and dependent variables. We focus on a policy scenario in which all net changes in carbon associated with agriculture and forestry practices are charged or credited to landowners, and on three dependent variables representing carbon sinks: soil sequestration, afforestation, and biofuel offsets. The first variable refers to carbon stored in agricultural soils, and is related to cropping and tilling practices; afforestation refers to expanded forested land area (from a 1990 base); and biofuel offsets refer to emission savings from substituting away from fossil fuel energy sources. The model also produced a family of analytic response functions describing each of the dependent variables as a multiplicative function of the vector of inputs, specifically for incorporation into a CGE model. Here this approach is revised by taking only the carbon price as an input. The choice of a single independent variable allows a more detailed analytic representation of the abatement curves; the carbon price was the strongest indicator, and most applicable to the SGM context. The distinctive shape of the relationship for each carbon sink led to two different functional forms, both smooth and continuous, expressing emission reductions in terms of price. Equation (1) was used to fit the soil sequestration curve, while Equation (2) was fitted to the afforestation and biofuel curves: a

e E = ---a.""'--""~ ' 1+ b P a e cp E = ~ + ke 1 + b e ce

(1)

,

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where E = emission reductions, P = carbon price, and a, b, c, k, and c are positive real parameters. The rational form of Equation (1) captures the sharp asymptotic behavior of the soil sequestration curve, while the positive ~ parameter generates the slight decrease, or "backward2The carbon prices examined were {10, 20, 30. . . . . 90, 100, 200, 300, 400} dollars per ton of carbon equivalent (CE); other signals in the model, which include fuel prices, agricultural demand, and exports, were held constant at the base levels.

1462 bending" feature that occurs at higher prices due to competition for land. The logistic form of Equation (2) was chosen to simulate the inflection of the afforestation and biofuel curves, while the linear term ensures slow and steady growth for higher prices. Figure 2 shows the fitted functions against the simulated data points. O

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Figure 2: Reduction in carbon emissions from three activities simulated in the Agricultural Sector Model. Continuous and smooth functions were fit to model output generated at discrete carbon prices. The backward-bending portion of the soil sequestration component reflects competition for land between traditional crops, biofuel crops, and afforestation. High carbon prices create incentives for biofuel crops, which lead to a more intensive use of land for traditional crops and less area harvested (see [7] for further explanation). Therefore, the cost curves for some mitigation options depend on the presence or absence of other options.

COMBINED RESPONSE

Equations (1) and (2) are particularly convenient for use with SGM; the reduction in carbon emissions is a continuous and differentiable function of the carbon price. If there were an emissions target, SGM would search for the carbon price that met the target, given some set of mitigation options. In Figure 3, one of the marginal abatement cost curves from Figure 1 is combined with all of the cost curves from Figure 2 to simulate the availability of mitigation options in year 2015. Although the marginal cost curves from SGM are indexed by year, the cost curves from ASMGHG are not. The cost curves from ASMGHG can be thought of as an annualized reduction in net carbon emissions until saturation is reached for carbon sequestered in agricultural soils or by afforestation. However, the curves do depend on the timeframe in which they are applied, because of their relation to the model base case. It is reasonable to imagine that the curves would not remain the same over the course of the next half-century, even without considering the eventual saturation effect. The dynamics of land use change emissions depend

1463 on the baseline assumptions about agriculture and forestry practices as much as they depend on the relative prices in the future economy. 250 with

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Figure 3: Combined marginal abatement cost curves for United States energy system in 2015 and three emissions mitigation activities in agriculture and forestry.

DISCUSSION We have simulated the response of the United States energy system to a carbon price using SGM, and the response of the United States agricultural system using ASMGHG. At carbon prices above $100 per tC, the reduction in net carbon emissions, from three agricultural options combined, is on the same order of magnitude as that from the energy system. At carbon prices below $50 per tC, the contribution from agricultural mitigation options is mostly from soil sequestration. Ideally, one would prefer a single model that captures mitigation options from energy and agriculture in one integrated system. SGM captures many interactions within the energy system, while ASMGHG captures interactions within agriculture and forestry. However, commercial biofuels represent an important link between the energy and agricultural systems and we have not adequately simulated the demand for commercial biofuels. Furthermore, the mitigation options from agricultural carbon sinks are expressed here in terms of a response to the carbon price alone. While this parameter proved highly significant in regression analysis conducted with output from ASMGHG, other factors, especially the price of alternative fuel supplies with respect to biofuel offsets, should be considered and incorporated. The methodology described in this report is seen as an intermediate step in the process of fully integrating the agricultural and energy sectors. Eventually, we hope to replace some of the twodimensional abatement curves produced here by an endogenous simulation of agricultural responses to carbon, fuel, and commodity prices, as well as shifting demand and the impacts of climate change itself. In the meantime, we have demonstrated the importance of modeling both fossil fuel and agricultural mitigation strategies with a combination of sector-specific tools.

1464 ACKNOWLEDGEMENTS

This research was funded by the program to enhance Carbon Sequestration in Terrestrial Ecosystems (CSiTE), US Department of Energy. Pacific Northwest National Laboratory is operated by Battelle for the United States Department of Energy under contract DC-AC0676RLO1830. The views expressed in the paper are those of the authors and do not necessarily reflect the views of the US Department of Energy or Battelle.

REFERENCES

1. MacCracken, C.N., Edmonds, J.A., Kim, S.H. and Sands, R.D. (1999). "The Economics of the Kyoto Protocol." In: The Costs of the Kyoto Protocol: A Multi-Model Evaluation, Weyant, J. (Ed.). The Energy Journal special issue. 2. Edmonds, J.A., Pitcher, H.M., Barns, D., Baron, R. and Wise, M.A. (1993). "Modeling Future Greenhouse Gas Emissions: The Second Generation Model Description." In: Modelling Global Change, Klein, L.R. and Lo, F. (Eds.). United Nations University Press, New York. 3. US Energy Information Administration (2002). Annual Energy Outlook. http://www.eia.doe.gov/oiaf/aeo. 4. McCarl, B.A., Chang, C.C., Atwood, J.D. and Nayda, W.I. (1993). "Documentation of ASM: The U.S. Agricultural Sector Model," Staff Report, Texas A&M University. http://agecon.tamu.edu/faculty/mccarl/asm.html. 5. Schneider, U.A. (2000). Agricultural Sector Analysis on Greenhouse Gas Emission Mitigation in the United States. Ph.D. dissertation, Department of Agricultural Economics, Texas A&M University. 6. McCarl, B.A., Schneider U., Murray, B., Williams, J. and Sands, R.D. (2001). "Economic Potential of Greenhouse Gas Emission Reductions: Comparative Role for Soil Sequestration in Agriculture and Forestry." In: Proceedings of the First DOE National Conference on Carbon Sequestration, May 14-17, 2001, Washington, D.C. 7. McCarl, B.A. and Schneider, U.A. (2001). "Greenhouse Gas Mitigation in U.S. Agriculture and Forestry." Science 294, 2481-2482.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1465

CSiTE STUDIES ON CARBON SEQUESTRATION IN SOILS G. Marland, C. T. Garten Jr, W. M. Post, and T. O. West Environmental Sciences Division Oak Ridge National Laboratory Oak Ridge, Tennessee, 37831-6335, USA Phone 865-241-4850, Fax 865-574-2232, Email [email protected]

ABSTRACT The Consortium for Research on Enhancing Carbon Sequestration in Terrestrial Ecosystems was created in 1999 to perform fundamental research that will lead to methods to enhance C sequestration as one component of a C management strategy. Research at one member of this consortium, Oak Ridge National Laboratory, has focused on C sequestration in soils. Studies of C and N dynamics are leading to an understanding of the factors that affect the inputs to and outputs from soils and how these might be manipulated to enhance C sequestration. Both the quantity and the quality of soil C inputs influence C storage and the potential for C sequestration. Changes in tillage intensity and crop rotations can affect C sequestration by changing the soil physical and biological conditions and by changing the amounts and types of organic inputs to the soil. Analyses of changes in soil C are supplemented with studies of the changes in the associated management practices and their implications for fossil-fuel use, emission of other greenhouse gases such as N20 and CH4, and impacts on agricultural productivity. Improved understanding of the factors and mechanisms that control the spatial and temporal variations in soil C can lead to landmanagement strategies that incorporate C management and increase the C stocks of terrestrial ecosystems.

INTRODUCTION The Consortium for Research on Enhancing Carbon Sequestration _In Terrestrial Ecosystems (CSiTE) was created in 1999 by the U.S. Department of Energy, Office of Science, Biological and Environmental Research, to conduct basic scientific studies and analyses related to C sequestration in terrestrial ecosystems. The consortium is led by the Oak Ridge, Pacific Northwest, and Argonne National Laboratories, and involves collaborators from universities and other research institutions both in the USA and in Europe. The objective is to perform fundamental research that will lead to methods to enhance C sequestration as one component of a C management strategy. CSiTE efforts during its first three years have focused on C sequestration in soils. Improved understanding of the factors and mechanisms that control spatial and temporal variations in soil C can lead to land management strategies that incorporate C sequestration. Studies range across multiple scales, from the molecular to the landscape, and include modeling to extrapolate understanding across these scales. Studies also include assessments of C sequestration potential, net C balances, and the environmental and economic implications of C sequestration. We summarize here some results from the initial three years of CSiTE research at the Oak Ridge National Laboratory.

CARBON AND NITROGEN DYNAMICS IN FOREST ECOSYSTEMS Ecosystem and landscape-scale studies of soil C and N are important to strategies for enhancing C sequestration in terrestrial ecosystems. Past studies indicate a large potential for landscape-level differences

1466

in soil C and N stocks depending on soil type, topography, land-use history, and current land use and land cover. For example, landscape-level studies o f soil C and N on the 14,000 ha Oak Ridge Reservation in East Tennessee indicate that soils under pastures have larger stocks of both C and N, lower C:N ratios, and greater N availability than do soils under transitional vegetation and forests [ 1]. At this location the effect of topography is secondary to that of land cover. Partitioning of C between soil pools with different turnover times is also affected by land cover. Because of greater soil C stocks and greater allocation of C to soil pools with longer turnover times, the potential for soil C sequestration is greater under pastures than under forests. However, changing land use from forest to pasture would counter the objective of total ecosystem C sequestration because the above-ground C stocks are substantially less in pastures than in forests. We are studying factors that affect the inputs to and outputs from the C stocks of forest soils and how these factors might be manipulated to enhance C sequestration. Simple models that partition soil C into "labile" and "stable" pools [2] can be useful for understanding the effects of changing climate or land-cover type on soil C storage. Our simple model partitions soil C into these two pools and includes fluxes that correspond to soil C inputs, organic matter decomposition, and the conversion of organic C from the labile to stable pools. Stable C corresponds to organo-mineral soil C or C complexed with soil silt and clay [3]. Labile C is comprised of C in the O-horizon and C in the sand-sized soil fraction (i.e. particulate organic matter). Both the quantity and quality of soil C inputs influence C storage and the potential for C sequestration. Table 1 shows the parameters for modeling soil C storage under 3 forest types (pine forest, mixed forest, and deciduous forest) on the Oak Ridge Reservation. Estimated annual above-ground litterfall, litterfall C:N ratio, total C input to soil, and C:N ratio of the O-horizon are seen to vary with forest type. Lower litter quality (indicated by a higher C:N ratio) is associated with higher labile C stocks, a slower decomposition rate for labile C, a slower conversion rate for labile to stable C, and a smaller percentage of soil C in the stable pool. TABLE 1 PARAMETERS USED TO MODEL SOIL C DYNAMICS ON THE OAK RIDGE RESERVATION Variable Units Pine Forest Mixed Forest DeciduousForest 350 413 480 Annual litterfall inputs§ g m -2 315 372 432 Estimated annual input to soil C~ g C m -2 Leaf litterfall C:N ratio'~ none 100 80 60 O-horizon C:N ratio none 49.9 + 1.8 37.6 + 1.0 37.3 + 1.5 O-horizon C stock g C m2 872 + 66 807 + 75 779 + 70 Mineral soil C stock (0-40 cm) g C m2 3257 + 288 3005+ 217 3066 + 236 Measured mean total C stock g C m "2 4129 + 295 3812+ 193 3845 + 212 Particulate organic matter C % 32.3 + 1.1 30.2 + 2.9 28.8 + 1.2 Labile C stock g C m2 1924 1715 1662 2205 2097 2183 Stable C stock g C m "2 Stable C % 53.4 55.0 56.8 Calculated kl ~: yr1 0.1433 0.1951 0.2365 Calculated k2:~ yrl 0.02046 0.02185 0.02345 Turnover time of labile C years 6.1 4.6 3.8 Soil C:N none 15.5 ± 1.0 14.8 ± 1.5 16.8 ± 1.2 Mean values (n = 16) are followed by + 1 standard error. 1 gm 2= 10 kg hal § Annual above-ground litterfall inputs are based on data from sites on the Oak Ridge Reservation; Walker Branch Watershed [4] and the Integrated Forest Study [5]. ¶ Annual input of C to soil is twice the C input from above-ground litterfall because below-ground C inputs are assumed to be equivalent to above-ground C inputs. I" Leaf litterfall C:N ratios are based on data from Walker Branch Watershed [6]. Rate constants for the decomposition of labile soil C (k~) and conversion of labile to stable C (k2) were derived according to methods presented by Garten et al. [2]; based on a literature review [1]. The turnover time of stable soil C in the model is 56 years.

1467 The rapid turnover times of labile soil C make this pool particularly important in the response to environmental changes, such as changes in climate or land cover. Other studies indicate that changes in land use affect stocks of labile C to a greater degree than stocks of stable C (e.g., [7]). Predictions with our model indicate that an increase in C inputs to forest soil, such as might result from N fertilization [8] or elevated atmospheric CO2 concentration [9], will increase both labile and stable C stocks; however the rate of C accumulation in the labile pool will be faster than that in the stable pool. Similarly, labile soil C under deciduous forest will respond more quickly to a change in C inputs than will labile soil C under pine forest, because the turnover time of labile soil C is faster under deciduous than under pine forests. Field experiments are continuing on the Oak Ridge Reservation to determine how changes in litter amount and quality affect different stocks of soil C.

CHANGES IN SOIL CARBON STOCKS IN AGRICULTURAL ECOSYSTEMS As with forested landscapes, the quantity and quality of soil C inputs change across agricultural systems. Litter quantity and quality in agricultural systems depend on the crop(s) cultivated and on the inputs to production (e.g., fertilizers, irrigation, and soil tillage). Changes in crop management can result in either the accumulation or loss of soil organic C. Analysis of 67 long-term agricultural experiments, consisting of 276 paired treatments, was conducted to estimate the potential for sequestering C in soil with a decrease in soil tillage or by changing the number of crops in a rotation [ 10]. On average a change from conventional tillage to no-till, using best management practices, resulted in a C sequestration rate of 570 + 140 kg C ha 1 yr-l (Fig. 1a). Crops rotated with soybeans appeared to have the largest potential for sequestering C (840 + 520 kg C ha -l yr-1) with a change from conventional tillage to no-till. Rates of C sequestration following a change in tillage are predicted to reach a maximum in 5-10 years and decline toward 0 kg C ha -I yr-i in 15-20 years as a new equilibrium for soil C is approached (Fig. l b). In a separate analysis that considered a change from continuous cropping to rotation cropping, an average C sequestration rate of 200 + 120 kg C ha ~ yrl could be attained using best management practices (Figure 1c). This analysis suggests that the duration of sequestration following an enhancement in rotation complexity is longer (-40 - 60 years) than that for a decrease in tillage, with peak sequestration rates occurring during the initial years following the change in management (Fig. 1d). A decrease in tillage results in increased rates of C sequestration by changing soil physical and biological conditions, thereby promoting the formation of soil aggregates and influencing decomposition rates of soil organic C. Changes in crop rotations affect the quantity and quality of litter. Increasing the quantity of litter in wheat-fallow systems by decreasing the number of fallow periods resulted in increased C sequestration rates. Changing the quality of litter by moving from continuous cropping to rotation cropping increased C sequestration rates in most cases, regardless of whether there was a simultaneous increase in litter quantity (with the exception of a move from continuous corn to corn-soybean rotation). Combining a decrease in tillage with an enhancement in rotation complexity may result in a larger amount of C sequestered, with sequestration rates continuing for a longer period of time. Additional analyses are being conducted to provide estimates for regional sequestration potentials and to determine quantitative relationships among sequestration rates, climate, soil attributes, land cover, and land management.

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1: Average annual C sequestration expected following a change in agricultural practice. The top half of the figure shows (a) the C accumulation rate immediately following a change from conventional tillage to no-till and (b) the evolution of this accumulation rate over time. The bottom half of the figure shows (c) the C accumulation rate immediately following an enhancement in rotation complexity (i.e., a change from continuous cropping to a crop rotation system, increasing the number of crops in a rotation, or decreasing the fallow period in wheat-fallow systems; and (d) the evolution of these accumulation rates over time. Bold and thin lines in parts (b) and (d) represent the mean C sequestration rates and the 95% confidence intervals, respectively (from [10]). Negative values are fluxes with respect to the atmosphere and represent C sequestration in soils. Figure

NET EFFECT EMISSIONS

OF

CARBON

SEQUESTRATION

ACTIVITIES

ON

GREENHOUSE

GAS

Having demonstrated that a change in agricultural management can result in an increase or decrease in soil organic C, we have then examined in detail some of the changes in management practices that have high potential for sequestering C. Conversion from conventional to no-till agriculture is one of the most promising approaches for increasing soil organic C [ 11 ], but it is accomplished by changes in agricultural practice that have other greenhouse gas implications. To evaluate the full impact on greenhouse gas emissions we have estimated associated changes in fuel use in agriculture. A change in management practices also has implications for application of fertilizer, lime, pesticides, seed, and irrigation water, all of which have consequences for fossil-fuel use and hence for greenhouse gas emissions [12]. In addition, changes in the use of N fertilizer impact emissions of N20 and any changes in crop productivity could be compensated by a change in the amount of land being cultivated. We recognize further that a change in agricultural practice can result in C sequestration over the early years following a change, but that soil C will eventually reach steady state with the new suite of practices. In order to retain the sequestered C in the soil it may be necessary to maintain the new suite of management practices, even though there is no continuing net sequestration of C.

1469 Life cycle assessment of a change from conventional to no-till agriculture in the U.S. shows that, on average, there is a saving in fossil-fuel use on the farm and a net decrease in CO2 emissions due to reductions in production, transport, and application of agricultural inputs such as fertilizers and pesticides. This savings is in addition to the average amount of C sequestered in soil over a 20-year period (570 + 140 kg C ha l yr-1). The time paths of the annual and integrated net change in CO2 emissions to the atmosphere are shown in Figure 2. The results illustrated in Figure 2 are for average U.S. practice, circa 1995, and will vary notably with site-specific details that include the history of land management and the specific crop or crop rotation in production. Note that, especially over time, the change in energy-related inputs to agriculture plays a large role in the impact on net emissions of CO2.

-

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Annual (a) and cumulative (b) net carbon flux to the atmosphere using estimates of C sequestration and inputs to production for an average U.S. crop. Carbon sequestered in soil (thin line) minus the change in CO2 emissions from agricultural activities (dashed line) results in the net C flux to the atmosphere (bold line) attributable to the change from conventional to no-till agriculture. Positive and negative values represent fluxes of C to and away from the atmosphere, respectively. Figure 2:

There are two other ways in which changing agricultural practice might have a significant impact on net emissions of greenhouse gases. Figure 2 is based on the assumption that there is no change in agricultural output. If a change in practice results instead in a change in agricultural output, one can expect that the area in production will change in order to maintain output and that there will be associated emissions or uptake of C on the land newly cultivated or abandoned [13]. In addition, changing land management can impact the balance of other greenhouse gases, particularly CH4 and N20. Most notably, to a first approximation the emission of N20 is related to the amount of nitrogen fertilizer applied. Because N20 emissions are widely variable, dependent on factors such as method of application and local climate variables, it is difficult to derive generic estimates; but it is clear that changes in N20 emissions could be an important supplement or counterbalance to C emissions reduction activities [14]. The interaction between C and N balances is critical in many ways when considering carbon sequestration in terrestrial ecosystems.

SUMMATION In efforts to manage the increase in greenhouse gases in the atmosphere, there are important opportunities to increase C in soils and other parts of the terrestrial biosphere. The opportunities are not infinite in magnitude and they are limited in time of application, but they are opportunities in the short term that are generally compatible with desired and sustainable land-management practices. Soil organic C is an essential attribute of soil quality and increased soil organic C is generally associated with improved soil tilth, improved water-holding capacity, improved storage and availability of plant nutrients, and reduced soil erosion. CSiTE is exploring the basic science that will identify and enhance the options and opportunities to add additional benefit by helping to constrain the increasing atmospheric concentration of CO2.

1470 ACKNOWLEDGEMENTS

This research was performed for the Consortium for Research on Enhancing Carbon Sequestration in Terrestrial Ecosystems, and was sponsored by the U.S. Department of Energy's Office of Science, Biological and Environmental Research. Oak Ridge National Laboratory is managed by UT-Battelle, LLC, for the U.S. Department of Energy under contract DE-AC05-00OR22725.

REFERENCES

o

7. 8. 9. 10. 11. 12. 13. 14.

Garten, C.T., Jr., and Ashwood, T.L. (2003) Biogeochemistry, in press. Garten, C.T., Jr., Post, W..M., Hanson, P.J., and Cooper, L.W. (1999) Biogeochemistry 45, 115. Ruhlmann, J. (1999) Plant and Soil 213, 149. Edwards, N.T., Johnson, D.W., McLaughlin, S.B., and Harris, W.F. (1989). Carbon dynamics and productivity, pp. 197-232. in Johnson, D.W. and Van Hook, R.I. (Eds.) Analysis of Biogeochemical Cycling Processes in Walker Branch Watershed. Springer-Verlag, New York. Johnson, D.W. and Lindberg, S.E. (Eds) (1992) Atmospheric Deposition and Forest Nutrient Cycling: A Synthesis of the Integrated Forest Study. Springer-Verlag, New York. Garten, C.T., Jr., Huston, M.A., and Thoms, C.A. (1994) Forest Science 40, 497. Guggenberger, G., and Zech, W., (1999) Forest Ecology and Management 124, 93. Johnson, D.W., and Curtis, P.S. (2001) Forest Ecology and Management 140, 227. Canadell, J.G., Pitelka, L.F., and Ingram, J.S.I. (1996). Plant and Soil 187, 391. West, T.O. and Post, W.M. (2002) Soil Science Society of America Journal, in press. Follett, R. F. (2001) Soil Tillage Research 61, 71. West, T.O., and Marland, G. (2002) Agricultural Ecosystems and Environment, in press. West, T.O., and Marland, G. (2003) Biogeochemistry, in press. Marland, G. and West, T.O. (2002) Tellus, in press.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1471

MICROAGRICULTURE-BIOFIXATION OF CO2 USING NITROGEN- FIXING MICROALGAE IN RICE FIELDS Y.Ikuta SeaAg Japan, Inc. Tokyo, Japan

ABSTRACT Rice cultivation requires large amounts of fertilizers and also emits greenhouse gases. The use of nitrogen-fixing cyanobacteria (microalgae) has been used in traditional low-yield rice culture in some countries (Vietnam, India, etc.) but not yet developed for the intensive rice agriculture practiced in Japan and other countries. One concept is to integrate microalgae culture with rice cultivation, but this suffers from the problem of limited time available for the algae to grow before canopy closure. An alternative is to utilize a part of the rice field to cultivate nitrogenfixing cyanobacteria such as Anabaena or Nostic in raceway type paddle wheel mixed ponds that are then used to irrigate and fertilize rice fields.

INTRODUCTION

70 years have passed since the first encounter of Professor Oswald at the Presidio of Monterey, California, where he identified Asterionella to be the source of taste and odor in the Presidio's drinking water. The industrial utilization of microalgae started in the 1950's. Professor Oswald constructed a raceway type algae pond for waste water treatment of municipal waste water [ 13 . Meanwhile, in Japan, the first commercial microalgae production system was established in the early 1960's. Based on a number of reports in the Japanese press that Chlorella had beneficial health effects, a health food market for Chlorella developed and this led to the establishment of over a dozen small production facilities ~ 2 ~ . Production facilities for Spirulina were established in the early 1970's by the Sosa Texcoco Co. near Mexico City ~3J . During the 1970's an active program of microalgae development for foods and feedstuffs was ongoing in Israel and Germany. Of great interest was the Israeli project by the Koors Company dealing with Dunaliella production for glycerol, beta carotene, and protein [4J . A Dunaliella production system, developed at the Weizman Institute of Israel was built in Israel. With the start of the energy crisis in 1973, large scale cultivation of microalgae was considered as a source of fuel and a number of projects were carried out in the U.S. This, despite the fact that microalgae fuel production appears to be economically quite difficult. Technologies for mitigating CO2 emissions from fossil fuel-fired power plant flue gas using microalgae culture were investigated in Japan during the 1990's.

1472 RESEARCH AND DEVELOPMENT OF COz BIOFIXATION IN JAPAN

Hydrogen Production by Photosynthetic Microorganisms Hydrogen is a clean energy alternative to fossil oil. A stable system for the conversion of solar energy into hydrogen using photosynthetic microorganisms has been developed by Mitsubishi Heavy Industries Ltd. in co-operation with Kansai Electric Power Co. The system consists of three stages: (1) photosynthetic starch accumulation in green algae Chlamydomonas sp.; (2) dark anaerobic fermentation of the algal starch biomass to produce hydrogen and organic compounds; and (3) further conversion of the organic compounds to produce hydrogen using photosynthetic bacteria Rhodovulum sulfidophilum sp. W/S. A pilot plant was constructed at Nankoh power plant in Osaka, at which a series of tests using CO2 obtained from a chemical absorption pilot plant were conducted t:5] .

Carbon Dioxide Fixation by Microalgal Photosynthesis Using Actual Flue Gas At the Tohoku Electric Power Co., four small pilot scale microalgae ponds were continuously operated for a year (1993). The small scale pilot plant operations included: the selection of the appropriate algae, their long-term (one year) cultivation, investigation of the effects of SOx, NOx, and particulate matter in the actual flue gas from the low sulfur fuel oil burning power plant on the growth of the algae. A major conclusion of the studies was that microalgae can be used for biofixation of CO2 using actual power plant flue gas without the need for pretreatment. However, further long-term R&D work is required to improve photosynthetic efficiency and the conversion of the biomass into other useful products. R&D was conducted by Mitsubishi Heavy Industries Ltd. in co-operation with Tohoku Electric Power Co. [6] .Microalgae biofixation of CO2 from power plants cannot yet be considered as a technically or economically viable option for greenhouse gas mitigation. Thus, there is the need for alternative processes that can produce higher value products while utilizing significant amounts of CO2.

MICROALGAE-BIVALVE PRODUCTION PROCESS In many aquaculture operations, small batches of microalgae are produced under highly controlled conditions in translucent cylinders, plastic bags, or tanks of various descriptions, generally under artificial illumination and/or in greenhouses. SeaAg Inc. in Florida has developed a process for a larger-scale open pond culture of marine microalgae suitable for bivalve aquaculture. The process is similar to that used in the commercial production of Spirulina and Dunaliella: raceway, paddle wheel mixed, plastic-lined ponds, supplied with CO2 and other nutrients are used as growth vessels. SeaAg Japan Inc. has established demonstration facilities to produce bivalves by feeding microalgae cultivated in open ponds. 600m 2 and 1,100m'~ algae ponds were constructed in 1997 and 1998 respectively in Kagoshima, Japan. This plant has been operated satisfactorily for more than 5 years. The material balance for bivalve production shows that over 90% of the CO2 supplied to the algal pond is fixed into the algal biomass, and that about one third of this organic carbon is captured in the bivalves. However, this organic carbon is eventually released when the bivalves are consumed by humans. Thus, such a process is only a temporary biofixation of CO2, and by itself, would not contribute to the mitigation of fossil CO2 emissions. However, it is an example of a microalgae production process that could eventually evolve into larger scale applications of relevance to greenhouse gas reduction [7] .

1473 STUDIES FOR THE U T I L I Z A T I O N OF M I C R O A L G A E IN RICE A G R I C U L T U R E

Objectives of Rice Agriculture in Japan An objective of rice agriculture in Japan is to reduce the amount of chemical fertilizers, herbicides, and pesticides used. Nitrogen in chemical fertilizer exists in an inorganic form and is easily absorbed by plants. Once chemical fertilizer is supplied to a rice paddy, it is absorbed by the rice, as far as the rice will accept it, regardless of whether or not it is appropriate for the production of rice. Eventually, part of the surplus fertilizer is exhausted into the air in the form of nitrous oxide, and the rest is exhausted into the agricultural waste water. Although herbicides relieve the farmer of the hard work of weeding, and pesticides control insects which damage the crop, they create new problems of pollution such as EDCs (endocrine disrupting chemicals). Here seems to be a possibility for microalgae to be utilized as a bio-fertilizer and a herbicide. Utilization of Microalgae in Rice Culture In Japan, due to the over-production of rice, 30% of all rice paddies are required to be kept dormant. A part of the dormant rice paddy may be utilized to cultivate algae, which can be used as a herbicide and a bio-fertilizer. Nitrogen-fixing cyanobacteria, Anabaena may be cultivated in the raceway ponds separately installed near each rice paddy, then introduced into the rice paddy as a herbicide which kills weeds by shading sun light during the transplantation period, and then subsequently utilized as bio-fertilizer. In this way, inorganic nitrogen and phosphates contained in agricultural waste water is recycled to the above raceway ponds and utilized as the nutrient for nitrogen-fixing cyanobacteria. Microalgae as Herbicide During the transplantation period of rice, the seeds of the weeds in the soil under the water of the rice paddy are germinated by sun light and oxygen. Microalgae cultivated at separately installed raceway ponds under the injection of CO2 are introduced into the rice paddy. An adequate amount of algae for the shading of sun light would be cultivated before starting the transplantation of rice. Similar methods of shading sun light by other materials such as paper, and activated charcoal powders have been tested in Japan. So, the same effect may be expected by this method. Microalgae as a Bio-fertilizer It is reported that microalgae has potential as a source of fertilizer because of the relatively high level of its nitrogen content. Moreover, nitrogen-fixing algae such as Anabaena can fix nitrogen to make a bio-fertilizer [ 8 ~ .Anabaena, Nostic, and the aquatic plant Azolla with which Anabaena grows symbiotically, can also be used as a bio-fertilizer after being used as a herbicide. Besides cyanobacteria, Anabaena, Nostic and the aquatic plant Azolla, microalgae such as diatom can be utilized for the same purpose, especially in cases where nutrient nitrogen and phosphates are available from other sources such as from nitrogen and phosphate enriched lakes as are common in Japan.

1474 Diatom ..... Near places where CO2 sources such as power plants exist, and nutrients are available from nitrogen and phosphate enriched lakes, diatom may be used as a herbicide and then as a biofertilizer. Diatom may also be utilized as good feed for fish and shell aquaculture. The advantage of diatom in comparison with other algae is that the productivity of diatom is the highest. The expected productivity of diatom in Japan is 20g/mVd.

AzoUa ..... The Aquatic plant Azolla with which Anabaena grow symbiotically, can be used as bio-fertilizer after being used as herbicide. As Anabaena fix nitrogen and transfer it to Azolla, and Azolla supply to Anabaena photosynthate, no nutrient nitrogen and no CO2 injection is required. The expected productivity of Azolla is 9.5g/m2/d. Anabaena ...... Heterocystous cyanobacteria are capable of simultaneous nitrogen fixation and photosynthesis. Mass cultivation of these microalgae results in nitrogenous fertilizer production using solar energy. A model of heterocyst has been proposed in which vegetable cells furnish heterocysts with photosynthate and in return are provided with nitrogen fixation products from the heterocysts [8J . Productivity is not high, averaging 3g/m2/d in the outdoor experience. Anabaena can be utilized where CO2 sources such as power plant exists.

EXPECTED EXAMPLES OF APPLICATIONS Rice Field Model

Figure 1 shows a three hectare rice field model. This rice field model consists of 10 Japanese standard rice paddies each; 30m x 100m. 30% of the rice paddy is left unused as a rice field but may be used to cultivate microalgae. Because of the difference in productivity, the area required to cultivate the necessary amount of microalgae and aquatic plants is 1 standard rice paddy, 2 standard rice paddies, and 3 standard rice paddies, depending on diatom, Azolla and Anabaena respectively. In the case of diatom and Anabaena, CO2 exhausted from a power plant is utilized and in the case o fAzolla, CO2 in the air is utilized. Shinji-lake and Nakaumi-Sea Restoration Plan

Figure 2 shows the Shinji-lake and Nakaumi-sea Restoration Plan. Shiji-lake and Nakaumi-Sea are blackish lakes where the salt concentration is 0.5-1.0% and 2.0-3.0% respectively. Until 1925, many bivalves lived in both blackish lakes, Corbicula in Shinji-lake and Scapharca in Nakaumi-sea respectively. However, in 2000, the harvest of Corbicula in Shinji-lake decreased to 50% of that of 1950, and in 1960, Scapharca in Nakaumi-sea died out. Both lakes have been well investigated by Shimane University for the past 70 years and dominant species of microalgae are also well known.

1475

FIGURE 1 RICE FIELD MODEL

C02 Fresh

Water

!. I i....~ Raceway Pond

U

.

.

Rice Field

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.

.

.

.

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FIGURE 2 LAKE-SHINJI--NAKAUMI-SEA RESTRATION PLAN

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Until 1950, the dominant species of microalgae were fresh water and salt water diatom. Then the dominant species of algae changed from diatom to cyanobacteria , Aphanocapsa, when it received the enrichment of the nutrients in the lakes coming from the Hii-river. Figure 2 shows that diatom cultivated in the raceway ponds by utilizing CO2 exhausted from a power plant are used as the feed for bivalves while the nutrient free clean water is produced as the important byproduct.

1476 DISCUSSION

Biofixation of COz A method to utilize dormant rice paddies to cultivate microalgae which can be used as herbicide and bio-fertilizer, is investigated. The microalgae applied to the system, Diatom, Anabaena and Azolla are considered. The appropriate species of microalgae is determined, based on considerations of the site conditions. In Japan, because of the over-production of rice, a 30% reduction in rice cultivation is enforced by the government, leaving the total area of dormant rice paddies at about a million hectares. These can be utilized to cultivate microalgae. If so, the total amount of CO2 sequestrated through biofixation becomes 73 million tons per year, assuming the productivity of microalgae is 20 g/m2/d(CO2 basis).

Treatment of Agricultural Waste Water In Japan, the treatment of agricultural waste water has not been considered as an important problem. However, it is true that the agricultural waste water, along with municipal waste water, exhausts nutrients such as nitrogen and phosphates into rivers, causing the nutrient enrichment of rivers, lakes, and the bays. The harvest of fish and shellfish has decreased accordingly. The Shinji-lake and Nakaumi-sea Restoration Plan proposes the idea of restoring the dominant species of microalgae from cyanobacteria back to diatom, thus restoring the proper food supply for fish and shellfish. Treatment of agricultural waste water using microalgae in the dormant rice paddies is the cheapest way to treat the agricultural waste water and it also produces valuable clean water. REFERENCES

1. 2 3. 4. 5. 6. 7. 8

Oswald W.J. and Golueke C.G.(1960). Biological transformation of solar energy:: Adv. Applied Microbiol.,2: 223-262 Tamiya H. (1957).Mass cculture of algae: Ann. Rev. plant Physiol. Benemann J.R., Weissman J.C. and Oswald W.J.(1979) Algal Biomass:Economic Microbiology, Academic Press. Ben-Amotz A. and Avron M. (1980). Clycerol,beta-carotene and dry algal meal production by commercial cultivation of Dunaliella: Elsvier Press. Ikuta Y. Akano T.,Shioji N., Maeda 1.(1998). Hydrogen production by photosynthetic microorganisms: BioHydrogen, edited by Zaborsky et al. Plenum Press., New York Negoro M,Ikuta Y., Makita T, et. Al.(1993 ). Carbon dioxide fixation by Microalgae photosynthesis using actual flue gas:Applied Biochem.and Biotech. Vo139/40 Ikuta Y., Weissman J.C.(2OOO).Carbon dioxide utilization-microalgae biofixation: Technology: Vol. 75, pp137-145 Benemann J.R.,Weissman J.C., Oswald W.J., et.al.(1977).Final report; Fertilizer production with nitrogen fixing heterocystous blue-green algae UC.Berkeley

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1477

POSSIBILITY OF CO2 FIXATION ON ARID LAND IN WESTERN AUSTRALIA K. Yamada 1, T. Kojima2, Y. Egashira 3, Y. Abe4, M. Saito 5, and N. Takahashi 1,6 1Department of Fine Materials Engineering, Shinshu University, Ueda, Nagano, 386-8567, Japan 2Department of Applied Chemistry, Seikei University, Musashino, Tokyo, 180-8633, Japan 3Department of Chemical Science and Engineering, Osaka University, Toyonaka, Osaka, 560-8531, Japan 4Institute of Agricultural and Forest Engineering, University of Tsukuba, Tsukuba, Ibaraki, 305-8572 Japan 5Forestry and Forest Products Research Institute, Tsukuba, Ibaraki, 305-8687, Japan 6Japan Science and Technology Corporation, 2-1-13 Higashiueno, Taito-ku, Tokyo 110-0015, Japan

ABSTRACT

Carbon fixation by afforestation is one of a few effective countermeasures against the carbon dioxide problem. In particular, afforestation of arid land is promising, since the arid land exists in large quantities in the world. Under the above background, the authors started a research project supported by the Japan Science and Technology Corporation in 1998. The main research area was set up in the interior of Western Australia where mean annual rainfall is about 200 mm. The growth tendency of trees at the site C, where the breakage of the impermeable layer was conducted, is reported. At this site, 12 water ponding banks were developed surrounding a planting area (50 m x 50 m) to collect runoff and retain rainfall. Then, around 50 trees were planted in each planting area. Tree height, crown diameter and trunk diameter at 0.3 m and 1.3 m from ground level for several species such as Eucalyptus camaldulensis, Acacia aneura, and Casuarina obesa were measured every few months after planting. The results from other site are also reported. Finally, an integrated simulator of plant growth, photosynthesis, transpiration, and soil water transport was developed as a platform for the competition of arid land afforestation technologies for CO2 Fixation. Mathematical models of processes from rainwater to vegetation; these were implemented as a web application and the amount of primary production of planted tree calculated. Thus, the effect of introduction of various technologies could be quantitatively evaluated. INTRODUCTION

C02 fixation by afforestation is expected to be a sustainable, economical and also low environmental burden

1478 method. According to the COP agreement, the amount of CO2 absorbed in planted trees can be counted as the reduction of CO2 imposed to each developed country. However, this afforestation requires a large area to be a countermeasure against the global warming. When considering a requirement to secure such a large area, arid and semi-arid land are the most favorable candidates for afforestation on a large scale, because of freer accessibility than to areas of higher rainfall. However, needless to say, water necessary for tree growth is insufficient in such regions and the growth of planted trees cannot be expected without any effort to increase available water. There are other environmental conditions unfavorable for tree growth. Therefore, it is important to improve such unfavorable conditions with the minimum energy consumption and to effectively utilize a low level of rainfall. Much individual or basic research has been done on afforestation of arid land. However, a systematic method integrating individual techniques, including traditional ones, is needed to attain a sustainable CO2 fixation as a measure to reduce atmospheric CO2. For the establishment of the afforestation system, many individual works on rainfall, evaporation, runoff, soil structure, hydrology, topography, plant, salts etc. and their integration are required. Against the above background, the authors started a research project supported by the Japan Science and Technology Corporation in 1998. One of the aims of the project is the proposal and demonstration of new techniques and systems applicable for the afforestation of the arid land. The main research area was set up in an interior region of Western Australia, where mean annual rainfall is about 200 mm. We have set several test afforestation sites in the area, named as sites A-E. In the present paper, initially, the plant growth results at site C are shown. The results from other sites will also be reported shortly. Finally, an integrated simulator of plant growth, photosynthesis, transpiration, and soil water transport is introduced as a platform for the competition of arid land afforestation technologies for CO2 fixation.

OUTLINE OF THE TEST PLANTATION SITES The main research area set up in an interior region of Western Australia is shown in Figure 1. We have set several test afforestation sites in the area named as sites A-E. In or near all of the test afforestation sites, ground water was pumped up with windmills and stored in tanks set near the sites. Water irrigation was conducted at intervals or only during the drought season. Heights, canopy diameter, trunk diameter etc. of the planted trees were measured every three months at all of the planting sites. In order to estimate carbon fixation rates of the planted trees more accurately, a more detailed relationship between dimensions and mass of each species will be delivered in near future by using the obtained results. In the present study, first of all, the concepts and typical results of the sites are shown. At Site A, where the test afforestation under irrigation with different frequencies has been conducted, higher frequencies of irrigation caused higher growth rates of the planted trees. However, the difference in the growth rate among the trees growing with the different irrigation frequencies was larger than that in the frequencies. The reason is considered to be that the irrigation with a higher frequency encouraged a quicker and more extensive development of their roots. The planted trees with the developed roots could absorb more water from the soil and grow much more quickly than those growing under less irrigation. The results obtained from the test afforestation at Site A indicates that the growth rate of Casuarina sp. depends greatly on the irrigation frequency and can grow faster than Eucalyptus sp. under good water conditions. On the other hands, Eucalyptus sp., especially E. camaldulensis, can grow faster under worse water conditions than the other species. The present results also indicate the effect of gathering water only with precipitation water under dry conditions, which was already expected at the proposal period of the present project.

1479

~TAS~ Figure 1: Main research area at Westem Australia At the other sites as well as Site C, the detail of which is shown in the next section, various types of techniques for soil structure improvement and water collection were also introduced to improve the water utilization efficiency. It was demonstrated that afforestation is possible by the introduction of these techniques, even into the originally arid areas without any remarkable vegetation. The soil structure improvement techniques are demonstrated to be effective, as well as the water collection techniques.

THE TREE G R O W T H TENDENCY IN SITE C In Site C, 12 water pending banks were developed surrounding a planting area (50m x 50m) to collect runoff and retain rainfall. Then, around 50 trees were planted in each planting area. Topsoil in the site was thin because the impermeable layer existed in the shallow stratum and the water storage capacity of the soil was very low. Hence, this layer was broken using explosives and trees were planted in the destroyed pits, which were about 5 m in diameter. After soil improvement was performed, tree species to be planted, height of trees and planting positions were determined. Several species such as Eucalyptus camaldulensis, Acacia aneura, and Casuarina obesa were selected and planted, taking into consideration tolerance to water stress and growth speed. The trees were fertilized and irrigated with water for nourishment until sufficient root development. The tree height, crown diameter and trunk diameter at 0.3 m and 1.3 m from ground level measured every few months after planting were analyzed as follows. Total above-ground biomass for a tree was estimated using a prediction equation derived from results of the cutting off survey in the Leonora for each species. The estimated results of change in total above-ground biomass at Site C per hectare are shown in Figure 2. Not only did the trees effectively survive from the first plantation, but also trees additionally planted after the death of the trees first planted; this contributed towards the biomass increase of ten times, after two and half years from the first plantation. The change in average tree height of a tree for each species is shown in Figure 3 with statistic error bars. It can be said that C. obesa and E. camaldulensis were relatively higher and grew more rapidly than the other species in two years. The growth rate of E. torquata was lower than E. camaldulensis although the initial height was comparable. Furthermore, it was lower than E. lesouffei, A.aneura, E..salburis and E. griffithsi although the initial height was much greater.

1480 120

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Figure 2: Total above-ground biomass at the site C

~-~ 600

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Aug-99 Mmr-00 Feb-01 M0.r- 02

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8 N Figure 3" The change in mean height of a tree for each species

SIMULATION PLATFORM OF ARID LAND AFFORESTATION FOR C02 FIXATION An integrated simulator of plant growth, photosynthesis, transpiration, and soil water transport, seems a suitable tool for the estimation of the amount of vegetation. In contrast to the correlation technique extrapolating or interpolating results of well-examined afforestation technologies, the simulation technique can be applied for many afforestation technologies, including noble ones, and the estimated results can be compared with each other. An integrated simulator can be termed a platform for the competition of afforestation technologies. The integrated simulation platform that can predict the amount of carbon fixed by afforestation is thus attempted. The afforestation project site at Sturt Meadows near Leonora was chosen as model case of this platform.

1481 The design of the simulator platform started from considerations on water transport. As shown in Figure 4, water in arid land can be classified into five categories according to their locations: water in atmosphere, surface water, soil water, underground water, and water in plants. Water transport between/in these categories should be considered for the complete simulation model. Fortunately, some of the water transport processes can be simplified, taking the conditions of the project site into account. At first, the existence of the hardpan restricts water transport from surface soil into underground water, so underground water was not considered in the model. Also, atmospheric water were not modeled, instead, measured data of rainfall and humidity was used. The surface water model is simplified as follows: During the rainfall period, runoff, an extensive surface water transfer, sometimes occurs. After such rainfall, the amount of surface water assumed to be restricted to the height of bank, or geographical structure act as bank. Otherwise, total rainfall was used as surface water amount after rainfall. According to the above considerations, a simulation platform was constructed based on the soil water transport model. Two types of soil water transport simulators were implemented; one for the wetting process and the other for the drying process. The wetting process simulator, or infiltration process simulator, deals with the situation such as liquid water remaining on the soil surface. This infiltration simulator is applicable for rain time or directly after rainfall. When all surface has water infiltrated or evaporated, a simulator for the drying process should be used. In this simulator, root uptake of soil water by the plant system is taken into account, and also the model for plant water transport, transpiration, was combined. This evapo-transpiration simulator can be used until the next period of rain or irrigation time, and be succeeded by the infiltration simulator, etc. Both the infiltration simulator and the evapo-transpiration simulator are fundamentally one-dimensional soil water transport simulators based on Darcy's law of water transport, combined with an empirical model of the unsaturated permeability coefficient. In the evapo-transpiration simulator, transport of vapor phase water was also taken into account. The effects of plants are also limited to the evapo-transpiration simulator, as the timescale of the infiltration process, minutes-hours, and that of the evapo-transpiration process, days-months, are quite different, and the evapo-transpiration process occupies the greater portion of the whole time. In the evapo-transpiration process simulator, the transpiration rate for a unit leaf area is modeled as flux caused by the difference between soil water potential and atmospheric water potential as driving force. The resistance for transpiration flux should include root, stem, and leaf flow resistance, stoma resistance, and resistance of boundary layer around the leaf. It is probable that the total resistance for transpiration is dominated by the diffusion process of vaporized water, instead of flow process of liquid water. Therefore, only stoma and boundary layer resistances are used for transpiration rate calculation. Considering the limited water conditions at arid lands, stoma resistance is modeled as a function of leaf water potential, for taking into account the effect of water stress of the plant, and the leaf water potential is approximated by soil water potential. The photosynthesis rate is modeled as a function of light intensity and CO2 supply through stoma from the atmosphere. Through this relationship, the water transport model is connected to plant CO2 fixation. For example, when water concentration in soil decreases, i.e. soil water potential decreases, leaf water potential also decreases and stoma close to reduce the water transpiration rate. Thus, increased stoma resistance limits CO2 supply and photosynthesis rate decreases. Respiration rate should be estimated for calculating plant growth. Although some detailed models for respiration process are proposed, less quantitative information on growth process of the plants in arid land limits their applicability. Thus, a simple modeling and parameter fitting technique was applied. Respiration rate is assumed to be proportional to photosynthesis rate, and remaining carbon fixed by photosynthesis is used for plant growth. Accumulated plant growth for each time step results in total weight of the plant and an

1482 allometric relationship is used to estimate leaf area index. Plant growth results in an increase in the leaf area index and also an increase in photosynthesis and transpiration; in this way, the plant system and soil water transport are correlated. Application and parameter fitting using this simulator platform to the data of afforestation experiments performed at site C indicates that the ratio of carbon used to plant growth in photosynthesis is around 1 0 - 20 % for A c a s i a a n e u r a .

dmulttbn (Pu'd.*tO : water

roundwater

Figure 4: Summary of water storage form and their transfers in arid land.

CONCLUSIONS In order to attain net fixation of CO2 by afforestation, the quantitative evaluation of fixed carbon achieved as well as that of CO2 released from afforestation processes is essential. In the present study, it was demonstrated that the former evaluation is possible by both numerical simulation and test afforestation.

ACKNOWLEDGEMNENT This work was financially supported by the Japan Science and Technology Agency.

U T I L I S A T I O N - ALGAE

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1485

CO2 REFORMING OF METHANE CATALYZED BY Ni-LOADED ZEOLITE-BASED CATALYSTS

Satoru Murata Nobuyuki Hatanaka, Hiroharu Inoue, Koh Kidena, and Masakatsu Nomura Department of Applied Chemistry, Faculty of Engineering, Osaka University, 2-1 Yamada-oka, Suita, Osaka 565-0871, Japan

ABSTRACT The catalytic performance of nickel-loaded, zeolite-based support for CO2 reforming of methane was investigated. Among the three zeolites employed (H-Y, H-mordenite, and Na-mordenite), H-mordenite was found to be the best support for the above reaction, probably due to its thermal stability. Comparing the activity of Ni/H-mordenite (Ni/HM) with conventional Ni/alumina catalyst (Ni/A1203), the authors found that initial activity of Ni/HM was higher than that of Ni/A1203, while deactivation of the former proceeded at a slightly faster rate than that of the latter. It was also found that a physical mixture of alumina and zeolite, and composite support consisting of alumina and zeolite, became a more effective support than zeolite itself. The resulting Ni/H-mordenite-alumina catalyst (Ni/Mix or Ni/Cmp) showed the highest performance among the catalysts employed in the present study: under the conditions of atmospheric pressure of CO2/CHn/H2 stream (20/20/40 mL/min) at 700 °C, initial CO2 conversions were

ca.

90 %, this value being maintained for

at least 3 days.

INTRODUCTION Global warming by greenhouse gases is a serious problem in the world. Therefore, mitigation of greenhouse gases becomes an important research target in academic and industrial fields. Reforming of natural gas with carbon dioxide is one of the most promising technologies for mitigation of two kinds of greenhouse gases, carbon dioxide and natural gas [ 1-3]. Group VIII transition metals catalyze the above reaction, among which, nickel and some noble metals (rhodium, ruthenium, etc.) are the candidates as industrially practical catalysts of the reaction. Nickel can be used at a low price and is highly active, although it loses this activity rapidly

1486 by carbon deposition. In general, noble metals resist carbon deposition, but these are expensive. Under these situations, methods for preventing carbon deposition on nickel catalysts have been studied extensively, including doping of alkaline or alkaline-earth metals [4-6], use of basic supports such as La203, Ce203, etc., using solid solution catalyst of basic oxides and nickel, and co-loading of secondary active species. Zeolite is one of the most convenient and common supports in the catalytic research fields. However, few reports were published for the application of zeolite-based catalyst for the dry reforming reaction of methane [7-8]. The authors prepared several nickel-loaded zeolite based catalysts to submit to the dry reforming reaction and found that some modified mordenites showed higher performance as the support of the reaction.

EXPERIMENTAL SECTION

Preparation and Characterization of Ni-loaded Catalysts H-mordenite [JRC-Z-HM-20(4), abbreviated as HM] and Na-mordenite [JRC-Z-M-20(1), abbreviated as NaM] were provided by the Catalysis Society of Japan as the reference catalysts.y-A1203 was provided by Sumitomo Metal Mining Co. Ltd. A physical mixture [abbreviated as Mix(50HM-50A1)] of HM and alumina was prepared according to the following method: Zeolite and alumina (1:1, wt/wt, 10 g in total) were mixed in water (100 mL), the resulting mixture being stirred for 1 h at a room temperature, then, being filtered, dried at 120 °C under an atmospheric

pressure

for a night

before

nickel

loading.

Composite

support

[abbreviated

as

Cmp(95HM-5A1)] of HM and alumina was prepared by the following method: HM was treated with water (50 mL) containing determined amounts of aluminum nitrate, then water being removed by using a rotary evaporator. The resulting sold was dried at 120 °C under air and was calcined at 500 °C for 3 h under air before nickel loading. Nickel loading to each support was conducted according to the following procedure: A mixture of aqueous solution of nickel nitrate (25 mM, 100 mL) and support (5 g) was stirred at 50 °C for 1 h, then water being removed by a rotary evaporator. The resulting solid was dried at 120 °C for a night before use. Alkaline or alkaline-earth doped catalysts were prepared by the following method: A mixture of aqueous solution of potassium carbonate or calcium nitrate and Ni/HM catalyst was stirred at 50 °C for 1 h, then water being removed by using a rotary evaporator. The resulting solid was dried at 120 °C for a night before use. Amounts of metal loading (Ni, K, and Ca) was about 3 wt%.

Catalytic Test Reforming reactions were carried out at atmospheric pressure by using a continuous flow fixed bed reactor. The nickel catalysts prepared (200 mg) diluted with 1.0 g of sea sands (20-35 mesh, Wako Pure Chemicals Co.) were placed on a center of the reactor, then being calcined at 450 °C for 1 h under a flow of He/O2 (4/1, total flow 50 mL/min) and being reduced at 450 °C for 1 h under a flow of H2 (50 mL/min). After that the furnace was heated up to 700-750 °C (in a typical case). In the case using Ni/A1203 as a catalyst, reduction was conducted at 800 °C. After the temperature of the electric furnace reached to the determined

1487 temperature, the feed gas (He/CO2/CH4 = 40/20/20, in mL/min) was introduced into the reactor for the start of the reaction. The products were analyzed by an on-line gas chromatograph (a Shimadzu GC-17 with a PoraPLOT Q column and a thermal conductivity detector).

RESULTS AND DISCUSSION

Catalytic Performance of Ni-Loaded Zeolitesfor Dry Reforming of Methane The dry reforming reaction of methane with Ni-loaded catalysts was conducted at 750 °C under atmospheric pressure. Time profiles of CO2 and CH4 conversion are summarized in Figure 1. Ni/HM and Ni/NaM showed rather high activity: initial CO2 conversions were 95 % for Ni/HM and 92 % for Ni/NaM. Along with elongation of the reaction duration, CO2 conversion gradually decreased to 92 % for Ni/HM and 87 % for Ni/NaM respectively. On the other hand, Ni/HY catalyst (not shown in Figure 1) had the lowest activity and loses it during 5 h reaction: CO2 conversion with the catalyst being 40 % and 15 % for 30 min and 5 h. These results indicate that H-mordenite is the best support for dry reforming reaction of methane among the zeolites employed. Therefore, in the following experiments, HM was employed. Compared with Ni/A1203 catalyst, one of the reference catalyst for the dry reforming of methane, initial activity of Ni/HM was higher than that of Ni/A1203, while rate for deactivation of Ni/HM was more rapid. The authors also examined the mixed support consisted of alumina and H-mordenite [Mix(50HM-50A1)], the results also being shown in Figure 1. Nickel-loaded mixed support showed the highest CO2 conversion and no deactivation was observed during 24 h reaction. As to CH4 conversion, similar trends for catalyst deactivation were observed as observed in CO2 conversion. The ratios of CH4 conversion over CO2 conversion were 0.95 for Ni/A1203, 0.94 for Ni/HM, 0.93 for Ni/NaM, and 0.91 for Ni/Mix(50HM-50A1).

100 • • A []

? "6 95

Im

Ni/Mix(50HM-50AI) Ni/HM Ni/AI203 Ni/NaM

----

m,..

£ o

o 90 e,l

o L)

400

800 1200 time (min)

1600

0

400

800 1200 time (min)

Figure 1: Time profiles for CO2 and CH4 conversion in dry reforming of methane. Atmospheric pressure, 750 °C, [CO2]:[CH4]:[He]=20:20:40 (in mL/min)

1600

1488

Modification of Ni-Zeolite Ni/HM catalyst showed rather high catalytic activity, while deactivation was observed during 24 h reaction. Therefore, the authors intended to modify Ni/HM catalyst to retard the deactivation by two ways: One is modification of mordenite surface with alumina, the other being co-loading of alkaline or alkaline-earth metals. As to the former, 5% of aluminum nitrate was impregnated on mordenite and the resulting mixture was calcined to obtain the composite support, Cmp(95HM-5A1). Ni/Cmp(95HM-5A1) was prepared by the conventional impregnation method of nickel nitrate. As to the latter, potassium carbonate or calcium nitrate (3 wt%, metal basis) was impregnated on Ni/HM. After an usual workup, Ni-K/HM or Ni-Ca/HM were obtained. These catalysts were submitted to the reaction under the similar conditions as shown in Figure 1 except for reaction temperature (700 °C), the results being shown in Figure 2. The conditions employed here seem to be somewhat severe than those in Figure 1, because catalyst deactivation proceeds faster by Boudouard reaction. In fact, faster deactivation of Ni/HM was observed than in the reaction at 750 °C. Retarding the deactivation was successful by co-loading of potassium (Ni-K/HM) or calcium (Ni-Ca/HM) as reported in the literature [4-6]. It should be noted that modification with alumina showed similar effects for retarding the deactivation. Both physical mixture of zeolite and alumina, and composite of zeolite and alumina were effective. Among the catalysts examined, both Ni-K/HM and Ni/Cmp(95HM-5A1) were effective and retained the activity at least 3 days. TABLE 1 CO2 CONVERSION OF THE DRY REFORMING OF METHANE BY USING SEVERAL NICKEL LOADED CATALYSTS.

100

o

90

g

Catalyst 80

ocq o r..)

• /~ • []

14 I-c~o \

70 ~ 0

20

Ni/Cmp(95HM-5AI) Ni/Mix(50HM-50AI) Ni-K/HM N!-Ca/HM

40

' 60

80

time (h) Figure 2: Time profile for CO2 conversion in dry reforming of methane. Atmosphericpressure, 700 °C, [CO2] : [CH4] : [He] = 20:20:40 (in mL/min)

conv0.5h conv24h conv72h (mol%) conv0.5h conv0.Sh

Ni/Cmp(95HM-5A1) Ni/Mix(50HM-50A1) Ni-K/HM Ni/Ca/HM Ni/HM

89 89 90 88 84

1.00 0.99 1.00 0.99 0.86

0.99 0.98 0.99

Reaction conditions: see caption of Figure 2. conv0.5h: conversion of CO 2 after 0.5 h reaction. conv24h: conversion of CO2 after 24 h reaction. conv72h: conversion of CO2 after 72 h reaction.

To obtain an insight into the carbon species deposited on the catalyst, TPO (temperature-programmed oxidation) experiments were conducted. After dry reforming reaction at 700 °C for 24 h, the catalysts recovered were submitted to TG analysis: The catalysts were heated under air stream from room temperature to 800 °C. Typical differential curve of the TG profile is shown in Figure 3. Each profile showed two peaks at around 0-350 °C and 400-800 °C, these corresponding to desorption or oxidation of small molecules and oxidation of carbon species, respectively. Amounts of carbons deposited on the catalysts can be calculated by integration of the peak at higher temperature region, the results being summarized in Table 2. After 24 h reforming reaction, 0.2 to 9 wt% of carbon species were deposited on the catalysts. As reported in the

1489 literature [4-6], co-loading of potassium or calcium lead to reduction of carbon deposition. This should be the reason for retardation of catalyst deactivation observed in the reaction with Ni-K/HM or Ni-Ca/HM. On the other hand, nickel loaded mixed support and composite support had more carbons than that on Ni/HM. Details of the mechanism of retardation of catalyst deactivation on alumina-modified Ni/HM are now unclear. Now, further study including one on the effects of the amounts of alumina on Ni/HM catalyst, SEM observation, XPS analysis of the fresh and used catalysts, etc, is now in progress.

TABLE 2 PEAK TOP TEMPERATURE AND AMOUNTS OF COKE DEPOSITED ON THE CATALYSTS ~,

Catalyst

o o

Ni/Cmp(95HM-5A1) Ni/Mix(50HM-50A1) Ni-K/HM Ni/Ca/HM Ni/HM

o

.o X o

~

Peak top Amoutns of coke temperature (°C) (mg-C/ g-cat.)

0

200

400

600

Temperature (°C)

612 602 555 623 638

74.7 89.3 1.8 32.1 75.9

800 Conditions for treatment and TPO: see caption of Figure 3.

Figure 3: Typical TPO profile of the used catalyst: Ni/Cmp(95HM-5A1). TPO conditions, from room temperature to 800 °C with 10 °C/min; catalyst pretreatment: at 700 °C, for 24 h, with CO2/CH4/He (20/20/60 mL/min).

REFERENCES 1.

Nielsen, J. R. R. and Hansen, J. H. B., (1993) J. Catal., 144, 38.

2.

Wang, S., Lu, G. Q., and Millar, G. J., (1996) Energy Fuels, 10, 896.

3.

Bradford, M. C. J., and Vannice, M. A., (1999) Catal. Rev. Sci. Eng., 41, 1.

4.

Ruckenstein, E., and Hu, Y. H., (1995) Appl. Catal. A: General, 133, 149.

5.

Frusteri, F., Arena, F., Calogero, Ct, Torre T., and Parmaliana, A., (2001) Catal. Commun., 2, 49.

6.

Quincoces, C. E., Dicundo, S., Alvarez, A. M., and Gonzalez, M. Ct, (2001) Materials Lett., 50, 21.

7.

Chang, J.-S., Park, S.-E., and Chon, H., (1996) Appl. Catal., A: General, 145, 111.

8.

Song, C., Srimat, S. T., Murata, S., Pan, W., Sun, L., Scaroni, A. W., and Armor, J. N. "CO2 Conversion and Utilization", (2002) ACS Syrup. Ser. Voi.809, ACS, Washington DC, Chapter 17, pp.258-274.

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1491

P R O M O T I O N OF CO2 H Y D R O G E N A T I O N IN FIXED BED RECYCLE R E A C T O R S M. J. Choi*, J. S. Kim, S. B. Lee, W. Y. Lee, and K. W. Lee ENR Team, Korea Research Institute of Chemical Technology, Taejon 305-600, Korea

ABSTRACT One of the promising technologies for the utilization of CO2 is the selective synthesis of valuable chemicals by means of catalytic hydrogenation. A catalytic fixed bed recycle reactor and series reactors have been proposed to increase the level of reaction conversion in conducting the hydrogenation of CO2. The hydrogenation of CO2 was carried out over Fe-K based catalyst. The conversion of carbon dioxide (Xco2) increased with increasing reaction temperature and residence time (Xmod)in the fixed bed single reactor. In series reactors, Xco2 increased up to the level of 68.5% (T=300°C, P=I.0MPa, H2/CO2=3 and SV=l.0N1/gcat.hr) in comparison with the level of 40.8% in the fixed bed single reactor at the same conditions. Also, Xco2 increased with increasing recycle ratio (R) and it had maximum values with increasing total space velocity (SVT) around 4-5N1/gcat.hr in the recycle reactor. For the olefin rich production, maximum Xco2 was the level of 75% in the recycle reactor, however paraffin selectivity was increased when the Xco2 was above 80%. From the results of experiments, the recycle reactor as an alternative reactor was beneficial to increase Xco2 for the hydrogenation of CO2 instead of the fixed bed single reactor. INTRODUCTION

To control and reduce emissions of CO2, various countermeasures such as capture, storage and utilization have been proposed [ 1-4]. One of the advanced concepts to mitigate CO2 is the catalytic conversion of CO2, into valuable chemical feedstock, because it can be developed to commercial process by treating the large amount of CO2 rapidly. There have been two kinds of methods for the hydrocarbon synthesis from CO2 hydrogenation. The one is the combination of methanol and hydrocarbon synthesis (MTG process), and the other is the direct hydrogenation synthesis by means of the modified Fischer-Tropsch (MFT) process gained special attention as a potential way for producing liquid hydrocarbons as well as Gas-to Liquids [3-8]. The catalyst system for the hydrogenation of CO2 has been developed to obtain more valuable chemical feedstock such as light and higher olefins. For the direct hydrogenation of carbon dioxide to hydrocarbons over various kinds of Fe based catalysts, K, V, Cr, Mn and Zn promoted iron catalysts have been prepared by precipitation or impregnation method. It has been reported that Fe-K catalyst gives the relatively high CO2 conversion as well as the high selectivity of light olefins [9-12]. As results of previous studies in the fixed bed reactors, it has been reported that the CO2 conversion and CO selectivity have not been available levels to commercialize the process, because water vapor and products inhibit CO2 conversion. However, there has been little available information on alternative processes such as recycle of unconverted gases or use of reactors in series, which can be anticipated as an effective scheme for the removal of water vapor and product and heat of reaction during the hydrogenation of CO2, since the reactor is highly exothermic [13-16]. In this study, thus, a fixed bed recycle reactor has been employed as alternative reactor configurations to increase the CO2 conversion on conducting the direct hydrogenation of CO2 as well

1492 as fixed bed series reactors. Effects of alternative reactor configurations on the CO2 conversion and hydrocarbon selectivity for the maximum yield of olefinic liquid products have been investigated.

EXPERIMENTAL

Preparation of Catalyst Fe-K based catalyst was prepared by impregnating the y-alumina support with Fe(NO3)3.9H20 and K2CO3 solutions. The catalyst gel was formed with colloidal alumina by extruder (2.5mm diameter x 5mm length), dried (110°C, 24hr) and calcined in air at 500°C for 12 hours.). The catalyst was reduced at 450°C at atmospheric pressure in a hydrogen flow for 24h. The composition and properties of the catalyst are given in Table 1. Reaction

System

CO2 hydrogenation was carried out in a bench scale fixed bed reactor (1.6cm-ID x 60cm-High). Schematic diagram of fixed bed reactor system used for CO2 hydrogenation was shown in Fig. 1. The reaction and internal standard gases (CO2, H2, N2, He) were taken from cylinders and their flow rates were controlled by MFC (mass flow controller, Brooks co.), respectively. Reaction temperature was controlled in the range of 250-325°C by temperature control system and reaction pressure was maintained in the range of 0.5-2.5 MPa by BPR (back pressure regulator, Tescom co.). 21g of catalysts were filled out and the total gas flow rates of reaction gases were changed in the range of 350-1400 ml/min, the space velocity of the mixed gas was controlled ranging from 1 to 4 N1/gcat.hr at STP. H2/CO2 mol ratio was ranged from 2 to 5. The liquid phase products were separated from gas phase products in the gas-liquid separator and condenser. And the exit gas flow rate was measured by the digital bubble flow meter to evaluate the reaction conversion. The gaseous products were analyzed by 2 kinds of on-line GC using internal standard gases, N2 and He to measure the consumption of CO2 and H2, respectively. With the data obtained from the GCTCD analysis, the conversion of CO2 and the yield of CO and CH4 were calculated. Also with the peak area of organic products were referred to the peak area of CH4 (GCTCD), the organic product selectivities and yields were calculated and determined from the GC-FID analysis.

igure 1: Experimental apparatus 1. Mass flow controller 2. Fixed bed 1st reactor 3. Fixed bed 2 nd reactor 4. Electric heater 5. Gas-liquid separator 6. Condenser 7. Heat exchanger 8. Back pressure regulator 9. Gas compressor 10. Buffer tank 11. Pressure regulator 12. Wet gas meter

1493 TABLE 1 COMPOSITION AND PROPERTIES OF Fe-K BASED CATALYSTS CO2 uptake BET surface area Composition [mE/g] [~%] [~tmol/g]

Catalyst

514

92

Fe:K:A1203 = 20:7:100

Fe-K/A1203

uptake [pmol/g]

H2

20

RESULTS & DISCUSSION In previous studies, effects of operating variables on the CO2 conversion (Xco2) had been investigated. The CO2 conversion increased with increasing reaction temperature (250-325°C), Pressure (0.5-2.5MPa) and H2/CO2 mol ratio (2-5) however, it decreased with increasing space velocity (1-4 Nl/gcat hr)[17]. The values of Xco2 are correlated as a function of the operating variables in Eq. (1). This correlation can be seen in Fig.2 with correlation coefficients of 0.89. It shows that CO2 hydrogenation depends on mainly reaction temperature rather than Space velocity per pressure, and reactor diameter per particle diameter of catalyst in the range of operating conditions.

FLs-vj

xc~):

A lifetime tests of Fe/AI203 catalyst has been conducted on the CO2 hydrogenation in fixed bed reactors as shown in Fig.2. The catalyst is used more than 1000 hours to maintain the CO2 conversion level up to 60 C-mol % (SVT=4, R=3) with recycle of unconverted gases (or recycle reactor). It had been shown high activity the CO2 conversion level up to 35 C-mol % with single-pass (or single reactor) [ 17]. In fixed bed reactor, catalysts generally have diameters larger than l mm due to pressure drop constraints. Fig4 shows the effects of catalyst size on CO2 conversion (Xco2) and CO selectivity for the CO2 hydrogenation. Xco2 is decreased with increasing catalyst size due to intra-particle diffusion limitation. However, Sco is increased rapidly with increasing the particle size of catalyst (>2mm). It has been explained that internal-diffusion regime is encountered with increasing particle size for consecutive reactions [18, 19]. 50

•

i

•

i

,

i

~/,

I

80

,

45

,/'•

15% error "0

E, o

SVT=4, R=3 (Recycle reactor)

, ~J

•

iiwiillii~iiiiAnllllllinulii~ilniiRminmiliniiw

6O

,,/

40

-

o

E

~ 35

,;./...,-

8 X 30

25

i 25

,

. " l

,

~

x

so

SV=2 (Single reactor)

40

:}E~E]OnEEEEEE~rToo~EE~E~{~E}O~EEt::}EE~~

,

,

,

,

, 20

30

35

40

45

50

Xco2..x~,,,.~e.t..[C-mol %]

Figure 2: Comparison of Xco2 between the Exp. and Cal. values in fixed bed single reactors (H2/CO2- 3).

l

o

I

200

i

I

,

I

,

400 600 Time on stream [hr]

I

|

soo

Figure 3: Activity and lifetime test of FeK/AI203 catalyst in fixed bed reactors (T=300°C, P=IMPa).

1494

6O

Iniet

Xco2 =

Sco ---c~-- (300°C, 1.0MPa)

=

- - - o - - (315°C, 1.5MPa)

;

'

'

'

'

I

5O

N

~',

84o

Or)

"o

--~ 0.4 20

10 0

2

0

4

6

dp

8

0.0

280

10

[ram]

Figure 4: Effects of catalyst size on Xco2 and Sco in fixed bed single reactors (H2/CO2- 3).

Outlet

i

-"-

~,y~

--t--720hr

-,

290

~'°hrI

i/! i 300

,

i

,

310

320

T e m p e r a t u r e Profile [°C]

Figure 5: Temperature profiles of C02 hydrogenation in fixed bed reactors (T=300*C, P=IMPa).

Axial temperature profiles can be seen Fig.5, the fixed bed reactor has a hot spot in the region of the inlet since the heat transport is relatively low for the exothermic reaction of CO2 hydrogenation. Further down the reactor tubes, hydrogenation rates are much lower as the reactants are being depleted. The hot spot is moved near the outlet when the time of stream flows since the catalyst is deactivated. It has been occurred in classical fixed bed reactors. Therefore, recycle mode was employed to enhance heat removal as well as efficiency of reactor performance. In the fixed bed recycle reactors, space velocity (SV), recycle ratio (R) and total space velocity (SVO were determined by Eq. (2), (3) and (4), respectively. S V = VI (

hourly volumetric flow rate of feed gas, ml/hr) mca, (amounts of catalyst, goat.)

R = SVR SV F

SV r

(space velocityof recycle feed gas, ml/g¢=hr) (space velocityof fresh feed gas, ml/gc=.hr)

(total space velocity) = S V g + S V F

(2)

(3)

(4)

Effects of recycle ratio (R) on the XCO2 and YHC and Yco can be seen in Fig. 6. XCO2 and YHc increased with increasing recycle ratio at constant total space velocity but Yco decreased. It can be understood that real residence time increases since the unconverted reactants used as feed gases. Inhibitions of water vapor and hydrocarbon products, also was reduced. It is noted that the Xco2 and YHC had maximum values with increasing total space velocity (SVT) around 4- 5 N1/geat.hr in the recycle reactor (Fig.7). Effects of residence time (Xmod) on the Xco2, YHc, Yco and product selectivity in the fixed bed recycle reactor (Figs.8, 9). Xco2 and liquid products were increased with increasing residence time due to the increase of contacting time. For the olefin production, maximum Xco2 was the level of 75% in a fixed bed recycle reactor, however paraffin rich products were produced when the Xco2 was above 80% due to low space velocity and high recycle ratio. From the results of experiments, the recycle reactor as an alternative reactor was beneficial to increase Xco2 for the hydrogenation of CO2 instead of the fixed bed single reactor (Table 2).

1495 •

SVr[mUg = hr] 2000 4000

Xcce YHc ---B--- ----0---13-- - - O - -

,

i

'

80

i

!

,

i

,

i

,

i

X~I Y~ Y¢o

SV~ = 570 SV~= 1000 SVF 20OO Single reactor

o~

5 E

i

Re-c~cle~eact;r

Yco

---4-- ---e---o-- --O-- - ~ - --o-- --o-- --ZY-

-5

60

o

E

60

~

40

o

o >)-

4O

X

)<

-... ........ ................... ....................

1000 0

1

2

3

4

5

2000

4000

5000

6000

7000

6

SV T [ml/g=, hr]

Recycle ratio, R

Figure 7: Effects of SVT on the Xco2, YHC and Yco in a fixed bed recycle reactor

Figure 6: Effects of R on the Xco2, YHC and Yco in a fixed bed recycle reactor

6o

3000

loo

(T=300~C, P = IMP,a, HT/CO~= 3).

(T?300]C, P = 1MPa, H~/CO2-- 3)..

+ Xcoz --41-- Y,c Yco

A

o~'

80

V

"

¢"

60 ,.....

o'

o~

Y

60 O '--'

,_oo

40

g -e

>-

4o

----=--- Liquid products - - e - - - C z - C4 CH 4 --@-- 0 / 0 + P

,,~ 20 "~ >., I

20

&-41=----0

, 0

I 1

i

I 2

,

I 3

0

i--

,

I 1

0

4

~

I 2

,

I 3

%od [gca,s/ml]

%od [g~t. s/ml]

Figure 9: Effects of Xmod on the hydrocarbon selectivity in a fixed bed recycle reactor

Figure 8: Effects of 1;mod on the Xco2, YHC and Yco in a fixed bed recycle reactor

(T=300°C, P =IMPa, H2/CO2 =3, R=2).

(T=300°C, P=IMPa, H2/CO2 =3, R=2).

TABLE 2 CARBON DIOXIDE CONVERSION AND PRODUCT SELECTIVITY Catalyst

Single reactor

Xc02

[C-mol%]

CO Sel.

[C-mol%]

40.8

11.1

68.5

13.7

C1

7.4

Hydrocarbon distribution [C-mol%] C2= C2 C3= C3 C4= Ca

5.8

1.4

9.6

1.1

7.0

>C5

0.9 55.7

O/O+P Ratio [%]

86.8

77.5 10.1 4.9 2.4 6.5 1.1 3.4 0.8 57.1 75.6 2.2 7.3 3.8 2.2 7.4 1.2 3.8 0.8 71.3 78.1 Recycle reactor-A 88.2 2.2 7.3 3.8 2.2 7.4 1.2 3.8 0.8 71.3 78.1 Recycle reactor-B (T=300°C, P = l . 0 M P a H2/CO2 =3, Single reactor: SV=I N1/gcat.hr, Series reactors: SV=I Nl/geat.hr, Recycle reactor-A: R=6, SVT=4 N1/gcat.hr, Recycle reactor-B: R=5, SVT=2 Nl/gcat.hr).

Series reactors

-

1496 CONCLUSIONS

A catalytic fixed-bed recycle reactor has been used to increase the level of reaction conversion in the hydrogenation of CO2.as well as fixed bed series reactors. The hydrogenation of CO2 was carried out over Fe-K/A1203 catalyst. From the experimental results of this study, some significant conclusions can be drawn, as follows: In fixed bed single reactors, effects of operating variables on the CO2 conversion (Xco2) had been investigated. The CO2 conversion increased with increasing reaction temperature (250325°C), Pressure (0.5-2.5MPa) and H2/CO2 mol ratio (2-5). However, it decreased with increasing space velocity (1-4 N1/gcat. hr). The values of Xco2 are correlated as a function of the operating variables (temperature, pressure and space velocity). In series reactors, XCO2 increased up to the level of 68.5% (T=300°C, P=I.0MPa, H2/CO2=3 and SV=lN1/gcat.hr) in comparison with the level of 40.8% in the fixed bed single reactor under the same conditions. XCO2 increased with increasing recycle ratio (R) and it had maximum values with increasing total space velocity (SVT) around 4-5 N1/gcat.hr in the recycle reactor. For the olefin production, maximum Xco2 was the level of 75% in the fixed bed recycle reactor, however, paraffin produced when the Xco2 was above 80%.

From the results of experiments, the recycle reactor as an alternative reactor was beneficial to increase Xco2 for the hydrogenation of CO2 instead of the fixed bed single reactor. REFERENCES

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19.

Fujimoto, K., Omata, K., Nozaki, O. and Han, Y., Energy Convers. Mgmt., 33, 529 (1992). Inui, I., Hara, H., Takeguchi, T. Ichino, K., Kim, J. B., Iwamoto, S. and Pu, S. B., Energy Convers. Mgmt., 38, 385 (1997). Park, Y. K., Park, K. C. and Ibm, S. K., Catalysis Today, 44, 165-173 (1998). Riedel, T., Claeys, M., Schulz, H., Schaub, G., Nam, S. S., Jun, K. W., Choi, M. J., Kishan, G. and Lee, K. W., Appl. Catal., 186, 201 (1999). Riedel, T., Schaub, G., Jun, K. W. and Lee, K. W.,Ind. Eng. Chem. Res., 40, 1355(2001). Dry, M. E., Appl. Catal., 138, 319 (1996). Satterfield, C. N., Huff, Jr., G. A., Stenger, H. G., Carter, J. L. and Madon, R. J., Ind. Eng. Chem. Fundam., 24, 450 (1985). Steynberg, A. P., Espinoza, R. L., Jager, B. and Vosloo, A. C., Appl. Catal., 186, 41 (1999). Yan, S. R., Jun, K. W., Hong, J. S, Choi, M. J., Lee, K. W., Appl. Catal., 194, 63 (2000). Choi, P. H., Jun, K. W., Lee, S. J., Choi, M. J. and Lee, K. W., Catalysis Letters, 40, 115 (1996). Nam, S. S., Lee, S. J. Kim, H., Jun, K. W., Choi, M. J. and Lee, K. W., Energy Convers. Mgmt., 38, 397 (1997). Nam, S. S., Kim, H., Kishan, G., Choi, M. J. and Lee, K. W., Appl. Catal., 179, 155 (1999). Hu, Y. C., Hydrocarbon Processing, May, 88 (1983). Kim, J. K., Moon, I., Joo, O. S. and Han, S. H., HWAHAK KONGHAK, 37, 670 (1999). Raje, A., Inga, J. R. and Davis, B. H., Fuel, 76, 273 (1997). Luyben W. L.,lnd. Eng. Chem. Res., 39, 1529 (2000). Choi, M. J., Kim, J. S., Kim, H. K., Lee, S. B., Kang, Y. and Lee, K. W., Korean J. Chem. Eng., 18, 645 (2001). Voge, H.H. and Morgan, C. Z., lnd. Eng. Chem. Process. Des. Dev., 11,454 (1972). Andrigo, P., Bagatin, R. and Pagani, G., Catalysis Today, 52, 197 (1999).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1497

THE USE OF MARINE M A C R O A L G A E AS R E N E W A B L E ENERGY SOURCE FOR REDUCING CO2 EMISSIONS M. Aresta* 1,2, A. Dibenedetto 1, I. Tommasi l,, E. Cecere 2, M. Narracci 2, A. Petrocelli 2, and C. Perrone 3 1Department of Chemistry and METEA Research Center, University of Bari, Via Celso Ulpiani, 27, 70126 Bari - Italy - e-mail: [email protected] 2Istitute for the Marine Coastal Environment - IAMC,CNR, Talassografico "A. Cerruti", Via Roma, 3, 74100 Taranto, I t a l y - e-mail: [email protected] 3Department of Plant Biology and Pathology, University of Bari, Campus Universitario, 70126 Bari, Italy, e-mail: [email protected]

ABSTRACT

The mitigation of carbon dioxide emissions, agreed at the international level with the Kyoto Protocol, has not yet been fully implemented because of the difficulty of implementing the reduction such emissions. The existing debate on the emission/immission of carbon dioxide has increased the need to develop the use of alternative energy sources to carbon-based fossil fuels, as well as the development of technologies aimed at the disposal of carbon dioxide in natural fields. Reducing carbon dioxide by using renewable energy sources is one of the strategic approaches that has received the highest attention. The use of biomass, as a direct or indirect energy source, is one of the ways for combining expectations of increased use of energy for future development with the need for controlling the concentration of greenhouse gases in the atmosphere. In this paper, we discuss the results of our studies on selected species of marine macro-algae for the production, under mild energetic conditions, of biofuel, through the extraction of oils or any other material that may be assimilated as a liquid fuel, and their potential for CO2 capture and as a source of energy. The study was carried out comparing different extraction technologies, among which were SC-CO2 and solvent extraction. The extraction based on SC-CO2 is quite advantageous. SC-CO2 is not toxic and, as its critical temperature is quite close to room temperature, it could be also used for the extraction of thermo-labile compounds. The current cost of production of macro-algae is compared with that of micro-algae, for an economic use of marine biomass for energy production.

INTRODUCTION The potential ofbiomass utilization for carbon dioxide capture is under assessment at the intemational level. Both terrestrial and aquatic biomass attract the interest of scientists and technologists. Aquatic biomass are particularly attractive as they have a higher photosynthetic activity with respect to terrestrial plants, an easier adaptability to grow in different conditions, and the possibility of growing either in fresh- or marine waters, thus avoiding the use of land. So far, attention has been devoted to fresh-water and marine microalgae, although much less to marine macro-algae, that could be also used as an energy source. Such application would have a great value for Mediterranean Countries, some of which are not rich in fresh water, but have an extended coastal zone with optimal climatic conditions. Curiously, the only studies available in the literature on the use of macro-algae as source of fuel are very preliminary and were carried

1498 out by Japanese or USA Researchers on algae from the Pacific Ocean. We have started a study aimed at the characterization of macro-algae of the Mediterranean Ocean that may have a potential for fuel production. In particular, we have considered algae that might be used for the up-take of nutrients from fishery wastewater and then processed for fuel production. Such an approach presents a double benefit: i) the abatement of N- and P-compounds in residual water from fisheries, making them suitable for either the immission into the sea or re-circulation, and ii) the production of fuel that could be used by fisheries, or distributed. Biodiesel has been considered as fuel. Alternatively, biogas could be produced through anaerobic fermentation of algae, a technology that has been already investigated. For the production ofbiodiesel, three techniques have been evaluated so far: extraction with supercritical-CO2 or SC-CO2 with methanol as cosolvent, and organic solvent extraction. The liquefaction of algae, and the pyrolysis technologies are also under evaluation. Here we report the list of algae selected for our studies and the preliminary results of biodiesel production through either SC-CO2 or solvent extraction and a preliminary assessment of the potential for energy production. We also compare the cost of growing macro-algae with that of micro-algae. RESULTS

Selected Algae Five marine algae were selected, namely: Chaetomorpha linum (O.F. Muller) Kutzing (Bryopsidales, Chlorophyta), Ulva laetevirens Areschoug (Ulvales, Chlorophyta), Gracilaria bursa-pastoris (S.G. Gmelin) P.C. Silva (Gracilariales, Rhodophyta), Pterocladiella capillacea (S.G. Gmelin) Santelices et Hommersand (Gelidiales, Rhodophyta), Codium vermilaria (Olivi) Delle Chiaje. All of them easily grow in the Mediterranean Sea and, more generally, in the boreal hemisphere. Additionally, some may live in the austral hemisphere. C linum is present in the unattached form in both estuarine systems [1] and coastal lagoons [2] subject to eutrophication. Several eco-physiological studies [la, 3] have demonstrated the ability of C. linum for short term adjustment of internal allocation of both nutrients and carbon. This makes C. linum greatly competitive for living in environments characterized by either light or nutrient supply variability. Therefore, C. linum can live throughout the year and can reach high biomass values, estimated at 5 kgfwt m 2 in the Venice lagoon [4] and 3.5 kgfwt m 2 in the Mar Piccolo of Taranto [5]. U. laetevirens (as U. rigida C. Agardh) is present in estuaries [la,b] and shallow eutrophic lagoons [6]. During the growing season it may reach [4] 15-20 kgww m 2 and large flee-floating thalli. G. bursa-pastoris is one of the few Rhodophyceae able to live in eutrophic coastal lagoons [5, 7] where in some periods it becomes the dominant species of the drifting bed. P. capillacea commonly lives on rocky hard substrata, often on vertical rock-faces, from the intertidal level to about 20 m depth, in wave exposed areas. This species is widely distributed in the Mediterranean Sea, but lives in both hemispheres at any latitude, except for the cold extreme ones. P. capillacea is also a common species in the nitrophilous biocenoses. It is perennial and is present throughout the year with erect thallus. The reproduction is both sexual and asexual, or through vegetative propagation by means of stolons [8]. C. vermilaria lives on hard horizontal substrata, often interested by a remarkable sedimentation, either in sheltered or lightly wave-exposed areas, between 0 and 50 m depth, in shady places. This species is distributed in the boreal hemisphere from North Atlantic Ocean to Mediterranean Sea. It is perennial, present throughout the year with erect thallus, but occasional sea-storms can detach the algae from their base C. vermilaria reproduces sexually, but often entire populations can be female and parthenogenetic [9]. Due to their adaptability to variable conditions and presence throughout the year, the algae listed above can be good candidate for cultivation in ponds. Our research program includes the following steps. •

• • •

Eco-physiological characterization of the selected algae. Standardization of the culture conditions. Definition of the photosynthetic capacity as function of the temperature and light intensity. Optimization of the conditions for growing algae in ponds.

1499 As our objective is the use of recovered carbon dioxide from either power plant flue gases or industrial plants as source of carbon, we also have planned to investigate the effect of • carbon dioxide concentration • NOx and SOx level in feed gas on the rate of growth of the algae and on the yield and quality ofbiodiesel. Additionally, we intend to ascertain if such macro-algae can be conveniently grown in a bioreactor, that would allow their growth under unfavorable climatic conditions.

Optimization o f the Conditions for the Growth of Algae The selected algae have been investigated for the definition of the best conditions for their growth in a pond. The influence of temperature, irradiance, weight/volume ratio on the growth, and oxygen production has been followed during one year. Also, the production of oxygen by a freshly collected sample has been seasonally monitored as a function of the temperature. In this way, the best period for harvesting the algae has been defined and the wet collectible mass estimated. This procedure was standardized for C. linum. Both the best growth rate and the highest Oz production were attained by C. linum cultivated at a temperature of 24 °C, an irradiance of 92 ~Em-Zs-1 and a weight/volume ratio of 0.2g/0.7L. The maximum daily growth rate was of about 10% and the O2 production of 0.2 ~LO2 hqmgfwt-1. These values are in the range of those registered for other high productive seaweeds present in the Mar Piccolo of Taranto [ 10]. For the freshly collected thalli, the highest 02 production of 0.62 ~tLO2 h-lmgfwt was measured in the thalli collected at the beginning of spring, at the field temperature of 15.4 °C. This period corresponds to a minimum of growth in the life cycle of C.linum [5], so the lack of self-shading by the high biomass of this free-floating species, could justify the highest productivity attained. This could even be confirmed by the highest production of 02 obtained in each cultivation test at the lowest weight/volume ratio used. We plan to evaluate the effects of CO2 concentration, as it was observed that C. linum grown in a Spanish coastal lagoon showed an increased O2 production both in spring and in summer, under CO2 enrichment [2b]. Treatment of the Algae: Equipment and Methodology Five algae were treated so far, namely C. linum, P. capillacea, U. rigida, C. vermilaria and G. bursapastoris. Five techniques were used for the extraction of products that may be used as biofuels: extraction with supercritical-carbon dioxide (SC-CO2), extraction with SC-CO2 and methanol as co-solvent, extraction with organic solvents, liquefaction, and pyrolysis. In this report we focus on the use of SC-CO2 extraction, SC-CO2 with methanol as co-solvent and the extraction with an organic solvent. The equipment used for SC-CO2 extraction was a SITEC apparatus, (Scheme 1) which temperature and pressure are fully computer controlled. The range of the working conditions is: temperature up to 500 K, pressure up to 33 MPa. (~5

r ....

C1 ,,~- C 0 2

L .................

q

r .......

J

_.

i i I

._

I

r

~..

i!

,_a_

vs

L

i_ . . . . . . . . . . .

I

!

!

i i

d

! I

~

III ~

v36

L_X/_I],

I

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.

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.

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IIIw3

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ill

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i L_.LI i Jl v'll- ,.,.,, ..., ! ii

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-.-=-

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l .L.L_. i-" ' -'-"

Wl !,, ................... . ............

:.--t

:

i

r. . . . . . . .

L . . . . = - . ~

'_ . . . . .

II

~a

i "

~------ . . . . . . . . . :

I

i I

i i

~

!~

I

i

L ..... .,

I

~

,,,~

Zi_! -

i

r ....

i

'

~

~]~--L....r ~ l

J

I'I

,, ""

t

I W4

'

I "::::: I

I

'

' c~zt,o

-,,=,

"1"

I ~ ~

Figure 1: Supercritical-CO2 apparatus used for the extraction of fatty acids and hydrocarbons from algae. Bl=Extractor; Rl=Reactor; B2=Separator; Kl=Condensator

1500 The organic solvent extraction was carried out with a Soxhlet apparatus using hexane as solvent. Because of the different permeability and resistance of the cell membrane of the tested algae, the use of either technique was not equally possible for all algae. In fact, U. rigida, C. vermilaria and G. bursa-pastoris resulted to be totally unaffected by SC-CO2 extraction, also in the presence of methanol as co-solvent, unless they were smashed and milled and the resulting sludge extracted with SC-CO2. When methanol was used as co-solvent, 0.5 mL of methanol were placed into the extractor (250 mL) with 3 to 10 g of room-temperature dried algae.

SC/CO2 Extraction: the Operative Conditions We have tried several operative conditions for the extraction of fuels by SC-CO2, always using algae dried at room temperature for 24 hours. The best conditions resulted to be 373 K and 5-8 MPa, with methanol as cosolvent. 3-10 g of algae were charged in the extractor, depending on the species used. The extraction was carried out for 4-8 hours. It has been reported [ 10] that both temperature and pressure may influence the efficiency of the extraction process of lipids and other components from marine macro-algae. Cheung [ 10] reported that for the red alga Hypnea charotidis, 5 MPa were necessary for the optimization of the extraction process. As a matter of fact, it is not possible to use the same operative conditions for every algal species. Moreover, increasing the carbon dioxide pressure does not assure a more efficient extraction. However, the extraction conditions must be adapted to the algal species.

Potential Fuels Extracted from Algae and their Heat Content. Table 1 gives the classes of major compounds we have isolated from the algae so far treated. Besides fatty TABLE 1 CLASSES OF COMPOUNDS ISOLATED FROM MARINE ALGAE TREATED IN THIS WORK

Algae

Fatty acids and their Hydrocarbons methyl esters

Chaetomorpha linum

C-C

Ulva laetevirens

C-C C-C C-C

C8-C~0, saturated C12-C18, unsaturated Pterocladiella Capillacea C10-C12, saturated Gracilaria Bursapastoris Clo-C12, saturated C16-C22, unsaturated

acids, we have extracted some saturated hydrocarbons. Other minority compounds were also isolated and characterized. They are not considered in this work because are less relevant to the production of energy. The compounds listed in Table 1 may be used as biofuel. Depending on the algal species, a different composition of the extract is obtained, that gives a different neat energy yield. Table 2 gives the distribution of fatty acids in some marine algae [ 11 ]. TABLE 2 COMPOSITION OF THE FATTY ACID FRACTION EXTRACTED FROM SOME ALGAE

Fatty acid Number of carbon atoms/Number of unsaturated bonds Saturated C~2 -~ C2o Monounsaturated

Species and relative percentage of organic compounds Ulva Enteromorpha Laurencia Padina lactuca compressa obtusa pavonia 15%

19.6%

23.4%

30.1%

18.7%

12.3%

25.8%

9%

66.3%

68.1%

50.8%

60.9%

C14 ~ C2o

Poly-unsaturated C16/2 --9 C16/4 C18/2 ----) C18/4, C2o/2

1501 The energetic value of the algae obviously depends on the amount and nature of the extracted compounds that may be used as fuels. The content of fuels is very variable with the species considered. As an example, in our case, 5 g of dry C. linum afforded 0.7 g of a mixture of "potential fuels", that represents an overall average content of 14%. A similar trend has been observed for the other algal species investigated in this work, that showed the content of potential fuels reported in parentheses: C. linum and P. capillacea (15%), G. bursapastoris (18%), and U. laetevirens (16%). Although these figures require a further verification by averaging samples collected over a longer period of time, it is worth to compare them with those reported in the literature (Table 3) for other algal species. TABLE 3 LIPIDCONTENTIN SOMEMARINEMACROALGAE

Species

Lipid c o n t e n t g/1 O0g dry weight

Palmaria palmata [11] Fucus serratus [12] Codium harveyi [13] Codium duthiae [13] Codium fragile [13] Hypnea charoides [14]

0.3 2.1 8.8-12.1 12.2-20.7 21.1 18-41.7

It is quite evident that the lipid content of the algae species may vary over a wide range. A content of 10-20 % dry-weight (dw) is quite usual, with a peak value at 40%. This property is very important for deciding about the use of the algae for fuel production. Algae with a lipid content of only a few units % are not economically interesting. Another key parameter to be evaluated for the assessment of the economic value of the algae is the energy that can be obtained from the extracted fuel, that depends on the nature of the compounds extracted. Such value, combined with the content in fuel of the species, allows to calculate the net energy obtainable from the algae, once the energy needed for their growth (Eg), harvesting (Eh) and processing (Ep) is known. (Eqn. 1) Noteworthy, Eg can be substantially reduced if algae take-up nutrients from waste water. Net Energy = A H -

(:)

(Eg+Eh+Ep)

In order to evaluate the heat content of the extracted fuel fraction, Eq. 2 can be used, that considers the nature of the following organic compound usable as fuel: hydrocarbons, carboxylic acids or the relevant methyl esters. Eqn. 2 holds for linear compounds with a number of carbon atoms, in the linear chain, equal to 6 or higher, AH represents the enthalpy of combustion of the fuel, while An is the number of carbon __AH= 3500 + 650 An + (a + b)

kJ mo1-1

(2)

atoms exceeding 6 in linear chain. The basic equation (AH = 3500 + 650 An) is valid for an acid, while constants a and b allow to calculate the enthalpy for the acid methyl ester [by adding the constant value (a=700)] or for an hydrocarbon with the same number of carbon atoms as the acid [by adding the constant (b=650)], respectively. Equation 1 and 2 are quite useful for the immediate evaluation of the heat content of the extracted material from algae and for evaluating the energetic yield of algae, not considering the dry residual material. Is worth to recall that, the residual algal mass after SC-CO2 extraction is practically water free, and can, thus, either find an use as fuel or as additive in composite materials. In addition, its use for amending soil is possible. The use of the residual dry mass gives energy credits to the process. For an approximate evaluation of algae as fuel source, we have taken in consideration an average composition for the extract equal to a fatty acid-C:8. By applying Eqn. 2 an average heat content of 11,300-

1502 13,500 kJ mo1-1 of oil has been calculated, or 37-44 GJ t 1. This value should be compared with the heat content of coal that ranges from 14 to 28 GJ t -1, or oil that is 40-46 GJ t 1. If nutrients are taken up from waste water, using the most appropriate harvesting technique per each alga, one can assume that Eg=Eh= 0.25 MJ kg -~ of oil. Combining the values reported above with the average PF content of the algae, their net heat content has been estimated to range around 6.2-7.5 GJ t -1 of algae (considering only the extracted fuel). Assuming a productivity of 200 t ha ~ (that has been calculated to be the minimum acceptable value for an economic use of macro-algae as source of energy, and has been already verified as a real target for a number of sea-weeds cultivated in ponds) one gets an energy production of 1.24-1.50 GJ ha 1 of water surface, with a depth of 0.65 m. These figures suggest that macro-algae have a quite good potential as source of energy. Interestingly, the current production cost of several macro-algae (100 US$ tldw [ 15]) represents the target value that should be reached for micro-algae, [ 16] that right now have a much higher production cost (500-5 000 US$ t-ldw [ 17]). ACKNOWLEDGEMENTS

This work was done with the financial support of CNR-Rome, Agenzia 2000, Project CNRC008EBF. REFERENCES

1. (a) Lavery, P.S., and McComb, A.J. (1991) Bot. Mar., 34, 251-260. (b) McComb, A.J., and Humpries, R. (1992) Estuaries, 15, 4, 529-537. (c) Riisgaard, H.U., Christensen, P.B., Olesen, N.J., Petersen, J.K., Moiler, M.N., and Andersen, P. (1995) Ophelia, 41,329-344. 2. (a) Lee, V., and Olsen, S. (1985) Estuaries, 8, 191-202. (b) Menendez, M., Martinez, M., and Comin, A.F. (2001) 3". Exp. Mar. Biol. Ecol., 256, 123-136. 3. (a) McGlathery, K.J., Krause-Jensen, D., Rysgaard, S., Christensen, P.B. (1997) Aquat. Bot., 59, 99-115. (b) McGlathery, K.J., and Pedersen, M.F. (1999) 3". Phycol., 35, 721-731. 4. Sfriso, A., and Marcomini, A. (1996) in EUMAC Synthesis Report and Proceedings of the Second EUMAC Workshop, Srte, 29 February-3 March Rijstenbil J. W., Kamermans P., Nienhuis P.H. Eds. Springer-Verlag, Berlin Heidelberg, 1996, 222-248. 5. Cecere, E., Saracino, O., Fanelli, G., and Petrocelli, A. (1992) J. Appl. Phycol., 4, 323-327. 6. Malta, E.J., and Verschure, J.M. (1999) 3". Sea Res., 38, 71-84. 7. Marinho-Soriano, E., Laugier, T., De Casablanca, M.L. (1998) Bot. Mar., 41,559-564. 8. Felicini, G.P., and Perrone, C., (1994) in Biology of Economic Algae, Akatsuka I. Ed., SPB Academic Publishing bv, The Hague, The Netherlands, 283-344. 9. De Cabioc'h, J., Floc'h, J.Y., Boudouresque, C.F., and Meinesz, A., (1992) Guide des algues des mers d'Europe, Editions Delachaux et Niestlr, 232. 10. Cheung, P.C.K. (1999) Food Chemistry, 65, 399-403. 11. Wahbeh, M.I. (1997),Aquaculture, 159, 101-109. 12. Morgan, K.C., Wright, J.L.C., Simpson, F.J., (1980), Econ. Bot., 34, 27-50. 13. Mi-Kyung Kim, Dubacq, J. P., Thomas, J.C., Giraud, G., (1996), Phytochemistry, 43, 49-55. 14. Quing Xu, X., Tran, V.H., Kraft, G., Beardall, J., (1998), Phytochemistry, 48, 1335-1339. 15. FAO (1990), Training manual on Gracilaria culture and seaweed processing in China, 6, 2-46. 16. Benemann J.R. and Oswald W.J. (1996), Systems and economic analysis of microalgae ponds for conversion of C02 to biomass, Final Report, Pittsburg Energy Technology Centre. 17. Weissman J. C. and Goebel R.P. (1997), Solar Energy Research Institute, Final Report, SERI/STR 2312840.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1503

DESIGN PARAMETERS OF SOLAR CONCENTRATING SYSTEMS FOR CO2-MITIGATING ALGAL PHOTOBIOREACTORS Eiichi Ono and Joel L. Cuello Department of Agricultural and Biosystems Engineering, The University of Arizona, Tucson, AZ, USA

ABSTRACT

The strategy of exploiting photosynthesizing microalgal cultures to remove carbon dioxide (CO2) from flue gases through fixation has potential in effectively diminishing the release of CO2 to the atmosphere, helping alleviate the trend toward global warming. The use of fiberoptic-based solar concentrating systems for microalgal photobiorectors has the potential to meet the two essential criteria in the design of a lighting system for algal photobioreactors: (1) electrical energy efficiency; and (2) lighting distribution efficiency. The overall efficiencies of solar concentrating systems have significantly improved in recent years, exceeding 45%. Meanwhile, achieving uniform lighting distribution within photobioreactors constitutes probably the greatest challenge in using fiberopticbased solar concentrators as a lighting system for photobioreactors. The light-emitting fibers appeared to be a most promising candidate in achieving such uniform light distribution in photobioreactors. Also, when a hybrid-solar-and-electric-lighting scheme is adopted to augment solar lighting whenever needed, the hybrid lighting distribution needs to be designed accordingly. INTRODUCTION

In addition to the several commercial applications of microalgal cultures, including health foods, aquaculture feeds, animal feeds and specialty chemicals [1, 2], their photoautotrophic or photomixotrophic capacity has also recently been exploited to remove carbon dioxide (CO2) from flue gases through fixation [3, 4]. The strategy has potential in effectively diminishing the release of CO2 to the atmosphere, helping alleviate the trend toward global warming. The large-scale intensive cultivation of microalgal cultures that this strategy demands, however, calls for the design of appropriate photobioreactors. Current methods for mass cultivation of microalgae include growing them in translucent fiberglass cylinders, polyethylene bags, carboys and tanks under electric or solar illumination in greenhouses [1]. The algal production in these systems was far lower than the theoretical algal productivity of 60 g/m2-d, however, owing primarily to light limitation [1]. For instance, at an algal density of 0.45 g/L, light penetrated the suspension only at a depth of 5 cm, leaving over 60% of the cultures in complete darkness [5]. The use of fiberoptic-based solar concentrating

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systems for microalgal photobiorectors has the potential to meet the two essential criteria in the design of a lighting system for algal photobioreactors: (1) electrical energy efficiency; and (2) lighting distribution efficiency. This paper presents the recent efforts in the United States in designing fiberoptic-based solar concentrating systems that are compatible with algal photobioreactors, focusing on the two parameters of (1) solar concentration and (2) lighting distribution. SOLAR CONCENTRATION

National Aeronautics and Space Administration (NASA) A series of NASA-funded studies on the use of solar concentrating systems to harness solar irradiance for use in a plant growth chamber located in a subterranean facility were conducted at The University of Arizona. Two fiberoptic-based solar concentrating systems were used. First was the fresnel-lensbased Mini 7-Lens Himawari Solar Concentrating and Transmitting System (La Foret Engineering Co., Ltd., Tokyo, Japan). The fresnel-lens-based Mini 7-Lens Himawari (Figure 1), which was developed in the early 1980's by Kei Mori of Keio University in Tokyo, Japan [6], collected light through a protective acrylic resin capsule. Inside the capsule, hexagon-shaped, honey-combed patterned fresnel lenses captured incoming parallel light rays that were then focused onto the highly polished input ends of fiberoptic cables. The Mini 7-Lens Himawari had a capsule diameter of 0.94 m, stood 1.3 m, had a base frame of 0.9 m x 0.9 m and had an aggregate lens surface area of 0.22 m 2. Each of its seven 10-m fused-silica fiberoptic cables contained 20 optical fibers, each with a diameter of 0.51 mm.

Figure 1: The Mini 7-Lens Himawari Solar Concentrating and Transmitting System. The second fiberoptic-based solar concentrating system that was used was the mirror-based Optical Waveguide (OW) Solar Lighting System [7], consisting of two solar tracking units, each equipped with two 50-cm parabolic primary mirror concentrators (Figure 2). At the focal point of each primary concentrator was a fused quartz secondary concentrator, which further concentrated the high-intensity solar flux from the primary concentrator and injected it into a fiberoptic cable. Each fiberoptic cable was 10 m long, consisting of 37 optical fibers, each with a diameter of 1 mm.

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Figure 2: The Optical Waveguide (OW) Solar Lighting System. The overall efficiencies of solar concentrating systems have significantly improved in recent years. Such improvement is attributable mainly to the enhancement in the light transmission efficiencies of commercially available optical cables. Table 1 shows how the overall efficiency of the OW Solar Lighting System compared with that of the fresnel-lens-based Mini 7-Lens Himawari Solar Concentrating and Transmitting System. In Table 1 the Himawari, whose fused-silica cables had a transmission efficiency of 32.4%/10 m, had an overall system efficiency of 23.2%. The OW SICTDS that was used in this study was equipped with fused-silica cables having a transmission efficiency of 64.1%/10 m, resulting in a higher overall system efficiency of 40.5%. And when proprietary liquidbased cables with a transmission efficiency of 72%/10 m was used for OW SICTDS, its overall system efficiency improved further to 46.1%. The projected average instantaneous photosynthetic photon flux (PPF) within the plant growth chamber in the subterranean plant growth facility per hour and per day throughout the year were calculated using the databases for hourly solar irradiance incident upon Tucson, AZ compiled over a 12-year period from 1987 through 1998. The results [8] showed that replacing the available solar irradiance within the growth chamber as delivered by the Himawari in June would require either 97.7 W m 2 of HPS lighting or 185.9 W m -2 of CWF lighting supplied continuously for 450 hrs. In energy terms, these would be equivalent to 44.0 kW-hr m 2 for the HPS lamp and 83.7 kW-hr m 2 for the CWF lamp. For a whole year, the equivalent energy expenditures would be 0.4 MW-hr m 2 for the HPS lamp and 0.7 MW-hr m ~ for the CWF lamp. Replacing the available solar irradiance within the growth chamber as delivered by the OW Solar Lighting System in June would require either 229.9 W m 2 of HPS lighting or 437.4 W m 2 of CWF lighting supplied continuously for 450 hrs [8]. In energy terms, these would be equivalent to 103.5 kW-hr m 2 for the HPS lamp and 196.8 kW-hr m 2 for the CWF lamp. For a whole year, the equivalent energy expenditures would be 0.9 MW-hr m 2 for the HPS lamp and 1.7 MW-hr m 2 for the CWF lamp [8]. TABLE 1 SOLAR COLLECTOR'S EFFICIENCIES System Fresnel based solar collector (Himawari) Mirror based, double mirror (PSI-Silica Cables) Mirror based, single mirror (PSI-Liquid-Based Cables)

Efficiencies 23.2 % 40.5 % 46.1%

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Department of Energy The Department of Energy's Oak Ridge National Laboratory has also designed solar concentrators with the solar lighting of commercial buildings as the original motivation, but now is also being adapted for use in microalgal photobioreactors. The design, shown in Figure 3, used segmented secondary ultraviolet (UV) cold mirror to reflect and focus the visible portion of sunlight onto several 12-mm large-core optical fibers that transport visible light into buildings while transmitting the UV and infrared (IR) wavelengths to IR-thermal photovoltaics [9]. The design was selected to accommodate the use of two different commercially-available primary mirrors: (1) a polished 1.2 m diameter glass mirror with an enhanced aluminum 92% reflective coating; and (2) a steel 1.5 m diameter mirror with an 85% adhesive-backed first-surface aluminum reflective coating [9]. The secondary mirror consists of eight segmented mirror surfaces each focusing light onto separate optical fibers [9]. ,',,,

\~" S.oondaxyMirror ~:~.~<'~..~"~

PrimaryMirror

Figure 3: DOE solar concentrator design. LIGHTING DISTRIBUTION Achieving uniform lighting distribution within photobioreactors constitutes probably the greatest challenge in using fiberoptic-based solar concentrators as a lighting system for photobioreactors. Light distribution patterns from various optical devices, including silica and polymer optical cables, light pipes, woven optical pads, and light-emitting fibers, were investigated by Cuello et al. [ 10]. The lightemitting fibers appeared to be a most promising candidate. These light-emitting fibers were used by Cuello et al. [ 11] in delivering irradiance into a growth chamber from remotely-located xenon-metal halide illuminators. Also, a version of these light-emitting fibers, configured for use in a flat-plate algal photobioreactor as designed by Oak Ridge National Laboratory, is currently being tested at Ohio University (Figure 4) [9]. There is need for light-emitting optical cables that can emit light more uniformly at longer lengths and with numerous turns and bends.

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Figure 4: Light-emitting cables for use in a flat-plate photobioreactor. Since solar irradiance is not always available, it is only logical to consider a hybrid solar and electric lighting strategy for large-scale intensive algal photobioreactors to augment the solar lighting whenever needed. When hybrid lighting is adopted, the hybrid lighting distribution needs to be designed accordingly. An example of a hybrid lighting distribution scheme was developed by Cuello et al. [ 12], wherein the fiberoptic tips from the solar-concentrators formed a rectangular array with strips of lightemitting diodes (LEDs) (Figure 5). Cuello et al. [11] also used light-emitting fibers connected to xenon-metal halide illuminators running alternately with the fiberoptic tips from the solar concentrators.

Figure 5: Rows of solar fiber tips running in parallel and altemately with LED strips.

CONCLUSIONS The overall efficiencies of solar concentrating systems have significantly improved in recent years, exceeding 45%. Meanwhile, achieving uniform lighting distribution within photobioreactors constitutes probably the greatest challenge in using fiberoptic-based solar concentrators as a lighting system for photobioreactors. The light-emitting fibers appeared to be a most promising candidate in achieving such uniform light distribution in photobioreactors. Also, when a hybrid-solar-and-electric-lighting scheme is adopted to augment solar lighting whenever needed, the hybrid lighting distribution needs to be designed accordingly.

1508 REFERENCES

1. 2. 3. 4. 5.

Spektorova, L., Creswell, R.L. and Vaughan, D. (1997) World Aquaculture June 1997, 39-43. Benneman, J.R. (1990) J. Indust. Microbiol. Suppl., 5, 247-256. Miyamoto, K. and Benneman, J.R. (1991) Chem. Eng., 26, 490-494. Hirata, S., Taya, M. and Tone, S. (1996) J. Chem. Eng. of Japan, 29, 953-959. Richmond, A., Vonshak, A. and Arad, S.M. (1980). In: Algae Biomass, pp. 65-73, Shelef, G. and Soeder, C.J. (Eds.). Elsevier, New York. 6. Mori, K. (1985) Biotech. andBioeng. Syrup., 15, 331-344. 7. Nakamura, T., Case, J.A., Jack, D.A. and Cuello, J.L. (1999) Proc. of the 29th International Conference on Environmental Systems. SAE: Engineering Society for Advancing Mobility in Air, Sea and Space. Paper No. 1999-01-205. 8. Cuello, J.L., Jack, D.A., Ono, E. and Nakamura, T. (2000) Proc. of the 30th International Conference on Environmental Systems. SAE: Engineering Society for Advancing Mobility in Air, Sea and Space. 9. Muhs, J. and Earl, D.D. (2001) Proc. of the 36th Intersociety Energy Conversion Engineering Conference. ASME. 10. Cuello, J. L., Sadler, P., Jack, D., Ono, E. and Jordan, K.A. (1998) Int. J. of Life Support and Biosphere Sci., 5, 389-402. 11. Cuello, J. L., Yang, Y., Ono, E., Jordan, K.A. and Nakamura, T. (2000) Proc. of the 30th International Conference on Environmental Systems. 12. Cuello, J. L., Yang., Y., Kuwahara, S., Ono, E., Jordan, K., Nakamura, T. and Watanabe, H. (2001) Proc. of the 31st International Conference on Environmental Systems.

PANEL DISCUSSIONS

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Public Outreach on C02 Sequestration Chair: Paul Freund, lEA GHG Programme [Paul Freund] Welcome to the panel session on public outreach on CO2 sequestration. My name is Paul Freund and I will be chairing the session, which will consist of short presentations from four speakers. So far this week, we have been mostly talking about technology. The important issue for the future is will the public accept these technologies? At the moment, as far as I can see, the public in most countries is not very interested in sequestration, or climate change for that matter. In fact, until recently, even our self-appointed representatives, the environmental pressure groups, have not been interested either because other, more immediate issues have been more important to them. So, does it matter if the public is not interested in sequestration? I think "Yes", it does. The reason that it matters can be explained briefly by an example from another field. In the U.K. and in Europe in recent times there has been a lot of debate about genetically engineered plants. These scientific developments were made 15-20 years ago when it was not usual to seek public views on such developments. I think it is now fair to say that manufacturers and farmers are beginning to pay the price for this arrogance, with the boycotting of their products. Perhaps we can avoid getting into similar problems by involving the public in decisionmaking, which I think public outreach is all about. It will be the key step for gaining acceptance. For this to be successful, we need to start preparing for this now. In 15-20 years time it might be that some of the people in this room may be seeking public license to make very necessary changes in energy technology. Members of the panel include David Hawkins who is with the Natural Resources Defense Council. A lawyer by training, he joined the NRDC in 1971, before being appointed by President Carter to a senior position in the Environmental Protection Agency for four years in the late 1970s. Subsequently, he returned to NRDC and worked on air pollution and energy issues. Dr Makuto Akai is Senior Scientist at the National Institute of Advanced Industrial Science and Technology in Japan. Among other duties he is project manager for the International Collaborative Project on CO2 Ocean Sequestration.

Howard Herzog is Principal Research Engineer at MIT's Laboratory for Energy and the Environment, where he has been since 1989. He trained as a chemical engineer and has industrial experience. He is studying energy and the environment with an emphasis on greenhouse gas technologies. Professor Satumo Fase is Professor of International Law at Yokohama University. He specializes in the law of the sea. He is chairman of the Planning Council of the International Ocean Institute.

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The first speaker will be Howard Herzog.

[Howard Herzog] Hello Paul. It's a pleasure to be here. I'm not going to be presumptuous and say that I want to give the answer, or any answer, during my talk. I will try to frame the issue and give some observations as well as hopefully stimulate our discussion this afternoon. As some of you will know, I have been involved in an experiment on ocean carbon sequestration that Dr Akai will elaborate on later this afternoon. To start, I would like to read something that could very well describe this experiment: "After two years-of winding its way through a regulatory maze, the plan is on hold. The project has run up against strong opposition to the test from many residents where the test is planned. Scientists and regulators generally agree that this particular experiment poses little or no hazard to the public, health or the environment. Most citizens spoke against the experiment. If the experiment was not dangerous, then the project team would have told them about it earlier." This was not written about our present project but was, in fact, written about 16 years ago in Science magazine, about a biotechnology test aimed at trying to move from the laboratory to the field. So, what we are talking about here is not new. Hopefully, as this field emerges, we can be a little wiser and maybe a little more proactive than other fields have been in the past. Let me now talk about carbon sequestration. There are two views that we can take about this: an optimistic or a pessimistic view. Let me go through the optimistic view first. We have been injecting low volumes of CO2 geologically for other purposes for many years. Thus, since the 1970s we have been performing geologic sequestration for EOR, and acid gas injections since 1989. We have 31,000 km of CO2 pipelines in the U.S. and have underground stores of approximately 10"trillion cubic feet of natural gas annually in the U.S. These processes have evolved incrementally over time into major operations. For instance, the first acid gas operation injected roughly 10 tons/day in 1989. Today the largest acid gas projects inject nearly 1400 tons/day. Through research, experience and public outreach, operators and regulators have managed successfully the risks, benefits and public apprehension in relation to these activities. The extension to geologic sequestration involves primarily an increase in scale, both by volume and time-horizon. These views are sometimes presented in the Press. The British Geological Survey was featured on the BBC in some articles and here are some of the comments made:

"CO2 emissions will, in the future, have to be injected into the Earth's surface if the environment is to be saved, the scientist said..." "CO2 sequestration is one of the powerful tools we have for reducing CO2 emissions." "CO2 sequestration is viewed as an interim measure for the next 50-60 years to effect the major cuts we need to achieve."

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Pessimistic views also occur, with these technologies having the potential to become a lightning rod, and we need to be vigilant. The opposition can be local, external or a combination of both. The opposition can offer simple explanations to these complex issues. Groups with different agendas and priorities can mobilize to oppose projects. These groups do not have to win every battle but just cause delay and force projects to consume resources. Two examples of this are (1) at COP6 in The Hague, there was opposition to forest sinks. A statement from Greenpeace accused countries of cheating on their Kyoto commitments by claiming credit for carbon stored in trees; and (2) the WWF stated that: "the only way to combat climate change is through deep cuts in emissions of global warming gases ..... We could see native forest destruction accelerate but still see no benefit for the global climate." The recent discovery of methane hydrates off the coast of British Columbia in Canada caused this comment by Greenpeace: "Govemment and industry should do more to develop renewable energy resources instead of offshore oil and gas exploration..." Local concerns may also slow projects, such as the insistence by the Union of Indian Chiefs in British Columbia that they be consulted before any development can go ahead. So, there are two different views. What is the answer? It is probably a little of everything. One thing I do want to say about public outreach is that you have to define what you are talking about. It needs to occur at all levels. There are several levels, such as a local level or the project level where NIMBY (not in my back yard) forces become a concern. There are also regulatory levels, for example, at the state level in the U.S., or sometimes at an international or regional level, that deal with health, safety and environmental concerns. It is at national levels that policy may be made, such as that involving fossil fuels, where the rules are made as to where and how one gets credit for CO2 reductions. At the international level there are treaties and international laws that affect what you can do. An example is the London Convention that states what you can do in the oceans. All these levels are important and the other speakers will talk about them. I will speak only about the NIMBY level. The situation of sequestration is not unique. Lots of other industries such as power, oil and gas, face similar problems every time that they want to carry out a project. Also, not all sequestration is the same--geologic, forestry or oceanic, but they face similar opposition forces. I'm sure that transport and geologic storage will inevitably prompt local and international opposition, so one has to be prepared. NIMBY can turn into IMBY, as the presence of oil wells in people's backyards illustrates. There is always going to be opposition that you cannot reach. The goal is not to convert everyone. The goal is to have a good plan where education, communication and responsiveness are they key. Communication needs to start early to build trust. Education and openness are essential throughout the project. Resources and skilled people are also needed. There has to be a two-way street. One final thought to leave you with is that not every project is a target, but every project has the potential to be a target.

1514 [Professor Tsutom Fuse, Department of International Relations, Yokohama City University, Japan] The theme given to me by the organizers is to provide a brief overview of the legal issues of CO2 sequestration in the ocean environment and to give some idea of how to open the way towards solving the delicate issue of public outreach. In 1982, the UN Convention on the Law of the Sea (UNCLOS) was signed. As one of the members present, I was very proud of the convention, but am worried about its implementation. The convention was initiated by a famous speech given by Arvid Pardo on 1st November, 1967. It was a very long speech, lasting several hours, and at its conclusion he proposed that the ocean should not be an object for appropriation by sovereign states, but should be owned by humankind as a whole. This idea was very new, fresh and creative at the time, but frankly speaking, as a young and ambitious lawyer, I could not accept his ideas logically and realistically. I have since come to understand the implications of his ideas and also to have confidence that this is the only way that human society can survive in coming centuries. The purpose of UNCLOS is therefore, firstly, to solve the so-called program through the proper development of ocean-orientated resources. Secondly, it is to protect the ocean environment totally and sadly to secure peace in the ocean space under the principle of the common heritage of mankind. The creation of this unique principle of UNCLOS was naturally followed by the following outcomes: (1) humankind as a whole was given legal status, to some extent, of course, as the subject of international law; (2) the fights of sovereign states over the ocean transformed the duty of those states to humankind or human society. The harmonization between environmental development in the ocean space has become an urgent policy task. From this legal transformation, the whole axis of human society came to hold responsibility to set up a workable system--so-called ocean governance. This should require a total management system in the ocean space by the consensus of human society. It embodies, for example: (1) the involvement of all actors in the management system for the benefit of all; (2) the duty of sovereign states to protect and conserve the ocean environment; (3) the obligation of sovereign states to use the ocean l~eacefully, consequently, the definition of marine pollution in the convention. The situation may be drastically changed by man's introduction, directly or indirectly, of a substance into the marine environment that is likely to result in deleterious effects to human health and marine ecosystem. Therefore it could be a very delicate problem as to whether CO2 sequestration causes an element of pollution or not, according to the article of UNCLOS. To realize the ocean governance at the level of our daily lives, the states, including Japan, are now attempting to develop a totally new management system for the oceans. That is to say, ICGM (integrated coastal management). In this system, the coast means not only the water space, but includes the inland coastal area, roughly 100 km both inwards and outwards from the coast. Integration means the full participation of all actors and stakeholders, including citizens. In my hometown, Yokohama, the overall examination of how to implement the new system, is about to start. To undertake this work, Yokohama University is to start a postgraduate course for citizens, ensuring that civil leaders will be involved in such management.

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[David Hawkins, Director Climate Center, Natural Resources Defense Council, USA.] Thank you very much. I appreciate the chance to talk to you as someone who was, until 5 years ago, an uninformed member of the public about this subject. My first comment is that a lot of issues here with respect to acceptance of this approach involve risk. Risk in society is not a quantitative issue. As a U.S. philosopher once said, "Risk is like a kiss. The numbers don't matter, context is everything". If you want to find if the risk is worth it, you have to understand the context. This means that people's understanding of the role of this technique needs to be one that Professor Akai said, "is not banged into them by a P.R. effort, but is a function of communication based on trust". Those of you who did not hear my talk earlier this week won't know that personally, I feel that this technology is something that would be very valuable to have in the toolbox, or arsenal, that we need to combat climate change. I also think it's important not to crowd out ecosystem preferable options, such as efficiency and renewables, but we need it in our toolbox. I really think it is important that we think about how to get interested members of the public to understand what the pluses and minuses are. Firstly, the newspaper is not the best place for people to get to know about this, especially in a newspaper article such as that in a Hawaiian paper, announcing that a project was coming to their backyard, and that is how people got to know about it. Secondly, it is important to think ahead of time about the 'all risk, no benefit' framework that individual projects may carry when they are brought to the attention of a community, because it does not matter how well you do it in advance, the typical reaction will be: "Well, what's the benefit for doing this thing here, and what are the risks?" If you don't have a basis for people's understanding the context, then you don't have a basis for explaining the benefit. I will return to this point later. The third issue is especially with the energy advocacy and environmental community. It is important to address the concern that this option is really a scam to preserve the undeserved total domination of the planet by the fossil fuel industry. I say it in these strong terms because that is the way people will perceive it if this is not carefully addressed, and that goes back to the notion of not advocating this as a superior alternative to efficiency and renewables, but as part of a portfolio that can help us get the job done more effectively and overcome some initial impasses. The fourth point I would like to make is the need to change the concept of a 'project'. Basically, I think we have to think about front-loading the publicity effort. We need to change from the paradigm of: "Let's define a project, let's pick a location for it, and then let's think about talking to the public." You start off behind the curve with that approach because you go into a community and the first thing you have to tell them is why this concept at all. It's the first time they've heard about it. Then you have to explain, why here? Is it safe? Is it worthwhile? What people at this conference need to do is persuade funding sources that it is important to fund the public outreach efforts now, before projects are selected. It is important to discuss the options for dealing with global warming and how this particular option has a role to play. This gets into the discourse and it gets into the understanding of the elite, if you will--opinion leaders, editorial writers, small and large environmental groups and energy policy advocates. Outreach needs to be a two-way street. It is as much about getting information as giving it. This is another reason why it is important to start soon. You may have a picture in your mind about what the issues are that you are going to have to overcome in dealing with public concerns about this project, but the real people who know what these issues are, are the members of the public. Why not find out from them what their thoughts are and their

1516 concerns early on when it is not necessarily connected with a particular project in a particular backyard. I will conclude by saying that the most powerful persuasive argument to consider this argument will come if you have a coherent message that says: "We have a big problem facing the planet in the form of climate change and it is irresponsible to delay taking action." We need to look at the tools available to facilitate the deep carbon cuts that are needed to preserve options to stabilize at lower rather than higher levels and arraying the different options that are available, showing the power of this technology. Two very important things facing us today are firstly overcoming political impasse. We have countries around the world that have large reserves of fossil fuels, and their leaders are not quite persuaded. Nor do I think they will be persuaded quickly enough to "give up" those resources unless they see a calamity is facing them. With this option, if it is responsibly deployed, it can actually avoid this kind of binary choice between thinking about climate as a serious problem and being able to continue some responsible use of fossil duels. This is a powerful message to the political leaders of the world. Secondly, if the technology proves it can deliver deep carbon cuts sooner than the expected path of penetration of some of the favorite technologies. The industry has a very important role to play here. The message would be, I think, much more persuasive if industry would say: "We have a big problem. It is impossible to wait. We need to find a way to facilitate deep carbon cuts. We need to keep open the options of stabilizing at lower rather than higher levels, and that is a challenge." Many in industry are not ready to articulate that message and maybe they don't believe it themselves. So, maybe they are also an audience for outreach. [Makoto Akai, Senior Research Scientist, Japan] I would like to discuss the lessons that we learnt from experiments in Hawaii. As you can see, it took two years to get sponsors to help with public outreach. We tried to obtain support from the public at grassroots level, not by using public relations from the top. In Hawaii, the marine environment is viewed as a top priority to be protected. Public outreach should focus locally first. The target audience involves a lot of stakeholders in the location. Sometimes opponents have their own personal reasons that may have nothing to with the merits of the program. The inside story mentioned on my slide gives an example of this, where Mr X and Mr Y, leading opponents in Hawaii, asked for money and became very violent when refused. Public outreach cannot guarantee 100% approval by the public. It is most important to analyze your opponents. By accumulating scientific knowledge, having better communication with the public and conforming with the regulations, we may gain social acceptance for the technology in the future.

Question time Paul Freund: Now we will open this up for discussion. I would like us to stick to the themes.

[Nick Reiily, British Geological Survey] One of the problems is that a lot of big business and a lot of politicians don't accept that anthropogenic emissions are a threat to the climate, so one of the issues that I am rolling out is that CO2 levels are increasing exponentially, and regardless of whether we have global warming or not, we are getting acidification of the oceans by those rises in emissions. It is justification enough for not emitting them into the atmosphere. We have damaged a lot of carbonate-secreting organisms at all levels of the food chain in the ocean.

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[David Hawkins] I think demonstrating another reason to care is important, but I don't think that breaks the logjam of cognitive dissonance. They can't believe it's real because the implications for their line of business are too great and disruptive, and so they reject the information. This is another interesting feature of this technique. It may offer a way to break this cognitive dissonance because someone in a boardroom may say: "You mean we can actually carry on my business, perhaps in a modified way, but I won't go out of business i f I believe that this is serious?" If you can actually say "yes" to this, you can open another line of communication.

[David Keith, Carnegie Mellon University] This technology is an ugly, end-of-pipe solution, but in every way better than many alternatives. The reason why I and others in this room take it seriously is that we see it as a giving us a real option for making deep reductions and is an option that is more plausible in environmental impact and monetary terms than alternatives. How does the community get that conversation going in a healthy way without seeming to be just bolstering a one-sided case by presenting more and more objections to other options. I am personally involved in large-scale wind use that has widespread environmental implications. [David Hawkins] To me, a much more persuasive argument about the merits of this approach is not the demerits of the efficiency of renewables, but really the efficiency or track record in the success of the environmental community to meaningfully accelerate those alternatives and if I look at the penetration rate of those technologies, and I look at the Johannesburg Declaration, which was supposed to be a big step forwards, and look at the amount of efficiency in the world' s energy mix in renewables in the next 20 years, it is still pitifully small. It's the time to delivery of success that is the most powerful argument to keep this in the toolbox. We won't get alternatives, which I think are still preferable, to be deployed in sufficient quantities in time.

[Paul Freundl There is another aspect to it, David, and I just wonder whether it may be counter to the philosophy that everyone here espouses, but perhaps if we recognized that some projects will not go ahead because the public decides that they shouldn't, and if we were seen to be accepting that control of the sequestration projects lies with others, we might convince people that we are not overselling the option.

[Howard Herzog] We must remember from the fairytale that the "ugly" duckling grew up into a swan.

[David Keith] I would like to respond to Paul's point. Makoto, from your presentation, on the one hand you said that one of the purposes of good public outreach is genuinely to find out what the public want and to honestly engage in dialogue with the public, not oversell the project, and to help determine outcome. Later on you said that public outreach couldn't guarantee 100% acceptance by the public. In your talk, we can see natural straining in two dimensions: on the one hand, to embrace in a healthy way the idea that public outreach should be a dialogue, but on the other hand, realizing that we want to get some projects to happen, and I think that Paul's point is very powerful and we can't be taken very seriously unless we have some projects not happen.

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[Unnamed speaker] In all debate and communication we have words, which have secondary and tertiary meanings, such as after the London Convention, putting CO2 in the ocean or beneath the ocean bottom is unlawful. International Law prohibits the transport of industrial waste between countries. For decades countries have been transporting CO2 on ships in a liquid state from one country to another and from one plant to another, and we all drink it - in beers, soda water, Perier--call it what you will. It is CO2, mostly coming from power stations, refineries, hydrogen plants, and purified, transported and used for nutrition. Is that not industrial waste? When we began our recent project, we decided not to call it 'disposal' or sequestration. Sequestration is storing CO2 for 50-60 years namely in soil preparations or in trees. What we are doing at Sleipner is 'storing' CO2 - a deliberate choice of word. [Eric Larsen, Princeton University] As scientists, we all learn from our mistakes, as a part of good science. Some of these experiments are going to fail and that needs to be discussed in advance as part of public outreach.

[Paul Freund] Are you suggesting that we expose the risks of the experiment going wrong?

[Eric Larsen] Essentially. In some of these experiments, the CO2 is not going to stay retained, for example, and that's what we will learn from these. One failed experiment can be pretty disastrous.

[Unnamed speaker] The flipside of this is that the premature declaration of success, at least from my side of the Atlantic, is that results from Sleipner came across to some in our community as a premature declaration of success.

[Unnamed speaker] I would like to comment on David Keith's 'end-of-pipe' solution as 'ugly'. We need to work at getting across the fight messages about what this technology can achieve. We've only begun to look at it. All we have, quite honestly, is a bunch of technical assessments and studies. We have started the process where if we worked at this intelligently, we can make capture more efficient and reduce emissions to the atmosphere. There are a lot of good points in this technology that we haven't been able to shake out. I think it's important to get the message fight about what this technology can achieve and think of it in terms of cleaner technology, rather than clean-up technology.

[David Hawkins] Let me give an explanation about what that can mean. What a coal plant achieves in the US is 33-34% efficiency, IGCC plants are higher. Build some plants with capture at 40% efficiency with no emissions and these will not be called ugly.

[Unnamed Japanese speaker] I would like to comment on the UNCLOS question. This agreement was both political and legal. The fundamental philosophy of human beings has changed. Among the political issues is that the US has kept out of the convention, but is now a very active country with respect to ocean developments. Every year, many people ask the US to join the university convention. There are political problems. If someone wants to undertake ocean storage, they will be denied. States do not have fights over the oceans. If sovereign states agree on sequestration,

1519 they could go ahead, but what if there are problems? All ecosystems are joined ultimately. Norway and Sweden are to explore sequestration for testing purposes only.

[Paul Freund] We should not undermine this achievement but should the bodies responsible for the law of the sea and the London Convention to be on our list of groups to talk to?

[Unnamed speaker] Oil leaks out of the ground; methane leaks out of the ground; carbon dioxide leaks out of the ground and comes out in huge amounts when volcanoes erupt. Nature is not particularly benign environmentally. It strikes me that this shouldn't be described as 'end-of-pipe' technology, but rather the completion of a circle, in which carbon is being taken out of the ground, used and then put back in again. If some leaks out again, it doesn't seem to be different from what nature does. The key thing is to put it into the ground faster than it leaks out again. It is important not to view this as a technology that has to be perfect and absolutely watertight in respect of a criterion. That is not its objective. It is to get greenhouse gases out of the atmosphere and into the ground, and it is a very good thing that should not be seen as a scam on the part of the global energy industry. It is very important that there is a separate analysis of what one does with greenhouse gases and the globalization issue, which is a quite separate question.

[Elizabeth Hovorka] There is a perceived difference between natural risk and human risk. People would be annoyed if CO2 bubbled out of the ground following a sequestration experiment and would see that as different from a natural release. They also don't see that they are doing worse themselves by putting CO2 into the air themselves.

[Unnamed speaker] When humans started putting CO2 from combustion into the atmosphere, we did not know what we were doing. This shouldn't be used as a yardstick for what we do in the future.

[Susan Walker, Bureau of Economic Geology, Texas] I am involved in teaching the public about topics such as global warming. They do not seem to be able to distinguish global warming issues from the ozone hole. I want to have sophisticated information available on carbon sequestration to be specific and understandable for my classes, which may include environmental activists and Texas oil producers present in the same room. [Makoto Akai] In our Hawaiian example, we arranged meeting for teachers and pupils and found that we achieved effective and important communication. It is important to understand the makeup of the audience.

[Unnamed speaker] As people involved in the energy industry, scientists and technicians involved in research don't have credibility in the public eye - they are seen as inherently biased and compromised. Public outreach might be seen as having the conscious intent of manipulating public opinion.

[Eric Lindeberg, Sintef, Norway] Norway has an interesting laboratory for experiments in carbon dioxide disposal and public outreach. When a major Norwegian oil company launches a highly carbon intensive petroleum project, the rallying of trade unions and political leaders, on the assumption that

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there will be lots of new jobs, can result in serious conflict with environmentalists, who have been neutral or positive to carbon sequestration. That puts a lot of strain on relationships. Industry is not part of the public. When you start talking about 'them' and 'us', it is too late. When you talk about convincing them, it is too late. We must have the public on our side. We must be part of this movement and spread the message at schools, to friends, neighbours, etc. We cannot sit in our towers and try to spread the light. This organization has to have this on its agenda.

[Paul Freund] You're offering us a practical solution. Norway has contributed to the case law in this area generally about public participation. Ibsen's 'Enemy of the People' catalogued what can go wrong, 100 years or more ago. Anyone want to comment on Eric's suggestion?

[Unnamed speaker] Before you can have a conversation about a problem, it helps to have a common definition of the problem and I still think it is a significant interference in going to the point that Mr Hemple raised earlier. The fact that there is a substantial amount of industry funding for this, if viewed objectively, is a positive development. Viewed suspiciously, it looks like a device to avoid being held accountable. In part this is due, I think, to the commonly held perception that the energy industry is continuing to deny the problem; this is definitely true in the US, but maybe not in Norway.

[Unnamed speaker] It is not Norway. It started with Mr John Brown of BP--the European Englishman and the accent that he speaks with provides indicates large differences in attitudes here, and in the publics' perception. It is the same with Royal Dutch Shell--another different attitude to this. I agree with Mr Akai, that we should have openness early. The Salvic Process started that and we will publish all our results from this. We have, in fact, already done this and you are free to order these. Nevertheless, there are people spreading rumors are not substantiated by the publications.

[Peter Haugen, University of Bergen, Norway] It takes time to get treaties in place. How do these evolve as science progresses? Our understanding of the carbon cycle and the oceans has changed over the years since the laws of the oceans were written. We have good intentions when drawing up these, but there need to be systems in place to update them. [Paul Freund] There is a lot of inertia built into these systems and I suspect that it is a good thing. I don't think we want them to be blown hither and yon by any particular thing and the inertia will make them slower to change, and rightly so.

[Professor Fuse] We have UNCLOS and there have been some problems in implementing it, such as deciding how to preserve the Sea of Japan and the East China Sea, for example. Total destruction and pollution is possible. In China, a lot of the population has moved to coastal cities. Pollution is now bad in the sea near the southern part of Japan. We have to go back to the starting point and try to get them to agree to protect the sea.

[Peter Haugen, University of Bergen] I agree that treaties are not too rigid and need to be updated. We need mechanisms for this.

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[Unnamed speaker] I don't think the principal impediment to the ocean disposal of CO2 is the Law of the Sea. You still need public approval. There are concerns among the scientific community about its effectiveness as a technique, the impact on the ecosystem, and about the addition of waste materials into the ocean. All these make ocean disposal the anchor that could drag down geological storage, which I am interested in. I hope its advocates don't lead with ocean disposal.

[Isabelle Czernichowski-Lauriol, BRGM, France] I think we have to communicate with journalists, colleagues and friends. When you talk about sequestration, you have to define the context of climate change, and this interests people, and this is a good way to start. There are several steps: (1) Give facts about climate change and give evidence for it. Base arguments on the IPCC report and use graphs etc. (2) Talk about energy issues--growing populations and energy demands (3) Fossil fuels should be dominant during the next decade (4) Talk about a portfolio of actions such as sequestration and show that two industrial operations already exist. I think people will have a positive impression. [Unamed speaker] We should reach out to the media and educate them, as well as approaching schools and leaders.

[Paul Freund] Isabelle can convey an obvious logical message, but we've heard that the public does not trust scientists. You suggest using the media, but newspapers may not be the best way to communicate by.

[Unnamed speaker] Meyer said about the guy with an oil well in his backyard. He didn't own it, the company did. People accept these things if they can see the benefits. In California, you couldn't build a power plant for 10 years, then the electricity went out and people saw the relationship between turning on a light switch and building a power plant. You say in Norway that you have a lot of acceptance, but Norway is a country that depends a lot on the oil and gas industry and people there think favourably of it because it is a mainstay of the economy. It's a lot easier to convince people when you have that type of economic incentive, then you can convince people in countries that don't have such a large dependence on the fossil fuel industry. So how can you tell people that you can benefit from this? I think it comes back to what people accept. You can tell them that we're doing this because of climate change and this will help. That it has long-term benefits not short-term benefits may be more difficult.

[Unnamed speaker] From my own experience, in a limited way, I would say that we have met the enemy and the enemy is us. To quote Kelly, our scientific community is bad at talking to people about this stuff. I know that everyone here knows a lot about climate change and can talk to anyone about it clearly and easily, but we don't go out to church and talk to people after a church meeting. We don't go to a town hall and do the same. We don't take time out of our busy schedules or away from our families to go to talk to the city hall or the Lions' club. We don't take that outreach step and talk to people, and as a result, we're in the problem that we're in because we are not communicating what we are really concerned about in this regard. The first necessary step in this outreach is to build from the grassroots up and to start at this level. Everyone talks about the density of power plants in the Ohio River valley and the density of the population in the Ohio River valley, but we are not going to get sequestration projects

1522 started there if we don't talk to people in the Ohio river valley, at their churches and city halls about why this is worth doing. I don't think the media is the answer here.

[Jason Anderson, Climate Action Network] Basically, I think there are several different issues in terms of communication here. We have heard some good ideas about how local communities react to a particular project and we have also heard about communication issues on a large scale and about what his means nationally and internationally for the climate scene. Sometimes people don't realize that these are separate issues and they get confused, but they are always going to overlap with each other to some degree. Any individual project is going to have to be responsible for what it implies for the direction that things are taking. Scientists may think that they have a perfectly scientifically valid experiment and that there is no impact and they can explain it well. The question will still enter people's minds: "What will this mean for global warming if it is done on a large scale?" It may not be fair to pin it on that particular person but you still have to realize that you are speaking for a larger issue than any particular case. The same thing goes for the corporations that may be supporting particular projects. Dave mentioned cognitive dissonance. It doesn't wash in the public's mind if you have a corporation whose corporate policy has been hostile to climate change policy then starts talking about sequestration. Why is it that one oil company is having boycotts against its products in Europe and another has has environmentalists who sit down and talk to it? It could be a certain amount of image making, but to give them some credit, it is upfront and public and real. Maybe it's not only the public that needs talking to, but it's the corporate governance and policy makers, because until we see a real clear sign from governments and corporations that they actually believe that climate change is a problem and that we need to do something about it, the message will always be mixed. You will be starting out on the wrong foot. In the early stage you don't want to be mixing your message and be putting something like: 'it's either the oceans or the environment'. You're putting the environmental community and the public into a really difficult position there and you don't want to be posing that fight at the outset. It is best avoided. It is important to keep an eye on the big picture and if the previous speaker's suggestion is taken, we need to convince everyone around us. It should eventually filter through to corporate leadership and governments that we need to take climate change seriously and that these options are presented as a way of dealing with the problem rather than being seen to be divorced from an honest initiative to deal with it instead of being a particular corporate interest or a particular scientific interest. I think that at that point, we can have more of a Dutch model of consensus discussion and move forward together.

[Unnamed speaker] I would like to clarify a point I made earlier. I don't equate natural risk with private risk at all, but I do think that having regard to anthropogenic risk, it is important to set it in context. There are two anthropogenic risks, one is putting carbon into the atmosphere and the risks of doing this are hugely greater than putting the carbon underground (the other risk). This is not to say the risk is negligible, but context setting is the point I was trying to make earlier. We have been asked what can usefully be done. I think that the organizations that fund it should stop denying the problem. If all the big industries would say unanimously that there is a problem and what they are doing about it, the problem would be taken much more on the level. The first thing to do about communication is to go back a step and stop denying the problem. I would like to say a little about the Climate Change Action Network that I have tried to communicate with in the past, particularly at the time of COP6, first and second occasions. Communication is a two-way thing and you have to listen as well as speak. The CAN was quite incapable of understanding there might be a difference between a good sink

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and a bad sink. I found that it was difficult to deal with at the time. I do think that everyone involved in this process has to be more communicative.

[Paul Freund] Any one individual may represent a particular point of view and it may be unfair to brush the whole organization with one remark.

[Unnamed US Speaker] The CAN is a group of 320 engineers representing 10 million people. Dave's organization is a member, WWF is a member as are many tiny groups around the world. That's definitely painting things with a broad brush.

[Unnamed US speaker] The problem that you can get into with carbon storage is analogous to the one that Peter just mentioned about sinks. There are lots of problems about sinks. One of these was that it was a zero sum gain, with reforming of the energy system. So, one of the reasons that the environmental advocacy community started off being skeptical of the biomass sequestration option was that they saw it as draining away attention from the longer term need of changing the energy system, which was essential to achieving the deeper carbon cuts that are necessary in the second, third and fourth commitment periods. We can get into the same position with respect to the carbon storage options if the environmental community perceives it as crowding out attention for efficiency and renewable energies. I am pleading that we do not do that.

[Unnamed Asian speaker] We have many restraints on the flow of knowledge to the public. Property fights and copyright are barriers. Only second-class information is available, as most is classified.

[Makoto Akai] Regarding public outreach - in the real world, in the case of our project in Hawaii, there were many restraints from sponsors and the public. It was hard to compromise between PO and PR.

[Unnamed US speaker] One of the points about putting CO2 in the oceans is that it could be perceived by the public as a short-term solution or a band-aid solution. One thing going for renewables is that the public can easily see them as long-term solutions. So, if we really are interested in selling this new technology, we have to convince ourselves that it is a long-term solution and then communicate this as well.

[Unnamed speaker] Another way to look at this is as a bridging solution to buy us time so that the other technologies come in. Economics--by encouraging sequestration we can encourage renewables and efficiencies to come in faster because sequestration raises the cost of fossil energy, therefore making the alternatives more competitive more quickly.

[Unnamed Asian speaker] How long do you think we took to get public acceptance to build a new nuclear power plant in Japan? 15 years. If we are confident that we should address climate change and if we decide sequestration is necessary, we should start persuading people. It took 2 years in Hawaii. Climate change does not happen overnight and we do have time for public acceptance.

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[Paul Freund] You will all take your own message away from the talks we have heard today. The thing that sums up a lot for me is that responsibility is with us as technologists to change what we do, not just expect other people to change as well.

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The Role of Industry in the Strategy for Mitigating Global Warming Chair: Baldur Eliasson, Department Head, Energy & Global Change CHCRC. G, ABB Corporate Research Ltd., Switzerland. [Baldur Eliasson] I would like to say a few words to set the stage and show some philosophical slides--not technical ones. There can be no application of technology without the involvement of industry in any strategy for mitigating global warming. This problem cannot be talked away or traded away. We will have to apply the technology in the end. The problem is real and we will have to get used to that. Energy will become much more expensive and plus, we do not pay the right price for energy today. These are the facts we will encounter in the next decade. I will show you a few slides before I ask the participants to speak. Each one has 15 minutes but I am so modest that I will take only 5 minutes for my slides. We stand at the beginning of a new century. It marks a shift in energy technology. A new issue has become the dominating factor, like the global environment we face. Now we face a global environmental problem--it is not the smoke coming out of our chimneys and making our washing on the line dirty; it is a global warming problem. We can't smell it or see it. We have the global market that affects everything we do. Today, we have the rapid development of the less developed countries. Today, most of the CO2whalf comes from the industrialized countries and in future, the additions will come mostly from the developing countries. We have instant worldwide communication now. At the beginning of the 21 st century, there is another philosophical question. We know more and more and understand less and less, relatively speaking, because we have instant access to any knowledge through the Internet, but we are lost in all of this knowledge. With time, knowledge expands exponentially, but what we know and understand increases much more slowly. So, our ignorance actually grows exponentially and I call this the "knowledge graph". I sometimes call it the Eliasson graph, but I am much too modest to do this today, the difference between science and politics." What you see here is the global warming falls. The ship is the world and we are all passengers on it. This ship is moving towards the global warming falls. The science measures the distance the ship is from the falls and signals this to the politicians, who tell the captain what to do. The captain is in charge of the steering wheel and it is the political power that tells him he should try to, hope~lly, avoid the waterfall, and Kyoto is the very first turn of the steering wheel. There are some young countries in the world that do not realize that to make this turn, you first have to take a very little turn, and that is what we are trying to do. To solve this problem, we have to involve industry, which plays the game and delivers the technology. We have to involve the government that sets the rules of the game and we have to involve academia and research institutions, which tell us which game we can play. It is very important that we all meet. It is not enough in this case, that just specialists meet and try to solve the problem. They will not succeed. We need all the stakeholders to be involved. The speakers on the panel are:

Hiroshi Morimoto Managing Director, The Kansai Electric Power, CO.INC., Japan, Jae-Ou Choi Principal Research Engineer, Pohang Research Institute of Industrial Science and Technology, Korea, G a r d i n e r Hill Manager, Environmental Technology, BP Group

1526 Technology, USA and Anthony Millington Director General of the Tokyo Office of European Automobile Manufacturing Association

[Hiroshi Morimoto] My presentation here is "The role of the electric power industry and the Kansai Electric Power's activities." After the increase in oil prices, Japan has made efforts to reduce energy use in the industrial sector and in households, and to install nuclear power stations and to use natural gas, in order to reduce oil dependence. Strategies have been aimed at introducing a mix to eventually make a contribution to the Kyoto emission targets. In 1999, there were 1.2 billion tons emitted in Kyoto. That is about 5% of the global Kyoto emissions. Japan's GDP is 1/3 that of the US and ½ that of the European Union; the country's intention is to achieve GHG emissions 6% under the Kyoto protocol. Although Japan's industry has achieved the lowest level of CO2 emissions (in kWh) in the world, the country's GHG emissions in 2000 increased by 8%, compared to those in 1999, mainly in households and transportation. Furthermore, it has been estimated that GHG emissions, if events proceed as usual, will increase by 24% by 2010. Japan has already achieved 6%, the best in the world. However, we need to achieve 30%, and this is a very severe target. A voluntary plan has been set up by the industry sector. The voluntary target of the Nippon Keidanren, the Japanese Federation of Economic Organisations, which consists of the commercial and industrial sector, is to endeavour to reduce carbon dioxide emissions from the industrial and energy-converting sectors in the fiscal year 2010 to below the level of the fiscal year 1990. In 2000, the result of this action plan was that CO2 emissions from Keidanren were almost the same as 1990. The federation of electric power companies also set out a voluntary plan to aim (by 2090) to further reduce CO2 emissions per unit of end-use electricity by approximately 20% from the 1990 level, to about 0.3kg-CO2/kWh. The Kansai Electric Power Company instituted the so-called New ERA strategy in 1995. The name means Efficiency-efficient utilization of energy by society as a whole; Reductionmreduction of greenhouse gas emission in electric power supply: Activities abroad--activities carried out abroad to prevent global warming. As a result of this strategy, CO2 emissions saved about 10 million tons of CO2 in 2000, compared with 1990 levels, which is ½ the emissions from Kansai Electric Power. Nuclear power contributed nearly 90% of the total reduction. Approximately ½ of Kansai's power comes from nuclear stations. The renewable portfolio standard law is supposed to be in force in February next year. It was approved in May this year. RPS law imposes the generation of renewable electricity on the electric power companies. Renewable electricity quotas are allocated to each electric power company in proportion to electricity sales. The electric power companies can generate renewable electricity by themselves or can purchase renewable credits. In order to reach CO2 emission targets, Japan must promote nuclear energy and liberalize electricity markets. The liberalization of 30% retail sales from generated power in Japan has been in force since March 2000. Promoting nuclear energy is one of the main energy policies of Japan and one of the main policies of anti-global warming. On the other hand, nuclear power has to compete with cheap electricity in a competitive market. The Kyoto protocol has three weak points. Firstly, global warming has become a political problem. The target of the protocol comes from diplomatic compromise, and is not based on scientific grounds. Secondly, it was made without the participation of the US and developing countries. The US produces ¼ of the CO2 in the world, and emissions from developing countries will exceed those from developed countries by 2025. Therefore, it is necessary to create a framework to bring the US and these countries into the program. Thirdly, the target is very severe in the short term. Although the Kyoto protocol demands a severe short-term goal,

1527 carbon dioxide has been accumulating gradually in the atmosphere in the 200 years since the industrial revolution, having had its main effect in the past 100 years. We should aim to reduce these levels by disseminating existing efficient technology, as well as developing new technology. It should be possible for us to achieve huge Kyoto emission reductions without added expenditure by installing new facilities. It is estimated that if every country in the world achieved the same decrease in GHG as Japan has, more than 60% reduction could be achieved. Taking action on global warming is not a question of doing it now or in the future. We must take action continuously.

[Baldur Eiiasson] Thank you Mr Morimoto. The next speaker is Dr Choi.

[Dr Choi] Earlier in the conference, people were talking about the merits of different technologies to mitigate global warming. I would like to begin my talk with the word "marriage". In Germany, people say that coal is married to steel, because for the last 30 years (since 1969), the steel industry in Germany has insisted that the steel industry use their own coal for steel production. This nice expression is not only true as an historical fact, it is also true in technical terms m steel production is hardly possible without coal. The coupling of coal and steel faces a big problem. Should they be divorced because of the risk of global warming in the future? On the slide you can see the main route for coal production. There are two main methods---one uses iron ore (integrated method) and the recycling method uses scrap. The efficiency of iron and steel making processes is often described in terms of its energy use. To cut down on energy input has been the key method adopted in reducing production costs and is directly related to competitiveness. Amongst the different steel making processes, chemical reduction and the making of iron ore, converting iron to steel, and casting and rolling processes are the main steps that need huge amounts of energy. Technologies for energy saving in these unit processes have been developed a lot to date. If you compare the energy used in the different practices, you will see some differences. Steel mills use electricity as the main energy supply for the melting of scrap. Carbon emissions from such steel mills are directly related--dependent---on the energy source for the production of electricity. Steel is recyclable at high levels, compared with other industrial materials. It is recycled at a rate of 75-80% in developing countries today. In the graph of the present status of energy input, reductions of both routes can be represented by a reverse s-curve. Energy reductions have been concentrated since the 1970s and the energy crisis. Today, the trend is an asymptote to the minimal level. Energy input is about 22.5 GJ per ton crude steel. Some leading Japanese mills can get 20-21, and Korean mills 22%, with European mills achieving 23%. The main technologies for saving energy include gas and heat recovery. Almost all gas streams are recovered and used, as are most heat streams over 400°C. Coke can be substituted by pulverized coal or other waste materials. Processes may be eliminated or linked with others; continuous casting is a good example. Waste is recycled and is a very efficient way of reducing energy input. In the future, there will be some radical solutions, such as listed in IISI, 1998. These include new iron and steel making processes, non-carbon dioxide energy sources, non-carbon reducing agents and carbon sequestration. Hydrogen has been suggested as a fuel, but this will be of use only if it is available in large amounts. It is possible to reduce CO2 emissions in the

1528 short term by 5-10%; it is happening in many countries, in the mid-term, to around 20-30% of scrap metal use increases. Long-term, there will be many options that we cannot imagine. To reduce emissions by half may be a challenge. The task will be easier if all steel mills cooperate and set up concrete action plans.

[Baldur Eliasson] We have had the electricity industry, the steel industry and now we have the oil industry, represented by Mr Gardiner Hill from BP.

[Gardiner Hill] I have been asked to represent the oil and gas industry. We are talking about the energy industry, not just oil, but gas and other energy sources too. Clearly, energy is a global commodity. Overall, primary energy use is over 10 billion tons and over 80% of the world's energy needs are today met by fossil fuels. As an observation; transportation represents less than 20% of the total and it is almost totally undiversified i.e. it is oil. Industrial, residential and commercial represents --40%, but it is diversified with renewables in the form of wood, peat and dung. These play a significant role in many regions. Electricity generation is also diversified, but coal remains clearly the dominant supply for this. In the future, the growth in primary energy will increase. Despite the hopes of many in the next 20 years or so, oil and gas will continue to dominate, but we believe that technology will reduce the impact. On the graph, you can see that gas is gaining market share dramatically-at twice the rate of oil. Solar and wind are growing quickly from a very low base and globally, are not restrained by supply. What can the oil and gas industry do to mitigate global warming? I have presented the technological carbon options in three categories (buckets): reducing carbon intensity, improving efficiency, and sequestration. I think the one at the center for the oil and gas industry and the one we are working hard on is improving efficiency, both on the demand and supply sides. The key part is looking at the flaring and venting that we do in our industry. Most countries now have aggressive targets to reduce venting and flaring and to improve efficiency. The two other buckets involve renewables and sequestration. Renewables are typically solar, hydrogen, wind and solar and fuel switching, e.g. heavy carbon fuel like oil replaced by gas. We have heard about sequestration this week and we can see that this has a key role to play in moving towards a lower carbon future. Underpinning all that, the options need to be driven by market mechanisms. We need to apportion environmental targets within industry and among different countries. We need to understand clearly the environmental impact of each new technology or any new energy source brings with it. Industry has taken some action already to tackle climate change issues through improvements in EE, flaring and venting and reducing carbon intensity, Additionally, it has shown leadership in technology development. Our targets have been met early, such as in 1998, BP targeted a 10% reduction in internal GHG emissions from a 1990 baseline (90MT) by 2010. In 2001, emissions are 80.5 MT (9.5MT reduction), well ahead of schedule. Now that we have met our target, it is time to move on, taking new, distinctive steps to tackle climate change in the future. Is the problem a technical or a political one? First, we have the issue of security of supply. This has never been made more real than since 9/11 last year and the imminent threat of war in the Middle East. The whole issue of fuelling economic and social growth includes that of the fact that 2 billion people have no power or light or heat. We have to deal with climate

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change, not just the issue of global warming, but the fact that it shows up as shifting weather patterns, floods, droughts and more violent weather affecting millions of people. What are the next steps for climate change? We need to recognize the need for stabilization of GHGs in the atmosphere. Currently, there are no universal agreements on a safe level of stabilization. Many emissions trajectories could lead to stabilization. We need to acknowledge that a combination of actions will be needed. These include improved energy efficiency, lower carbon fuels and the capture and storage of carbon dioxide in the medium term. We must not underestimate the scale of the challenge, transforming from a carbon-based energy system to a low or non-carbon-based future. This is a journey that has just begun. Three things facing us on the journey are social needs and values in the developing and the developed world; introducing new technologies; and political factors such as protecting jobs, industries and countries. Should industry take the lead? Unquestionably the answer is yes. Leadership in industry is required. This has already been demonstrated through a number of programs and a number of companies reaching specific targets and commitments. Careful steps need to be taken on this journey. We can't get to the end in one step--we need to take one small step at a time. A portfolio of technologies and options is needed--there is no silver bullet. Outreach and communication will be the key. Industry cannot do this alone. Public/Private partnerships have an important role to play, so that we can be successful in working this through to a successful conclusion. Let me now show you an example. BP will now use its skills and technology and business process to set our own internal target to hold our net emissions at 10% below 1990, through 2012, by a combination of 10-15% improvements in operational energy efficiency by 2012, and by the use of flexible mechanisms such as GHG emissions trading and carbon credits. Finally, let me share with you a view of these options available to us and give you an optimistic view of the future. We are on a journey to a lower carbon world and we have three axes to work with: the efficiency, decarbonization and renewables axes. We are going from a world of high carbon intensity to a world of low carbon intensity and this slide shows a number of areas being worked on: low energy processes, capture efficiency, venting and flaring, fuel substitution, using hybrids and fuel cell economics and using such renewables such as solar, wind and in some cases geothermal. Let me finish with just one thought: I have talked mainly about the supply side, but that is only half of the equation. Looking ahead, I think the customer has a role to play. Thank you.

[Baldur Eliasson] This was the view from the oil industry. Have we any questions?

[Unnamed speaker] Would you care to comment on your opinion of the oil and gas industry and the nuclear industry?

[Gardiner Hill] This is a personal question. We can learn a lot about nuclear energy when we think about the technologies like carbon capture and storage, where the issue of how you store waste has become a big issue for the nuclear industry. The NIMBY syndrome is relevant. Clearly, nuclear power has been around for many years and it has gained a lot of bad publicity with stakeholders and the public, because of concems about safety. I think in the oil and gas

1530 industry, we can leam from that. It will have a big role to play in the IIEE work. Nuclear will still be aroundmit may grow or shrink, but may stay about the same level as it is today.

[Baldur Eiiasson] The next and last speaker is Mr Millington from the Tokyo Office of the European Automobile Manufacturing Association.

[Anthony Millington] Thank you Mr. Chairman. Today, this conference room is very orderly. You, the delegates are all in your seats. There is no heckling, or at least not so far. Sir, this must be a tribute to your very firm chairmanship that you have demonstrated. But, exactly five years ago the scene in this room was very different. I know, because I was here. This conference center swarmed with unruly crowds of government officials, scientists, journalists and NGO representatives during the closing stages of the COP3 Kyoto Protocol. The then head of the US delegation described it as the most complex negotiation ever held. Over many sleepless nights the outcome hung in the balance, but then confounding all the pessimists, the delegates reached agreement and the developing countries set themselves extremely ambitious targets to reduce greenhouse emissions. Today, as we approach the half way point in this Kyoto process, this is an appropriate place to take stock. I am very pleased, Mr Chairman, to have this opportunity to say a few words about the role of the automobile industry in making the commitments a reality. The automobile industry faces a dual challenge. Mobility is a basic human desire, an essential facilitator of economic development and the improvement of quality of life. Already on this planet there are 740 million 4-wheel vehicles, almost 1 for every 8 people. As global prosperity grows, so does the number of motor vehicles. Motor vehicle km to be traveled between now and 2020 will increase by 86%. Increased mobility of course, also has negative effects including an increase in greenhouse gas emissions, as everyone who has tried to get around Kyoto in a taxi knows. But the share of carbon dioxide emissions by motor vehicular traffic in OECD countries will continue to increase over the next twenty years, whatever the policy measures are that are adopted. The Association of European and American automakers (ACEA) therefore acknowledged at this Summer's Johannesburg Conference on Sustainable Development, that we must meet the demands of our customers while minimizing the social, economic and environmental impact. Addressing the risk of global climate change requires not only a long-term strategy but also immediate action. As a representative of ACEA in Japan I should like to explain briefly what our member companies are doing dramatically to reduce new CO2 emissions to help the EU meet its Kyoto protocol commitments. In 1998, ACEA members entered into a unique voluntary collective agreement with the European political authorities to reduce by 2008 the average new car CO2 emission by some 25%, compared with an average 185g/km in 1995. This will contribute 15% of the CO2 reduction target that was assigned to the EU by the Kyoto Protocol. More specifically, ACEA committed to bring to the market individual car models with CO2 emissions of 120 g/km or less by 2000. ACEA also committed to achieve by 2008 an average CO2 emission figure of 140g/km for new cars sold in the EU and to reach the interim target range of 165-170g/km in 2003. Lastly, ACEA committed to review in 2003 the potential for additional improvements, with a view to moving the new car fleet average further towards 120g/km. What has been achieved so far?

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By 2000, ACEA members had put on the market more than 20 models with emissions of 120g/km or less. In 2001, sales of the models doubled to over 306,000 units, equal to approximately 2.5% of total sales in the European market. Last year, the average new car CO2 emissions in Europe were 164g/km and cars that already meet the 2008 target of 140g accounted for nearly one quarter of all sales. The interim target for 2003 was already achieved in 2001. The European authorities and industry recognize that external factors will influence ACEA's ability to honor its commitment. The commitments are therefore, based on a number of assumptions that include: the full market availability of enabling fuels with sufficient quality to enable the application of the technologies needed for the industry to achieve its commitments; ensuring that European industry is not put at a competitive disadvantage in world markets by its CO2 commitments in the EUmthe industry needs a level playing field so that competition is not disturbed; looking to avoiding fiscal or other policies that might hamper the diffusion of CO2 efficient technologies into the EU market; ensuring that the regulatory authorities do not adopt measures that will have the impact of making it more difficult for us to achieve our CO2 objectives. How has this process so far been achieved? ACEA members in the last four years have introduced a wide range of product and technical innovations to reduce CO2 emissions. Some of these include the introduction of direct injection diesel engines and a whole new range of technically advanced diesels (notably those incorporating highly efficient unit injector and common rail technology). Last year alone saw the introduction of a 2-step variable valve lift, the fully variable intake manifold, and a second generation of common rail injection, robotized gearboxes, 6-gear manual boxes, electric power steering etc. have become more widely available. To support the efficiency gains brought about by technological developments, manufacturers in Europe have also slowed the growth in physical car characteristics, like weight and engine size. In fact, since 1999 in the EU, there has been virtually no increase in vehicle mass. Similarly, the engine capacity of petrol and diesel cars has remained almost static. Thanks to these efforts, simulations made in Europe as part of the auto oil program show that in Europe at least, road transport CO2 emissions will stabilize around 2004-2005, notwithstanding the expected increase in traffic growth. Despite all this progress, ACEA members have been lowering CO2 emissions by --1.9%/year, but in order to meet the target of 140g in 2008, the process has to be speeded up and the annual reduction will have to increase to 2.1%/year. So far at least, ACEA's CO2 reduction performance has exceeded expectations, but ACEA is fully aware that in the period up to 2008, future developments may not be so readily accepted in the marketplace if we are to continue to improve fuel efficiency. Also it is important to remember that car manufacturers operate in an extremely complex regulatory environment and they have to manage finite resources to meet a whole range of societal and customer demands, which go well beyond the need to reduce CO2. It is an unfortunate fact that often fuel efficiency gains are offset by mutually exclusive demands put on the automobile industry by the regulators, e.g. to improve vehicle safety, other emissions, performance, noise and recycling, and then the customer does not choose to follow where the manufacturer attempts to lead. This is well illustrated by what has happened in the past. Estimates made by ACEA suggest that the 1995-2001 new automobile regulations have adversely affected CO2 emission performance by some 3% by adding --25g to the mass of a typical car. So in terms of the task ahead, it will be essential for the policy makers to ensure that new policy initiatives do not impose mutually exclusive demands on the industry. The message I would like to leave with you is that the global automobile industry will continue to gear its research and development program to bring about the technological breakthroughs that will be necessary in the longer term to improve radically fuel efficiency, but unfortunately many of these promising

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technologies, like fuel cell technology will only begin to come on stream well beyond the deadline for achieving the Kyoto targets. A week ago, for the first time ever, the chief executives of the automobile industry met in Paris. In a statement made at the end of their meeting, they said that to expedite the market penetration of the vehicles that incorporate the new technologies that will be required, it would be essential for industry to gather support for technical innovation and for the appropriate infrastructure to be provided. To improve the availability of available fuels, particularly sulphur-free fuels, and to convince customers to adopt these technologically sophisticated vehicles in large numbers. Mr Chairman, I hope that today's panel discussion, like the conference this week, will contribute to this process.

[Baldur Eliasson] I would like to open the discussion. You have heard the views from the electric industry, the steel industry, the oil and the automobile industries. So what role should industry play in mitigating global warming? Do you believe what you have heard? Do you think industry will met its goals?

[Professor Kayia, RITE, Japan] I have a general question about the role of industries. Almost all industries are doing quite well in minimizing energy consumption in their own products and processes and also in the minimization of energy consumption in their own products, e.g. automobiles. However, the problem is the customer's behaviour, as Mr Hill pointed out. If we look at Japan for example, the energy consumption in transportation and in the residential sector is increasing, while the energy consumption in industry is almost static. The problem is how to solve this gap. Can industry play a role in reducing such kinds of customer behavior, can it depress energy demand on the customer's side? This is a difficult question to answer; if we look at for example, electric companies, if they want to reduce energy demand by customers, they have to reduce it themselves. In order to prevent global warming we have to find some solutions for this. [Baldur Eliasson] Thank you, Professor. I know in Germany, some years ago, a utility tried to donate washing machines and dryers to their customers that were very advanced and reduced the power need in that way.

[Mr Millington] I think there is a very interesting difference in the approach between that adopted in Europe and Japan. Perhaps it didn't come through as well as I would have liked in my talk, but in Europe, the auto industry has committed itself to an outcome. It has not committed itself to make available fuel efficient vehicles and then encouraged the public to buy them, not being concemed about what the overall output is. The ACEA commitment is to ensure that the average new car sales that are put on the market in 2008 taken together, all cars being sold, will be 140g. By comparison, here in Japan, a supply side approach has been adopted. The authorities have set for 9 different weight segments in the market, a maximum allowable level of fuel consumption. But essentially, because it is a supply measure, the outcome cannot be predicted in advance. It will all depend upon how the customer reacts to the offerings that have been made. Of course, the Japanese authorities are making sure that the customer is going where the industry is leading, but the industry is not under any obligation to meet any specific objective. This is what is unique about the European approach. It has given a lot of flexibility to the industry, but the industry itself has to commit to reduce the fuel consumption of its vehicles to achieve the target and the only way that can do that is by ensuring that the

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products it brings to the marketplace are attractive to the consumer and that its product mix will be appropriate to achieve that target. The target will be achieved by competition between the manufacturers. That approach shows a considerable level of leadership on the part of industry. [Max Hilhorst, EMAC, The Netherlands] The AMAC is an agricultural institute for agriculture and environmental engineering. The question is the role of industry. I simply do not believe that industry should have a role. The only role is to follow the market. We will determine what they can sell.

[Baldur Eliasson] Who are "we"?

[Max Hilhorst] The customers, we the public. We fire up the government, set the rules, stimulate them. The talks here were more like an excuse to the customers than they really were deciding to do something.

[Baldur Eliasson] I don't think that's enough. Do you think the public asked us to come to Kyoto just to discuss that the public is not important? Of course, in the end, the public will drive the whole thing, but now the public is uninformed and can't drive the discussion.

[Gardiner Hill] This is an important point. Much of what we have talked about really has been the supply side, but there are two sides to his equation and the other side is important. When you talk about sustainability then you have to consider quite seriously that if you are sustainable, then you have got to address the demand side. There has to be the pull from the customer to want the products, which hopefully will be low carbon products. Part of the war around this clearly has something to do with behavior knowledge and a good example is the US where there is a very strong car culture; notwithstanding the issues of climate change, people are still driving and buying more SUVs than smaller, more economical cars. So, there are cultural issues here and certainly knowledge is here. What will it take to get the customer to change his behavior and actually demand different types of products? A good example of where government could work with industry is something that happened in Germany where the government has a tax break for citizens who buy solar products; here, there is a real customer pull for people to buy solar products, more so than anywhere else in Europe or the world at the moment. So, we are seeing a big demand in solar products because of that incentive that the government provides as a tax break. There are perhaps some partnership issues here where you can create or change the customer's behavior and then once he gets used to these new products and these become familiar and commonplace, then these types of subsidies and support mechanisms can probably be reduced in the future.

[Wim Turkenberg, University of Utrecht, The Netherlands] Most members of the panel were talking about energy efficiency improvements as an option, indicating that they are doing their best, that they have done a lot and that their potential for improvement is limited. I doubt that that is true. I was involved in the world energy assessment that has been prepared by the UN and also by the World Energy Council, and in one of the chapters, it is indicated that the potential for energy efficiency improvement is, in general, a factor of 4. So for example, in an industry, it could be a factor of 2; a 50% reduction in energy consumption with the same output. It could be a factor of 4 in the transport industry and a factor of 10 in another. So there is still a lot of potential for

1534 improvement. How will it be developed? A lot of research and development has to be done. We have to look for breakthrough technologies. Money is coming from industry for R&D. In the last 10-15 years, in most companies, e.g. the energy industry, a budget for R&D and administration has decreased. Also, at the government level, we've seen decreased investment in energy R&D by a factor of 2 in the last 20 years. We have got to develop a lot of breakthrough technology that requires budget investment at government and industry levels of R&D investment. Are you really doing your best?

[Baldur Eliasson] Thank you, Wim. I hope you read the newspapers and know that there is an economic slowdown. That's one reason why we spend less on research. I can see something for improving energy efficiency. I see all the taxis waiting in front of the Price Hotel have their motors running, like in America, while they wait for customers, and this is Japan.

[Gardiner Hill] There are lots of opportunities for improving energy efficiency. Most companies in the oil and gas industries continue to take large challenges to improve energy efficiency further than they have already. Certainly, we have now in BP, and we are spending more on energy efficiency because we see that as an essential way to decrease our emissions. There are some radical technologies that will be required both in the way we operate our upstream facilities as well as our downstream facilities. Certainly it is something that is central to our technology program.

[Mr Choi] Producing energy efficiency in the steel industry is very specialized. Energy input is directly related to CO2 emissions. General ways are used to improve efficiency, such as heat recovery, can be made, but we can't improve energy efficiency. We can reduce CO2 emissions. We can recycle more scrap and use nuclear energy to make electricity.

[Baldur Eiiasson] There is a simple solution to CO2 and that is called nuclear energy. No CO2 emissions.

[Wim Turkenberg] My question was more about cutting of R&D budgets. I want to understand why.

[Baidur Eliasson] You can be sure that the world is spending much more on CO2 research than it was 2-3 years ago. [Wim Turkenberg] It is not true, what you are saying.

[Baldur Eliasson] It is true and I know better than you. This problem is not going to be solved by R&D alone, but has to be solved by society as a whole, by the public, by the government, by industry and by the professors in the universities, but they will have to come out of their labs and onto the streets and talk to us.

[Unnamed African speaker] The Protocol does not give commitments to developing countries. You also see that in the future, emissions from developing countries will outgrow those of developed countries. I come from a developing country and the problem these days is bread and butter; the people think you are just joking when you talk about global warming. We need to remember about

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socio-economic issues and how we can address these. Until we can solve the problem of economic imbalance, we are trying to marginalize a big chunk of the population who can also cause increases in the amount of greenhouse gases.

[Baldur Eliasson] You know that there is an environmental bank, GEF (global environmental facility) that holds 3-4 billion dollars. The rich countries pay into it but the developing countries have to present their projects, then they will get money or support. [Doug McDonald, University of Waterloo, Canada] Perhaps the reason that R&D funds go down is related to publicly listed companies. We watch the stock market on a 3-monthly horizon and the goals we have here are much longer than most of us are able to contemplate, particularly when it comes to our retirement investments. How do the executives on the panel deal with their shareholders against longer-term goals and expensive solutions we have to face with some of the problems we have here?

[Gardiner Hill] A number of the energy industries are now engaging the shareholders in the challenge we have as energy companies and taking responsibility for getting proactive action in the environment. More and more shareholders and people who invest in energy companies are concerned about the environment and we are getting an increasing number of green shareholders who will preferentially invest in some companies because of the actions that they are taking. This is part of the communication and knowledge base and more companies, including BP, are engaging in dialogue to shareholders understand the size of the challenge and what we are dong to address that. Clearly, we can't be seen to be doing things that reduce the retirement to shareholders. So what's important is getting into action early and by doing so, be able to learn by doing and identify all the things that will make the right improvements and will be sustainable for the company and hence return the best value for shareholders. i.

[Kelly Thambimuthu, NRCan, Canada] If we sit around and talk about this issue and achieve things by slow consensus, we are not going to get anywhere. The system needs a shock. The oil crisis brought about some of the best gains in efficiency that we have made. It was mixed, in a sense that some countries very prudently pursued energy efficiencies while others in the OECD switched to coal. Overall, that shock created change. We need a similar shock.

[Baidur Eliasson] Our memories are very short. We had the oil crisis but now in Europe and the US people drive SUVs that use more fuel than ever. Energy might need to have its right price -$5 or $10 a gallon.

[Anthony Minington] The oil crisis of the 1970s did have an impact on changing both product offerings we put on the market and consumer behavior. I am concerned about technological development and administering a shock to the system. It would be a wasteful way of deploying resources. We should be accelerating regular development not pursuing a zigzag path. We need a stable investment environment where our companies can invest in new technologies and speed up incremental change. There is growing public awareness to improve efficiency. This may be partly reflected in shareholder interest. Certainly in the auto industry it comes from consumer pressure and the auto industry cannot present itself as being environmentally unfriendly. Customer needs must be met but they must show sensitivity to the environment..This includes improved fuel efficiency in gradual, more accelerated way than a shock treatment.

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[Mr Choi] Climate change is slow, not a shock like the oil crisis.

[Baldur Eliasson] Mr Morimoto, we have been involved in a project of electricity development in China where we have been trying to find the correct price for electricity. The price today is lower than the price to the environment of creating so much energy. Do you think electricity is too cheap? Maybe sustainability needs to be considered. We have looked at only the economics. There is also society and the environment. BP did wonderful things in the Philippines when they put solar panels in the jungle where people had access to electricity and clean water for the first time. Solar technology is the most expensive technology but there it was the cheapest. If you have clean water for the first time you are not talking about cents per kW, you are saving lives. We have to forget this cents/kW and include society and the environment.

[Jorund Buen from Point Carbon, a carbon analysis company] I would like to hear Mr Millington's views on the bill signed recently by Governor Davis in California that states that emissions from all vehicles, including SUVs are going to be reduced significantly after 2009, starting from 2005 onwards. [Anthony Miilington] This question would be better answered by someone from the American auto industry, but as GM and Ford are also members of ACEA through their subsidiaries, I shall try to answer. The US approach is very different from that in Japan or Europe. ACEA companies have built up experience that is applicable in the US. There is a different auto culture in the US and there is no guarantee that whatever choices are offered that the US consumer, including those in California, will be willing to take them. Only with political initiatives at whatever level will the consumer be likely to accept the fuel-efficient and emission efficient vehicles that are available. It takes two to tango and somewhere regulatory initiative is needed. Perhaps Governor Davis is only adopting what has already happened in Europe and Japan.

[Andrew Howelis, South Africa] I want to present an African perspective and am interested in electricity supply. To me, the biggest disappointment of this week is that the two most obvious ways of reducing greenhouse gas emissions, hydro power and nuclear power have been so little discussed. Africa has colossal potential for hydro power. For example on the Congo fiver, one site, at Inga Falls without a dam, could produce 100 gigawatts, and save more CO2 at this one site than all the renewables in the world. As for nuclear power, its safety record is no better than many others and has by far the least waste problems. It is the best way forward to prevent greenhouse gases. South Africa is producing a new, inherently safe small nuclear power reactor, which in a few years we will be happy to sell to Mr Morimoto in any number he likes. [Baldur Eliasson] This conference is certainly open to people who have good ideas about hydro and nuclear power, but we cannot force them to come here. It's a free society.

[Eric Lindberg, Sintef, Norway] What happened after 1973 was that consumers started to buy Japanese cars in the US for instance. A lot of US car companies went down. Steel to make these cars came from the Japanese steel companies who also reduced their CO2 emissions. If you have to reduce CO2 emissions, the cost of energy will increase so much that the public is going to again act

1537 accordingly and I don't trust industry to take the lead here. The question is too important. Governments and international bodies will have to impose proper measures and restrictions. Pressures and price of energy will go up and the public will act accordingly.

[Baldur Eliasson] Who do you trust if you don't trust industry?

[Eric Lindberg] The industry just wants to make money, period.

[Baldur Eliasson] And you?

[Erie Lindberg] My job is to tell people to accept that two cents on the price of a kWh is the price of solving future climate problems.

[Baldur Eliasson] And who should solve the climate problem?

[Eric Lindberg] Two cents a kWh will solve it. The public has to takes its punishment.

[Baldur Eliasson] The higher energy cost will solve it?

[Eric Lindberg] The higher energy cost will solve it. If industry can make money from increasing CO2 it will do it. If it can make money from decreasing CO2 it will do it. They are there for the shareholders to increase their investment.

[Baldur Eliasson] Thank You Eric, you should go into politics.

[Anthony Millington] I agree with the last speaker. It is not for industry to set society's goals. It is for governments and society. The question is setting the goals and means. I have no problem with government or regulatory authorities setting goals. The problem is finding the means to set the goal. This is where there is a lot of room for debate. As industry representatives we would say that by all means let the government set the regulatory environment. As far as possible leave it to the free initiative of the economic actors--the industry itself to determine the means to achieve those goals. There industry can show initiative on behalf of its shareholders to achieve these goals.

[Baldur Eliasson] You might be right, Mr Milligan. Governments draw a line on the ground that defines the field and then industry comes and plays the game.

[Judith Packer, member of the public] When I go to do my weekly shopping at my supermarket, either Tescos or Sainsburys, mostly there is a Tescos or Sainsburys petrol station down the road from a BP station. I usually pass

1538 these and go into the supermarket. Sometimes I pay a premium for organic apples - maybe 30% more. I do not have this choice at the petrol stations.

[Baldur Eliasson] You mean hydrogen or methanol?

[Judith Packer] Not that extreme. I do not have the choice to pay say 2 cents a gallon for that contribution to go to a cleaner fuel, or to have our taxes that Gordon Brown puts on petrol reduced significantly. Some of that tax could be siphoned off into research so we can afford carbon capture.

[Baldur Eiiasson] You are talking about taxing gasoline and using that money for these options?

[Judith Packer] No. We are already taxed. I don't have a choice where it goes. Perhaps Gardiner might like to negotiate with Tony Blair and take some of the money that I pay every week, because there is no suitable public transport system and use some of that. Let us decide if we want our taxes or pay a premium to go to new technology development.

[Baldur Eliasson] I see that the UK is not as advanced as Switzerland because when I go to buy oil for my house, I buy clean oil and it is more expensive, but it has no contaminants. We already do this.

[Gardiner Hill] I think it is a fine idea - all very good and valid points. You do have the choice in America where BP does have a program in some states and cities where we are introducing a clean fuel. It costs a premium, but reduces emissions. We are increasing our production. Governments might like to consider the idea on tax. It would be an opportunity to assist new technologies. I am not party to these discussions but I am sure they are going on.

[Baldur Eliasson] There have also been suggestions that we have to lower income taxes so that an energy levy can be introduced, but income tax stays the same. It makes sense.

[Unnamed speaker] Anthony pointed out the important fact that not just industry should be involved. How can we stimulate these ideas or set the context for them? Companies care only about their shareholders.

[Baldur Eliasson] Governments and bureaucrats define the game. They paint the lines on the ground and have to do this job very well. We need better bureaucrats. Then industry comes running onto the field and plays the game.

[Unnamed Italian speaker] I agree with industry leading, because where I come from, industry and research come together. Who must pay who?

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[Baldur Eliasson] You are saying that the relationship between government and industry should be better and suggest that a CO2 tax might make things better? I guess in your statement you are referring to Norway?

[Gardiner Hill] I think there is value in having CO2 have a value, the way things are progressing with tax in Norway and tax in the UK, and what the EU is planning to do in 2005. That will help enormously. When carbon has a value it will make a whole bunch of things more possible than they are today. People will be able to invest money and get a return for the investment they have made. Verification of reductions of emissions is very important. Once we have a value for CO2 we need clear verification of claims about the emissions we are saving to the atmosphere, because what we are trying to do is to save what goes into the atmosphere. Once money starts changing hands about reductions we are making on reducing CO2 there will need to be a new business set up to see that what is being said is being done. We don't want to find in 20 years' time that the concentration in the atmosphere is higher than it should be. The value could be by tax, but there could be other ways of giving value. We should be improving the relationship between academics and industry. In BP, we have been engaging a number of academic institutions to help us think more deeply about the whole climate change issue and about new technologies. We have put in place specific relationships with universities in the UK, US and China. They are all very important relationships and we will be doing more of that. We pick a topic and then choose which academic institution can make a real and valuable contribution to the technology or understanding of the fact. We are funding this ourselves. There may also be a role here in partnerships with government and industry to fund these relationships and increase them further.

[Unnamed Asian speaker] Little has been said about parmerships; that between industry and the public is critical, as are some points about the government setting the target: I learnt that government is very good at setting the target, but that some of the industries that are most polluting are doing so at night, when there is no government inspector to record it. There is no transparency from the government side. The aim of industry is to minimize cost and make profits. A change of culture at the corporate level is needed - to take global warming seriously, and we will be better off.

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POSTER PAPERS

CO2 CAPTURE

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

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INTERNATIONAL CO2 CAPTURE TEST NETWORK J M Topper IEA Environmental Projects Ltd, Gemini House, London SW19 6AA, UK

ABSTRACT

Post-combustion capture of carbon dioxide by solvents such as methanolamine (MEA) is commercially available now from well-known licensors. However, their processes were not originally designed for application to large fossil fuel-fired power stations. About 40% of the world's power generation is based on the use of pulverised coal, which if linked to solvent-based CO2 capture would introduce a host of potential solvent contaminants into the boiler flue gases. Both the scale of application and the presence of these contaminants suggest that there is considerable potential for process optimisation with commensurate cost saving benefits. IEA Greenhouse Gas R & D Programme is co-ordinating an effort to research and optimise the MEA capture system for application to these power stations. Three workshops have been held in Gaithersburg, USA in 2000; Calgary, Canada in 2001; and Apeldoorn, Netherlands, earlier this year. Representatives from 12 countries have attended some or all of the workshops. The specific objectives and scope of work, which the contributors have set themselves are:To develop more efficient and cost effective carbon dioxide capture from flue gases, than is currently available, through demonstration of a range of amine-based solvent scrubbing technologies. Over the long term it is important to achieve severe cuts in costs for the technologies developed to be competitive with other options. Four elements are proposed:Task Task Task Task

ABCD-

Process simulation Process and economic assessment Process innovation at test facilities Feasibility study

These objectives and tasks were agreed at the first workshop, whilst the second and third workshops developed activity with respect to Tasks A & B. This poster will draw on work being undertaken, primarily in North America and Europe to illustrate both the R & D needs and the progress so far.

1544 INTRODUCTION Carbon dioxide capture and disposal is now included in most OECD countries' energy policies and R & D programmes as a potential contributor to carbon dioxide mitigation strategies. Techno-economic studies have generally concluded that in any widespread deployment the largest element of capital and operating costs will be associated with the capture element of the chain. A number of ways of achieving high levels of carbon capture have been identified, with the proviso that some systems are more likely to be matched to some power production methods. The overwhelming majority of fossil fuel fired power plants produce a low pressure low CO2 concentration flue gas and actions to remove these are more likely to be based on some form of solvent scrubbing with separate solvent regeneration and recycle. A number of proprietary processes capable of such capture are on the world market and have been for many years, based on the use of monoethanolamine (MEA) or a derivative of it. However, these have not been developed for large power plant operations and could be much improved in efficiency and economic performance. Three workshops have been held in USA in 2000, Canada in 2001 and Netherlands earlier this year. Representatives from around 12 countries have attended some or all of the workshops. A fourth workshop will follow the day after the close of the GHGT6 conference in Kyoto. The specific objectives and scope of work, which the contributors have set themselves are:To develop more efficient and cost effective carbon dioxide capture from flue gases, than is currently available, through demonstration of a range of amine-based solvent scrubbing technologies. Over the long term it is important to achieve severe cuts in costs for the technologies developed to be competitive with other options. Four elements are proposed:Task Task Task Task

ABCD-

Process simulation Process and economic assessment Process innovation at test facilities Feasibility study

These objectives and tasks were agreed at the first workshop, whilst the second and third workshops developed activity with respect to Tasks A & B.

Gaithersburg, USA At the Gaithersburg workshop participants identified a number of areas for potential technical co-operation and/or information exchange. These included:o o

Solvent design to suit the particular composition of flue gases, especially the presence of SO2. Absorption column design, in particular identification of suitable packings and packing heights

1545 o o o

Integration of the energy system within the power plant flowsheet and minimising the thermal penalty associated with solvent regeneration. Modelling and evaluation to determine potential economies of scale and impact on sent out power costs Collaboration and possibilities for cost sharing in R & D activities

Calgary, Canada The Calgary workshop was convened to further develop possibilities associated with Task A and to some extent Task B. Presentations were made on the following topics o o o o o o

a review of the status and confidence in available v a p o u r - liquid equilibria data rate data modelling mass transfer the International Test Centre (ITC) the Boundary Dam project, GTI's test facilities the benefits and limitations of pilot plant work software issues and systems

Apeldoorn, Netherlands The intentions for this workshop were to o o o o o

Review actions from Calgary Advance work on simulation & modelling Introduce new entrants Begin review of practical results Consider finances for future events

To give an indication of breadth, topics covered at Apeldoom included o

Costs of CO 2 Capture and Storage by IEA Greenhouse Gases

o o o o o o o o o o o

CO2 Capture and Storage in the Netherlands CO 2 Capture Initiatives in Canada Norwegian efforts to reduce GHG emissions CO2 Capture Activities in Italy and ENI Capabilities of Hyprotech CO2 Capture Solvent Selection by IFP Optimisation using exergy analysis in ASPEN by TNO IEA GHG Assessment Criteria by lEA GHG A Plant-Level Model of CO2 Capture and Storage Options by Carnegie Mellon University Modelling CO2 capture in oxygen-IGCC system by EdF Simulating CO 2 Capture From Pulverized Coal Fired Power Plants- Model

o

Assumptions by University of Waterloo MEA - CO 2 Capture Processes Using AspenPlus by U. Waterloo

o o o o

International Test Centre for CO2 capture (ITC), University of Regina Update of Activities, Boundary Dam CO2 Pilot Plant by Fluor CO2 capture activities at NTNU,Norway CO2 capture from flue gas by TNO

1546

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Figure 1:CO2 Capture using Amine Based Systems (from the presentation by Carnegie Mellon University at the Apeldoorn workshop) Kyoto Workshop 5 October 2002 This workshop follows on from the GHGT6 conference. It is intended to restrict preliminaries to a welcome from the Japanese hosts and a single summary presentation by the co-ordinator, before moving into the main technical sessions. Following comments made at the Apeldoorn workshop it is intended to deal first with systems modelling and economics and then with practical R & D results, leaving fundamental data on Vapour Liquid Equilibria and MEA rate data to the last. Hence, 4 sessions are envisaged. o o o o

Session 1 - Welcome, Introductions and Review of Past Activities Session 2 - Systems Modelling and Economics Session 3 - Pilot plant and Laboratory results Session 4 - Fundamental Data Vapour Liquid Equilibria Rate Data

Spring 2003 The Spring 2003 Workshop is likely to be in Ottawa, Canada

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1547

THE INTERNATIONAL TEST CENTRE FOR CARBON DIOXIDE CAPTURE (ITC) M. Wilsonl, p. Tontiwachwuthikul l, A. Chakma2, R. Idem 1, A. Veawabl, A. Aroonwilas2 and D. Gelowitz 1 1University of Regina, Regina, Saskatchewan, Canada $4S 0A2 2University of Waterloo, Waterloo, Ontario, Canada N2L 3G 1

ABSTRACT The GHG research team at the University of Regina, in collaboration with the two senior levels of Canadian government, as well as industrial partners, has established the International Test Centre for CO2 Capture (ITC) with the mandate to explore and develop new, cost-effective technologies for CO2 capture. The team has designed a research program that aims at reducing the cost of CO2 capture in the short to medium term while attempting to find "novel" approaches that can significantly reduce the cost in the long term. In order to accomplish our research objectives, we have invested over sixteen million dollars in infrastructure building in the ITC. The research infrastructure consists of a well-equipped bench-scale CO2 separation unit at the University of Regina (U of R), a revamped sub-commercial technology demonstration unit at the Boundary Dam Power Plant of SaskPower (BD unit), and a multi-purpose technology development pilot plant unit at the U of R (UR units). It is also equipped with top-of-the-line analytical and computer support. The ITC provides a unique, seamless basic science/technology development infrastructure, which comprises fundamental research, technology development and pre-commercial demonstration. Although two other facilities exist, one in Japan and the other in Norway, the ITC will be the only one in the world that brings all aspects of basic science/technology development under the auspices of a single entity. This paper provides a description of this infrastructure as well as show how it is used to accomplish our research objectives on CO2 capture.

BACKGROUND

Energy is the most critical factor for the growth of any nation's economy. However, its use has a major impact on the environment especially as it contributes to presence of air pollutants in the atmosphere. In addition, energy production from fossil fuel, the world most important fuel, is known to be the key contributor of the CO2 (a major greenhouse gas) that is blamed for climate change and global warming problems. In Canada, fossil fuels are, however, the major energy resources providing a healthy balance of trade to Canada and employment to many Canadians. Despite these positive contributions, the fossil fuel industry faces a major challenge. It is a major contributor to greenhouse gas (GHG) emissions in Canada. For example, energy related production activities accounted for 20% of CO2 emissions in 1999. Electricity production also added another 17% making the total contribution of CO2 emissions from fossil fuel industries (including coal) 37%. In order to minimize these adverse effects, industrialized countries under the Kyoto Protocol indicated their intent to reduce collective emissions of GHGs by 5.2% below 1990 levels by the period from 2008 to 2012. Canada's target is 6% below 1990 levels. The scale of the problem can be illustrated by the fact that, in order to sustain the current production capacity of crude oil in Western Canada, Enhanced Oil Recovery (EOR) techniques utilizing CO2 must be used. At the same time, a large amount of CO2 is being produced by coal-fired power plants and industrial facilities in this region (Saskatchewan and

1548 Alberta). This large quantity of CO2 is discharged into the atmosphere and is likely cause enhanced greenhouse effect and global warming problem as mentioned above. To overcome CO2 emission problems, there is great interest in capturing the CO2 and utilizing it as a flooding agent for EOR processes. Capturing, using, sequestering or storing greenhouse gases (GHGs), particularly CO2 has been identified I as one of the key measures for the mitigation of GHG emissions in Canada. However, the main obstacle to the capture and sequestration option is the high cost of CO2 capture (in the range of $40 to $80 per ton of CO2 captured). Thus, using present day technology, the high cost makes the CO2 capture option economically unattractive. Consequently, there is a need to develop technologies that can capture CO2 at much lower costs. Current commercial technologies available for CO2 capture from low pressure and dilute combustion gas streams are essentially based on a chemical solvent process where CO2 is absorbed into a chemically reactive solvent. The solvent is then regenerated for further use by application of steam. While process optimization and integration as well as efficient use of conventional solvents can reduce the costs of CO2 capture by 20-30%, novel techniques need to be designed and developed based on fundamental scientific and engineering principles if a substantial reduction in costs is required. The GHG research team at the University of Regina has been working on various aspects of CO2 separation issue for over a decade. The team has taken advantage of this expertise to establish, in collaboration with the two senior levels of Canadian government, as well as industrial partners, the International Test Centre for CO2 Capture (ITC) with the mandate to explore and develop new, cost-effective technologies for CO2 capture. We have designed a research program that aims at reducing the cost of CO2 capture in the short to medium term while attempting to find "novel" approaches that can significantly reduce the cost in the long term. This paper provides a description of this infrastructure as well as show how it is used to accomplish our research objectives on CO2 capture.

RESEARCH PROGRAM Our research team has been working on various aspects of CO2 separation issue for over a decade. We have taken advantage of this expertise in the establishment of the International Test Centre for CO2 Capture (ITC). We have also used this expertise to design a research program that aims at reducing the cost of CO2 capture in the short to medium term while attempting to find "novel" approaches that can significantly reduce the cost in the long term. Our research program consists of two distinct components: Innovative Research and Development (IRD) and Technology Development and Demonstration (TDD). The IRD component of our research focuses on fundamental research and laboratory scale studies on high efficiency CO2 capture technologies from industrial gas streams at "low pressure" (e.g. fossil-fired combustion flue gases) as well as "high pressures" (e.g. gas streams from IGCC, O2-CO2 recycle combustion processes). The research program involves studies on (i) high efficiency column internals, (ii) high pressure, physical and reactive membrane separation, (iii) use of physical and chemical solvents as well as the molecular design and formulation of new solvents, (iv) corrosion control for gas treating process, (v) cogeneration concept, and (vi) process integration. The TDD component consists of pilot plant testing for technology development and subsequent demonstration in industrial applications in collaboration with industrial partners. Other uses are: (i) to evaluate the economic feasibility of various chemicals and components proposed after laboratory and pilot-plant studies, (ii) to test the technical and economic feasibility of promising processes prior to commercialization, and (iii) to evaluate the possibility for process integration with the overall system.

INFRASTRUCTURE Infrastructure in the ITC consists of a well-equipped bench-scale CO2 separation unit at the University of Regina (U of R), a revamped semi-commercial technology demonstration unit at the Boundary Dam Power Plant of SaskPower (BD unit), and a multi-purpose technology development pilot plant unit at the U of R (UR units). It is also equipped with top-of-the-line analytical and computer support. The ITC provides a unique, seamless science/technology development infrastructure, which comprises fundamental research,

1549 technology development and demonstration. Although two other facilities exist, one in Japan and the other in Norway, the ITC will be the only one in the world that brings all aspects of basic science/technology development under the auspices of a single entity. This paper provides a description of this infrastructure and shows how it is used to accomplish our research objectives on CO2 capture.

Innovative Research Using the Bench Scale Facilities at the University of Regina The ultimate goal of our fundamental research program is to develop effective CO2 capture technologies for processing natural gas, flue gases and other industrial gas streams. Currently, we are working on a number of projects related to high efficiency CO2 separation processes. These include: • • • • • • • • • • • • • •

Determination of C02 absorption capacity of novel solvents Evaluation of gas separation process related thermodynamic data Studies of CO2 absorption kinetics in various solvents Molecular design and synthesis of novel absorption solvents Formulation of high performance CO2 absorption solvents Studies of high performance column internals for absorption and solvent regeneration Studies of reactive membranes for gas separation processes Development of design strategies for high efficiency CO2 absorption processes Studies of corrosion and corrosion control in CO2 & solvent environments Studies of solvent degradation in CO2 absorption processes Modeling and simulation of gas separation processes Optimization and cost studies of cogeneration-based CO2 capture Knowledge-based systems for solvent selection in CO2 separation processes Intelligent monitoring and control of CO2 generating systems

Examples of our bench-scale research facilities are given in Figure 1.

(a)

(b)

(c)

Figure 1: Bench-scale research facilities at the University of Regina (a: CO2 absorption/regeneration unit, b: Analytical equipment, c" Calorimeter).

Technology Development in the Regina Multi-purpose Technology Development Pilot Plant The technology development plant at the University of Regina consists of a CO2 capture unit, which has a number of 12" diameter absorption and regeneration columns that are fully integrated with power/heat generation facilities. Research in this plant explores new technologies and seeks to optimize their use prior to final demonstration at the Boundary Dam semi-commercial unit. This pilot plant is small enough to provide the ease and flexibility of operation, yet large enough to gather extensive operating data. This plant can be used for conducting research and development on new CO2 capturing technologies such as: • High capacity column packings • High efficiency separator units • Novel C02 separation using hollow fiber membranes

1550 • • • •

Studies using spray columns Co-generation Process Integration Modeling, simulation and optimization for CO2 separation

Technology Demonstration at the Boundary Dam Semi-Commercial Pilot Plant Technology demonstration is conducted in a pre-commercial CO2 capture unit located adjacent to the Boundary Dam Power Station (BDPS), near Estevan, Saskatchewan. This CO2 plant consists of a fly ash removal unit (baghouse), a sulfur dioxide removal unit, and a CO2 chemical absorption/regeneration unit with a current capacity for separating 4 tonnes/day of CO2 using an 18" diameter absorption column. A picture of the plant is shown in Figure 2. This plant is used for technology demonstration as well as for conducting tests to develop good engineering data essential for the design of commercial facilities. Other uses include:

Figure 2: Overview of the Boundary dam CO2 extraction unit. • • •

Testing the technical and economic feasibility of a proposed process prior to commercialization. Evaluating process integration with the overall system. Evaluating the economic feasibility of various chemicals and components after laboratory and pilot-plant studies

PARTNERSHIPS The International Test Centre brings together stakeholders from the academia, governments, the oil and gas producing sector, coal producing sector, power generation sector and the engineering, procurement and construction sector to form a consortium. The consortium members are: SaskPower, Fluor Canada, TransAlta, EPCOR, Luscar, Nexen Energy, EnCana, Natural Resources Canada, Saskatchewan Industry and Resources, Alberta Science and Technology, US Department of Energy, University of Regina, and University of Waterloo.

SUMMARY The ITC is equipped with an array of facilities that provides a unique, seamless science/technology development infrastructure, and the capability to carry out fundamental research, technology development and pre-commercial demonstration on various CO2 capture technologies.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1551

DEVELOPMENT OF CO2 SEPARATION MEMBRANES (1) POLYMER MEMBRANE

Hiroshi Mano 1, Shingo Kazama I and Kenji Haraya 2 1Research Institute of Innovative Technology for the Earth (RITE) 9-2 Kizugawadai, Kizu-cho, Soraku-gun, Kyoto 619-0292 Japan 2National Institute of Advanced Industrial Science and Technology (AIST) AIST Tsukuba Central 5, 1-1-1 Higashi, Tsukuba, Ibaraki 305-8565 Japan

ABSTRACT With the aim of developing technologies for separating and recovering CO2 from exhaust gases of stationary CO2 emission sources amid the ongoing problem of global warming, we developed a new cardo type polymer membrane. The cardo type polymer has a molecular structure with a bulky loop form. The polymer shows the important characteristics of a high gas permeability and high solubility in organic solvents that provide hollow fiber membrane processability and heat stability derived from an aromatic structure. Since a cardo type polyimide showed the highest CO2/qXT2selectivity and CO2 permeability during the screening of many newly synthesized cardo type polymers, we selected it and conducted a structure function relationship analysis looking at CO2/N2 selectivity and CO2 permeability. We identified new cardo type polyimide structures for CO2 separation. Then, we developed the wet spinning technology to produce an asymmetric hollow fiber membrane, and incorporated the membrane in module. In addition to using bench-scale testing to obtain basic data for implementing the module, we considered a 1,000MW coal combustion power plant. The information obtained confirmed that in energy terms, the developed membrane separation method is superior to current methods.

INTRODUCTION

Exhaust gas from thermal power plants, cement plants, steel mills, etc. consists mostly of N2 and CO2 and thus technology to separate these gases is required. Our project aims to develop a membrane that provides excellent selectivity for CO2 and is durable and heat resistant. Furthermore CO2 separation membranes needs to be modular in order to cope effectively with the large volumes of exhaust gases from stationary sources. Membrane separation technology was selected for the research topic, rather than chemical absorption methods, adsorption methods, low-temperature processing or other established methods for treating CO2

1552 quickly and effectively in large volume, for the following reasons; 1) The membrane separation method should be more energy efficient than other methods; there are no accompanying phase changes; and if the CO2 selection efficiency of the membrane can be increased, the separation energy can be made less than other methods. In addition, there is greater room to make improvements in the technology as no commercial membranes are available, whereas commercial methods are available for other methods. 2) It is an environmentally clean method because it does not discharge harmful substances such as amines into the air and there is no liquid amine waste to dispose of, as there is with the absorption method. Both polymer and inorganic C02 separation membranes have been researched, but in this study, polymer membranes were selected since their permeability is generally large and they have a large capacity; this is important, given the large volumes of gas to be processed. The cardo type polymer was first selected from polymer membrane materials previously trialed for the following reasons; 1) Past trial results showed it can separate 02 and N2 and that there was the possibility of separating CO2. 2) The processing to make the membrane is easy as the polymer has excellent solubility.

DEVELOPMENT OF MEMBRANE MATERIAL

The cardo type polymer is a polymer that has a molecular structure with a bulky loop form and the one that we examined in this research development has a bisphenylfluorene structure. This thicker than normal, bulky loop chemical structure gives the polymer the important characteristics of a high gas permeability, a high solubility in organic solvents, that provides hollow fiber membrane processability and heat stability derived from an aromatic structure. Our research and development was carried out in order to enhance the CO2 separating performance of the cardo type polymer. The cardo type polymer can be synthesized as various polymer materials such as polyimide or polyamide. Since a cardo type polyimide showed the highest CO2/N2 separation coefficient and CO2 permeability during the screening of many newly synthesized cardo type polymers, we selected it and conducted a structure function relationship analysis looking at CO2/N2 separation coefficient and CO2 permeability [1,2]. Cardo type polyimide PI-BT-COOMe and PI-PMBP64 were found to be excellent due to their good balance of C02/N2 separation coefficient and CO2 permeability [3]. The high C02/N2 separation coefficient of the cardo type polyimide PI-BT-COOMe is probably due to its structure having a high affinity for CO2. In order to raise the Co2/rN2 separation coefficient and the CO2 permeability of PI-PMBP64 further, PI-PMBP64(4Me) was developed by introducing methyl groups to the side chain of the aromatic ring and it showed very high CO2 permeability. Following this development, we then focused on the bromine atom. The bromine added cardo type polyimide PI-PMBP64(4Me)-Br was synthesized for use as membrane material (Figure 1). In this way, we obtained PI-PMBP64(4Me)-Br membrane which has excellent CO2/N2 separation coefficient and CO2 permeability properties. Our successful development of the bromine substitution process in polymer solution is largely responsible for synthesis of bromine substituted cardo type polyimide PI-PMBP64(4Me)-Br.

1553

r

CH2X CH2X 0

_

0

60 Figure 1: Cardo type polyimide PI-PMBP64(4Me)-Br (80% o f X = Br) D E V E L O P M E N T OF M E M B R A N E MODULE AND EVALUATION We have developed the wet spinning technology to produce an asymmetric hollow fiber membrane by extruding polymer solution through a double tube nozzle together with core liquid (coagulant water), and coagulating the spun membrane in water, utilized the cardo type polyimide. CO2 permeability was much improved by refining the processing conditions. This included the use of an active separation layer of asymmetric hollow fiber membrane, 100nm or less, made by means of the wet spinning method. When these cardo type polyimide fiber membranes are heat treated, the stability of the hollow fiber membrane improves. As a result of evaluating the module incorporating the newly developed hollow fiber membrane, the cardo type polyimide PI-PMBP64(4Me)-Br hollow fiber membrane showed high CO2 permeability. CO2 permeation rate : 1.3 x 103cm3/cm 2 s cmHg CO2/N2 separation coefficient : 41 (at 298K)

(at 298K)

This is the first time that the CO2 permeability of a hollow fiber membrane reached the order of 10-3cm3/cm2 s cmHg. It was confirmed that the CO2/tN2 separation coefficient of the cardo type polyimide PI-PMBP64 hollow fiber membrane module lasts for more than 12,000 hours at 323K. Next, a bench scale examination was carried out in order to monitor the influence of scaling up the membrane module and of gas flow. This used the newly developed cardo type polyimide membrane module (0.35mm hollow fiber inner diameter, 500mm length, 25,600 fibers, 8m2). The bench scale examination apparatus was built so that a mixed gas, simulating a combustion exhaust gas, could be supplied at a rate of 1.6m3/h. As a result, even if the supply gas quantity increases to as high as 1.6m3/h, a performance decline of the hollow fiber membrane was not observed. This shows that the design of the system on the basis of 60% recovery of CO2 from the exhaust gas of a coal fired power station is realistic. As far as we know, our cardo type polyimide membrane test is the first time a bench scale test on a CO2 membrane separation system has been conducted on simulated exhaust gas. In addition, we have carried out a preliminary test with the cardo type polyimide PI-PMBP64 membrane module using actual exhaust gas. Durability testing was conducted using real exhaust gases which were the combustion smoke after desulfurization from a fine coal-fired power station and the exhaust gas from a converter of a steel mill. In another series of tests, we found that the CO2/N2 separation coefficient of the cardo type polyimide PI-PMBP64 hollow fiber module over a period of 3,500 hours was the same for both cylinder gas (simulation gas) and for real gas from a steel mill. This means that the CO2 concentration ability can be achieved even with real exhaust gas. This is the useful knowledge for practical application.

1554 STUDY OF CO2 SEPARATION PROCESS We investigated the optimization of the practical plant design covering the whole CO2 separation and liquefaction process, using the newly developed separation membrane (CO2/N2 separation coefficient : 35) at a scale equivalent to exhaust gas of a 1,000MW coal combustion power plant, which is the standard for our trial system. In order to design a practical plant, the investigation examined simulations of the flow pattern analysis, the pressure difference ratio between supply side and permeate side, the relationship between the CO2 recovery rate, energy and cost, and the energy load distribution of the membrane separation and liquefaction. A consequence of this was that the energy necessary for the whole separation and liquefaction process for CO2 concentration was reduced to about 60%. A pressure ratio between the supply side (almost atmospheric pressure) and permeate side (reduced pressure) of 0.13 was found to be best. It was found that 40-60% of CO2 recovery rate is beneficial in terms of energy required. When a cardo type polymer membrane with a CO2/N2 separation coefficient of 35 was used, a CO2 separation and liquefaction energy of 0.41kWh/kg-CO2 was obtained. Thus, the membrane separation method developed was shown to be an important factor in energy effectiveness. Furthermore, we have investigated the application of the membrane separation method for exhaust gases from other stationary gas emission sources. When the membrane of CO2/N2 separation coefficient 35 is used, examples of CO2 separation and liquefaction energy are: • •

In the case of cement plant exhaust gas (CO2 concentration 25%): 0.29kWh/kg-CO2 In the case of steel mill exhaust gas (CO2 concentration 27%): 0.28kWh/kg-CO2

This indicates that the energy required for these high CO2 concentration exhaust gases is much lower than that of membrane separation methods used in a coal-fired power station.

PRACTICAL APPLICATION OF THIS TECHNOLOGY It was shown that about 17% of the total CO2 emission in Japan could be recovered if the new CO2 membrane separation method could be applied to theall coal-fired power stations, steel mills and cement plants. This CO2 membrane separation method is effectively applicable to a wide range of CO2 separations. It is able to be applied to CO2 separation recovery, as the prior process to CO2 sequestration underground or in the ocean.

ACKNOWLEDGEMENTS This work was supported by Ministry of Economy, Trade and Industry, Japan, and New Energy and Industrial Technology Development Organization (NEDO).

REFERENCES 1. 2. 3.

Hirayama, Y., Kazama, S., Fujisawa, E., Nakabayashi, M., Matsumiya, N., Takagi, K., Okabe, K., Mano, H., Haraya, K. and Kamizawa, C. (1995). Energy Convers. Mgmt., 36 (6-9), 435-438. Tokuda, Y., Fujisawa, E., Okabayashi, N., Matsumiya, N., Takagi, K., Mano, H., Haraya, K. and Sato, M. (1997). Energy Convers. Mgmt., 38, S 111-S 116. Karashima, S., Tokuda, Y., Tachiki, A., Takagi, K., Haraya, K. and Kamizawa, C. (1999). Greenhouse Gas Control Technologies, 1035-1037.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1555

DEVELOPMENT OF CO2 SEPARATION MEMBRANES (2) FACILITATED TRANSPORT MEMBRANE

Kazuhiro Okabel, Norifumi Matsumiya ~, Hiroshi Mano I and Masaaki Teramoto 2 i Research Institute of Innovative Technology for the Earth 9-2, Kizugawadai, Kizu-cho, Soraku-gun, Kyoto 619-0292 Japan 2 Kyoto Institute of Technology Matsugasaki, Sakyo-ku, Kyoto 606-8585 Japan

ABSTRACT

The facilitated transport membrane, which is immobilized K2CO3 aqueous solution by polymer gel, was studied to improve its stability. This polymer gel membrane preserved high selectivity for about six months under a high humid gas mixture, imitative of combustion gas. K2CO3 aqueous solution played an important part in keeping the membrane wet, and the polymer gel played an important role in maintaining the membrane's stability. The polymer gel membrane has potential for practical use in the recovery of CO2 from combustion gas.

INTRODUCTION

In recent year, there has been concern about global warming due to CO2, and a need has arisen to develop technology for suppressing its emission. The Research Institute of Innovative Technology for the Earth (RITE) has been developing membrane technology for separation and recovery of CO2 released to the atmosphere from such facilities as coal thermal power plants. The membrane separation method is a clean and simple process, and ideal as a method for dealing with the global environmental problem [ 1]. The energy to recover CO2 is dependent on the selectivity of CO2, therefore RITE adopted the challenging goal of developing a facilitated transport membrane which was expected to have much higher selectivity than a conventional polymer membrane.

1556 EXPERIMENTAL

Preparation The facilitated transport membrane has a two-layered structure; one is polymer gel containing a carrier solution that reacts with CO2, and the other is a porous membrane which supports the gel layer. The support membrane for the gel layer is a hydrophobic polytetrafluoroethylene (PTFE) porous membrane (poreflon FP010, pore diameter 0.1 ~tm, membrane thickness 60 lam, porosity 55% manufactured by Sumitomo Electric Industries, Ltd.), and the polymer gel is a vinylalcohol-acrylate salt (hereafter "PVA-PAA") copolymer (Sumikagel L-5H, manufactured by Sumitomo Chemical Co., Ltd.) [2]. A 5% water solution of PVA-PAA was spin-coated onto a PTFE porous membrane with a diameter of 47 mm, then heated at 120 °C for 1 hour to cross-link the PVA-PAA. This composite membrane was dipped into the potassium carbonate (K2CO3) aqueous solution of 2 mol/kg, which was already known as a CO2 absorbent. The cross-linked PVA-PAA layer absorbed a carrier solution then the gel layer was formed.

Measurement The mixed gas (CO2: 10%, N2: 90%) saturated with water vapor was supplied to the membrane to evaluate performance under conditions of simulated combustion gas. The permeability of the membrane was measured under the conditions of temperature 25 °C, the pressure at the permeation side was reduced to 2.7---5.3 kPa (20-~40 mmHg), and the pressure at supply side was 120.9 kPa (about 1.2 atm). The gas that permeated the membrane was analyzed with a gas chromatograph, and the selectivity and permeation flux calculated. RESULTS AND DISCUSSIUON

Membrane Preparation The conventional facilitated transport membrane had problems that included low durability and difficulty in preservation as a thin membrane, as it was a liquid membrane impregnated into the porous support. In order to resolve these problems, we developed a polymer gel membrane with the structure shown in Fig. 1. Polymer gel membrane ..................... Z ~cross-linked PVA-PAA) . . . . . . .

._-__ _--.-_._-__._--__ _--_._ ~

G

Permeate

_~-_ .--------÷_~-

Support membrane (PTFE)

Figure 1: Structure of polymer gel membrane The thickness of the cross-linked PVA-PAA layer before swelling was about 1 gm. The thickness of the polymer gel was determined by the conditions of cross-linking because the swelling ratio depends on the degree of cross-linking when the concentration of K2CO3 aqueous solution was constant. PVA-PAA cross-linked by the conditions noted absorbed K2CO3 aqueous solution of 2 mol/kg and increased 50 times in weight. The thickness of

1557 polymer gel was then estimated to be about 50 ~tm.

Stability The water retention test was carried out before the measurement of stability. The weight reductions of water in the solution or polymer gel are shown in Figure 2. When the solution and polymer gel were exposed to relative humidity of 50% at temperature of 25 °C, solvent water evaporated and the K2CO3 solution and its gel reached the equilibrium concentration with the vapor pressure corresponding to the relative humidity of 50%. However, water and polymer gel without salt dried up. These results mean that salts, rather than gel, play an important part in keeping the membrane wet.

=e

o~ ~ ~

1.2 J= 1.0 0.8 0.6 0.4 0.2 0

Initial weight of water

g H20 /k K2CO3[2 mol/kg]aq. O H20/PVA-PAAgel K2CO3 [2mol/kg]aq./PVA-PAAgel

Temp ' 25 ~C Relative humidity • 50% 0

50 100 Time [hr]

150

Figure 2: Water retention test The equilibrium vapour pressure above the K2CO3 aqueous solution at the temperature of 25 °C is shown in Figure 3. From Figure 3 and the results shown in Figure 2, it was thought that the polymer gel membrane works under conditions in excess of equilibrium water vapor pressure.

c-+

100

o O

(1) c" E~

~-

50

0

2.5

5

7.5

10

KgCO~ concentration I'mol/ka]

Figure 3: Equilibrium vapor pressure above K2CO3 aqueous solution at 25 °C Stability of a polymer gel membrane formed on PTFE which was immersed in 2 mol/kg K2CO3 aqueous solution was measured (Fig.4). With the impregnation membrane without polymer gel, permeability of the membrane was lost approximately 15 minutes after the start of testing. However, with the polymer gel membrane, the CO2 permeation rate was nearly constant over a period of about six months. The separation factor declined as time

1558 passed, however, after six months, this polymer gel membrane preserved high selectivity and it remained wet. The declining selectivity was due to the increase of the N2 permeation rate. Some causes of this increase were thought to be due to defects such as micropores occurring during measurement, or N2 solubility increasing as a result of the decrease of K2CO3 concentration due to deposition of salt or condensation of water vapor. From the findings of this measurement, polymer gel plays an important role in keeping the membrane stable and the polymer gel membrane has a potential for practical use.

10-6,

1000

~

10-;'"

100

oi-i.

10 -8"

10

"0

t-f"

10 -9

0

50

100

150

~ o

1

200

Figure 4: Stability of polymer gel membrane

CONCLUSIONS The polymer gel membrane preserved a high selectivity for about six months under a high humid gas mixture, simulating combustion gas. K2CO3 aqueous solution played an important part in keeping the membrane wet, and polymer gel played an important role in maintaining the membrane's stability. The polymer gel membrane has potential for practical use for recovering CO2 from combustion gas.

ACKNOWLEDGEMENTS This research was supported by the New Energy and Industrial Technology Development Organization (NEDO). In conducting this research, we received appropriate advice from Professor Masaaki Teramoto of Kyoto Institute of Technology, and we would like to express our deep gratitude to him.

REFERENCES

Mano, H. (1998) Proceeding of the 63th SCEJ Annual Meeting, Bl13, 35 Nakabayashi, M., Okabe, K., Matsumiya, N., Mano, H. (1995) Energy Convers. Mgmt 36, 419

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1559

EVALUATION OF M E M B R A N E S E P A R A T I O N P R O C E S S OF CO2 R E C O V E R Y

Norifumi Matsumiya l, Hiroshi Mano I and Kenji Haraya 2 IResearch Institute of Innovative Technology for the Earth (RITE) 9-2 Kizugawadai, Kizu-cho, Soraku-gun,Kyoto 619-0292 Japan 2National Institute of Advanced Industrial Science and Technology (AIST) 1-1 Higashi,Tsukuba,Ibaraki 305-8565 Japan

ABSTRACT A computer simulation was carried out to estimate the energy and cost for a CO2 separation process with a membrane applied to the exhaust flue gas from a 1000MW coal combustion power plant. Three types of separation processes, depending on the mode of pressure application were investigated, i.e., membrane separation processes driven by decompression, compression and compression-decompression. It was found that both the energy and cost for CO2 separation were smallest in the case of the compression-decompression mode. The membrane separation process driven by compression-decompression was the most economical among the three types of processes.

INTODUCTION Various technologies, including CO2 geological storage and ocean storage, CO2 utilization and so on, have been investigated as a countermeasure to the greenhouse effect. Before they are applied to the fields of thermal power plants, cement plants, steel mills, etc., CO2 must be recovered from the exhaust flue gas from the plants. To recover CO2 from flue gas, a membrane separation processes is applicable, in which the pressure difference should be applied across the membrane as a permeation driving force. It can be done either by compressing the flue gas with a compressor or connecting a vacuum pump to the permeation side of the membrane module. The energy consumed to operate the equipment is regarded as the CO2 separation energy. We have investigated the optimization of the following three types of CO2 separation processes, for a coal combustion power plant generating 1000 MW of electricity. 1. Decompression membrane separation process: The pressure of the supply side is almost at atmospheric pressure and that of the

1560 permeation side is decompressed by a vacuum pump. 2. Compression membrane separation process: The flue gas is compressed at the supply side by a compressor and the pressure of the permeation side remains at atmospheric pressure. The energy of high pressure residue gas is recovered by an expander. 3. Compression - decompression membrane separation process: The flue gas is compressed at the supply side by a compressor and the pressure of the permeation side is decompressed by a vacuum pump. The energy of high pressure residue gas is recovered by an expander. These separation processes are investigated for two cases. Firstly, the separation energies and membrane areas were calculated by a separation calculation program developed by Matsumiya et al. [ 1]. Secondly, total separation costs were estimated by summing up the separation cost and other instrumental and working costs. The energy and cost of liquefaction were included. In this study we used the membrane permeability data of a new type of polymer membrane with a high CO2 permeability and a high CO2/Nz separation coefficient, which was developed by RITE as a result of a Japanese national project on CO2 chemical fixation [2].

T H E C A L C U L A T I O N C O N D I T I O N AND E Q U A T I O N The cost of C O 2 separation depends on the electrical charge to operate the C O 2 separation equipment and the equipment cost. The electrical charge depends on the consumed energy to separate COz and the equipment cost depends on the membrane area of a module. The estimated cost takes not only the CO2 separation process but also the COz liquefaction process into account. The CO2/N2 separation coefficient and the COz permeation rate of membrane used for this calculation are 35 and 1.68 x 10 -7 mol m / s ~ P a -1, respectively. The detailed calculation conditions are shown in Table 1. TABLE 1 CALCULATION CONDITIONS feed pressure PI (kPa) Decompressmn process Compression process CompressionDecompression Process

permeate pressure P2 (kPa)

expander compresser stage stage effciency n u m b e r N effciency n u m b e r N effciency n u m b e r N q (-) (-) (-) (-) (-) (-) vaccum pump stage

gas component (tool%)

lO0

lO

-

CO2:15

lO00

lO0

3

0.85

3

0.85

N2:81

0.85

1

0.85

0.85

2

0.85

02:4 H20: saturated

1

0.63

case 1

250

25

-

0.73

1

case 2

500

50

-

0.8

2

gas temprature (centigrade)

50

The consumed energies Wc of the compressor and vacuum pump are calculated by equation (1), and the recovery energies Wr of the expander are calculated by equations (2), respectively [3]. Wc=N Pi F k / ( k - l ) [(Po/Pi)(k'l)/Nk-1] /q

(1)

Wr = N Pi F k/(k-1) [ 1-(Po/Pi) (k-l)/Nk]q

(2)

1561 where F is the total volume flow rate, k is an adiabatic constant, Pi and Po are pressures of the inlet and outlet streams of compressor, vacuum pump and expander. Other symbols are in Table 1. The values of efficiencies for the compressor, expander and vacuum pump were obtained from literatures [4, 5]. The energy requirement o f the liquefaction process was calculated by the Process Simulator "PRO2". RESULTS The result of the calculation of the CO2 separation energy is shown in Figure 1. ~ " = decompressbn = = = pressurizatbn press-decom p (case 1) press-decom p (case 2)

60

~ ~,~

50

7'

40

~=

30

~"

20

~. "o

%

-

10 0

0

I

l

I

I

I

0.2

0.4

0.6

0.8

1

Re c ove r ] r a t b of C02

F i g u r e 1: The energy of CO2 separation The consumed energy for CO2 separation of the compression membrane separation process is the largest of all, because the feed stream must be compressed to high pressure (1000 kPa) to enrich CO2 and the considerable energy of the high pressure residue gas cannot be recovered. On the other hand, the energy of CO2 separation becomes smaller in the decompression membrane separation process because only the vacuum pump is required. In the compression-decompression membrane separation process, not only the compressor, but also the vacuum pump are employed to separate CO2 from the flue gas. This process consumed small energy, however, as the pressure of the feed stream is low (Case 1 : 2 5 0 kPa, Case 2 : 5 0 0 kPa) and the vacuum pump can be operated at higher efficiency. The energy of CO2 separation was the smallest in Case 1 of compression-decompression mode (feed pressure:250 kPa, permeate pressure:25 kPa). The membrane area of the module depends on the CO2 driving force. It becomes the smallest in the compression membrane separation process (feed pressure:1000 kPa, permeate pressure:100kPa) because the large value of the CO2 driving force is adopted in this process. The cost o f CO2 separation was calculated under the conditions listed in Table 2. The total cost is defined as the total amount of membrane separation equipment cost, liquefaction equipment cost, electric charge, fixation cost and labor cost. The result of the calculation on the cost of CO2 separation is shown in Figure 2. Although the compression-decompression membrane separation process (Case l) needs many pieces of equipment (the compressor, the expander, the vacuum pump, etc), the cost of CO2 separation was also found to be the smallest. The reason for this result is that the energy cost occupies more than 60% of the total cost for CO2 separation in each separation process.

1562 CONCLUSIONS The energy for C O 2 separation becomes considerably greater in the compression membrane separation process. There is little difference between the consumed energies of the decompression membrane separation process and the compression-decompression membrane separation process. The total cost of the system is the smallest when the compression-decompression membrane separation process is adopted. This process is an excellent process in terms of economy. TABLE 2 CONDITIONS FOR COST ESTIMATION Membrane separation cost ([(9+@+@+@+@+@] x C) C=2.5 C:factor of design,construction and project cost Liquefication cost Fixation cost Electric charl~e Labor costs

(~) (~) (~) (~) O ®

~ 1000

. "~

T 800 "~ ~

yen/kWh millionyen/year 'persons

•"-- - decompressbn - - - pressurization press-decom p (case 1) press-decom p (case 2)

1200 o

yerdm2 ~¢en/kmol.s" yen/kmol.s-I ~,erd(kcal/hr) yen/kw million yen/kmol.s"l million yen

module 4000 compressor 33500 coolingpump 1.31 heat exchanger 5 expander 100000 vaccumpump 56 16000 x (power/0.228)°'7 14% for total constraction cost 12 6

6oo

X =~ 400 ~''

200 0 0

I

I

I

I

0.2

0.4

0.6

0.8

Recovery ratb oft 0 2 F i g u r e 2: The cost o f CO2 separation ACKNOWLEDGEMENTS This work was supported by New Energy and Industrial Technology Development Organization (NEDO). REFERENCES

1. Matsumiya,N., N.Ioue, H.Mano, K.Haraya (1999). "Kagaku Kogaku Ronbunshu, 25,367-373 2. Mano,H.,H.Hasegawa(2000). SEI Technical Letter 157, 22-26. 3. Kagaku Kougaku Kyoukai ed. (1988); Kagaku Kougaku Benran, 5th Ed.,Maruzen, Tokyo, Japan. 4. Kagaku Kougaku Kyoukai ed. (1968); Kagaku Kougaku Benran, 3th ed., Maruzen, Tokyo, Japan. 5. Nihon Kikaigakkai ed. (1991); Kikai Kougaku Benran, 5th Ed.,Maruzen, Tokyo, Japan.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1563

PSA P R O C E S S E S FOR R E C O V E R Y OF C A R B O N DIOXIDE

Jong-Nam Kim, Jong-Ho Park, Hee-Tae Beum, Sang-Sup Han, and Soon-Haeng Cho Korea Institute of Energy Research 71-2, Jangdong, Yusungku, Taejon, Korea

ABSTRACT PSA processes are studied for the recovery of carbon dioxide from various sources including steel mill offgas, petrochemical waste gas and combustion flue gas. The 1-stage PSA process is applied when the concentration of CO2 is higher than 25% like the steel mill off-gas and petrochemical waste gas. The 1-stage PSA process generally consists of four steps; pressurization with feed gas, adsorption, high pressure rinse with product CO2, and evacuation. Especially, when the feed contains about 25% COz, performing low pressure purge and recycling the effluent to the feed inlet greatly enhanced the process performance. In a typical run, a high purity CO2 of 99% is produced with recovery of 80% from feed gas containing 25% CO2. The 2-stage PSA process is more efficient than 1-stage PSA when the concentration of CO2 is low. At the first stage of the 2-stage PSA, CO2 is concentrated to 40-60% from the feed of less than 15% CO2 and then concentrated to 99%, at the second stage. With the 2-stage PSA process composed of 2-bed for each stage, 99% CO2 is recovered with 80% recovery from the feed containing 11% CO2. INTRODUCTION Carbon dioxide is considered as the main cause of global warming. For the sustainable development, efforts are being undertaken to mitigate the emission of CO2 to the atmosphere. Capture and storage of CO2 to the ocean or depleted oil field is considered as one of the possible options for the CO2 abatement. To be viable the option, the cost for the capture of CO2 from its source should be as small as possible. The pressure swing adsorption (PSA) process is a highly efficient gas separation process and also applied for the removal of carbon dioxide from various gas mixtures [1 ]. The configuration of the PSA process for CO2 recovery varies according to the CO2 concentration of the feed. When the concentration of CO2 is higher than 20%, a 1-stage PSA process is enough to produce 99%-CO2 with high recovery [2]. On the other hand, when the concentration of CO2 is lower than 15%, it is difficult to recover CO2 with high purity and recovery using the 1-stage PSA process. In this case, a 2-stage PSA process is applied [3]. In this study, the performance of the PSA processes for the recovery of CO2 from steel mill off-gas, petrochemical waste gas, and combustion flue gas are investigated. The 2-stage PSA process is applied for the recovery of CO2 from combustion flue gas and the 1-stage PSA process is applied for the steel mill off-gas and petrochemical waste gas. A new 1stage PSA cycle giving high recovery and productivity is proposed. And, the power consumption of the 2stage PSA process is analyzed with a mathematical model. PROCESS CONFIGURATION

1-stage PSA process A schematic diagram of the 1-stage PSA process is shown in figure 1. The 1-stage PSA is composed of three adsorption beds filled with zeolite-X and operated between adsorption pressure of about 850mmHg and final evacuation pressure of 60-80mmHg. CO2 PSA cycle generally consists of four steps; pressurization with

1564 feed gas, adsorption, high pressure rinse with product CO2, and evacuation. Since the adsorption isotherm curve of CO/on zeolite-X increases sharply at the low adsorption pressure, much of CO2 is still adsorbed at the final evacuation pressure. In order to recover this remained CO2 on the adsorbent, the low-pressure purge step after evacuation step was introduced by flowing a part of effluent gas of adsorption step, and the effluent gas of purge step is used to the feed gas at the latter part of the adsorption step. The conventional cycle operated without low pressure purge and the new cycle operated with low pressure purge are shown in figure 2. ~aast~i~ ~ ,,

Feed

~

Product

Figure 1: Schematic diagram of the 1-stage PSA process

W W

W

W

GU

F

W

W

W

w feed gas product W ,, waste H - holder PR ,, pressurization step A D ,, adsorption step C B = cocur~nt blowdown step RS ,, high pressure rinse step with product gas DE " desorption step WPR - countercur~nt pressurization step with waste gas LPF - adsorption step with the effluent gas of low pressure purge step LP ,, low pressure purge step with the effluent gas of adsorption step F " p z

w

w

F

~"

[

_.3k__ p W

W

Figure 2" Cycle sequence of the 1-stage PSA process

2-stage PSA process When the concentration of CO2 is lower than 15%, like the combustion flue gas, it is difficult to recover carbon dioxide with high recovery using the 1-stage PSA process. In this case, the 2-stage PSA process is more efficient than the 1-stage PSA process in terms of the recovery and power consumption. A schematic diagram of the 2-stage PSA process is shown in figure 3. A scrubber, dryer, and 2-stage PSA process comprise three main parts of the process. The scrubber plays the role to remove dust and part of SO2 and to cool down the flue gas to ambient temperature. The dryer reduces the water content of the flue gas before it enters the main 2-stage PSA process. And then, the dried stack gas enters the 2-stage PSA process, where CO2 is enriched over 99%. The two adsorbers of the dryer packed with activated alumina periodically undergo the adsorption, depressurization, hot gas purge, cooling, and feed pressurization steps. Dried flue gas is then fed to the first

1565 stage PSA process, where carbon dioxide is concentrated to 40-60%. The cycle sequence of the first stage is the adsorption, pressure equalization, blowdown, low pressure purge, pressure equalization, and feed pressurization steps. Part of the effluent of the adsorption step is used to purge the adsorber in the low pressure purge step and the rest of the effluent is used to regenerate the dryer. CO2 -rich stream obtained in the first stage PSA process is further processed in the second stage PSA process and CO2 is concentrated over 99%. CO2 flowing out of the adsorber is recycled to the inlet of the scrubber. The cycle sequence of the second stage PSA process is almost the same as that of the first stage PSA process. The only difference is that the second stage is operated without the low pressure purge step.

Flue

L(~" I

gas

"-"

1 St-stage PSA

2"d.stage PSA

I

Stack Figure 3: Schematic diagram of the 2-stage PSA process. RESULTS AND DISCUSSION Figure 4 shows the process performance of the 1-stage PSA process for recovery of carbon dioxide from the steel mill off-gas, which contains 25%-CO2. Since the concentration of CO2 was high so that the 1-stage PSA process was applied. When the process is operated without the low pressure purge, the recovery at 99% CO2 is about 63%. However, when the process is operated with the low pressure purge and the effluent is recycled to feed inlet, the recovery at 99% CO2 is 80%. That is, by employing the purge step, the recovery was increased by 20%.

1.4

It30 4__.~ 'o. .

.~

,

==

12 " ~

8~

~limut

.?: ;E

90 o-'

....

\

•

(18

?

,o (16

80

,

50

60

~

,

70 nmlwy

L

80

,

A

90

,

04

I(30

[°/4

Figure 4: Performance of the 1-stage PSA process for recovery of CO2 from steel mill off-gas Figure 5 shows the process performance of the 1-stage PSA process for recovery of carbon dioxide from the petrochemical waste gas, which contains 79%-CO2. In this case, it is possible to recover CO2 of 99% with high recovery without the low pressure purge step. As shown in figure 5, the recovery of the process at 99% CO2 is 96%. Figure 6 shows the performance of the 2-stage PSA process for recovery of carbon dioxide from the

1566 combustion flue gas, which contains 11%-CO2. Lines of figure represent the simulation results. The power consumption of the process was estimated with a mathematical model, which accounts for the power consumption of the blower installed in front of the scrubber and two vacuum pumps of the main PSA process. The power consumption was calculated from the following equation for adiabatic compression of gas. 5

ICO

o..

Q,

49 48 ' ~

95

44

91

%

95

4.3

97 98

99

IC0

~ P 4

Figure 5: Performance of the 1-stage PSA process for recovery of CO2 from petrochemical waste gas

0.29 ~E 0.29

................ •

/

/" ";: ....

0.28

............:

/ /

.= ~.

0.28 0.27~

/ 7O 60

. 70

.

. 8O

. 90

.

. 100

2ncls~c aclso~on s ~ ~

110

120

0.27 130

(s)

Figure 6" Performance of 2-stage PSA process with the second stage adsorption step time (symbols • experiment, lines: simulations)

k-I W~-hRgTl k-~ ICpal-i-1 1

(I)

CO2 over 99% is produced when the adsorption step time of the second stage is 120s. As the second stage adsorption step time increases, the purity of CO2 and the power consumption are increased. According to the simulation, 0.28 kWh is consumed for the production of 1Nm 3 of 99%-CO2. With the increase of the adsorption step time, the amount of carbon dioxide recycled to the first stage is increased, which increases the power consumption of the first stage vacuum pump. As a consequence, the power consumption of the process is increased with the increase of the second stage adsorption step time. The power consumption of the process given in figure 6 does not account for the efficiencies of the vacuum pump and blower. Therefore, the actual power consumption of the process may be higher than the value given above.

REFERENCES Sircar, S. (1988) Sep. Sci. Technol., 23, 519 Chue, K.T., Kim, J.N., Cho, S.H. and Yang, R.T. (1995) Ind. Eng. Chem. Res., 34, 591 Ishibashi, M., Ota, H., Akutsu, N. And Umeda, S., Tajika, M., Izumi, J., Yasutake, A., Kabata, T. and Kageyama, Y. (1996) Energy Convers. Mgmt, 1996, 37, 929-933

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1567

NUMERICAL STUDY OF BOILER RETROFITTING TO USE RECIRCULATED FLUE GASES WITH 02 INJECTION L.M.R. Coelhol, J.L.T., Azevedo 2 and M.G. Carvalho 2 1 Esc. Sup. Tecnologia de Setfibal, Instituto Politrcnico de Setfibal, Estefanilha, 2914-508, Setfibal, Portugal 2 Mechanical Eng. Dep., Instituto Superior Tecnico,1049-001, Lisboa, Portugal

ABSTRACT The paper presents a numerical study on the adaptations required to convert a pulverised coal fired boiler from conventional air firing to flue gas recirculation with oxygen injection. A boiler performance model is used to determine the recirculation flow rate that produces equilibrium between the radiation and convection sections of the boiler and the boiler performance for those conditions is assessed. A Computational Fluid Dynamics (CFD) based numerical model is also used to evaluate the modifications in the radiation characteristics of the furnace and results are also presented for predicted NOx emissions.

INTRODUCTION

Coal is the more abundant fossil fuel but at the same time presents the lower H/C ratio, implying larger C02 emissions when used in conventional air firing fumaces. The removal of the CO2 from the combustion products of conventional fired power stations is not economically attractive due to its low concentration in the flue gases. The use of flue gas recirculation with oxygen injection, allows for the increase of CO2 concentration in the flue gases, reducing the gas flow rate to be treated. The objective of the paper is to present how. the use of flue gas recirculation and oxygen injection (FGROI) affects the furnace and boiler performance. The use of pure oxygen for combustion increase flame temperature, due to the absence of the inert nitrogen from air, to unacceptable levels for use in boilers. To lower temperature, recirculated flue gases (RFG) can be used as inert, increasing the flue gas flow rate. The recirculation ratio to produce adiabatic combustion temperature and gas flow rate similar to the case of air firing is not similar, requiting compromises to be made when retrofitting a boiler from air to FGROI firing. The combustion process with FGROI is different from air firing, changing the flame characteristics as discussed extensively [1,2] based on experimental data obtained in three independent laboratories involving different scales ( I C S T M - 150 kW, I F R F - 2.5 MW and R R - N E I - 35 MW). Difficulties in achieving good sealing increased with furnace scale, allowing CO2 concentrations to reach 91.4% for the 2.5 MW scale, but for the larger scale CO2 concentration was only increased to about 26% due to air in-leakage. The higher CO2 content in the flue gases changes the radiation properties and thus the incident heat flux distribution to the boiler furnace walls. NOx formation in pulverised coal combustion is mainly a result from the coal nitrogen and therefore the use of FGROI will form NOx, which may be removed from the flue gases as the CO2 for disposal. The next section presents a study on the overall boiler performance considering the boiler furnace and the tube bank boiler section. The following section presents results from the application of a CFD numerical model to analyse in further detail the heat transfer in the furnace and the NOx formation.

1568 BOILER P E R F O R M A N C E

A boiler performance model, based on simple heat transfer models, mass and energy balances was applied and adjusted for a pulverised coal fired boiler [3]. Heat transfer in the furnace occurs mainly by radiation, while in the tube bank boiler section, convection is predominant. To simulate the use of FGROI, mass balances were established as a function of the recirculation ratio (R) and considering a fraction (F) of air ingress in the boiler, according to figure l a. Figure l b presents the variation of some calculated parameters with the recirculation ratio, keeping the excess oxygen in the flue gases at a constant value and assuming no air ingress (F=0). The values of the parameters for air firing are included in brackets for comparison. CooJ

~" O0

Iz kg/s I Air Ingress

Ai=FY

C02 feed to pdmarv Oxygen or air feed Z

/, •

Comb . . . .

50

Combustion ] t

,[Boiler

I pr°ducts Y

Recirculated gas

--

~" Rueg

....

~I-R)II÷F}

~.~ "~" -~

.E

-

00

300C

~

250C -

50 00

L

200C

150C I l~

60%

A

d i ; 65%

a

b

: 70%

Recirculation

Temp. (2300)]l , -- 100C 75% 80% ratio (R)

Figure 1: Schematic of the gas flow rates for a unitary coal flow rate and variation of parameters with R. Figure l b shows the decrease of the adiabatic combustion temperature increasing the recirculation ratio, achieving a value similar to air firing for R=69%. Due to the modification of the flue gas composition, the mass and normal (1 bar, 0°C) volumetric flow rate are not directly proportional so the variation of both is indicated in figure lb, showing similar values than for air firing respectively for R=71 and 74%. The mass flow rate and specific heat capacity influence the heat balances, while the volumetric flow rate and temperature influence the convection heat transfer coefficients but not linearly. The variation of a convection heat transfer coefficient for fixed temperature (1000K) is also represented in Figure 1b, showing that similar values to air firing are obtained when R=68%. As can be seen from the parameters illustrated similar conditions to air firing are obtained for recirculation ratios between 68 to 71% from this simplified analysis. Some important factors to be considered for the FGROI technology are the level of air ingress into the boiler and the coal transport to the burners. The recirculated flue gases contain water vapour that may cause problems in coal mills, so one alternative is to use the dry recirculated flue gases, increasing the effective recirculation ratio by about 4% to achieve similar conditions. The elimination of SO2 in the flue gases for use in the coal transport system has also to be considered once it may form sulphuric acid. Air ingress in the boiler has a direct effect on the CO2 concentration in the flue gases and has to be minimised. A 5% level of air in leakage (F=5%) reduces the CO2 concentration in dry basis from 94% to 77% or 95% to 85%, when using respectively RFG and CO2 to transport the coal. The boiler performance model was used to calculate the heat transferred in both the furnace and tubes bank boiler section and the steam temperature for the main heat exchangers for the specific boiler. The steam flow rate is found to decrease when increasing the recirculation ratio but at the same time the capacity to superheat and reheat the steam is increased. The superheated steam temperature is controlled by the use of water injection to allow for variations in heat transfer due to slagging and fouling. From the calculations performed it was found that the normal steam temperature could be achieved for recirculation ratios larger than 70% but the steam flow rate is about 5% lower than in the case of air firing. In order to guarantee the steam temperature the recirculation ratio has to be increased by about 1% to obtain a water injection flow rate similar to the case of air firing. To retrofit an existing air fired boiler for FGROI keeping its capacity, the area of the superheaters section have to be increased. The boiler performance model is a suitable tool to perform such calculations.

FURNACE P E R F O R M A N C E For the furnace a further detailed study is presented based on a CFD based numerical model simulating the flow,

1569 combustion and heat transfer [4,5]. Some adaptations were performed on the CFD model to handle any specified composition for the inlet flows. The discrete heat transfer model, including isotropic scattering, is used to calculate radiation. The wide band model calculates the gas phase radiation properties, while for particles results from the application of Mie theory were used. Due to the furnace symmetry half of the furnace was simulated and three recirculation ratios were considered in the range of similar adiabatic temperature and mass flow rate. Table 1 presents the calculated absorbed heat to the different boiler walls compared with the values calculated for air firing. A similar total value was obtained for the lower recirculation ratio (R=67.9%) which is lower than the recirculation ratio (69.3%) leading to a similar adiabatic flame temperature mentioned in Figure 1. It should be noted however that the distribution of absorbed heat is affected as can be seen from the larger values for the back wall and lower for the front wall. The effect on the distribution of radiative absorbed heat fluxes on the furnace walls can observed in Figure 2. This is a result of the larger temperature observed close to the front wall for air firing. For the case of using recirculated flue gas with oxygen injection the temperature distribution is smoother and the flux to the front wall is lower, increasing the flux to the back wall. TABLE 1 DISTRIBUTION OF RADIATIVE ABSORBED HEAT BY THE WALLS (MW).

Wall \Recirculation (%) Front Back Side Nose and ash pit Total

Air 30.1 41.0 55.4 4.7 131.2

67.9 25.8 45.5 53.7 6.6 131.6

69.3 19.3 43.5 51.5 6.3 125.5

jiiii...............

cJ

73.5 ,. 19.3 36.0 43.1 5.3 103.7

Front Side wall Back

:

:

ir firing

iij

1.oI1~ ['-7] 5.0xlO!

:

Jili i~i~

E; ~

1.0~10~

~

~

W

1.6xlO2 1"8x102 2"0x102 2"4x102

:::::..

~

i~

FGROI

Figure 2: Distribution of radiative absorbed heat fluxes on the boiler walls. Figure 3 presents the 02 and CO concentration distribution in a vertical plane across the burners, showing higher values for both species when using FGROI with R=67.9%. The higher 02 concentration is a natural consequence of the lower 02 concentration in the oxidant inlets. Local higher values of CO concentration are observed in the case of FGROI but due to the shorter flames similar values of the CO concentration are observed close to the back wall as in the case of air firing. This analysis is important for the protection of the furnace walls from corrosion. The NO× post-processor is based on a competitive reaction global model where nitrogen-containing species released from the coal (HCN) may oxidise producing NO or may reduce NO to molecular nitrogen. The thermal NO mechanism was included as it contributes to NO formation in the case of air firing, while it may reduce NO for the FGROI case. For the air firing case the calculated NO concentration in the flue gases is 731 ppm a value close to the measured value (745ppm). For the calculations performed for the FGROI case, NO and N2 were considered at the inlet from the outlet gas composition. This leads to larger levels of NO in the furnace for FGROI and therefore a higher NO flow at the furnace outlet. The flue gas however corresponds only to the nonrecirculated flow (about 30%) decreasing the total NO emitted from the system. The calculated values are reported in Table 2, showing that the NO formed by energy on coal is for FGROI about 60% lower than in the case of air firing.

1570 "

"

Air ~rinc~

: :iiii

Mass fraction

02 rr~ 0.001 0.01 ~ 0.02 0.03 0.05

CO 5.0x10 -6 1.0xl0 "s 5.0xlO "s 1.0xl0 -4 5.0x10 -4

!~

5.0x10 3 1.0xl0 "2 5.0x10 "2

_.

0.10 0.15 0.20

Figure 3: Distribution of 02 and CO concentration in a vertical plane crossing the central burners. TABLE 2 CALCULATED NO FORMATION FOR AIR AND FGROI

NO at boiler outlet (k~s) NO for flue gas treatment unit (kg/s) NO2 in (g/GJ)

Air 0.0984 0.0984 422.

67.9 0.121 0.0388 167.

69.3 0.128 0.0394 169.

73.5 0.158 0.0396 170.

CONCLUSIONS The adaptation of a conventional boiler to FGROI require an increase of the superheating section, otherwise its capacity is reduced by about 5%. The recirculation ratio to produce similar conditions to air firing in the boiler is about 71%, considering the superheating section adaptations and air leakage in the boiler. A parametric study was carried out using the tridimensional model to determine the recirculation ratio that provides a similar heat transfer to the boiler fumace walls as in the case of air firing, to minimise the implications on the boiler geometry. This recirculation ratio was found to be 67.9% for the boiler analysed, which is lower than the recirculation ratio (69.3%) leading to a similar adiabatic flame temperature. For an equivalent adiabatic temperature of the gas, the heat transferred to the boiler walls is reduced as a result of the higher absorption coefficient of the combustion products, which leads to larger temperature uniformity. The predicted combustion behaviour in the furnace leads to similar levels of carbon monoxide concentration close to the boiler walls suggesting that the use of recirculated flue gases with oxygen provide an equivalent protection as in the case of air firing. The calculated NO formation, shows that its concentration is larger due to the recirculation effect, but the flue gas flow to be treated corresponds to a 60% lower quantity of NO when expressed on a specific basis of the coal feed rate. ACKNOWLEDGEMENTS

This work was performed in the frame of the European Union sponsored project JOUF2-CT92-0220. REFERENCES

Allen, G. (1995) Coal combustion in advanced bumers for minimal emissions and carbon dioxide reduction technologies, Vol I I - Powder coal combustion projects, European Union Report 17524EN. Woycenko, D.M., van de Kamp, W.L. and Roberts, P.A. Combustion of pulverised coal in a mixture of oxygen and recycled flue gas, Vol I I - Powder coal combustion projects, EUR 17524EN. Azevedo, J.L.T., Carnall, F. and Carvalho, M.G. (1996), In: New Developments in Heat Exchangers, Gordon and Breach, pp 117-129. Coelho, L.M.R., Azevedo, J.L.T., and Carvalho, M.G. (1995), proceedings of Numerical Simulation

and Comparison of NOx Emissions from a Low NOx Front Wall Fired Boiler for Different Operating Condition, 3rd Int. Symp. on Coal Combustion, Beijing, China. Azevedo, J.L.T. and Carvalho, M.G. (1999), In: Combustion Technologies for a Clean Environment, Vol. 2, Gordon and Breach Publishers, pp 111-122.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1571

P R E C O M B U S T I O N DECARBONISATION FOR P O W E R GENERATION P. Freund and M.R.Haines IEA Greenhouse Gas R & D Programme Cheltenham, GL52 7RZ, U.K.

ABSTRACT

Removal of carbon before combustion, by making a low-carbon fuel such as hydrogen or a hydrogen-rich mixture, is an alternative to the established process route of capturing CO2 after combustion. This concept is referred to as pre-combustion decarbonisation. If hydrogen production is fully integrated with power generation, pre-combustion decarbonisation presents a promising alternative to post-combustion capture of CO2. The PCDC project has been established to investigate the optimisation of this concept, coupled with cost minimisation as this may offer further improvement in the economics of this route. This is necessary preparation for the following step in technical and commercial risk reduction, the design of a demonstration plant. With this in mind the IEA Greenhouse Gas R&D Programme and the IEA Hydrogen Agreement invite potential stakeholders in this technology to participate in the PCDC project to prepare for a demonstration project.

INTRODUCTION

Removal of carbon before combustion, by making a low--carbon fuel such as hydrogen or a hydrogen-rich mixture, is an alternative to the established process route of capturing CO2 after combustion. This concept is referred to as pre-combustion decarbonisation (PCDC). If hydrogen production is fully integrated with power generation, pre-combustion decarbonisation presents a promising alternative to post-combustion capture of CO2. Furthermore, from a strategic point of view, PCDC represents a potentially attractive route to sustaining economic exploitation of fossil fuels and is a first step on the evolving pathway to an energy economy based on hydrogen.

PROJECT PROPOSAL

This project aims to develop a "standard" engineering design package for a fully integrated hydrogen plant with CO2 extraction for sequestration and producing sufficient hydrogen for a 400MW combined cycle power generation plant. By standard is understood a fully integrated power plant, based on best available technology, that could be offered as a basic package for installation in multiple locations. The project will include cost minimisation processes and will produce a design package with sufficient detail for sanction of a demonstration plant. By increasing the degree of engineering definition to this level and optimising the integration of the hydrogen production and power cycle the cost of COa capture is expected to reduce by 20-30% based on scoping studies published to date. Experience with design of IGCC systems suggests that optimal integration of process and power cycle blocks can produce economic improvements of this magnitude. Further substantial cost savings can be expected through development of standardised modules for use in subsequent projects.

1572 PROJECT SCOPE AND TIMING The project will be executed in 4 steps. The first is a review of process options which will result in a shortlist of preferred processes. The second step will be to prepare a plant technical specification defining a single process scheme and the preferred technology. Funding and expertise for this initial work has been made available by the CO2 Capture Project (CCP), a consortium of oil industry participants which is funding research and development of carbon dioxide capture and sequestration technology. The third step is formation of a Joint Industry Project (JIP) and obtaining funding for the fourth step which is the preparation of a front end engineering design (FEED) and cost estimates suitable for seeking sanction for a demonstration project. Progress

l Process

options review Shortlist

JIP

Plant technical specification

formation

Final selection

Aligned members with funding

FEED Preparation Design and cost estimate

Figure 1: PCDC Phase one - main steps IMPLEMENTATION OF DEMONSTRATION It is expected that more pioneering geological sequestration projects will be implemented in the next decade. Once this practice gains acceptance there will be a window of opportunity for demonstration of large scale CO2 capture by the power generation industry. In the project sanction phase it is envisaged that a consortium of partners seek a favourable financing package for the demonstration and attractive terms for sale of the power and CO2 credits. Further tailoring of the design for the selected site will be required and commercial agreements to build and operate a profitable demonstration will be set up. The project will be in competition with other CO2 abatement schemes but has huge potential, strategic alignment with the hydrogen economy and a promising relative cost advantage. It is thus considered to be well placed to succeed. The likely time for start up will be around the end of the decade. The final phase would be the construction of the plant and its day to day management with comprehensive performance monitoring. In this final phase options to extend the project to foster elements of the hydrogen energy economy would also be sought out and implemented. PROCESS OPTIONS The PCDC process consists of 2 parts - the hydrogen production process block and the power cycle block. These processes have been demonstrated separately but there has yet to be a demonstration of an integrated combination. A number of process options for the hydrogen production have been studied [ 1] and generally the choice of synthesis gas production technology appears to be a marginal decision with the eventual choice being determined by system integration issues. The main process contenders are steam reforming of natural gas, partial oxidation with pure oxygen and catalytic partial oxidation with air. Combinations are also possible. CO2 extraction from the syngas would be by conventional amine scrubbing.

1573

Design Financing

PCDC phase 2

Execution

c) n•

~1-]1Weybur s,

PCDC phase 3

More pioneering geological 002 sequestration projects

s

1995-2000

2001-2005

Geological002 sequestration routine and accepted practice

@

2006-2010

2011-2015

Figure 2: PCDC project overall timeline

The main areas to be considered for process integration are: air supplies to gas turbine and partial oxidation, steam circuits in the steam power cycle/reforming process, heat flows in the waste and process heat systems. In addition there is huge potential for integration of utility and auxiliary systems. PARTICIPANTS A wide range of participants are expected to have interest in a PCDC demonstration. These include: Oil and Gas companies Power generation and distribution companies, General utility companies Process Licensors and Engineering contractors Industrial gas companies Governments International banks and funding agencies Energy research institutions NGO's Universities Carbon abatement traders The benefits are expected to include: Preferential access to design and operational experience Sharing of development costs Access to "green" power Potential access to Carbon certificates Establishment of track record in capture and sequestration technology

1574 HYDROGEN ENERGY The PCDC process will consist of a hydrogen manufacturing plant closely integrated with its associated power plant. The unit will produce low quality hydrogen since the gas turbine of the CCGT unit does not require high purity. The plant will however present options for further testing hydrogen as an energy source. For example it could provide hydrogen for blending with natural gas or to consumers requiring hydrogen for fuel cells. The plant would also be in a position to consume hydrogen from renewable hydrogen sources. If such "green" alternatives do not arise the plant could supply hydrogen, syngas or CO2 to industrial consumers. These options increase the long term attractiveness of the project. The location of the PCDC demonstration should take into account the central position the unit could have in early development of a hydrogen energy infra-structure. Choice of a site where other hydrogen consumers are near or with easy access to alternative "green" energy markets would be preferred. A demonstration power plant of the size envisioned is expected to have a useful life of at least 10 years and possibly much longer. It should thus be viewed in the context of likely developments through to at least 2030.

i p , ~ . p = = = i = = . . = = , ,..=== ,

Primary product Alternative Industrialproducts "Green" options

Hydrogen to NG

"Green" hydrogen

Renewable hydrogen

PCDC400MW

CO 2 to industry

~

Green Electricity

Hydrogen to industry

Sequestered CO 2

Syngas to industry

Figure 3: Alternative applications for PCDC project products FURTHER INFORMATION For further information please contact Mr M.R.Haines at the IEA Greenhouse Gas R&D programme tel +44 (0) 1242 680753, e-mail [email protected]

REFERENCES Audus H, Kaarstad O, Skinner G. (1998) C02 capture by pre-combustion decarbonisation of natural gas. Green house gas control technologies, Eliasson B, Riemer P, Wokaun O, (eds) (Pergamon) pp 557-562

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1575

CHALLENGES OF RECOMMISSIONING A CO2 CAPTURE PILOT PLANT IN SASKATCHEWAN, CANADA Dave Skoropad l, Don Gelowitz l, Raphael Idem2, Bob Stobbs 3, John Barrie 4 1 Process Combustion Systems (2000) Inc. Calgary, Alberta, Canada, T2G 5M4 2 Faculty of Engineering, University of Regina, Regina, Saskatchewan, Canada, $4S 0A2 3 SaskPower Corporation, Regina, Saskatchewan, Canada, S4P 0S 1 4 Fluor Canada, Calgary, Alberta, Canada, T2X 3R4

ABSTRACT

The University of Regina has successfully re-commissioned a CO2 Extraction Pilot Plant at SaskPower's 875 MW Boundary Dam Power Station in southern Saskatchewan, Canada. This pilot plant had been idle for 12 years in significant ambient temperature extremes adjacent to an existing lignite coal-fired power plant. The pilot plant includes a boiler, pumps, blowers, towers, and control equipment, which needed to be inspected and brought to "as new" conditions. The pilot plant, part of the University of Regina's International Test Centre for CO2 Capture (ITC), is being used for technology demonstration involving a series of tests of newly developed amine solvents for CO2 capture at coal-fired power plants under extremes of climate. Significant challenges and delays were experienced in successfully re-commissioning this pilot plant, which currently is the only one of an appropriate size to develop the engineering data required for design of commercial facilities. The paper discusses issues related to the mechanical, electrical, control and data acquisition equipment and how this equipment was modified or replaced to meet the testing schedule and customer requirements.

INTRODUCTION

SaskPower owns and operates a number of generating facilities in the province of Saskatchewan, Canada. Major facilities include three (3) large lignite coal-fired power stations located close to the southern boundary of the province and the United States border. One of these stations, the Boundary Dam Power Station (BDPS) near the city of Estevan, was selected as a site for the CO2 capture pilot plant, since it was in close proximity to oil fields which could, in later years, utilize CO2 to increase oil recovery as the field's production declined. Saskatchewan is subject to extremes of climate, with temperatures dropping to-30°C and colder in winter and rising to +35°C in the summer, providing a test site with great climatic variability. The Boundary Dam CO2 Pilot Plant was first constructed as a joint venture project with SaskPower, govemment and three oil companies in the summer of 1987. It comprised a 152 mm (6 in) flue gas line tied into the stack on unit #6 of BDPS, and individual skid units for SO2 removal, CO2 recovery and heating, as well as a combined office/laboratory/warehouse skid unit. Tie-ins for cooling water, air, natural gas, and make-up water supply from BDPS to the pilot plant were also provided. The facility was designed to process 14 x 103 m3/day (500 mscfd) of lignite-fired power plant flue gas from which 450 ppm of SO2 was removed and 4 tonnes per day of CO2 captured. After commissioning, testing began using proprietary solvents

1576 provided by two major licensors. Although the facility was constructed to oil field standards, specific design conditions and quality of the feed gas caused the plant to be plagued with operational problems throughout the testing period. The major sources of these problems included excessive flyash entrainment that plugged various pieces of equipment and piping, as well as corrosion that resulted in continual equipment failure. The test program ended in October of 1988 after the impellor on the feed gas blower failed, at which point it was felt that sufficient data had been collected. The vessels, tanks, and other related equipment were then drained and the facility turned over to SaskPower. The greenhouse gas (GHG) research team at the University of Regina has been working on various aspects of CO2 capture issues for over a decade, and have taken advantage of their expertise to establish the International Test Centre for CO2 Capture (ITC), which has the mandate to explore and develop new technologies for CO2 capture. A research program has been designed that aims to reduce the cost of CO2 capture in the short to medium term, while attempting to find "novel" approaches that can significantly reduce the cost in the long term. This program consists of two distinct components: Innovative Research and Development (IRD) and Technology Development and Demonstration (TDD). The IRD component focuses on fundamental research and laboratory scale studies on high efficiency CO2 capture technologies from industrial gas streams at "low pressure" (e.g. coal-fired combustion flue gases) as well as "high pressures" (e.g. gas streams from IGCC, O2-CO2 recycle combustion processes). The University of Regina identified the Boundary Dam CO2 Pilot Plant facility as an opportunity to implement research on the TDD component, which involves CO2 capture technology demonstration on a subcommercial scale using flue gases from a coal-fired power station. After being left idle for 12 years, the plant needed to be put back to an "as new" condition before it could be used for various demonstration tests. Re-commissioning began in the fall of 2000. This project has been made possible through the participation of Canadian governments (at Federal and Provincial levels), many industrial partners and non-governmental agencies, which constitute consortium members for the ITC. A subcontractor, Process Combustion Systems (2000) Inc., was hired to re-commission the CO2 capture skid. Fluor Corporation provided consulting services to assist the University of Regina in completing this pilot facility.

RE-COMMISSIONING DETAILS The challenges faced during re-commissioning of the Boundary Dam CO2 Pilot Plant not only involved repairs to equipment, but also addressed historical operating problems including technologically advanced upgrades to the process operating system. The major historical issue identified in the original testing was flyash entrainment in piping and equipment. Following a first phase of re-commissioning, the new testing program began in late summer of 2001. Although data could be collected, operational problems were revealed ranging from process control to equipment failures. Major problem areas included the existing blower design that gave rise to excessive vibration leading to failure, feed gas supply reliability, heat duty limitations, and the inability to utilize the original pneumatic instrumentation system to execute process control during unmanned hours. The challenges, and the way these were mitigated, are discussed below:

Flyash Pilot Plant shutdowns in 1987-88 were caused by flyash entrainment in blowers and equipment. It had not been possible to have a continuous run for a sufficiently long time without shutdown due to equipment blockages with flyash. In order to minimize or eliminate this problem, a baghouse was specified and purchased to replace the flyash water scrubber installed for the early tests. This baghouse provided additional backup to the existing electro-static precipitator (ESP) which is part of BDPS unit #6. Recent testing has confirmed that the baghouse functions effectively and was correctly specified.

Piping and Plant Reliability Approximately 76 m (250 ft) of new 152 mm (6 in) piping was installed between the pilot plant and stack #6 since the original piping had been removed. During the initial testing program, the feed gas supply from stack #6 became unreliable as the unit incurred operational problems resulting in frequent shutdowns subsequently forcing the pilot plant to shut down during Unit #6 repairs. To further ensure continuous runs so that data could be collected reliably, the project team approved the addition of a tie-in to Unit #5, should

1577 Unit #6 be shut down due to a planned or unplanned outage. It was also noted that the composition of flue gas from Unit #5 was more consistent than Unit #6. There were significant challenges in locating the new 203 mm (8 in) line to Unit #5 due to interference with the power plant's existing infrastructure resulting in a pipe length of approximately 98 m (320 ft) between stacks #5 and #6. In order to maintain a flue gas temperature above sulphur dew point during extreme ambient weather conditions, the lines were heat traced and insulated. Early indications are that the two lines have greatly increased the ability of the pilot plant to run continuously.

Control Systems and Wiring Most of the original control equipment was replaced or rebuilt. Due to the age of the control equipment and the uncertainty related to the old electrical drawings, it was decided to replace or rebuild most of the electrical equipment. This included the alarm control panel, data logger, gas chromatograph, SO2/O2 analyzer, and pH/conductivity analyzers, all of which were obsolete. They were replaced with modem and more effective models. The relay logic control panel was replaced with a programmable logic control system (PLC) in order to allow for more flexibility in the control strategy. The data logger was upgraded to a personal computer (PC) including a panel containing the temperature and analog input cards. The PC was also configured to illustrate the process over several screen layouts indicating specific parameters such as pressures and temperatures. This information is also collected in a table for ease of retrieving historical data. Previously, the gas chromatograph (GC) used for determining CO2 concentrations was manually operated with results presented on a printout. This unit was replaced with a continuous CO2 analyzer utilizing a nondispersive infrared (NDIR) detector to determine the CO2 concentration. The CO2 analyzer also features an output signal for input to the data logger. The SO2/O2 analyzer was replaced with a small wall mounted unit that also allows signal input into the data logger. Finally, the pH and conductivity analyzers used in the SO2 removal process were upgraded to the latest technology. The new data acquisition system installed has process control capability. However, in order to use this system, analog output cards and I/P controllers are required and were installed. Additionally, the pneumatic level controllers were replaced with electronic level controllers. Mass flow meters were installed to replace orifice meters on both the amine circulation and absorber wash section in order to account for variations in flowing liquid densities. These units also provide a signal input into the computer. Additional CO2 analyzers were purchased and solenoid valves were installed along the length of the absorber column in order to allow automatic sampling of gas across the column for mass balance data and mass transfer calculations. Finally, the computer was reprogrammed to accommodate the process control through setpoints and loop control parameters. All necessary flowrates, as measured by orifice plates, and heat duties, are calculated by the program and are stored in the historical data file. A corrosometer unit, used to collect corrosion data at various points throughout the facility, has been linked to the data logger for real time and historical data collection.

Problem Equipment Most of the other equipment such as pumps and blowers were rebuilt, instrumentation was checked and recalibrated, and process piping was inspected and repaired as required. Significant problems were noted when the plant was first re-commissioned. Blowers and pumps were found to vibrate excessively leading to a forced shutdown. The original blower configuration included one single stage blower for the inlet gas and one single stage booster blower after the SO2 removal unit. The design of these blowers each require a large diameter impeller operating at high RPM in order to meet flow and pressure requirements. Operating these units at high RPM resulted in excessive vibration problems. An attempt was made to replace the shaft and impeller on the absorber feed gas blower with a new dynamically balanced unit. This lasted for a short period of time until vibration caused continual bearing failures. It was ultimately decided to replace both blowers with one multi-stage blower, which has since been working well within acceptable vibration limits. One of the existing pumps originally had an incorrectly specified impeller material composition. This impeller was severely corroded. Also, due to the historical mechanical seal problems with this pump, it was considered to be cost effective to replace the pump with an all stainless steel construction, multi-stage unit. After the upgrade of the various items of equipment, the absorber and stripper columns were removed, inspected, and packing replaced to the specifications provided by Fluor as per its testing program. Once the columns were back in place, commissioning commenced with an acid wash followed by charging the system with amine.

1578 The facility is located next to a coal unloading facility where trucks continually dump coal for power plant usage. Due to the prevailing wind, it is very challenging to keep the dust generated from the coal and the trucks operating on unpaved surfaces from covering both process and lab equipment. Cleaning is required on a continual basis.

Heat Duty Reboiler heat duty requirements also became an issue both in heat medium control and insufficient heat capacity. The heat capacity constraints became evident in the winter months when much of the heat provided by the main boiler was used up in building heat and heat tracing thus not allowing sufficient heat for the reboiler at high heat duty requirements. Additionally, the age of the boiler control system did not allow sufficient modulation of the burner control. Due to the distance between the boiler and reboiler, the on-off cycling of the boiler allowed for significant temperature variation causing a heat fluctuation in the regenerator section. This cycling resulted in boiler glycol leaks around the tube sheet due to the continued expansion and contraction between the tube and sheet. The reboiler heat duty problem was resolved by upgrading the boiler control to a full modulating control system and by increasing the pump size to increase the circulation rate. It is expected that this will also eliminate the tube sheet leakage problem.

Skid Operation The SO2 removal skid and the CO2 capture skid units both operated independently of each other. This posed problems in that the CO2 skid did not know if the SO2 skid was in an alarm state or vise versa, thus causing continued operation of one skid without the other. This has been mitigated by upgrading the SO2 removal unit control panel with a PLC and linking the alarm outputs to the main PLC.

RELATED ISSUES Other indirect issues pertain to manpower and physical location. Locating, training, and retaining the manpower necessary to commit to and deal with the operating issues has been a challenge. Currently, the facility employs two operating personnel, both of whom are expected to be capable of conducting the testing requirements and to maintain the facility in an operating status. The other issue is the location. SaskPower's Boundary Dam Power Station is located in a sparsely populated area of the Province. Consequently, it had not been easy to find skilled labor to operate the pilot plant. Although SaskPower's operating staff shared the new workload with their existing operational duties, it was still necessary to look for personnel who could remain at the facility for the full length of the testing runs.

CONCLUSION The conclusion is that it has been more cost effective to re-commission this facility rather than build a new one. Also, despite significant challenges, the Boundary Dam CO2 Pilot Plant is now operational. The major challenge related to flyash plugging has been resolved in the design of this plant. At present, baseline testing is ongoing using Fluor's Econamine FG SMsolvent and the facility will soon be available for testing of other solvents, packing and other plant configurations. Data collected in early spring of 2002 indicates that some additional instrumentation may be needed to obtain more meaningful data. Some inconsistencies recorded could be due to faulty instrumentation as well. An added benefit of this facility is the ability to transport it to another location if required in the future. Most of the units are skid mounted, which makes the plant easy to transport. The SO2 removal unit is skid mounted and set inside a building structure to avoid operational problems in winter. This building has the ability to be easily removed. This facility duplicates conditions existing in actual coal-fired power plants and is expected to give very meaningful data to researchers. At present, this pilot plant appears to be the only one of its type in the world that can be used for demonstrating a range of solvents, packing and equipment under severe environmental conditions, in an actual operating facility burning a very poor quality fuel with high ash and moisture content.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1579

NOVEL CO2 ABSORBENTS USING LITHIUM-CONTAINING OXIDES

Masahiro Kato 1, Kenji Essaki x, Sawako Yoshikawa 1, Kazuaki Nakagawal, and Hideo Uemoto2 1Power Supply Materials & Devices Laboratory Corporate Research & Development Center, Toshiba Corporation 1, Komukai Toshiba-cho, Saiwai-ku, Kawasaki, 212-8582, Japan 2Research & Development Center, Toshiba Ceramics Co., Ltd. 30, Soya, Hadano-shi, Kanagawa 257-8566, Japan

ABSTRACT Lithium-containing oxides have been developed for application as a series of novel CO2 absorbents. The absorption is ascribed to the mechanism whereby lithium oxide in the crystal structure reacts reversibly with CO2. Among these absorbents, lithium orthosilicate (Li4SiO4)reacts with CO2 at higher reaction rate at around 500°C. Furthermore, the emission was performed at a much lower temperature than that of CaO. This temperature enables Li4SiO4 to be used repeatedly in pure CO2. Moreover, the absorption also proceeds at ambient temperature in an atmospheric environment. This characteristic suggests numerous possible applications such as air cleaners or cartridges. In this study, CO2 absorption properties of lithium orthosilicate and its contemplated applications were investigated.

INTRODUCTION

From the viewpoint of preventing global wanning, there is a growing need to reduce the amount of emission of carbon dioxide (CO2). For that purpose, saving of energy, improvement of conversion efficiency, and development of altemative energy sources and separation of CO2 are promising countermeasures. Regarding separation of CO2, it is thought to be effective to remove CO2 fi'om the high-temperature fuel gas of power plants. However, most CO2 removal techniques have poor heat--tolerance. The authors [1] have developed a novel CO2 separation technique by employing the chemical reaction of lithium zirconate (Li2ZrO3)with CO2. In this method, lithium oxide (Li20) in Li2ZrO3 reacts with CO2 reversibly by the following reaction. ti2ZrO3 4- CO2 "--ti2CO3 -b ZrO2

(1)

This reaction immediately proceeds at around 450-700°C. Moreover, the products react and revert to Li2ZrO3at higher temperature, i.e. above 700°C. Certain candidate lithium-containing oxides, which react with CO2, were selected on the basis of thermodynamic stability. Among these absorbents, lithium orthosilicate [2] (Li4SiO4) is found to have the highest reactivity with CO2. The model of reaction between Li4SiO4 and CO2 is illustrated in Figure 1.

1580

~~~i~Absorption

Li4Si04 + C 0 2 ~

/

~

\

Li2Si03 + Li2C03

Figure 1: Reaction model of Li4SiO4 with CO2 Since Li4SiO4 is synthesized from silicon dioxide, Li4SiO4has lighter weights and lower costs. Furthermore, the absorption also proceeds at ambient temperature in an atmospheric environment [3]. In this study, CO2 absorption properties of lithium orthosilicate and its contemplated applications were investigated.

EXPERIMENTAL A LinSiO4 powder was prepared by the heat treatment of silicon dioxide and lithium carbonate. In the case of absorption at high temperature, the absorption and emission of CO2 was measured using a TG instnmaent. Absorption was performed at 500°C in an atmosphere of 20% CO2 gas balanced by air and 700°C in pure CO2. Emission was conducted at 850°C in pure CO2. The gas flow rates were controlled at 300 ml/min at ambient pressure. In the case of absorption at room temperature, samples were placed on a gold plate and left for up to one week. In order to keep the samples free of dust, they were placed in a large box with sufficient air circulation. CO2 absorption properties were evaluated by the change in weight. Throughout all these measurement, the CO2 concentration was around 500 ppm and the temperature was kept at about 25°C.

RESULTS AND DISCUSSION

Other candidate lithium-containing oxides The reaction between Li2ZrO3and CO2 is generalized to the reaction of lithium-containing oxides with CO2 to form lithium carbonate. Other candidate lithiumw,ontaining oxides for CO2 absorbents were selected on the basis of thermodynamic stability. The equilibrium temperature, at which the direction of the reaction changes to the opposite direction, is calculated from changes in Gibbs free energy. From the viewpoint of use at high temperature, lithium ferrite (LiFeO2), lithium nickel (LiNiO2), lithium titanate (Li2"I]O3), lithium metasilicate (LizSiO3), and lithium orthosilicate (Li4SiO4) were found to have a possibility of being applied as CO2 chemical absorbents at various temperatures [1]. Among these absorbents, lithium orthosilicate (Li4SiO4) is found to have the highest reactivity with CO2 [2].

Absorption at high temperature Figure 2 shows the TG curves obtained at 500°C in 20 % CO2 gases for lithium-orthosilicate and lithium zirconate, respectively. The weight increase corresponds to the amount of CO2 absorption. Therefore, it was found that the weight increase of LhSiO4 was about 50% greater than that of Li2ZrO3. Furthermore, it appeared that the slope of the tangent line at the beginning of absorption for Li4SiO4was much larger than that for

1581 Li2ZrO3. Since the slopes correspond to absorption speed, Li4SiO4absorbed CO2 more than 30 times faster than Li2Zr03 did. 30 25 ®

Li4Si04

211

e-

~ I-

15

U

~"

Li2Zr03 . . - ' " 11

111

500°C

• .,-""

~

s

../

0o

lo

20%C0~

20

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Time I min

Figure 2: TG curves for LhSiO4 and Li2ZrO3 obtained at 500°C in 20% CO/. Cyclic behavior

In order to examine the cyclic behavior, absorption at 700°C and release at 850°C were repeated 5 times as shown in Fig. 3. As a result, it was found that absorption amounts were almost the same as initial amounts.

40

1000 8OO o o

6OO

0

U

2OO -~a

--0

'

'

'

'

~

~

2

4

6

8

10

12

•

0

~ n ~ (h)

Figure 3: Cyclic behavior of CO2 absorption and release for Li4SiO4 Absorption at room temperature

Figure 4 shows the TG curves for lithium orthosilicate and lithium zirconate at 25°C in ambient air. From this figure, it is seen that LizZrO3 changes little in weight; on the other hand, Li4SiO4 has about a 30% weight increase. This weight increase was thought to involve water adsorption apart from the CCh absorption. However, from the mass analysis of gases evolved from the sample, it was confirmed that the weight increase was mainly due to the CO2 absorption.

1582

25~C

3O

500ppm COz Li4Si04 ® c.

20

J¢ o

.c

10 LJzZr03 .....

0

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100

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200

~ .........

300

t ....

400

500

Time I h

Figure 4: Weight changes for LhSi04 and Li2ZIO3obtained at room temperature in ambient air

Applicationplans The application to power plants is expected to be the most effective for combating global warming. To achieve continuous absorption, a system in which several reactors are changed sequentially constitutes a basic approach. However, fluidized bed type reactors or rotary removal apparatus are also promising [4],[5]. Furthermore, the application to an air cleaner would take advantage of the feature whereby CO2 is absorbed in the atmosphere. There is a report [6] that Li4SiO4 has much better absorption property at room temperature than soda lime, the commercially available absorbent.

CONCLUSION This study revealed the following. 1. 2. 3.

Lithium orthosilicate absorbs C02 about 30 times faster than does lithium zirconate at 500°C in 20% C02 gases. Lithium orthosilicate absorbs COz even from the ambient air at room temperature. The absorption amount is almost the same as initial amount after repeating absorption and emission 5 times.

REFERENCES 1. 2. 3. 4. 5. 6.

Nakagawa, IC, and Ohashi, T. (1998) J. Electrochem. Soc. 145, 1344. Kato, M. and Nakagawa, K. (2001) J. Ceram. Soc. Jpn. 109, 911. Kato, M., Yoshikawa, S., and Nakagawa, K. (2002) J. Mater. Sci. Lett. 21,485. Nagashima, T., Kimura, S., Noda, R., Horio, M., and Nakagawa, K. (2002) In proceeding of the 67th annual meeting of the Chem. Eng. Soc. Jpn., G309. Shimomura, Y., Goto, K., Hashimoto, M., Takagi, T., Kinoshita, S., and Nakagawa, K. (2002) In proceeding of the 21st Annual Meeting of the Energy and Resources Soc., Jpn., 1 Essaki, K., Kato, M., Yoshikawa, S., Nakagawa, K., and Uemoto, H., (2002) In proceeding of the 67th annual meeting ofthe Chem. Eng. Soc. Jpn., S123.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1583

CARBON DIOXIDE ABSORPTION CONTACTORS: H O L L O W FIBRE M E M B R A N E S AND PACKED ABSORPTION COLUMNS David deMontigny l, Paitoon Tontiwachwuthikul *~ and Amit Chakma 2 ~Process Systems Laboratory, Faculty of Engineering, University of Regina, Regina, SK, Canada $4S 0A2 2Department of Chemical Engineering, University of Waterloo, Waterloo, ON, Canada N2L 3G 1 e-mail: [email protected]

ABSTRACT One of the important aspects in an absorption system is the effectiveness in which the gas and liquid phases come into contact with each other. An effective absorption process will provide sufficient contacting area for the gas and liquid phases to interact upon. With this in mind, work was conducted to evaluate carbon dioxide (CO2) absorption into aqueous solutions of monoethanolamine (MEA) using two different types of contacting devices: gas absorption membrane (GAM) modules and traditional packed columns. The performance of these two absorption devices was compared to one another using the overall mass transfer coefficient (Kcav) as a basis. The GAM module contained microporous polypropylene hollow fibre membranes and the packed absorption column contained Sulzer DX structured packing. The results indicate that GAM modules tend to have slightly larger Kcav values, potentially opening the door for smaller absorption contactors.

INTRODUCTION There are a number of industrial processes requiring CO2 capture including ammonia production, natural gas treatment and hydrogen production. In recent years the capture of CO2 from flue gases has gained attention due to the threat of global warming. This is being driven by the fact that the scientific community generally agrees that CO2 is a significant greenhouse gas [ 1]. There are a variety of technologies available to capture CO2, but when it comes to gas treating applications absorption is the most commonly chosen technology [2]. There is an increasing trend in industry to use packed columns instead of traditional tray columns [3]. This is mostly due to the development of highly efficient structured packings. Previous work in our group [4,5] has shown that structured packings offer a superior performance when compared to random packings. One relatively new and promising application for gas treating is the membrane contactor. First proposed by Qi and Cussler [6,7], a membrane contactor serves the same purpose as a packed absorber, which is to effectively contact the gas and liquid phases so that mass transfer may occur. In a GAM module, the gas and liquid phases contact each other through the pores of the membrane. This arrangement allows for independent liquid and gas flow rates and reduces the problems of entrainment, flooding, channeling, and foaming that affect traditional absorbers [8]. Furthermore, a GAM module offers a very high surface area to volume ratio, allowing for smaller equipment. The goal is to develop a small membrane module that can effectively do the same job that previously required a very large, expensive, absorber.

* To whom correspondence should be addressed.

1584 In this work CO2 was absorbed from an air stream using aqueous solutions of MEA in both a GAM module and a packed column. The performance of the two contactors was compared to one another in terms of their Kaav. Previous researchers [9,10] have suggested that membrane modules can achieve Kc,av values that are up to five times higher than packed columns. If this is possible, then there may be an opportunity to use smaller GAM modules in industrial applications instead of larger traditional absorbers.

EXPERIMENTAL W O R K

The GAM module was made from acrylic and had an intemal diameter of 0.028 m. The module was roughly 0.25 m long and contained 1550 microporous polypropylene (PP) hollow fibres from Mitsubishi Rayon Ltd. The membrane fibres were roughly 0.146 m in length and had an outside diameter of 300 gm, an inside diameter of 244 gm, and a porosity of 35%. The gas was fed through the lumen side of the hollow fibres and the liquid was fed on the shell side of the module. Gas, liquid, and temperature sampling points were located along the length of the module. The packed absorption column was also make out of acrylic and had a height of 2.4 m and an internal diameter of 0.028 m. Sulzer DX structured packing elements were rotated 90" with respect to each other inside the column. Gas and temperature sampling points were located along the length of the column, which was wrapped with 13 mm foam insulation for adiabatic operation. Experiments were carried out in a counter-current mode of operation. A simulated flue gas of roughly 15% CO2 was generated by mixing CO2 with air. Air and CO2 flow rates were controlled by electronic Aalborg GFM-17 gas flow meters. These flow meters were calibrated with a Humonics Optiflow digital bubble flow meter. The CO2 concentration in the gas stream was measured with an infrared CO2 gas analyzer from Nova Analytical Systems Inc., model 302WP. MEA solutions were prepared using de-ionized water and laboratory grade MEA solvent. The solution concentration was determined by titrating a known sample volume with 1.0 N hydrochloric acid solution using methyl orange indicator. CO2 loading was determined using the procedure outlined by the Association of Official Analytical Chemists (Horowitz, 1975). The liquid flow meter was calibrated by collecting a known volume of solution over time prior to each run. Once steady-state conditions were reached, usually within 20-40 minutes, CO2 gas samples and system temperatures were measured along the column. At the end of each run a liquid sample was taken and analyzed for its CO2 loading. The Kc,av was calculated for the GAM module by solving Equation 1, and is derived elsewhere Kaav for the packed column was determined using Equation 2 and is also derived elsewhere [4].

(GI] Kca~ = -~

Y,4,~_ YA,r | (1-YA,I~) (1-yA,r) ) (YA --Y'A)B--(YA --Y'A)r In (YA--Y'A)B

Kaav= I

[11 ]. The

GI I(dY,41 P(Y A - Y'A) )~,- ~ 3

( y . - y~,)~

(1)

(2)

RESULTS AND DISCUSSION

The objective of this work was to compare the overall mass transfer coefficients obtained in a GAM module versus those obtained in a packed column. The generated results were compared with values reported in the literature by Matsumoto et al. [9] and Nishikawa et al. [10]. In short, they successfully conducted CO2 capture experiments using MEA solutions in a GAM module. They used polytetrafluoroethylene (PTFE) and polyethylene (PE) membranes. In the study by Nishikawa et al., the PE (2) membranes were treated on the surface with a fluorocarbonic material. The results are presented in Figure 1 and include a comparison to some random packing data referenced from Kohl and Riesenfeld [ 12].

1585

The Koav values are reported as a high and low value, reflecting a range obtained from a variety of runs. The GAM module in this study produced Koav values that were roughly twice as large as the Koav values obtained in the DX packed column. Overall, the GAM module Koav values are in-line with values obtained by other researchers. The PE membranes used by Nishikawa et al. [10] obtained higher Koa~ values than our work with PP membranes, however our results are comparable to the PE fibres used by Matsumoto et al. [9]. Discrepancies could be a result of differing membrane types, membrane pore size, or operating conditions. It is important to note that the comparisons presented here serve as a guideline. This is because the different studies did not use the same solution molarity or liquid flow rate, both of which affect Koa~ values. The referenced data was generated using MEA at a solution concentration of 5.0 moles/litre but the new experiments used MEA solution concentrations between 1.0 and 3.0 moles/litre. Also, the experiments were run at lower liquid flow rates than in the referenced data. Since the Koav value tends to increase with concentration and liquid flow rate [4], we could expect that the Kca~ values in both the GAM module and DX packed column would increase had they been done at a higher concentration and liquid flow rate. 6.0

..................................................................................................................

5.0 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ,lg I~. 4.0 .~

I

..........................................................

" Lj_ "_' _LUW[] High -" .....

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1

~

This work.

2.0

1.0

0.0

-

-~

,

Matsumoto

Matsumoto

Nishikawa

Nishikawa

Nishikawa

PP GAM

PE

PTFE

PE(1 )

PE(2)

PTFE

Studies

I

~---~DX Studies II

I

Membrane Modules

- - . ,

Kohl & Riesenfeld

I

I

Packed Columns

..........................................................

Figure l: Comparison of the Koav values obtained in packed columns and GAM modules.

In Figure 2 the effect of Koav on column height is shown. The data shows a range of column heights possible, based on the Koav values reported above. All operating parameters were assumed to be equal, with only the Koav values held variable. We admit that although a simple calculation was used to determine the column height, the results do show that GAM modules are generally smaller than packed columns.

Matsumoto

PE j J

Matsumoto

PTFE

Nishikawa

PE(1) i

Nishikawa

PE(2) [

Nishikawa

PTFE,]

PP GAM Studies i

l

II

!

[' {

!

J I

l

f

t

This work.

I~E~?~~:~!4!:~:t~/~~!~~'~{~<'l

DX Studies

J Kohl & Riesenfeld i ~-- -----~- ......... r.......... T 0.0 1.0 2.0 3.0

I~%~:~;: !~/i~E~f~i~4"~:~,~;~,'~i!-':~;~;;,4~,l

I 4.0

5.0

6.0

A b s o r b e r Height

i 7.0

8.0

9.0

10.0

11.0

12.0

(m)

.....................................................

Figure 2" Column heights required using packed columns and GAM modules.

1586 CONCLUDING REMARKS Work reported in the literature claims that GAM modules can achieve mass transfer coefficients up to five times higher than those obtained from packed columns. While this may be possible under certain operating conditions, our work has only been able to achieve a two-fold increase in the Kc,av value. This is still a positive confirmation, however, as it tells us that GAM modules can be built smaller than packed columns but still offer the same operating performance.

ACKNOWLEDGEMENTS We gratefully acknowledge the support received from the Natural Science and Engineering Research Council of Canada, The City of Regina, lODE Canada, Mitsubishi Rayon Ltd., and Sulzer Chemtech.

NOMENCLATURE GI Kc,av P YA y*A YA Z

= = = = = = =

the inert gas flow rate (kmol/m2.h) gas phase volumetric overall mass transfer coefficient (kmol/m3.kPa h-) column pressure (kPa) mole ratio (mol/mol) mole fraction of solute A in equilibrium with CA,L (mol/mol) mole fraction of solute A in the bulk gas (mol/mol) column height (m)

REFERENCES 1. Kamal, W.A. (1997) Energy Conversion and Management 38(1), 39-59. 2. Astarita, G., Savage, D.W. and Bisio, A. (1983). Gas Treating With Chemical Solvents. Wiley, New York. 3. Nawrocki, P.A., Xu, Z.P. and Chuang, K.T. (1991) The Canadian Journal of Chemical Engineering 69, 1136-1343. 4. deMontigny, D., Tontiwachwuthikul, P. and Chakma, A. (2001) The Canadian Journal of Chemical Engineering 79(1), 137-142. 5. Aroonwilas, A., Veawab, A. and Tontiwachwuthikul, P. (1999) Industrial and Engineering Chemistry Research, 38(5), 2044-2050. 6. Qi, Z. and Cussler, E.L. (1985) Journal of Membrane Science, 23, 321-332. 7. Qi, Z. and Cussler, E.L. (1985) Journal of Membrane Science, 23, 333-345. 8. Feron, P.H.M. and Jansen, A.E. (1997) Energy Conversion and Management, 38(Suppl.), $93-$98. 9. Matsumoto, H., Kjamata, T., Kitamura, H., Ishibashi, M., Ohta, H. and Nishikawa, N. (1994). In: Carbon Dioxide Chemistry: Environmental lssues, pp. 270-281, Paul, J. and Pradier, C.M. (Eds). The Royal Society of Chemistry, Cambridge. 10. Nishikawa, N., Ishibashi, M., Ohta, H., Akutsu, N., Matsumoto, H., Kamata, T. and Kitamura, H., (1995) Energy Conversion and Management, 36(6-9), 415-418. 11. Tontiwachwuthikul, P. (1990). Ph.D. Thesis. University of British Columbia, Vancouver. 12. Kohl, A.L. and F.C. Riesenfeld. (1985). Gas Purification. Gulf Publishing Company, Houston.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1587

NEW COLUMN DESIGN CONCEPT FOR CO2 ABSORBERS FITTED WITH STRUCTURED PACKINGS A. Aroonwilas l, A. Chakma 1, A. Veawab 2 and P. Tontiwachwuthikul 2 I Department of Chemical Engineering, University of Waterloo, Waterloo, Ontario, Canada N2L 3G 1 2 Faculty of Engineering, University of Regina, Regina, Saskatchewan, Canada $4S 0A2

ABSTRACT

This work presents a mechanistic concept that can be used for a rigorous absorber design. The concept involves an integration of various mathematical models that were built upon kinetics and thermodynamics of the CO2 absorption system as well as the geometry and the liquid irrigation features of the packing elements. The models were verified with a series of pilot plant data and used to simulate the performance of fulllength CO2 absorption columns containing stainless-steel structured packings with different specific surface areas (170-500 m2/m3). The simulation was done for the CO2 absorption into an aqueous solution of monoethanolamine (MEA), over a wide spectrum of operating conditions. The models accurately predicted the important mass-transfer data and provided an insight into the dynamic behavior within the structured packings. Essential simulated results are concentration of CO2 in gas-phase, concentration of reactive species in the liquid-phase, variation in column temperature, mass-transfer coefficients (k~ and kL), and effective interfacial area (a~) for mass-transfer at different axial positions along the absorption column. The simulation also provided liquid distribution plots representing the quality of liquid distribution or maldistribution across the cross-section of the column. Furthermore, the packing height required for each structured packing to fulfill a given CO2 capture target was successfully determined from the simulation.

INTRODUCTION

Carbon dioxide (CO2) absorption process is an immediate capturing technique suitable for the high-volume waste gas streams from coal-fired power plants. However, the overall cost of this process is relatively high. One of the reasons for this high cost is the use of rule-of-thumb or approximation technique for the process design. Customarily, the absorption column is designed using the lumped mass-transfer and hydrodynamic parameters that are simply assumed to be constant over the entire length of the column, leading to an unnecessary oversized unit. With the advent of the environmental crisis and the economic constraint, the approximation is no longer applicable to process design. It is therefore necessary to obtain a better understanding of the actual phenomena taking place in this particular system so that a more rigorous and accurate column design technique can be developed. This paper presents a mechanistic concept for a rigorous absorber design that describes mass-transfer and hydrodynamic behavior within the CO2 absorption columns fitted with structured packings.

1588 MECHANISTIC CONCEPT The development of the mechanistic concept was based on an integration of various theoretical models that aim to determine the distribution pattern of the flowing liquid inside the packing element, effective interfacial area, mass-transfer coefficients and other information such as thermodynamic contributions (vapor-liquid equilibrium-VLE). Each model is described below; further details are in Aroonwilas [ 1].

Liquid Distribution Model The liquid distribution model (LDM) was developed in order to evaluate the distribution features of irrigating liquid, at different locations inside the packing element, during the operation of the absorption columns. The model is composed of two major components; i) a distribution structure representing a network of all possible flow-paths (connecting between packing intersections) through which the liquid can travel within the packing element and ii) a distribution intensity that indicates the quantity of irrigating liquid in each path (liquid rivulet). The liquid distribution features were generated by taking into account the details of the packing sheet arrangement and perforation, including dimensions, coordinates and patterns of the opening space on the packing sheets.

Effective Interfacial Area Model After the flow rates of liquid rivulets in all flow-paths were assigned by the liquid distribution model, the effective area for the mass-transfer process was then evaluated from the calculated liquid rivulet dimensions (width and thickness). The calculations were based on the Shi and Marsmann's equations [2]. Such equations take into account physical properties of the associated liquid solution, including density, viscosity, surface tension and contact angle.

Mass-Transfer Coefficient Model The determination of absorption performance directly involves coefficients of mass-transfer across the gasliquid boundary. The overall mass-transfer coefficient in the absorption system associated with chemical reactions can be determined from two-film theory. The liquid-phase mass-transfer coefficient (kL°) can be estimated from Penetration Theory (Eqn. 1).

IDA L

k; -- 2v -g

where DA,c and t are liquid-phase diffusivity coefficient of component A and gas-liquid contact time, respectively. The gas-phase mass-transfer coefficient (kc) can be estimated from Eqn. 2 [3].

Shc = 0.0338(Rec)°s (Scc) °333

(2)

where Sha, Rea and Sca represent Sherwood number, Reynolds number and Schmidt number, respectively. The enhancement factor due to chemical reactions can be evaluated by using the relationships proposed by DeCoursey & Thring [4].

Thermodynamic Model The vapor-liquid equilibrium (VLE) behavior of the CO2 absorption system is another important element of the mechanistic model presented in this study. The equilibrium establishes the concentration gradient between the gas and liquid phases, driving the mass-transfer process to proceed. An understanding of the equilibrium behavior is particularly essential for CO2 absorption using aqueous alkanolamine solutions. In this work, the equilibrium behavior of the CO2-MEA system was evaluated by using the electrolyte NRTL model proposed by Austgen and colleagues [5]. The model can provide the necessary thermodynamic information, including the speciation (concentrations of different ionic species and molecules) in the CO2 absorption system. This means that the concentration of free CO2 in the bulk liquid can be estimated.

1589 MODEL SIMULATION A Fortran-90 computer program was written for the mechanistic concept in order to simulate the CO2 absorption performance of columns packed with structured packings. The simulation was based on the theoretical column design procedure for adiabatic gas absorption with chemical reaction. The procedure accounted for heats of absorption, solvent evaporation and condensation, chemical reactions in the liquid phase, and heat-and mass-transfer resistance in both gas and liquid phases. The simulation of the absorption column was achieved by dividing the column or packing height into a number of sections with height dz. Each of these sections was treated as a non-equilibrium (or rate-based) discrete stage, which was governed by the material and energy equations. SIMULATION RESULTS Result representation

Each run of computer simulation gave essential information for the design of absorption system. These include concentration of CO2 in the gas-phase, concentration of reactive species in the liquid-phase, system temperature, mass-transfer coefficients and the effective interfacial area at different axial positions along the absorption column. The simulation results were generally presented as plots against the column height to show the extent of the variation in process parameters at different column positions. The simulation also provided the plots, which represent quality of the liquid distribution across the cross-section of the column.

Model Verification The model verification was carried out by comparing the simulated and experimental C O 2 concentration profiles for CO2-MEA system. The comparisons were made under two extreme conditions, depending upon the significance of thermodynamics contribution in controlling the mass-transfer phenomena. The concentration profile in Figure 1-(a) was obtained for the absorption column operated under the condition where the increasing CO2 loading of the descending amine solution was maintained below a stoichiometric value of 0.5 mole CO2/mole MEA. Under this condition, the absorption performance of the packed column was mainly determined by the system kinetics rather than the thermodynamics. Figure 1-(b) shows the concentration profile of the absorption column, for which the mass-transfer performance was controlled by the system thermodynamics. Here, the column was operated under the condition that allowed the descending liquid solution in the system to reach the vapor-liquid equilibrium (0.5 mole CO2/mole MEA) before its departure. The rate of absorption in this case was rather slow. This resulted from the fact that the absorption kinetics became less important, allowing the system thermodynamics to dominate the masstransfer phenomena. It should be noted that the changes in the absorption rate from high to low along the column were successfully captured by the computer simulation, thus demonstrating the validity of the developed mechanistic model. 2.5 ~, o

1

~ ql~ 2.0 -~1~ •

2.5

Gempak 4A

Ga s load = 38.5 kmol/m 2 -h Liquid load = 15.9 m3/m2-h MEA conc. = 5.2 kmol/m 3 ~

.

E 2.0 o

=¢ 1.5

.

• I ~

E 1.0 ~

0.5

~" 0.5

o,o

.

0

2

.

.

4

.

6

.

8

.

.

w,

10 12 14 16

CO 2 concentration (%)

Experiment Simulation

k ~1~

Mellapak 500X .~ Gas load = 38.5 kmol/m2-h Liquid load : 3.8 m3/m2-h

~k

MEA c°nc = 30 kin°l/m3

~1b

0.0

0

2

4

6

8

10 12 14 16

CO 2 concentration (%)

(a)

(b)

Figure 1: Comparisons between the simulated and experimental C O 2 concentration profile.

1590

Simulation Results for Different Structured Packings The simulation was carried out for the absorbers containing stainless-steel structured packings with different specific surface area ranging from 170 to 500 m2/m3, i.e. Gempak-l.5A, Gempak-2A, Gempak-3A, and Gempak-4A. The simulation was based on 15%CO2 in feed gas and 1 m/s gas velocity. Figure 2-(a) shows the concentration profiles for the absorbers with the packing height of 5 m. The Gempak-4A having the surface area of 500 m2/m3 provided the highest recovery performance (98%), whereas the Gempak-l.5A having the area of 170 m2/m3 gave the lowest value of 57%. The Gempak-3A and -2A provided the recovery values in between the two extremes, i.e. 89% and 76%, respectively. The difference in the recovery performance of these packings is due to the difference in the effective interracial area shown in Figure 2-(b).

~ /

~t

i"

\

~

\ \

'~ ",,

Gempak-4A Gempak-3A Gempak-2A

~" 300

.E

i

3

2

~

250 200

Gempak-4A

i 150 150 t nn ~ 100

Gempak-3A

i

Gempak-l.5A

Gempak-2A

50 0

0 0

2

4

6

0

8

10 12 14 16 18 CO= concentration in gas stream (%)

1

2

3

4

5

Height from c o l u m n top

(a)

6 (m)

7

(b)

Figure 2:CO2 recovery performance of different structured packings. Figure 3-(a) illustrates the CO2 concentration profiles for the absorbers used to recover 1075 kg CO2/m2-hr. Based on this information, the relationship between the specific surface area of packing and the packing height requirement for a given recovery target can be plotted in Figure 3-(b). The required packing height increases proportionally as the packing surface area decreases from 500 to 233 mZ/m3. However, the height requirement increases substantially when the surface area is reduced to 170 mZ/m3. 1.0

5

"~ 0.8 ~

E4

Gempak-l.5A

'- 0.6 o1 \ ~, J= O.4

g3

Gempak-2A

fca 2

I~' 0.2 n, 0 0

2

4

6

8

10 12 14 16 18

CO2concentration in gas stream (%)

0

200

400 (m21m3)

600

Specific surface area

(b) (a) Figure 3: Height requirement for different structured packings. REFERENCES 1. 2. 3. 4. 5.

Aroonwilas, A. (2001). Ph.D. Thesis, University of Regina, Canada. Shi, M. G. and Mersmann, A. (1985). German Chemical Engineering 8, 87-96. Bravo, J. L., Rocha, J. A. and Fair, J. R. (1985). Hydrocarbon Processing 64, 91-95. DeCoursey, W. J. and Thring, R. W. (1989). Chemical Engineering Science 44, 1715-1721. Austgen, D. M., Rochelle, G. T., Peng, X. and Chen, C. (1989). Industrial & Engineering Chemistry Research 28, 1060-1073.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1591

HEAT STABLE SALTS AND C O R R O S I V I T Y IN A M I N E T R E A T I N G UNITS W. Tanthapanichakoon and A. Veawab Faculty of Engineering, University of Regina, Regina, Saskatchewan, $4S 0A2, Canada

ABSTRACT This work investigated the effect of eight heat-stable salts on corrosion in the amine treating units using an aqueous solution of 5 kmol/m 3 monoethanolamine (MEA). The investigation was done by conducting electrochemical corrosion experiments at 80°C and under atmospheric pressure/the CO2 loading of 0.20 mol/mol. Carbon steel 1018 was used as a representative of the typical construction material of process equipment. The test heat-stable salts were acetate, chloride, formate, glycolate, malonate, oxalate, succinate and sulfate. The outcomes of this work were discussed in terms of corrosion rates, corrosion behaviour and pitting tendency. The major heat stable salts contributing to the increased corrosion rate were identified and the relationship between their concentration levels and corrosion rate were correlated. In addition, the corrosion related phenomena such as passivation of protective films were also analyzed to reveal the associated corrosion mechanism.

INTRODUCTION

There is a great concern over the corrosion due to the presence of heat-stable salts in amine treating units. The heat-stable salts are essentially the reaction products of alkanolamines and the acids stronger than carbon dioxide (CO2). These acids are usually introduced to the amine units with makeup water and feed gas streams or generated within the units by undergoing the chemical reactions with contaminants such as oxygen (O2), carbon monoxide (CO), and sulfur dioxide (SO2). For example, formate is generated by the reactions of amine and 02, hydration and other reactions with CO as well as reactions with cyanides. By nature, the heat-stable salts are non-regenerable under solvent regeneration condition. As such, they remain and accumulate in the absorbent throughout the plant. The accumulation of heat-stable salts not only causes a reduction in CO2 absorption capacity, but also is claimed to cause a significant increase in the system corrosiveness [1-3]. The increased corrosion can lead to an increase in the amount of iron carbonate particles in the solution, thus causing other operational difficulties such as foaming, emulsions and fouling. This potentially undermines reliability of the amine units, particularly in terms of operation, throughput, treatment capacity, and productivity. At present, the knowledge of the influence of heat-stable salts on corrosion in this system is limited. This is basically an impediment to the development of cost-effective process. Therefore, this paper was aimed at investigating the role of heat stable salt on corrosion so as to extend the knowledge in this area.

1592 EXPERIMENTS

Prior to the corrosion experiments, validation of experimental technique and electrochemical instrumentation was performed in accordance with ASTM standard G5-94 (1999) to ensure the reliability of the electrochemical data. The experiments were conducted using several electrochemical testing techniques, i.e. linear polarization resistance (ASTM G59-91), cyclic polarization (ASTM 61-86), and potentiodynamic anodic polarization (ASTM G5-94). Carbon steel 1018 specimens were used as a main material, while stainless steel 316 was used only for the pitting tendency test. Aqueous solution of monoethanolamine (MEA) with the concentration of 5.0 (+ 0.1) kmol/m 3 and CO2 loading of 0.20 (+ 0.1) mol/mol was used as a blank solution. The test environment was maintained at 80.0 (+ 0.1) oC and under atmospheric pressure throughout the experiment. Eight heat stable salts including acetate, chloride, formate, glycolate, malonate, oxalate, succinate and sulphate were tested. It should be noted that the heat-stable amine salts were prepared from the heat-stable acid and aqueous solution of MEA. For example, formate is a reaction product of formic acid and aqueous solution of MEA. Corrosion rate was determined from linear polarization resistance (LPR) technique via the corrosion current resistance (Rp).

RESULTS AND DISCUSSION Corrosion behaviour of carbon steel specimens in aqueous solutions of MEA containing various heat-stable salts was investigated by conducting the potentiodynamic anodic polarization scan. The obtained polarization curves suggest that the presence of heat-stable salts did not alter the corrosion behaviour of carbon steel. As seen in Figure 1, all the test specimens in the solutions containing salts yielded the similar active-passive polarization curves to the specimen in the blank solution. This indicated that heat stable salts did not passivate or form the protective film on the metal surface. Figure 1 also suggests that the presence of heat-stable salts in MEA solution led to an increased corrosion. The increased corrosion was indicated by the open circuit potential (OCP) of the test system and the current density throughout the range of potential scan. The OCP of the system containing salts, except hydrochloric acid, was less noble than that of the system without salts. This means that the presence of the salts increased the system's susceptibility to the corrosion. It was also observed that the polarization curves of the system with salts shifted toward the direction of the increased current densities, thus implying higher corrosion rates. The magnitude of the increased corrosion rate depended on the magnitude of the current density shift. Among the test salts, oxalate system showed an apparent increase in corrosion. 0.8 0.6 0.4 m

0.2

0 -0.2

-I

~. -0.4 ~ -0.6 -0.8 -1 ' 1 .E-06

1 .E-05

1.E-04

I.E-03

I.E-02

Current density ( A / c m 2 ) N o acid • .....

.......

Formic acid Malonic acid

• ~

Oxalic acid

•

Acetic acid

Glycolic acid

x

Hydrochloric acid

Succinic acid

I

Sulphuric acid

Figure 1" Anodic polarization curves of MEA-CO2 system with and without acid (concentration of added acid = 10,000 ppmw).

1593

Figure 2 shows the corrosive effects of heat stable salts presented in terms of % increase in corrosion rate from the blank solution. It was found that oxalic acid (oxalate) was the major contributor to an increased corrosion rate. The corrosion rate of oxalate system increased 124% from that of the blank solution. Malonic acid (malonate) system yielded the second highest % increase in corrosion rate while the rest of the salts induced less than 20% increase. These findings were in a good agreement with the observation results from the previous polarization curves in Figure 1. 5 M M E A + 1% A C I D 80°C-0.2 r m l / m o l CO2 loading 140 •~

120

§

100

r, = ~

80

~ L 60

20 0

~,~

~o

.,~,°

~°

,o

~o

,/,°

~-°

,~

Added acid

Figure 2: % increase in corrosion rate caused by various acids at 10,000 ppmw. Since oxalic acid (oxalate) contributed to such a significant increase in corrosion rate compared to other acids, it was chosen as a representative of heat-stable salts in showing the effects of acid concentration on corrosion. From Figure 3, % increase in corrosion rate was plotted against the acid concentrations. Perspicuously, corrosion rate increased as the acid concentration rose. Neilson et al. [1 ] suggest that heat stable salts are corrosive because they lower the amine solution pH, increase solution conductivity and may also act as chelating agents, dissolving the protective film covering the base metal. The rest of the acids behave similarly to oxalic acid. Oxlic acid + 5N M E A 80oC-0.2 CO2 loading-CS 1018

1.4 ,-- 1.2 o .~, o 1

8 0.8

.=_

0.6 i0.4 ._ 0.2

1,000 ppm

5,000 ppm

10,000 ppm

Acid concentration

Figure 3: Effect of acid concentration on corrosion. Cyclic polarization was also carried out to examine the pitting tendency. Since all acids behave similarly on carbon steel 1018 at the test conditions, oxalic acid was regarded as a good representative and presented here in the cyclic polarization curve. As seen in Figure 4A, the reverse scan was located on the left side of the anodic polarization curve. This indicated no localized pitting. As for stainless steel 316, oxalic and

1594 hydrochloric acids were suspicious of pitting tendency and therefore tested. The result also showed that none of them showed a pitting tendency under the test condition (Figure 4B). 5N MEA + 1% Acid

5N MEA + 1% Oxalic acid 80°C-0.2 CO2 loading-CS 1018

80°C-0.2 CO2 loading-SS 316 0.8 0.6 0.4

0.5 r,.) ~

f

0

~" 0.2 o']

0

>. .~_

.,.

= -0.5

)

l

I

I

I

-0.2

=

-0.4

o

-0.6 -0.8 -1

-1.5 1.E-06

-

-1.2 .............................................................................................................. 1E-07 1F.,-06 0.00001 0.0001 0.001 0.01 1.E-05

1.E-04

1.E-03

Current density (A/cm2) (a)

I .E-02

Current density (A/cm2) ~

Oxalic acid ---0--. Hydrochloric acid (b)

Figure 4: Cyclic polarization curve of (a) oxalic acid for CS 1018 and (b) oxalic acid and hydrochloric acid for SS.316.

CONCLUSIONS For the CO2-1oaded aqueous solution of MEA, all test heat stable salts, including acetate, chloride, formate, glycolate, malonate, oxalate, succinate and sulfate, aggravated corrosion of carbon steel. Oxalate was the major contributor to an increased corrosion rate. None of the test heat stable salts showed pitting tendency on both carbon steel and stainless steel.

ACKNOWLEDGEMENTS Financial support from the Natural Sciences and Engineering Research Council o f Canada (NSERC) and Imperial Oil is gratefully acknowledged.

REFERENCES 1. 2. 3.

Nielsen, R.B. and Lewis, K.R. (1995) Corrosion in refinery amine systems: NACE International Corrosion'95: paper no. 571. Rooney, P.C., DuPart, M.S. and Bacon, T.R. (1997) Hydrocarbon Processing 76 (4), 65. Keller, A.E., Kammiller, R.M., Veatch, F.C., Cummings, A.L. Thompsen, J.C. and Mecum, S.M. (1992) Heat-stable salt removal from amines by the HSSXprocess using ion exchange: Laurance Reid Gas Cond. Conf. 73, 61.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1595

CORROSION IN CO2 CAPTURE UNIT FOR COAL-FIRED POWER PLANT FLUE GAS A. Veawab Faculty of Engineering, University of Regina, Regina, Saskatchewan, Canada $4S 0A2

ABSTRACT This paper reviews the knowledge of corrosion and corrosion control in the CO2 capture unit using reactive amine solvents. Plant experiences and the impacts of operating parameters on corrosion in the amine unit are addressed. The key operating parameters are amine type, amine concentration, solution temperature, CO2 loading, solution velocity, and degradation products. The corrosion data obtained from our laboratory experiments as well as from the literature over the decades were integrated to establish the interrelationship between such operating parameters and corrosion rate. This paper also reviews all the corrosion mechanisms that are commonly used to characterize corrosion phenomena in this particular CO2-amine system as well as the one that was identified by our rigorous corrosion model. In addition, the information on corrosion control and our work on low-toxic corrosion inhibitors are also provided.

INTRODUCTION Carbon dioxide (CO2) capture unit using reactive amine solvents is constantly subject to excessive corrosion problem. Based on plant experiences, corrosion takes place in almost every section of the plants. The most susceptible areas include the bottom portion of the absorber, flash drum, rich-lean heat exchanger, regenerator and reboiler. The corrosion detected in these areas occurs in many forms, i.e. uniform, pitting, erosion, galvanic, stress corrosion cracking and inter-granular. The corrosion problem has a direct impact on the plant's economy as it can result in unplanned downtime, production losses, reduced equipment life. It can also affect the plant's economy in an indirect way by limitingthe operational ranges of process parameters, such as amine concentration. As such, the capture unit cannot be practically operated to increase the unit throughput and/or to reduce the process cost, especially the operating cost due to excessive energy consumption in the regeneration section. Due to the tremendous corrosion impacts, suppression of excessive corrosion to an acceptable level becomes necessary for amine treating plants. In general, corrosion can be reduced by a number of approaches including i) use of proper equipment design, ii) use of corrosion resistant materials instead of carbon steel, iii) removal of solid contaminants from liquid solution, and iv) use of corrosion inhibitors. Of these alternatives, the use of corrosion inhibitors is considered to be the most economical technique for corrosion control.

I M P O R T A N T O P E R A T I N G PARAMETERS Corrosion in amine treating plants is influenced by a number of factors including CO2 loading, amine type, amine concentration, temperature, solution velocity and degradation products. CO2 loading or CO2 content in the amine solution is considered to be the primary contributor. An increase in CO2 loading intensifies the

1596 system's aggressiveness, thus accelerating the corrosion process [1, 2] (Figure l-a). As a result, the rich amine solution is generally more corrosive than the lean amine. There are a number of references providing guidelines for the CO2 loading that limits corrosion to the acceptable levels [3]. The recommended maximum CO2 loadings in the rich amine solution are in the range of 0.25-0.40 mol/mol, 0.33-1.00 mol/mol, 0.45-0.50 mol/mol, 0.25-0.45 mol/mol and 0.50-0.85 mol/mol for MEA, DEA, MDEA, DGA and DIPA, respectively. Temperature has a significant impact on corrosion as higher temperature tends to increase the rate of corrosion [2, 4, 5, 6] (Figure l-b). Because the operating temperature of the absorption process varies from 40°C to as high as 120°C, a great diversity of corrosion rates can be found throughout the plants. The most susceptible process areas are the rich-lean heat exchanger, the regenerator and the reboiler where the amine solutions are heated to an elevated temperature. For regions such as the absorber and the amine cooler, the operating temperature is relatively low and corrosion damage is rather small. 70 •--o- MEA-3.2M-121C (Kuznetsov et al., 1999) --o- MEA-3.2M-135C (Kuznetsov et at., 1999)

A 6O

// 50 --k- MEA-3.2M-149C(Kuznetsovet ai., 1999) / / -x-AMP-2.0M-80C (Veawab et al., 1999)

/

- e - MEA-2.0M-80C (Veawab et al., 1999)

/

p

4O

40

i+

30

20

10

~ 2o u

50

lo

100

150

200

T e m p e r a t u r e (°C)

0

0.1

0.2

0.3

0.4

C02 loading (mollmol)

(a)

0.5

0.6

0.7

MEA-49M (DuPart et al, 1991 ) DEA-1 9M (OuPart et al., 1991 ) MEA-3.2M (Helle, 1995) -->(--- DEA-2.0M (Helle, 1995) ---m---MDEA-4.2M (Keller et al., 1992) MEA-2.0M (Veawab et al, 199) -.o-- DEA-2 0M (Veawab et al, 199) AMP-2.0M (Veawab et al., 199)

(b)

Figure 1: Effect of CO2 loading and temperature on corrosion Amine type plays an essential role in corrosion. Although pure amines are not corrosive to carbon steel regardless of temperature, the amine aqueous solutions containing only small amounts of CO2 can be quite corrosive. Different types of amines induce different degrees of system corrosiveness. Generally, the primary amine (MEA) is found to be more corrosive than the secondary amine (DEA) which is in turn more corrosive than the tertiary amine (MDEA) [2] (Figure 2-a). The reason for this behavior is not fully understood. However, it was suggested that the Lewis base strength of the individual amine was responsible for the rate of corrosion [7]. Concentration of amine solution also affects corrosivity, i.e. an increase in amine concentration causes the higher corrosion rate [2, 4, 8] (Figure 2-b). Generally, use of a high amine concentration is desirable for energy saving purposes. However, too high amine concentration can damage the plants to a great extent. To limit the plant corrosion within the acceptable and manageable level, most of the amine plants are operated in compliance with the recommended maximum amine concentrations. These concentrations are in the range of 10-20 wt%, 20-40 wt%, 50-55 wt%, 50-65 wt% and 20-40 wt% for MEA, DEA, MDEA, DGA and DIPA, respectively [3]. Solution velocity can cause severe erosion corrosion, especially in the presence of solid contaminants. In a system without a protective film, the corrosion rate is completely controlled by solution velocity [9]. With inhibited systems, a protective film is normally developed to cover the metal surface and suppress the

1597 excessive corrosion. However, this film can be removed or damaged by the shear force of a high velocity fluid stream. As a result, erosion corrosion will be introduced into the system.

lso.J

)

80

E lO0-r ---)

)

g o .,-

g,

8

20

50-~

m 0

..,IN-

1

AMP

2

3

4

5

6

A m i n e concentration (M)

o.A~N

DEA

MEA

--O--DEA-100C (Chakma and Meisen, 1986) •--.&-- MEA-99C (DuPart et al., 1991) --e--DEA-99C (DuPart et al., 1991) ~ M D E A - 9 9 C (DuPart et al., 1991) .-e,-- MEA-80C (Veawab et al., 1999) --e--AMP-80C (Veawab et al., 1999) --4:3-- DEA-80C (Veawab et ai., 1999)

MDEA

3 kmol/m a, 80°C

(b)

(a)

Figure 2: Effects of amine type under CO2 saturation condition and amine concentration. Amine degradation is a chemical process that causes a reduction in the amount of reactive amine participating in the CO2 absorption process. Aqueous amine solutions can be degraded in the presence of carbon dioxide and oxygen. As reported by Gregory and Scharman [10], solvent degradation leads to corrosion in MEA plants. For plants using other amines, such as DEA, the connection between corrosion and degradation however remains inconclusive. Blanc et al. [11 ] stated that the DEA degradation had no or very little effect on carbon steel corrosion but other researchers showed there was a connection between the two operational problems [5,12,13].

CORROSION MECHANISMS Corrosion mechanism in an aqueous amine-CO2 system is not well understood. Several mechanisms have been used to postulate the corrosion phenomena. Riesenfeld and Blohm [14] suggested that the corrosion was associated with an evolution of CO2 from the rich amine solution. The evolved CO2 then reacts directly with carbon steel to form iron carbonate (FeCO3). However, in most cases, mechanisms of iron dissolution in a CO2-water system are used to represent the corrosion mechanism in the aqueous amine-CO2 system. Three different types of iron dissolution reactions have been suggested. First, the dissolution reaction involves a reduction of hydrogen ion (H +) (Eqn. 1). Second, bicarbonate ion (HCO3) in the solution functions as an oxidizing agent in the reduction reaction (Eqn. 2). Third, the reaction is governed by undissociated carbonic acid (H2CO3) (Eqn. 3). Fe + 2H + ~

f e 2+ + 9 2

(1)

Fe + 2HC03-

--9 FeC03 + C032 -k 9 2

(2)

Fe + H2C03

~

(3)

FeC03 + 11:

Recently, a mechanistic corrosion model was established to identify the oxidizing agents responsible for corrosion reactions in an aqueous amine-CO2 system [ 15]. The model incorporated the rigorous electrolyte-

1598 NRTL equilibrium model and mixed potential theory in order to simulate the concentrations of chemical species and the polarization behavior taking place at a metal-solution interface. The simulation results, based on the MEA system, indicated that HCO3- and H20 are the primary oxidizing agents and H+ plays an insignificant role in the reduction reaction.

CORROSION INHIBITORS

For decades, various corrosion inhibitors have been developed, commercialized and patented by many major chemical companies for uses in the amine treating plants. Inorganic corrosion inhibitors are in practice more favored than the organic compounds because of their superior inhibition performance. Among these, vanadium compounds, particularly sodium metavanadate (NaVO3), are the most extensively and successfully used in the amine treating plants. However, there is a concern over the use of toxic inorganic inhibitors as it makes disposal of the resulting industrial waste difficult and costly. This fact, together with growing environmental concern, has made the shifting from toxic corrosion inhibitors to the ones with less toxicity a significant corrosion issue in the field of gas treating [16]. The possibility of using low-toxic corrosion inhibitors instead of heavy-metal inhibitors, for CO2 absorption systems was investigated by Veawab et al. [17]. The performance of eight low-toxic organic inhibitors (amines, carboxylic acid and sulfoxide) were evaluated by conducting electrochemical corrosion experiments with carbon steel-1020 specimens immersed in 3.0 k m o l / m 3 MEA solutions under CO2 saturation. The experimental results showed that carboxylic acid had the best inhibition performance (as high as 92%), followed by sulfoxide and longchain aliphatic amine. Their performance depended upon inhibitor concentration and temperature.

ACKNOWLEDGEMENT

Natural Sciences and Engineering Research Council of Canada (NSERC) is gratefully acknowledged for financial support and experimental equipment.

REFERENCES

1. 2. 3. 4.

Kuznetsov, Y.I., Andreev, N. N. and Ibatullin, K.A. (1999) Prot. Met. 35(6), 532-536. Veawab, A., Tontiwachwuthikul, P. and Chakma, A. (1999) Ind.& Eng. Chem. Res. 38(10), 3917-3924. Nielsen, R.B., Lewis, K.R. and McCullough, J.G. (1995) Corrosion 95. DuPart, M.S., Bacon, T.R. and Edwards, D.J. (1991) Proc. Laurance Reid Gas Cond. Conf. 41 st, 196227. 5. Helle, H.P.E. (1995) Corrosion 95, paper no. 574. 6. Keller, A.E., Kammiller, R.M., Veatch, F.C., Cummings, A.L., Thompsen, J.C. and Mecum, S.M. (1992) Proc. Laurance Reid Gas Cond. Conf. 42 nd, 61-92. 7. Teevens, P. J. (1990) Corrosion 90, paper no.384. 8. Chakma, A. and Meisen, A. (1986) Ind. Eng. Chem. Prod. Res. Dev. 25(12), 627-30. 9. Videm, K.and Dugstad, A. (1989) Materials Performance 28(3), 63-67. 10. Gregory, L. E. and Scharman, W. G. (1937) 1BID 29, 514. 11. Blanc, C., Grail, M. and Demarais, G. (1982) Proceedings of Gas Conditioning Conference. 12. Polderman, L. D. and Steele, A. B. (1956) Oil and Gas Journal 54(65)i 206-214. 13. Moore, K. L. (1960) Corrosion 16(10), 111-114. 14. Riesenfeld, F. C. and Bholm, C. L. (1950) Pet. Ref 29(4), 141-150. 15. Veawab, A. and Aroonwilas, A. (2002) Corrosion Science 44, 967-987. 16. Asperger, R.G. (1994) Proc., Annu. Conv. - Gas Process. Assoc. 73 rd, 189-92. 17. Veawab, A., Tontiwachwuthikul, P. and Chakma, A. (2001)lnd.& Eng. Chem. Res., 40(22), 4771-4777.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1599

N E W AMINES FOR THE REVERSIBLE A B S O R P T I O N OF C A R B O N DIOXIDE F R O M GAS M I X T U R E S Michele Aresta and Angela Dibenedetto* Department of Chemistry and METEA Research Center, University of Bail, Via Celso Ulpiani, 27, 70126 B a r i - Italy Phone +39 080 544 2078, Fax +39 080 5442083 E-mail: [email protected]

ABSTRACT In this paper we discuss the use of new amines as a medium for the capture of CO2 from a gas mixture. The study was carried out comparing the absorption of carbon dioxide by two alkyl-di-amines with that of amines used so far at industrial level, namely mono-ethanolamine (MEA). A known mono silyl-alkyl-amine was also studied for comparison. The absorption of carbon dioxide was studied at different temperatures, in water solution, in organic solvents and using the neat amine. Several cycles of absorption/desorption were carded out. Xerogel solidified amines were also used.

INTRODUCTION Anthropogenic carbon dioxide is considered to be the greenhouse gas which most contributes to global warming. Its concentration in the atmosphere is considerably increased and the control of CO2 immission has been agreed at the international level. The capture of carbon dioxide from flue gases may be used as a mitigation technology. Several technologies have been developed for separating carbon dioxide: absorption by liquid amines [1,2] or solid materials, [3] or membrane separation [4,5]. Several examples of carbon dioxide absorption using liquid amines have been reported in the literature and, recently, also the use of ionic liquids beating primary amines [6] has been described. Mono-ethanolamine (MEA) and methyl-diethanolamine (MDEA) are the most popular amines used, either separately or combined at different ratios [7,8]. A separation technology can be exploited at industrial level if it is reliable and cheap. CO2 separation by amines is more economically convenient than the use of membranes. Therefore, the amount of CO2 absorbed per unit of absorbent is a key factor. Consequently, finding new amines able to capture a higher amount of carbon dioxide per mol has a great economic interest [9]. RESULTS It has been long known that aliphatic amines react with CO2 (Eqn. 1a) to afford an ammonium carbamate that, with some amines, may be converted into dimeric carbamic acid (Eqn. 1b) [ 10, 12]. 2 RNH 2 + CO2

--9.

RNH3+-O2CNHR

(1 a)

1600 RNHCOO-+H3NR

+ CO2

~

(lb)

(RNHCOOH)2

While, to date, the reaction of several mono-amines with CO2 has been studied, di-amines have not been investigated. We have studied the up-take of CO2 by using four alkyl mono- and di-amines, namely H2N(CH2)3Si(OMe)3 (I), HzN(CHz)3Si(OEt)3 (II), HzN(CH2)2NH(CH2)3Si(OMe)3 (III) and CH3(CHE)ENH(CH2)2NH2(IV) at different temperatures, in solution and as a pure sample. Figure 1 shows that amine I and II react within 15 min with C 0 2 at 298 K in THF. The amount of C 0 2 absorbed is almost 0.55 mol/mol of amine and this is in accordance with the stoichiometry of reaction l a, where one mol of CO2 reacts with two mol of amine to afford the relevant ammonium carbamate. This behavior is the same observed for MEA (Fig. 1).

| 0,9

l 0,9 .~ 0,8 0,7 ~. 0,6 ~ 0,5 0,4

~

~

~ o,3

-- -@--- monoan~ne !(298_K! - - ~ -- monoamine II (298 K) - - ? - -MEA(298 K) monoamine II (273 K)

~! ~'

~ 0,2 0,1 0 0

4

s4m

8

12 16 20 24 28 32 36 Time (rain)

Figure 1" Kinetics of reaction of silyl-alkyl mono-amines with carbon dioxide

..-

0,8 h" 0,7 ~.0"" ~d 0,6 0,5 ~"0,4 ~d 0,3 ~ 0,2 ,~

- - 41, - -di-aminelV -- • -- MEA

0,10 / 0

Jt 15

30

45

60

di-amine III 75

90

105

Time (rain)

Figure 2" Kinetics of reaction of di-amines with carbon dioxide

For both amines I and II, after the up-take of carbon dioxide it is possible to isolate a white solid which shows the characteristic IR band (1535 cm 1) of the ammonium carbamates obtained from other aliphatic mono-amines. Moreover, we have found that if the reaction is carried out at 273 K, the absorption curve of CO2 has a different shape with time. In fact, the absorption slowly increases to 1 mol of CO2 per mol of amine within less than 1 h (Fig. 1). This different behavior can be explained considering that, as already reported [ 10, 11 ], the ammonium carbamate may slowly convert into the dimeric form of the carbamic acid (Eqn. lb). In previous work [ 10], where C6HsCH2NH2 and CoCI(NO)2[PhP(OCH2CH2)2NH] were used, the dimeric carbamic acid was isolated and characterized by XRD. In the present work, by using amine I and II it was not possible to isolate the acid as a solid, but aider evaporation under vacuo of the solvent, a sticky liquid difficult to handle was obtained. The absorption of carbon dioxide by using mono-amines I and II was not reversible. No release of carbon dioxide was observed heating under vacuo at 330 K [12], while at higher temperatures the ammonium carbamate easily decomposed. Figure 2 shows the C O 2 uptake curve of di-amines III and IV at 295 K. Differently from the mono-amines, (Fig. 1) one mol of CO2 per mol of amine was taken up by amine III. In previous work [12], we have shown that amine III affords an intra-molecular more than an inter-moleCular carbamate. The reaction was quite fast (less than 20 minutes) and a glassy material difficult to handle was isolated. Nevertheless, by evaporating the amine solution under CO2 atmosphere, directly on a single KBr disk, it was possible to record the IR spectrum which shows the characteristic band at 1540 cm -I due to the carbamate RHNCOO- moiety [12]. The reaction quickly takes place also in absence of solvent, assuming that a thin film of the amine is used. As shown in Fig. 2, di-amine IV also takes-up CO2 with a 1:1 molar ratio, but differently from amine III, affording a white light powder more easy to handle. In both cases, the absorption was reversible and carbon dioxide was completely released at 333 K. If neat amine was used, the starting material was quantitatively recovered. Di-amines are, thus, able to absorb the

1601 double amount of CO2 per mol than mono-amines. A water solution of amine IV (H20:amine=1:1) was also used as absorbent mixture. By heating to 333 K CO2 was released: only half o f the CO/ absorbed was evolved. Such amount was then absorbed and desorbed for several cycles (Fig. 3). When a gas mixture (86% N2/14% CO2 ) was contacted for two minutes with the stoichiometric amount (with respect to CO2) of the amine, by monitoring the gas phase by GC we observed the complete disappearance of the CO2 signal (Fig. 4).

0.6 • . ~ . . . = . . . ~ . . . ~ . . . ~ .

~

0.5

1

,

,..~

i

,

,

i

i

,

,

i

, i

.

.

.

. ~ . . . |

.

.

.

i

,

.

.

i

" t

._= 0.4 E

(b)

0.3

(a)

O 0.2

_'~= 5.216 CO2 0.1

0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 Time (min)

Figure 4: GC of the mixture of gases before (a) and (b) after the absorption (time of contact: 2 min).

Figure 3: Absorption/desorption cycles of a water solution of di-amine IV.

When a N2/CO2 gas mixture (CO2=14.4%) and a water solution of amine IV (H20:Amine=55:l) were contacted, the same behaviour was observed (Figure 5). As shown in Fig. 5, the first absorption almost reached the 1:1 molar ratio. When the system was heated to 333 K, only half amount of CO2 absorbed was released. A second cycle was run. If fresh amine was added to the system (Cycle 3, Fig. 5) an increase of absorption of CO2 was observed due to the addition of the amine, but again when the system was heated to 333 K the amount of CO2 released did not correspond to the total amount absorbed. 1,4

addition of flesh amine

1,2

1,2045

._. 1 E E ,t E

0,8 ~

~

0,6815

0,6 0,4

E

Cycle 1

0,2

0

100

200

!,3285 Cycle 21~

300

400

0,32075Cycle 3

500

600

700

Time ( m i n )

Figure 5:CO2 absorption/desorption cycles using a water solution of di-amine IV and a N2/CO2 gas mixture The use of water or organic solvent solutions poses some limitations for the working temperature essentially for avoiding loss of amine by evaporation during the desorption phase that occurs with heating.

1602 It is very attractive to find an absorption/desorption system that does not decompose at high temperature (e.g. at the temperature of flue gases from a chimney: this would allow recovery of CO: without cooling the gas. From this point of view inorganic membranes are very attractive. We have tried to support amine III on a sol-gel matrix and to check its behaviour when the gel was contacted with a gas mixture. The silica xerogel was obtained by condensation of amine III and silicon alkoxydes under hydrolytic conditions. The homogeneous transparent gel obtained was then dried to obtain a white powder, which was contacted with the mixture of gases. Figure 6 shows the absorption/desorption cycle for a xerogel contacted with a gas mixture containing CO2. Several cycles were run in a closed loop. The absorption/desorption was very fast and reproducible.

25 =

•

20

,X . . . . .

e

E ,,,

15

0 rd

10

X 5

absorption

- - -X- - - d e s o r p t i o n

0

20

40

60

80

100 120 140 160

Time (rain) F i g u r e 6: Absorption/desorption of CO2 from a N2/CO2 gas mixture by using xerogel

The limiting factor of this system is the temperature used for drying the xerogel. In fact, the xerogel was able to take up carbon dioxide only if it was dried under vacuum at room temperature. Conversely, if it was dried by heating to 323 K, the xerogel did not absorb CO2. It is worth noting that at 323 K, the gel becomes opaque and the colour changes form white to yellow. The presence of the amine in the xerogel is crucial for cyclic up-take/release of CO2. In fact, if only Si(OR)4 was hydrolysed, the resulting material was not able to absorb cyclically CO2. ACKNOLEDGEMENTS This work was supported by the CNR Grant Agenzia 2000, Contract CNRC008BF and Ministry of University, Contract MM03027791. The authors thank Ms. Roberta Girardi for experimental assistance. REFERENCES 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12.

Bishnoi,S., Rochelle, G. T. (2000), Chem. Eng. Sci., 55, 5531. Rangwala,H.A. (1986)J. Membr. Sci., 112, 229. Byota, D. A. (1974) US Patent 3 847 837 Bhide, B.D., Stem, S.A. (1993) J. Membr. Sci., 81,209. RUCADI Project, BRRT-CT98-5089, (2002), final report. Bates, E. D., Mayton, R. D., Ntai, I., Davis, J. H. (2002) J. Am. Chem. Soc. Chem. Commun., 124, 926. Chakravarty, T., Phukan, U.K, Weiland, R.H. (1985) Chem. Eng. Prog., 81, 32. Glasscock,D.A., Critchfield, J.E., Rochelle, G.T. (1991) Chem. Eng. Sci., 46, 2829. Dibenedetto,A., Aresta, M., Narracci, M. 223rdACS National Meeting, April 7-11, 2002, Orlando Florida. Aresta, M., Ballivet-Tkatchenko, D., Belli Dell'Amico, D., Bonnet, M.C., Boschi, D., Calderazzo, F., Faure, R., Labella, L., Marchetti, F. (2000) Chem. Commun. 13, 1099. Aresta, M., Ballivet-Tkatchenko, D., Bonnet, M.C., Faure, R., Loiseleur, H. (1985) J. Am. Chem. Soc. 107, 2994. Dibenedetto,A., Aresta, M., Narracci, M., Fragale, C. (2002) Green Chemistry in press

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1603

CARBON DIOXIDE ABSORPTION WITH AQUEOUS POTASSIUM CARBONATE PROMOTED BY PIPERAZINE J. Tim Cullinane and Gary T. Rochelle Department of Chemical Engineering, The University of Texas at Austin Austin, Texas 78752, USA

ABSTRACT This paper presents thermodynamic and kinetic data collected for aqueous blends of piperazine (PZ) and potassium carbonate (K2CO3). Mixtures of K + and PZ have been investigated in a wetted-wall column at 40 to 80°C, typical conditions for an industrial absorber. The addition of 0.6 m PZ to 20 wt% (3.6 m) K2CO3 increases the rate of CO2 absorption by a factor of ten from the value in unpromoted solutions at 60°C. The addition of PZ increases the heat of absorption from 4 kcal/mol in 3.6 m K + to 10 kcal/mol when 0.6 m PZ is added. The capacity, ranging from 0.4 to 0.7 molCO2/kg-H20, approaches that of monoethanolamine (MEA) solutions and seems to be a strong function of K ÷ concentration. Speciation of the solution was obtained using proton nuclear magnetic reasonance (NMR), verifying and quantifying the presence of three PZ species. An equilibrium model and a rate model were developed to predict system speciation, equilibrium, and CO2 absorption rate. The model predicts that 3.6 m K + increases the specific rate constant of PZ by a factor of five from its value in water.

INTRODUCTION Amine and potassium carbonate solvents have proven useful for the removal of CO2 from natural gas and H2. Researchers have shown that blending amines accelerates the absorption process [ 1,2,3]. Others have investigated amine/K2CO3 blends with some success [4,5]. This work focuses on promoting K2CO3with PZ, a cyclic diamine. Previous research indicates that PZ is an effective promoter in methyldiethanolamine (MDEA) and monoethanolamine solutions [2,3]. Piperazine is expected to accelerate absorption rates while K2CO3 retains a low heat of absorption. Also, the reaction of carbonate in bulk solution is expected to improve solvent capacity.

METHODS AND RESULTS

Speciation Proton and carbon-13 NMR were used to determine the distribution of piperazine (PZ), piperazine carbamate (PZCOO-), and piperazine dicarbamate (PZ(COO-)2) at equilibrium as a function of CO2

1604 loading (Figure 1). Piperazine carbamate and PZ(COO-)2 do not exist at low loading. As loading increases, the relative amount of PZCOO- goes through a maximum and PZ(COO-)2 becomes an important species. Even at a high CO2 loading, P Z C O O remains a significant portion of the piperazine species. Temperature, from 25 to 60°C, was found to have a minimal effect on the speciation; however, free PZ concentrations generally increase as temperature increases. 100

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Equilibrium and Absorption Rates The rate of C02 absorption and solubility of CO2 were determined by contacting a N2:CO2 gas mixture with the solvent in a wetted-wall column [6]. The rate was interpreted as normalized flux, kg', which can be defined as

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Figure 2 summarizes the normalized flux of CO2 absorption as measured. Adding 0.6 m PZ to 3.6 m K + increases the rate of CO2 absorption by a factor of ten at 60°C. The rate of this solvent approaches that of 5 M MEA at both 40 and 60°C. At a rich loading, 3.6 m K+/0.6 m PZ solutions also compare favorably to MDEA/PZ blends [2] and DEA- and hindered amine-promoted systems [4]. The potassium concentration was shown to have little affect on the absorption rate [7]. At a constant CO2 vapor pressure, increasing the temperature from 40 to 80°C increases the normalized flux by a factor of two [7]. The heat of absorption of CO2, AHabs, was estimated from the temperature dependence of the CO2 solubility. The addition of 0.6 m PZ to 3.6 m K + increases AHabs from 3.7 [8] to 10.5 kcal/mol. A decrease in loading at an equivalent concentration increases AHabs from 10.5 to 14.0 kcal/mol, most likely due to differences in the heats of absorption of PZ and PZCOO. With a comparable loading and PZ concentration, a 4.8 m K ÷ solution has a slightly decreased AHabs of 10.2 kcal/mol.

1605 The solvent capacity of PZ/K2CO3 solutions varies significantly with concentration. Over a partial pressure range of 330 to 3300 Pa at 60°C, a 3.6 m K + solution has a capacity of approximately 0.4 m. The addition of 0.6 m PZ to 3.6 m K + at similar conditions increases the capacity to 0.5 m. An increase in potassium concentration to 6.2 m increases the solvent capacity to 0.73. The capacities of solutions containing large amounts of K + compare favorably to amine solvents such as 5.0 M MEA (0.81 m) and 0.6 M PZ/4.0 M MDEA (0.78 m) [2].

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A simple thermodynamic model was developed to predict equilibrium and speciation in promoted K2CO3. The model simultaneously solves equilibrium expressions, total mole balances, and a charge balance. Using an un-promoted K2CO3 solution at 60°C as a starting point, equilibrium constants were adjusted to fit model predictions to experimental data with high potassium concentrations. Adjusted constants were represented by the product of the original equilibrium constant and an adjustment factor. Using a least squares regression of the model predictions, the equilibrium constants were altered such that the model fits smoothed Pco2* data at 60°C as extrapolated from Tosh et al. [8]. For a 20 wt% K2CO3 solution, no adjustment was necessary [6]. When compared to 30 wt% K2CO3, the equilibrium constants required a large adjustment demonstrating non-idealities associated with high ionic strength [6]. A similar procedure was followed to match data for the speciation of PZ in the solutions, with each equilibrium constant treated independently. For a 20 wt% K2CO3 solution containing 0.6 m PZ at 60°C, the equilibrium constants were adjusted by matching predictions to NMR speciation data such that the constant for PZ to PZCOO- and the constant for PZCOO to PZ(COO)2 were 75 and 70% of their original values, respectively [6]. The continuous lines in Figure 1 are predictions of the equilibrium model. Throughout the range of loading the model performs well, although there is a slight discrepancy at high loading.

1606 A rate model capable of predicting the flux of CO2 into promoted potassium carbonate solutions was also developed [2,6]. Using a non-linear regression method, the rate model predictions were fit to experimentally determined fluxes by adjusting the rate constants present in Equation 2. The results of the regression and values obtained by Bishnoi [2] for aqueous PZ and MDEA/PZ mixtures are shown in TABLE 1. Rate constants of PZ and PZCOO- used in the model contained temperature dependence (AHa) in the form of an Arrhenius expression based on 298K.

r = {kt,z_on_ [PZIOH-]+ kez [PZ] + kezco o_ [PZCO0- ]}[CO2 ]

(2)

It was found that a low-loading interaction term (kpz-oH) w a s necessary to accurately predict CO2 absorption rates in aqueous K2CO3. With its inclusion, the PZ rate constant is increased by a factor of five from its value in water as reported by Bishnoi [2]. The PZ-hydroxide term at a high concentration of hydroxide, 0.45 M, in 3.6 m K + gives an apparent rate constant 22 times faster than in water. The rate constant for PZCOO- gives satisfactory results when its value in 4.0 M MDEA is used [2]. Previous research suggests the accelerated rate behavior is a result of a catalytic effect of carbonate or of increased ionic strength [4,5,9,10]. Regardless of the mechanism, relative rate constant values show that the CO2-PZ reaction is much faster than the CO2-MEA reaction (kMEA° = 7000 m3/kmol-s) [2].

TABLE 1 SPECIFIC RATE CONSTANTS AT 25°C REGRESSED FROM VARIOUS RATE EQUATIONS, AHA = 3.36E4 KJ/MOL FOR PIPERAZINE AND PIPERAZINE CARBAMATE [2] kpz.OH°

(m6/krnol2-s) [2] 0.0 This Work 2.69e6"* * Not Regressed ** AHa = 0 kJ/mol

kpz °

kpzcoo -°

(m3/kmol-s) (m3/kmol-s) 5.38e4 4.70e4 2.85e5 4.70e4"

As shown by the comparison to 5 M MEA, PZ is an effective promoter of CO2 absorption in aqueous K2CO3. Analysis of equilibrium data indicates that the AHabs of CO2 increases with the addition of PZ to aqueous potassium carbonate. Model predictions indicate that capacity is nearly independent of PZ concentration; conversely, an increase in K2CO3 yields a larger increase in capacity. Proton NMR suggests that PZCOO- is the dominant species at high loading; consequently, it is responsible for most of the reaction rate. Given that PZ reacts much faster than the PZCOO, loading should have a significant effect on absorption rates. REFERENCES

1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Bosch, H., Versteeg, G. F., and Van Swaaij, W. P. M. (1989) Chem. Eng. Sci. 44, 2745. Bishnoi, S. (2000) Ph.D. thesis, The University of Texas at Austin, Austin, TX. Dang, H. (2001) M.S. thesis, The University of Texas at Austin, Austin, TX. Sartori, G. and Savage, D. W. (1983) Ind. and Eng. Chem. Fund. 22, 239. Tseng, P. C., Ho, W. S. and Savage, D. W. (1988) AIChE. J. 34, 922. Cullinane, J. T. (2002) M.S. thesis, The University of Texas at Austin, Austin, TX. Cullinane, J. T. and Rochelle, G. T. Submitted to Chem. Eng. Sci. July 2002. Tosh, J. S., Field, J. H., Benson, H. E. and Haynes, W. P. (1959) U.S. Bureau of Mines, 5484. Laddha, S. S. and Danckwerts, P. V. (1982) Chem. Eng. Sci. 37, 665. Pohorecki, R., Xoan, D. T. and Moniuk, W. (1988) Inz. Chem. Proc. 9, 667.

G E O L O G I C A L STORAGE

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1609

EFFECT OF PRESSURE, TEMPERATURE, AND AQUEOUS CARBON DIOXIDE CONCENTRATION ON MINERAL WEATHERING AS APPLIED TO GEOLOGIC STORAGE OF CARBON DIOXIDE Robert G. Bruant Jr. l, Daniel E. Giammar 2, Satish C. B. Myneni 2, and Catherine A. Peters ~ ~Program in Environmental Engineering and Water Resources, Department of Civil and Environmental Engineering, Princeton University, Princeton, New Jersey 08544 2Department of Geosciences, Princeton University, Princeton, New Jersey 08544

ABSTRACT

CO2 mediated dissolution of silicate minerals and subsequent precipitation of carbonates in deep saline aquifers may allow permanent trapping of carbon dioxide. However, the time-scales and extents of the reactions are poorly understood for CO2 receptor formation conditions. To address these shortcomings, experiments were conducted to investigate the effects of pressure, temperature, and aqueous solution composition on rates and mechanisms of silicate mineral dissolution and carbonate precipitation. A high pressure/high temperature flow-through reactor system was used to derive steady-state dissolution rates of crushed forsteritic olivine. The system allowed continuous monitoring of temperature, pressure, and pH, and periodic sampling of effluent fluids for dissolved ion concentration analysis. Preliminary measurements of dissolution rates indicate good agreement with previously published measurements at ambient conditions. Increasing the pressure from 1 to 100 bar under constant CO2 conditions increased the dissolution rate by ---80%. The same reactions were studied in batch systems using an array of analytical techniques to investigate dissolution mechanisms and secondary precipitate formation. The extent of olivine dissolution in the batch reactors increased with temperature, Pco2 and surface area. Precipitation of magnesium-rich carbonates on reacted olivine was observed at initial magnesite saturation indices greater than 1.6.

INTRODUCTION AND B A C K G R O U N D

Deep (> 1 km) saline aquifer storage of CO2 is a carbon mitigation option that is receiving considerable attention (e.g., [ 1,2]). Associated dissolution of silicate minerals and precipitation of carbonates in receptor formations may allow near-permanent trapping of CO2. While an extensive body of work has been published regarding mineral weathering rates and mechanisms in ambient environments (e.g. [4,5]), less consideration has been given to these topics for conditions present in deep subsurface formations. Mineral reaction rates are often expressed using a simple rate law (e.g., Eqn. 1), accounting for effects ofpH, temperature, and reaction affinity:

r=koe-Eo/RT{H+}n#+(I_e'~Gr/RT),

(1)

where r is the reaction rate, ko is the intensive rate constant, E~ is the apparent reaction activation energy, R is the molar gas constant, T is the absolute temperature, {/-/+} is the hydrogen ion activity (= 10PH), nn+ is

1610 the order of the reaction with respect to the hydrogen ion activity, and AGr is the Gibbs free energy of the reaction [3]. In general, dissolution rates for silicate minerals will be higher at the high temperature and low pH conditions relevant to geologic storage of carbon dioxide than at ambient ground surface conditions. However, effects of pressure and CO2 concentration on dissolution rate are not well understood and not explicitly accounted for in most rate laws. A high pressure/high temperature flow-through reactor system was used to elucidate these effects on the steady-state dissolution rate of forsteritic olivine. Olivine was chosen as a model silicate mineral due to its well-constrained stoichiometry, documented congruent dissolution, and relatively fast reaction rate at ambient conditions. The weathering of Ca- Mg-, and/or Fe(II)-rich silicate minerals in the presence of carbon dioxide offers the potential for formation of carbonate minerals. For example, weathering of forsterite has produced high yields of magnesium carbonate (i.e., magnesite) in aqueous reactors engineered for direct mineral carbonation [6,7]: Mg2SiO4(s) + 2C02(aq) = 2MgCO3(s) + Si02(s). Such mineral reactions may also allow permanent in-situ trapping of CO2 in deep saline aquifers. While it is understood that the spontaneous precipitation of a mineral phase is related to the solution saturation index,

SI: SI - Log,o

),

(2)

where Q is the reaction quotient and Keq is the equilibrium constant, such indices are not well quantified for carbonate mineral formation at CO2 receptor reservoir conditions. High pressure/high temperature batch reactors were used to generate aqueous and solid samples for observation of primary mineral alteration and determination of conditions necessary for secondary mineral precipitation.

MATERIALS AND METHODS

Flow-Through System A 500 cm 3 reaction vessel and 790 cm 3 water/CO2 contacting vessel were constructed from 316 grade stainless steel; all other system materials were chosen for pressure tolerance and inertness (Figure 1). The system had a maximum operating pressure and temperature of 100 bar and 100°C, respectively. Influent water, transferred directly from a deionized water source, was stored in a polyethylene carboy under a He atmosphere. For each experiment, --1.6 g of 53-106/an size fraction San Carlos forsteritic olivine (Fo90, (Mg0.90Fe0.t0)2SiO4) with a specific surface area of---0.15 m E g-i was added to the reaction vessel. System temperature, maintained at 40°C, and influent/effluent pH were continuously monitored. Olivine dissolution rates were inferred from the effluent aqueous concentrations of magnesium, iron, and silicon, the volumetric flow rate, and the total mineral surface area. A suite of four independent experiments was conducted (Table 1). The pH was stabilized at 3.1 by direct addition of HCI to the influent water reservoir. The water/CO2 contacting vessel was used to equilibrate the aqueous influent solution with a pure CO2 headspace (Pco2 = 1 and 100 bar); no CO: delivery to the contacting vessel occurred for CO:-free (i.e., Pco2 = 0) experiments.

Batch System Batch reactions were performed in sealed Teflon-lined digestion bombs and in a Teflon-lined valved reactor (Figure 1). Digestion bombs used dry ice to generate pressure (Pr = Pco2), while a high-pressure syringe pump provided pressure control for the valved reactor. Batch experiments with two size fractions of Fo90 (20-50/zm and 125-250/zm) were conducted at 1 and 100 bar Pco2, a range of temperatures (30, 40, and 95°C), and a range of initial solution compositions. Solution compositions were selected to investigate the influence of common saline aquifer species on the weathering process and to probe the effect of saturation

1611

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Experiment Pr Pco2 pH

1 1 0 3.1

2 100 0 3.1

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4 100 100 3.1

state on magnesite nucleation and growth. At each set of experimental conditions, a time series of reactions was run to follow the progress of solid phase alteration.

Analytical Techniques Filtered aqueous samples from flow-through and batch experiments were acidified and analyzed for concentrations of dissolved magnesium, iron, and silicon with inductively coupled plasma optical emission spectroscopy. Surface areas of unreacted and reacted solids were measured by BET-N2 adsorption. Unreacted and reacted solids were also characterized with X-ray diffraction, diffuse reflectance infrared spectroscopy, and scanning electron microscopy with energy dispersive X-ray analysis.

PRELIMINARY RESULTS AND DISCUSSION Steady-state forsteritic olivine dissolution rates determined from preliminary flow-though experiments agree well with previously published rates (e.g., [4,5]). The average dissolution rate at Pr = 100 bar (1.68 x 10-12 mol cm -2 s-1) is ---1.8 times greater than that at 1 bar. The effect of CO2 on dissolution rate is inconclusive; replicate experiments are currently underway for error analysis. The extent of olivine dissolution in the batch reactors increased with increasing temperature, Pco2 (i.e., decreasing pH), and surface area. Although dissolution was generally congruent, Fe(II) released during dissolution oxidized and a Fe(III) solid (most likely hematite) precipitated at temperatures above 30°C. Iron dissolution pits and surface-associated clusters of iron-rich precipitates were observed on the coarser olivine fraction; less pitting was observed in the finer fraction. Measured aqueous magnesium concentrations and scanning electron micrographs (Figure 2) from ten-day batch dissolution experiments conducted at five initial magnesite saturation indices (Pr = Pco2 = 100 bar, T =

1612 95°C; Slinit = 0.74, 1.64, 2.28, 2.64, 3.09) indicate precipitation of magnesite on reacted olivine for indices > 1.64. Increasing degrees of magnesite precipitation occurred with increasing saturation indices.

Figure 2: Scanning electron micrographs of forsteritic olivine reacted for 10 days at days at 95°C and 100 bar Pco2 in solutions with varying initial saturation indices for magnesite. Arrows identify magnesite crystals in images with small amounts of precipitation. REFERENCES Bachu, S. (2001). In Geological Perspectives of Global Climate Change, pp. 285-303, Gerhard, L.C., Harrison, W.E., and Hanson, B.M. (Eds). American Association of Petroleum Geologists, Tulsa. Bruant, R. G., Jr., Guswa, A. J., Celia, M. A. and Peters, C. A. (2002). Environ. Sci. Technol. 36, 241A. Lasaga, A. C. (1995). In Chemical Weathering Rates of Silicate Minerals, Vol. 31, pp. 23-86, White, A. F. and Brantley, S. L. (Eds). Mineralogical Society of America, Washington. Wogelius, R. A. and Walther, J. V. (1991). Geochim. Cosmochim. Acta 55, 943. Pokrovsky, O. S. and Schott, J. (2000). Geochim. Cosmochim. Acta 64, 3313. Guthrie, G. D. J., Carey, J. W., Bergfeld, D., Byler, D., Chipera, S., Ziock, H.-J. and Lackner, K. (2001). Geochemical Aspects of the Carbonation of Magnesium Silicates in an Aqueous Medium. First National Conference on Carbon Sequestration. U.S. DOE, Washington. O'Connor, W. K., Dahlin, D. C., Nilsen, D. N., Rush, G. E., Waiters, R. P., and Turner P. C. (2001, Carbon Dioxide Sequestration by Direct Mineral Carbonation: Results from Recent Studies and Current Status. First National Conference on Carbon Sequestration. U.S. DOE, Washington. Wogelius, R. A. and Walther, J. V. (1992). Chem. Geol. 97, 101.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1613

ADVANCED CENTRIFUGAL COMPRESSORS FOR CO2 RE-INJECTION PLANT Akinori Tasakil, Tsunenori Satol, Norihisa Wada 1 ~Turbo-machinery Engineering Department, Hiroshima Machinery Works Mitsubishi Heavy Industries Ltd., 6-22, 4-Chome, Kan-on Shin-machi, Nishi-ku, Hiroshima 733-8553 Japan

ABSTRACT Today, we are dependent on hydrocarbons such as oil and natural gas, that are easily handled, for the majority of our energy requirements. As we burn these hydrocarbons, carbon dioxide (CO2) gas is produced. It is well recognized that CO2 gas is one of the main causes of recent temperature rises in the atmosphere, which is known as "the greenhouse effect". In recent years, not only the technology to save energy and thereby reduce CO2 emissions, but also that to get rid of unwanted CO2, has become prominent. This paper presents and explains the centrifugal compressors developed for CO2 re-injection below ground, as a practical solution to the problem of what to do with unwanted and harmful CO2.

INTRODUCTION The In Salah Gas Project is a joint venture of Sonatrach and BP Exploration Limited set up to produce natural gas from the Algerian Southern Sahara. One of the main environmental initiatives adopted by the In Salah Gas Project to limit greenhouse gas emissions has been to re-inject CO2 removed from natural gas, back into the production reservoir. As a result, the CO2 re-injection compressor manufacturer has had to demonstrate that he has prioritised HSE (Health, Safety and Environment) in all aspects of his design and production activities of this project. This paper describes the features of Mitsubishi Advanced Compressors (MAC) that have been applied as part of the main equipment for this epoch-making plant. Considering their purpose, several unique characteristics applied to these compressors are described.

1614

TRAIN ARRANGEMENT For the driver, a double end drive motor with soft starter was applied, considering environmental and user-friendly issues. Figure 1 shows the train arrangement of this plant. Two main advantages can be seen: Gear losses are minimized by this arrangement; this arrangement allows easy maintenance from both ends on each high pressure and low-pressure compressor.

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Figure 1: Train arrangement of this project STRUCTURE OF COMPRESSOR With its optimized design, MAC ensures several HSE friendly aspects, namely high efficiency, a wide operating range, high stability, stable vibration and easy maintenance. Figure 2 shows a cross section drawing highlighting the main features of MAC. Compared with the CO2 compressors supplied by MHI so far, the compressors applied for this project will be some of the largest centrifugal compressors in operation, when considering the following: 1) Discharge pressure:

203 bar

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1615

High Efficiency and Wide Operating Range for Saving Energy All impellers have optimized 3-dimensional profiles and are designed in conjunction with stationary parts, which come into contact with the gas flow path. As a result, for example, 85% polytropic efficiency at the 1st stage is achieved. Dry gas seals are installed in all compressors. Dry gas seals minimize gas leakage from the compressor and eliminate the need for a seal oil console.

High Stability Against Shaft Vibration In order to provide high stability against shaft vibration, direct lubrication beatings, an overhung damper and swirl canceled labyrinth seals are installed in the compressors. These combined countermeasures achieve a reduction in exciting force and an increase in damping ability.

Easy Maintenance Vertical split type compressors are applied for these re-injection compressors. With this arrangement, overhaul of the compressors can be done without removal of the main process gas piping. Cartridge-type internal bundles, fixed with shear tings, facilitate maintenance and shorten the time needed for disassembly and reassembly. Special tools for disassembly and reassembly are also prepared, based on safety considerations.

COz Property under High-pressure Condition For CO2 compressors, it is very difficult to predict the gas property, because CO2 gas shows a specific nature, which differs from an ideal gas under, high-pressure. Since Mitsubishi has extensive experience of designing and manufacturing CO2 compressors for UREA plants, actual compressor thermodynamic performance has been well documented in accordance with shop test data up to 235bar, as well as site operation data. From this data, MHI has a better handle on predicting CO2 gas properties over a wide operating range, and can achieve adequate compressor design accordingly.

For this project, the compressor performance will be further

confirmed under full load and full pressure conditions during testing at Mitsubishi's Hiroshima factory.

Elimination of Impeller Resonance Vibration For an impeller operating in high-density gas (a CO2 compressor yields a very high density at the final discharge section, and specific gravity of the gas can be one-third that of water), the effects of virtual mass and damping of the fluid, must be taken into account.

The natural frequency of the impeller in a

high-density gas was obtained by analysis. The results showed that the natural frequency could be significantly lowered to about 64% of that which exists in normal atmosphere. This reduction ratio is introduced as a factor into the design of the impeller.

Soft Start Operation As this site is in a rather isolated location the grid power supply cannot sustain high current demands for long periods. As a result, during the compressor drive motor start-up, a significant reduction of available electricity voltage may occur locally and cause problems for other electric equipment. To prevent this, a soft starter system, i.e. frequency control system, has been applied, limiting the electric current during start up to below

1616 the rated current. This sot~ starter system is shared by two 12MW compressor drive motors. FULL LOAD, FULL PRESSURE STRING TEST Finally all characteristics of these re-injection compressors are going to be verified by the "Full load, Full Pressure String Test" at Mitsubishi's Hiroshima factory, using a closed loop test facility as shown in Figure 3. Not only the mechanical properties but also thermodynamic performance, instability of rotors in very high-density gas, and noise characteristics will be measured to prove adequate performance of these compressors before shipment.

Gas turbine drive string test Steam turbine drive string test Electric motor drive string test Full load I full pressure test

25 MW 14.5 MW 14 MW 450 kglcm2g

Fig. 3: Large size compressor test stand REFERNCES In-Salah Gas pamphlet (not dated) text by Mike Wells Nojima, N., Kanki, H., Morii, S., Kaneko, A., Kawashima, Y. (Oct. 1994) MHI Technical Review Vol. 31 No.3

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1617

REACTIVITY OF INJECTED CO2 WITH THE USIRA SAND RESERVOIR AT SLEIPNER, NORTHERN NORTH SEA I. Czernichowski-Lauriol 1, C.A. Rochelle2, E. Brosse 3, N. Springer 4, K. Bateman 2, C. Kervevanl, J.M. Pearce 2, B. Sanjuan 1, and H. Serra 1 1BRGM, French Geological Survey, av. Claude Guillemin, BP6009, 45060 Orleans Cedex 2, FR 2 British Geological Survey, Kingsley Dunham Centre, Keyworth, Nottinghamshire. NG12 5GG, UK 3 Institut Francais du Prtrole, 1 et 4 Av. de Bois-Prrau, 92852 Rueil-Malmaison, FR 4 Geological Survey of Denmark and Greenland, Oster Voldegaade 10, 1350 Copenhagen K, DK

ABSTRACT

The chemical reactivity of CO2 with a host formation has to be assessed in any CO2 geological sequestration project, as it may affect injection operations and long term CO2 storage potential. At the Sleipner gas field (Norwegian sector of the North Sea), CO2 has been injected since 1996 into a deep saline aquifer (Utsira formation) approximately 1 km below the bed of the North Sea. This paper summarizes results of the geochemical work carried out as part of the 'Saline Aquifer CO2 Storage' (SACS) project, a European research project which aims to monitor the injection operations at Sleipner.

INTRODUCTION The objective of the geochemical work within the SACS project was to determine the potential for chemical reactions between injected CO2, formation water and the reservoir rock (Utsira sand), as these reactions may affect injection operations and long term CO2 storage potential [ 1,2]. For example, besides being trapped as a buoyant supercritical CO2 'bubble' (physical trapping), geochemical reactions with reservoir rock and formation water can trap the CO2 as a dissolved phase (solubility trapping), as bicarbonate ions and complexes (ionic trapping), and carbonate minerals (mineral trapping), according to a terminology derived from Bachu et al. [3]. This can enhance the CO2 storage capacity and have consequences on CO2 migration or immobilisation. A direct approach was used, based on laboratory experiments reacting samples of Utsira sand and formation water with CO2 under simulated reservoir conditions for timescales up to 24 months. Work was divided into three tasks: (i) determination of the initial state of water-rock interaction within the Utsira formation prior to CO2 injection, (ii) laboratory experiments on actual Utsira material, (iii) numerical modelling for the interpretation of the experiments. Such laboratory investigations are particularly useful for the study of shorter-term processes. Although limited in scale and timeframe, laboratory experiments have the advantage that they can help to identify the key geochemical reactions on actual rock material under actual reservoir conditions, which is very important as such reactions are known to be highly site-specific. They are also helpful to test the ability of geochemical codes to reproduce the experimental observations before using them to make long term predictions over experimental timescales up to thousands of years.

1618 BASELINE GEOCHEMICAL CONDITIONS PRIOR TO CO2 INJECTION Knowledge of the 'baseline' conditions of mineralogy, fluid chemistry and water-rock interaction prior to CO2 injection is essential as they provide a reference point from which changes due to the presence of CO2 can be compared and assessed. They are also used to define the experimental conditions, which should reproduce, as closely as possible, actual reservoir conditions. Figure 1 summarizes the geochemical data available at the time of the project. The core sample at Sleipner allowed for detailed mineralogical analyses and determination of transport properties. However, it was heavily contaminated by drilling fluids, and no useable formation water sample could be obtained from it. Only one borehole terminates in the Utsira at Sleipner (the CO2 injection borehole), and unfortunately no produced porewater samples were available from it. The only information about formation fluid chemistry comes from the Oseberg and Brage fields approximately 200 km north of Sleipner.

SLEIPNER • 37~, 8-11 MPt~ 35.40 g/I • 1 m ;RT¢ ( ~ 1-r~J-A23) •

nil,non° fluidrraJd)data(core ~E~=t~ is highly contaminatedby

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Figure 1: Baseline geochemical data from the Utsira Formation available during the SACS project Despite the scarcity on data and samples, a reasonable assessment of baseline conditions within the Utsira sand was made by combining information from the Sleipner, Oseberg and Brage hydrocarbon fields. A roughly homogeneous porewater chemical composition throughout the Utsira formation was reasonably assumed and the decision of using the Oseberg analysis as representative of the Utsira formation is presently an acceptable compromise. However, the need for acquiring new data and samples was emphasized.

LABORATORY EXPERIMENTS A range of experiments have been conducted in either 'batch' and 'flow through' equipment to react samples of Utsira sand from Sleipner with a synthetic Utsira porewater based upon a composition from the Oseberg field. A schematic diagram of the batch reactor is presented on Figure 2. The experimental conditions chosen were mainly 37°C and l0 MPa (in-situ temperature and pressure in the Utsira formation at Sleipner), though some experiments were run at 70°C and 10 MPa to enhance the rates of reaction. Durations ranged from one week to two years. Experiments were pressurised with either nitrogen or carbon dioxide. The former 'blank' experiments provided a 'non reacting' reference point from which to compare

1619 the more reactive experiments containing CO2. However, they also helped provide confidence in the baseline conditions within the Utsira formation prior to CO2 injection. The CO2 experiments provided direct information on how CO2 reacted with the Utsira sand and its porewater.

CO2 inlet

H20 outlet

Figure 2: Schematic diagram of the batch reactor used for SACS experiments These experiments have revealed changes in fluid chemistry associated mainly with dissolution of primary minerals. However, direct evidence from mineralogical observations has never been possible despite the high water-rock ratio used for these experiments (10:1), their relatively long duration (up to 2 years) and the higher temperature (70°C) used for some of them. This is because changes were below the resolution of the analytical technique or below the natural mineralogical variation within the sand.

NUMERICAL M O D E L L I N G OF THE EXPERIMENTS Several 'off the shelf' and 'custom-made' geochemical codes were used for this study. The modeling did confirm that the main observed changes in fluid chemistry are associated mainly with the dissolution of minerals. Ion-exchange processes on clays do not seem to be significant. The main reaction observed from the analytical data in the batch and coreflood experiments at 37 and 70°C and confirmed by geochemical modelling is the fast dissolution of carbonate phases (calcite and probably shell fragments) in presence of pressurised CO2. However this mineral is not fully dissolved at the end of the CO2 experiments. As the Utsira sand porosity is approximately 40% and as the carbonate minerals constitute 3.9% of the total rock volume, overall porosity will be little affected by the partial dissolution of calcite. The modelling also confirms that dissolution of silicate and aluminosilicate minerals is a much slower process that is enhanced by CO2. As an illustration, the behaviour of dissolved calcium in the blank and CO2 experiments at 37°C is presented on Figure 3, with comparison of the analytical and modelling results. The best fit was obtained by varying sligthly the solubility of calcite by AlogK = -0.3, which enters the uncertainty range of the determination of this thermodynamic constant.

1620 Total dissolved

calcium

Effect o f t h e u n c e r t a i n t y o n t h e t h e r m o d y n a m i c c o n s t a n t o f c a i c i t e d i s s o l u t i o n (A l o g K = - 0 . 3 )

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Measured Ca (CO2) Measured Ca (Oseberg) Modelled Ca (blank), IogK37°Ccalcite = 1.67 - 0.3 Modelled Ca (CO2), IogK37°Ccalcite = 167 - 0.3

Figure 3" Behaviour of dissolved Ca concentrations during the SACS batch experiments reacting Utsira sand with CO2 at reservoir temperature and pressure (37°C, 10 MPa). CO2 experiment" pressurised with CO2 Blank experiment: pressurised with N2 CONCLUSIONS This study appears to show that observed CO2-water-rock reactions have resulted in relatively little dissolution of the Utsira sand. Most reaction occurred with carbonate phases (shell fragments), but these were a very minor proportion (about 3%) of the overall solid material. Silicate and aluminosilicate minerals showed only slow, and minor reaction. In terms of geochemical reactions, the Utsira sand would appear to be a good reservoir for storing CO2. However further studies are needed to assess the long term storage behaviour within the Utsira formation, and investigate the reactivity of CO2 with the impermeable rocks (caprocks) above the Utsira formation.

REFERENCES Czernichowski-Lauriol, I., Sanjuan, B., Rochelle, C., Bateman, K., Pearce, J. and Blackwell, P. 1(996a). In: Deep Injection Disposal of Hazardous and Industrial Wastes, Scientific and Engineering Aspects, pp. 565-583, J.A. Apps and C.-F. Tsang (Eds), Academic Press, ISBN 0-12060060-9. Czernichowski-Lauriol, I., Sanjuan, B., Rochelle, C., Bateman, K., Pearce, J. and Blackwell, P. (1996b). In: The Underground Disposal of Carbon Dioxide, Chapter 7, S. Holloway (Ed.), Final Report of Joule II Project Number CT92-0031, British Geological Survey. Bachu S., Gunter W.D. and Perkins E.H. (1994). Energy Conversion and Management 35, pp. 269279.

ACKNOWLEDGEMENTS We acknowledge funding by the SACS consortium (Statoil, BP, Exxon, Norsk Hydro, TotalFinaElf and Vattenfall), the European Commission, and national governments. Other project partners are S1NTEF and NITG-TNO.

Greenhouse Gas Control Technologies, Volume lI J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1621

CARBON DIOXIDE SEQUESTRATION IN SALINE BRINE FORMATIONS John M. Andrrsen, Matthew L. Druckenmiller, and M. Mercedes Maroto-Valer The Energy Institute and Dept. Energy & Geo-Environmental Engineering, The Pennsylvania State University, 209 Academic Projects Bldg., University Park, PA 16802. e-mail: [email protected]

ABSTRACT Although brine formations have the largest potential capacity for permanent CO2 sequestration in geologic formations, little is known about the mechanisms of storing CO2 as mineral carbonates in brine. Accordingly, this study focuses on the kinetics of mineral carbonate formation using high-pressure thermogravimetric analysis that mimics the actual conditions found in saline brine formations. The transformation of gaseous CO2 into stable carbonates was investigated at various pressures and temperatures. When considering pressures between 200 and 600 psi and temperatures between 50 and 75°C, the experimental conditions are equivalent to those attainable through CO2 injection into shallow oil and gas wells.

INTRODUCTION Carbon dioxide emissions from US national energy consumption are estimated to increase at an average annual rate of 1.5 percent, from 1,562 million metric tons carbon equivalent in 2000 to 2,088 million in 2020 [1]. Sequestration of CO2, where the greenhouse gas is firstly captured and secondly stored in a permanent medium, could be a viable option to mitigate CO2 emissions [2]. Although CO2 sequestration is not yet an industrial practice in the United States, there exists potential large scale opportunities, such as sequestration in geologic formations that includes solubility trapping, hydrodynamic trapping, and carbonate conversion through reactions with minerals and organic matter [3]. The principle of the carbonation process includes the formation of stable calcium, magnesium, and iron carbonates that are solids and will be stored permanently in the crust of the earth [4]. The minerals necessary for the formation of these carbonates are abundant in saline brine formations, which are widely spread across the United States [5]. There exist three principal methods for sequestering CO2 in geologic formations. First, CO2 gas can be dissolved in underground liquids such as petroleum; a method known as solubility trapping. A second method known as hydrodynamic trapping exists, in which a cap rock can be used to trap CO2 as either a gas or as a fluid. Finally, CO2 may be converted to a solid through reactions with minerals and organic matter. The latter mineral trapping process includes the formation of stable calcium, magnesium, and iron carbonates [6]. This option could lead to a storage route for anthropogenic CO2 emissions without any environmental legacy to future generations. Although brine formations have the largest potential capacity for CO2 sequestration in geologic formations [7], little is known about the kinetics of trapping CO2 in mineral carbonates and is therefore the focus of this study.

1622 BODY OF PAPER

Experimental The brine sample used in this experiment was taken directly from a Pennsylvania gas well and underwent no treatment. The sample was analyzed for carbonate forming elements using an inductively coupled plasma (ICP) emission spectrophotometer. A thermogravimetric analyzer, CAHN TGA-151, was used to simulate conditions in saline aquifers associated with shallow oil and gas wells by varying both pressure and temperature. Brine samples of about two grams were placed into the analyzer and pressurized to the desired pressure using dry CO2 gas. Once the desired pressure was reached, the sample was heated to the desired temperature, while the weight change of the sample was monitored. Any increase in weight was attributed to an uptake of CO2 into the sample as bicarbonate or carbonate formation. A known mass of the un-reacted brine was dried at 95°C to characterize its salts and minerals composition. The resulting dried samples were then ground into a powder and placed into a vacuum oven for approximately 4 hours to remove all remaining moisture. The mass of solids was then weighed to determine the initial solid content of the brine. This procedure was conducted in triplicate to obtain an average solids mass percentage. This value was then used to calculate any increase in solids in the reacted brine samples, which is associated with the degree of carbonation. The solid mass percentage in the reacted samples was calculated by two methods: (i) measuring directly the weight of solids by drying the samples following their removal from the TGA apparatus; and (ii) measuring the weight uptake as reported from the TGA measurements.

RESULTS AND DISCUSSION Table 1 lists the concentration in ppm of the primary carbonate forming elements in the solid fraction of the brine studied. The remaining weigth is mainly sodium chloride (NaC1), while other trace elements, such as barium (Ba) and strontium (Sr), are present in low concentrations.

TABLE 1 CONCENTRATIONOF THE PRIMARYCARBONATEFORMINGELEMENTSIN THE BRINE SALT Element Concentration, ppm (}.tg/g)

Magnesium (Mg)

Calcium (Ca)

Iron (Fe)

3,847.0

35,340.9

140.4

The main reactions of concem are between the CO2 and the highly abundant magnesium and calcium, which are present in the forms of magnesium oxide (MgO) and calcium oxide (CaO), respectively. The formation of the stable carbonates take place in the following two simplified sets of reactions in Equation 1 and 2:

CO2(g) + Mg2+(l)+ 3H200) "-)' MgCO3(s)+ 2H30+0) CO2(g) + 2H20{1) "-)' HCO3(I) + H30+0) HCO30) + Mg"-0) + H200) "-) MgCO3(s) + H30+0) CO2(g) + Ca2+(1)+ 3H20(1) "-)' CaCO3(s)+ 2H30+(1) CO2(g) + 2H20(1) ")' HCO3-(I) + H30+(l) HCO3-(I) + Ca2+(1)+ H20(I) --) CaCO3(s) + H30+0)

(1)

(2)

Both magnesium carbonate (MgCO3) and calcium carbonate (CaCO3), commonly referred to as magnesite and calcite respectively, are geologically stable minerals and are also abundantly found in natural geologic formations.

1623 Figure 1 shows the weight uptake of the brine sample as it was exposed to 300 psi CO2 under isothermal conditions at 55°C for 25 minutes. Under these relatively mild conditions an increase in mass from 1907 mg to 1924 mg, or about 0.9 wt% with no signs of leveling off aider the 25 minutes was observed. Furthermore, it seems like the mass uptake is initially very fast followed probably by a somewhat slower bicarbonate and carbonate formation. This may indicate that a buildup of acidity, as indicated in Equations 1 and 2, may slow down the reaction.

HP-TGA Conditions: 300 psi, 55 °C 1930 1925 1920 ¢E 1915

j

1910

v

r

1905 1900 0

500

1000

1500

2000

Time, sec Figure 1" Weight uptake of the brine at 300 psi under isothermal conditions at 55°C for 25 minutes.

Table 2 compares the weight uptake values observed by measuring the brine solids with those calculated from the high pressure TGA measurements. The solid mass percentage of the un-reacted brine was 17.0-a:0.1%, as found by drying the sample. The solid mass percentage found by drying the sample reacted at 300 psi CO2 under isothermal conditions at 55°C for 25 minutes was 18.1%. This value is very similar to that calculated directly from Figure 1, where the high pressure TGA experiments yielded a 0.9 wt% increase in the mass of solids, which was attributed to mineral carbonate formation. The weight uptake represents around 6.5-5.3% solid weight uptake (1.1/17=6.5% or 0.9/17=5.3%). This weight uptake is rather significant when considering the short timeframe and the mild temperature and pressure over which the reaction was analyzed. Similar data was collected for various pressures between 200 and 600 psi and at isothermal conditions between 50 and 75°C. Furthermore, complimentary techniques that can verify the formation of carbonates, in particular CaCO3, are presently carried out in our laboratory, and these results will be presented. TABLE 2 WEIGHTUPTAKES IN THE BRINE SOLIDS Weight uptake observed by measuring the brine solids (drying)

Weight uptake observed from high pressure TGA measurement

wt%

Uptake solids wt%

wt%

Uptake solids wt%

1.1

6.5

0.9

5.3

1624 CONCLUSIONS The uptake of CO2 into a Pennsylvanian gas well brine was followed using a high pressure thermal gravimetrical analysis apparatus. The brine contained 35,341 ~tg/g Ca2+(1) and 3,847 l.tg/g Mg2+(1) available to form solid carbonates. The rate of CO2 uptake was followed at 300psi and 55°C, presumably forming stable carbonates. Initially there was a rapid increase in mass that somewhat slowed down after about 0.9 wt% uptake. The weight uptake measured from the high pressure TGA was confirmed by of-line weight measurements on the brine after reaction. Although the kinetics of formation of mineral carbonates through the sequestration of CO2 are complicated and yet still unclear, a process for determining a better understanding exists through the use of high-pressure thermogravimetric analysis. The method described here provides continuous data output throughout the duration of the reaction unlike what is attainable when using ordinary pressure vessels.

ACKNOWLEDGEMENTS

The authors would like to thank the Department of Energy and Geo-Environmental Engineering and The Energy Institute at Penn State University for supporting this work.

REFERENCES

1. Energy Information Administration. Energy Consumption by Source, 1949-2000. Retrieved 02/10/2002, from http://www.eia.doe.gov/emeu/aer/txt/tab0103.htm 2. Parson E.A. and Keith D.W., Science 1998, 282 (5391): 1053. 3. Hitchon, B. (1996) Aquifer disposal of carbon dioxide: hydrodynamic and mineral trapping: proof of concept, Geoscience Publishing Ltd., Sherwood Park, Alberta, Canada. 4. Fauth, D.J., Baltrus, J.P., Soong, Y., Knoer, J.P., Howard, B.H., Graham, W.J., Maroto-Valer, M.M. and Andrrsen, J.M. Carbon Storage and'Sequestration as Mineral Carbonates, Chapter 8 in "Environmental Challenges and Greenhouse Gas Control for Fossil Fuel Utilization in the 21st Century", Eds: MarotoValer, M.M.., Song, C., and Soong, Y., In Press. 5. Bergman P.D., Winter E.M., Energy Conversion and Management 1995, 36 (6-9): 523. 6. Office of Science, Office of fossil Energy, US Department of Energy. Carbon Sequestration Research and Development. December 1999. 7. Jones, A. Glass, C., Reddy, T. K., Maroto-Valer, M. M., Andrrsen, J.M. and Schobert, H.H., Prepr. Am. Chem. Soc. Div. Fuel Chem., 2001, 46(1), 321.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1625

THE GEO-SEQ PROJECT: A STATUS REPORT Larry R. Myer ~, Sally M. Bensonl, Charles Byrer2, David Cole3, Christine A. Doughty 1, William Gunter4, G. Michael Hoversten l, Susan Hovorka 5, James W. Johnson 6, Kevin G. Knauss 6, Anthony Kovscek6, David Law 4, Marcelo J. Lippmannl, Ernest L. Majer l, Bert van der Meer 8, Gerry Moline 3, Robin L. Newmark 5, Curtis M. Oldenburg l, Franklin M. Orr, Jr. 7, Karsten Pruess 1, Chin-Fu Tsang I 1Lawrence Berkeley National Laboratory, Berkeley, California; 2National Energy Technology Laboratory, Morgantown, West Virginia; 3Oak Ridge National Laboratory, Oak Ridge, Tennessee; 4Alberta Research Council, Edmonton, Alberta, Canada; 5University of Texas at Austin, Austin, Texas; 6Lawrence Livermore National Laboratory, Livermore, California; 7Stanford University, Stanford, California; 8Netherlands Institute of Applied Geoscience, Utrecht, The Netherlands

ABSTRACT The goals of the GEO-SEQ Project are to reduce the cost and risk of geologic sequestration and decrease the time to implementation. In order to reduce costs, it has been shown that enhanced oil recovery (EOR) methods can be optimized for sequestration, and enhanced gas recovery (EGR) with sequestration, is feasible. An evaluation of the effects of SOx and NOx on geochemical reactions between CO2, water, and reservoir rocks, has been done to assess the use of impure waste streams as a means to reduce overall sequestration costs. In order to reduce sequestration risks a methodology for site-specific selection of subsurface monitoring technologies has been demonstrated, baseline data needed for interpretation of isotopic tracers used to monitor reservoir processes have been developed, and a new definition of formation capacity factor for use in assessing sequestration efficiency has been developed. Code comparison studies are underway for oil, gas, brine and coalbed reservoir simulators for predicting the fate of CO2 in the subsurface. The GEO-SEQ Project has conducted field tests of monitoring technology at CO2 EOR projects in California and New Mexico, and is collaborating on a pilot brine formation sequestration test in Texas.

INTRODUCTION

Initiated in May of 2000, the GEO-SEQ Project is an applied research and development program with the overall goals of: (1) lowering the cost of geologic sequestration; (2) lowering the risk of geologic sequestration; and (3) decreasing the time to implementation of geologic sequestration by pursuing early opportunities for pilot tests and gaining public acceptance. The Project is supported by the U. S. Department of Energy, Fossil Energy (DOE FE) Carbon Sequestration Program through the National Energy Technology laboratory (NETL). Research is conducted by a core team of scientists and engineers from five research institutions in the United States, one in Canada, and one in Europe, working with four private-sector partners: BP, ChevronTexaco, En Cana, and Statoil. In addition, through ongoing collaborations and our advisory committee, the team extends to include other universities and public and private research organizations. Accomplishments to date of the main

1626 activities of the Project are summarized in the following sections. Additional information, including publications prepared by the GEO-SEQ team to date can be found at http://wwwesd.lbl.gov/GEOSEQ/.

CO-OPTIMIZATION OF CARBON SEQUESTRATION AND ENHANCED OIL RECOVERY (EOR) AND ENCHANCED GAS RECOVERY Two studies are focused on reducing sequestration costs by production of oil and gas in conjunction with CO2 sequestration. One effort is focused on modifying existing, and developing new, CO/EOR methods to increase the amount of CO2 stored in the reservoir relative to the amount of oil produced. As a first step, new criteria were developed for selection of candidate oil reservoirs for combined EOR and CO2 sequestration (Kovscek, 2001). Work next focused on specific approaches that could increase CO2 storage while at the same time enhancing oil recovery. Five initial methods are identified: (1) adjust injection gas composition to maximize CO2 concentration while maintaining an appropriate MMP; (2) design well completions (or consider horizontal wells) to create injection profiles that reduce the adverse effects of preferential flow of injected gas through high permeability zones; (3) optimize water injection (timing, injection rates and WAG ratio) to minimize gas cycling and maximize gas storage; (4) consider aquifer injection to store CO2 that would flow rapidly to producing wells if reinjected in the oil zone; and (5) consider reservoir repressurization after the end of the producing life of the field. Reservoir heterogeneity has a major impact on selection and implementation of specific approaches. Current work is focused on quantifying these relationships as well as developing additional co-optimization methods. A second effort focuses on injection of CO2 into depleted gas reservoirs while simultaneously enhancing CH4 recovery and offsetting sequestration costs. The feasibility of carbon sequestration enhanced gas recovery (CSEGR) has been assessed through numerical simulations performed with the TOUGH2 code, incorporating a new equation of state for water-CO2-CH4 mixtures. Initial, 2-D simulations were based on the Rio Vista Gas Field, the largest on-shore-dry-gas field in California. Results showed that significant CH4 recovery could be achieved before CO2 breakthrough and that breakthrough was controlled more by reservoir heterogeneity than mixing (Oldenburg and Benson, 2001). Subsequent 3-D simulations of a more realistic 5-spot well configuration similarly yielded results that were positive for feasibility of CSEGR. Current work is focused on an economic assessment of CSEGR (Oldenburg and Stevens, this volume). A depleted gas reservoir, which has undergone CSEGR, could also be used for gas (CH4) storage. Preliminary simulations suggest that 30% more CH4 can be stored using CO2 as a cushion gas as opposed to the conventional approach.

EVALUATION OF THE IMPACT OF CO2 AQUEROUS FLUID AND RESERVOIR ROCK INTERACTIONS ON THE GEOLOGIC SEQUESTRATION OF CO2 Another approach to lowering costs is to sequester less-pure CO2 waste streams that are less expensive or require less energy to separate from flue gas. The objective of this study is to evaluate the impact of this impure CO2 waste stream on geologic sequestration. To date, the influence of SO2, NO2, and HzS on COz/rock/water interactions has been evaluated for a feldspathic-sandstone and a carbonate reservoir. Simulations equivalent to batch-type (closed-system) reactions have been performed. The impact of the contaminants on dissolution/precipitation and changes in porosity is primarily due to the increase in acidity caused by their addition. The relative impact is given as: SO2>NOz>>HzS>COz. Reactive chemical transport modeling is currently being carried out to assess spatial and temporal impact of the chemical processes identified in the closed-system modeling.

1627 OPTIMIZATION OF GEOPHYSICAL MONITORING TECHNOLOGIES Monitoring the location and movement of CO2 in the subsurface will lower risks of sequestration. This effort focuses on assessing the sensitivity of geophysical methods and demonstrating their applicability for monitoring. The first phase of this effort involved implementation of a numerical simulation-based, three-step, interactive process of reservoir simulation, forward, and inverse geophysical modeling, to evaluate the sensitivity of candidate techniques and design optimum sensor configurations (Hoversten and Myer, 2001). The second major element of this effort is field demonstration of candidate methods. Four different methods are currently being evaluated: crosswell seismic, single well seismic, crosswell electromagnetic (EM), and electrical resistance tomography (ERT). A CO2 EOR pilot operated by ChevronTexaco in Lost Hills, California, provided an early opportunity to test crosswell seismic and EM techniques. High-resolution crosswell seismic and EM surveys were made before and after CO2 injection. Data from three time-lapse surveys were the basis of a joint seismic EM inversion providing quantitative estimates of gas saturation change resulting from CO2 injection (Hoversten et al, this volume). In a parallel activity, the ERT method is being applied in a CO2 EOR project at the Chevrontexaco Vacuum Field, New Mexico. A method in which well casings are used as electrodes for crosswell measurements is being tested. Time-lapse measurements have been made and are currently being analyzed.

APPLICATION OF NATURAL AND INTRODUCED TRACERS IN GEOLOGIC SEQUESTRATION The overall goal of this effort is to provide methods that use natural carbon and oxygen isotopes, and introduced tracers to determine the fate and transport of CO2 injected into the subsurface. Isotopic work has focused on assessing carbon and oxygen isotope changes as CO2 reacts with potential reservoir phases. Results show that the light isotopes (12C; 160) are preferentially adsorbed onto mineral surfaces resulting in an enriched free CO2. This partitioning is large when the solid is coated with hydrocarbons. As CO2 moves through an EOR environment it may become progressively enriched in the heavy isotopes. Model calculations indicate that typical CO2 gas from anthropenic injection sources will exhibit increases in ~3C/~2C ratios due to interaction with rocks and brines because most geological reservoirs are isotopically heavier. Current work is focused on analysis of gas and carbon isotope compositions of samples obtained from the Lost Hills CO2 EOR pilot. Work on introduced tracers has focused on development of a laboratory flow system for study of sulfur hexafluoride (SF6) and a suite of perfluorocarbon (PFT) tracers.

ENHANCEMENT OF NUMEICAL SIMULATORS FOR CO2 SEQUESTRATION IN DEEP UNMINEABLE COAL SEAMS, OIL, GAS, AND BRINE FORMATIONS Two studies are underway to improve simulation models for capacity and performance assessment of CO2 sequestration. The first is focused on coal bed methane (CBM) numerical codes. Work began with definition of the physical processes that need to be included in (CBM) codes. Benchmark problems were then developed, incorporating increasing levels of complexity. The numerical models being tested are CMG's, STARS, CMG's GEM, GeoQuest's ECLIPSE, BP's GCOMP, CSIRO's SIMEDII and ARI's COMET2. Testing of the first two sets of numerical problems has been completed. These numerical problems have now been repeated assuming injection of flue gas (Law et al, this volume). Further information can be found at http://www.arc.ab.ca/extranet/acbml (user name and password can be obtained by contacting David Law; [email protected]). The second effort is a code intercomparison study which has the goal of stimulating further development of models for predicting, optimizing and verifying CO2 sequestration in oil, gas, and brine formations. In Phase I, a set of eight benchmark problems were developed which incorporate a variety of processes of importance in sequestration. In subsequent phases, test problems will evolve to address greater complexity and

1628 validate experimental data. The Phase community, and researchers from nine Norway, Australia, and the Netherlands) (Oldenburg et al, this volume and Pruess

I problems have been widely distributed to the scientific organizations (including researchers from France, Canada, are participating. A first comparison of results has been made et al, this volume).

IMPROVING THE METHODOLOGY AND INFORMATION AVAILABLE FOR CAPCITY ASSESSMENT OF SEQUESTRATION SITES One of the important factors in determining the suitability of sites for sequestration will be the CO2 storage capacity of the formations. This effort first focused on developing a methodology for calculating capacity. Capacity depends not only upon porosity, but also multiphase flow properties, formation geometry and gravity, and geologic heterogeneity. The concept of a capacity factor, which could be used to quantitatively compare the sequestration capacity of specific sites, was introduced. Initial efforts focused on performing an assessment of the sequestration capacity of oil and gas fields and brine formations in California (Benson 2001). More detailed assessments were then carried out for specific sites in the Frio and Oakville Formations in Texas. Results show that gravity-driven buoyancy flow causes a decrease in the capacity of a given volume. Layer-type heterogeneities tend to counteract these effects by causing lateral spreading of the CO2 plume.

FRIO PILOT TEST The GEO-SEQ Project is a collaboration with the Texas Bureau of Economic Geology to conduct a pilot brine formation CO2 injection experiment. The overall objectives of the pilot test are to: (1) adequately characterize a site for CO2 disposal; (2) monitor the behavior and migration of CO2 behavior; (3) develop conceptual models of CO2 behavior; (4) develop expertise in design and performance of CO2 disposal facilities; and (5) provide information needed to characterize conditions adverse to long-term containment of CO2. Current work is focused on test design. GEO-SEQ investigators are performing reservoir simulation, geophysical simulations and geochemical calculations in support of the design of the CO2 injection strategy and selection of monitoring techniques. ACKNOWLEDGEMENTS Support was provided by the Assistant Secretary for Fossil energy, Office of Coal and Power Systems through the National Energy Technology Laboratory of the US Department of energy under Contract No. DE-AC03-76SF00098. REFERENCES Benson, S. (2001) in Proceedings of Fifth International Conference on Greenhouse Gas Control Technologies, Williams, et al (Eds). CSIRO publishing, pp. 299-304. Hoversten, G. and Myer, L. (2001) in Proceedings of Fifth International Conference on Greenhouse Gas Control Technologies, Williams, et al (Eds). CSIRO publishing, pp. 305-310. Kovscek, A. (2002) Petroleum Science and Technology 20(7 and 8), pp. 841-866. Oldenburg, C. and Benson, S. (2002) SPE 74367, presented at SPE International Petroleum Conference and Exhibition, Villahermosa, Mexico February 10-12.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 NERC. Published by Elsevier Science Ltd. All rights reserved

1629

THE lEA WEYBURN CO2 MONITORING AND STORAGE P R O J E C T - THE EUROPEAN DIMENSION J. B. Riding l, I. Czemichowski-Lauriol 2, S. Lombardi 3, F. Quattrocchi 4, C. A. Rochelle l, D. Savage5 and N. Springer 6 ~British Geological Survey, Keyworth, Nottingham, NG12 5GG, UK* 2Bureau de Recherches Geologiques et Minieres, BP 6009, 3, Avenue Claude Guillemin, 45060 Orleans Cedex 2, France 3Dipartimento di Scienze della Terra, Universita di Roma 'La Sapienza', P. A. Moro 5, Roma, 1-00185 Italy 4Istituto Nazionale di Geofisica e Vulcanologia, INGV Sezioni di Roma, Via di Vigna Murata 605, 00143, Rome, Italy 5Quintessa Limited, 24 Trevor Road, West Bridgford, Nottingham, NG2 6FS, UK 6Geological Survey of Denmark and Greenland, Oster Voldgade 10, DK-1350 Copenhagen K, Denmark * - with the permission of the Executive Director, British Geological Survey (NERC).

ABSTRACT The IEA Weyburn CO2 Monitoring and Storage Project is currently analysing the effects of a miscible CO2 flood into a carbonate reservoir rock at a mature onshore Canadian oilfield. Anthropogenic CO2 is being injected as part of an enhanced oil recovery operation. The European contribution includes the analysis of the long term safety and performance of CO2 storage via construction of a Features, Events and Processes (FEP) database. This will allow the integrity of deep storage of CO2 in sedimentary rocks to be investigated objectively. Initial work has also been focussed on better understanding the pre-injection hydrogeological and geochemical conditions in the reservoir in order to recognise changes resulting from injection of the CO2. The baseline studies also include analysing gas concentrations in soil and groundwater to determine potential migration pathways; two soil gas surveys were undertaken in July and September 2001. The CO2 distributions are irregular and reflect anthropogenic or near surface phenomena and seasonal variations in CO2 fluxes are present. There are no correlations between gas anomalies and injection wells or pipelines. Changes from these baseline conditions as a result of CO2 injection are also under investigation and will be the focus of future activities. Geochemical experiments, predictive computer modelling, microseismic monitoring and soil gas surveys will be carried out to investigate CO2 migration pathways and the rate and extent of chemical reactions of the injected CO2 with the host formation and adjacent strata.

1630 INTRODUCTION The IEA Weybum CO2 Monitoring and Storage Project is a collaborative investigation involving geoscientists from North America and Europe and is co-ordinated by the Petroleum Technology Research Centre (PTRC) in Regina, Canada [ 1]. It is studying the geological storage of CO2 during an enhanced oil recovery (EOR) operation at the Weybum oilfield, Canada. By the end of this phase of EOR, it is expected that approximately 20 million tonnes of anthropogenic CO2 will be permanently stored deep underground. Climate-warming greenhouse gas emissions will have been reduced in an efficient and cost-effective manner. The objectives are to enhance our understanding of the deep underground storage of CO2 via geoscientific monitoring. Furthermore, it is intended to promote international collaboration on carbon management research between researchers in Canada, the USA and Europe. The European arm of project is partly funded by the European Commission (EC).

THE WEYBURN OILFIELD - GEOLOGY AND ENHANCED OIL RECOVERY The Weybum oilfield is located in southern Saskatchewan, Canada (Figure 1A) and was discovered in 1954. It covers approximately 70 square miles of prairie and is operated by the EnCana Corporation (formerly PanCanadian Resources). Oil is recovered from the uppermost Midale Beds of the Charles Formation, a succession of upwards shoaling, shallow marine carbonate-evaporite sediments of Mississippian age. The Midale Vuggy unit represents open marine conditions and is overlain by the shallow water dolomitic mudstones of the Midale Marly Beds, which contain the greatest remaining oil reserves and is now the target for the miscible CO2 flood (Figure 1B). a

b N

• Regina

0

co,

100 km

Injection

Weybum

'

'

Manitoba

w.,

I ILL//F~du~o. ~:~. ~ll~ we,,

_el-- I Figure 1: a - the location of the Weybum oilfield and the route of the CO2 pipeline, b diagram illustrating how a miscible CO2-EOR flood produces incremental oil. At Weybum, the depth to the reservoir unit is c. 1400 m.

Since 1964, water injection has been the preferred secondary recovery mechanism. However, recently installed CO2-EOR operations are considered crucial to the future economic life of the field. The Midale Vuggy Beds proved more permeable than the overlying Midale Marly Beds and consequently have been more efficiently swept during the waterflood operation. It is hoped that the miscible CO2-EOR operation will significantly extend the life of the Weybum Field by the production of 130 million barrels

1631 of incremental oil (Figure 1B). Injection of CO2 commenced during September 2000. Initially, injection is in 17 patterns of nine wells each at the west end of the Weyburn Unit; this CO2 flood will roll out south-eastwards until 75 patterns have been flooded. The CO2 is a by-product of the coal gasification process and is supplied directly to Weyburn by the Dakota Gasification Company via a 330 km long pipeline from the Great Plains Synfuels Plant, Beulah, North Dakota, USA (Figure 1A) [ 1, 2].

THE ORGANISATION OF THE EUROPEAN PART OF THE PROJECT

Work Package I - Long Term Safety and Performance of C02 Storage The aim is to provide a means by which data can be integrated to give an assessment of the safety and economics of CO2 injection at Weyburn. Furthermore, a Features, Events and Processes (FEP) database will be devised and the economics and storage potential of the Weyburn Field comprehensively appraised. The construction of a FEP database is the starting point for safety assessment studies. Natural analogue data obtained through the NASCENT project [3] will also be incorporated. Genetic FEP descriptions for CO2 storage and a Weyburn specific FEP sub-set are currently being produced. Placing the economics of the Weybum EOR/storage operation into a European context are also being investigated.

Work Package 2 - Definition of Baseline Hydrogeological, Hydrochemical and Petrographical Conditions The aim of this package is to define the pre-CO2 injection hydrogeological, hydrochemical and petrographical conditions in the Weyburn reservoir unit at a local and regional scale. A comprehensive understanding of baseline conditions will allow the recognition of changes resulting from the miscible CO2 flood and the determination of the ultimate fate of the injected CO2. To understand the potential migration of CO2, the studies of baseline hydrogeological data from Weyburn have investigated both fluid flow within and outside the reservoir. Studies on baseline fluid chemical data from Weyburn aims to model the initial chemical environment within the reservoir, including the water-rock system and minerals that may react with reservoir fluids under high CO2 pressure. Baseline mineralogical data are also being analysed to assess the initial chemical environment and to identify core material within the CO2 flood area for use in hydrothermal experiments. Experimental geochemical studies on core samples from the first CO2 flooding area are being carried out to ascertain key fluid properties. A further aspect of these baseline studies is to determine the pre-injection regional gas fluxes and concentrations in both soil and groundwater. This will improve the understanding of fluid-flow pathways throughout the Weyburn oilfield. A variety of dissolved and free gases and elements have been studied; these help to determine the baseline and allow potential rapid transport pathways to be identified. Furthermore, elemental studies have analysed baseline water-rock interactions. Part of this task is to investigate whether soil gases and groundwater analyses can be used to identify the position of near surface features that may connect with the reservoir at depth. Seismic profiles were examined for faults, which may conduct gases and liquids above the reservoir, however none, which outcrop, were found. Consistent with this, the soil gas anomalies measured at Weyburn do not follow linear trends. The CO2 distributions reflect

1632 both the origins and natural reactions which typify CO2. The majority of the CO2 anomalies may be explained by anthropogenic or near surface phenomena. There is no correlation between these CO2 anomalies with the injection wells or the underground CO2 pipelines. Furthermore, the expected seasonal variations in CO2 flux data have been discerned. Measurements taken in September 2001 proved lower than those measured in July 2001. These differences are related to seasonal variations in soil humidity, vegetation and agricultural activities. Work Package 3 - Define Changes to Baseline Hydrochemical, Hydrogeological and Petrographical Conditions Resulting from COz Injection This part of the project has recently started to investigate the effects of the injection of CO2 into the Weybum reservoir, particularly those impacting upon the hydrogeological, hydrochemical and petrographical properties of the rock. Predictive computer modelling to assess the chemical impact of CO2 over a variety of temporal and spatial scales is ongoing. This will be supported by observations from laboratory experiments reacting with Weybum Rock and fluid samples, field geochemical monitoring and natural analogues. It is also intended to test whether microseismic monitoring is useful for locating real time fracture generation and fluid flow pathways stimulated by EOR injection. Re-surveys of soil-gas concentrations will also be undertaken to compare with baseline results and test whether any changes are linked to CO2 injection.

CONCLUSIONS The European part of the IEA Weybum CO2 Monitoring and Storage Project will garner scientific and technical knowledge related to an industrial miscible CO2 EOR operation. It is intended to serve as a model, which can be applied elsewhere. The participants expect that results from this project will help guide policy development on greenhouse emissions from industrial scale energy generation via deep underground storage. REFERENCES Moberg, R. (2001). Greenhouse Issues 57, 2. Malik, Q.M. and Islam, M.R. (2000). In: Society of Petroleum Engineers/Department of Energy Symposium on Improved Oil Recovery 2000, Tulsa, Oklahoma, 3-5 April 2000. Pearce, J.M., Nador, A. and Toth, E. (2002). Greenhouse Issues 58, 6.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1633

PRELIMINARY CHARACTERISATION OF REGIONAL HYDROGEOLOGY AT THE CO2 SEQUESTRATION SITE OF WEYBURN (SK- CANADA) Y.M. Le Nindre l, I Czemichowski-Lauriol l, S. Bachu 2, and T Heck 3 1BRGM-French Geological Survey, BP6009, 45060 Orlrans Cedex 2, France 2 Alberta Geological Survey, 4th Floor, Twin Atria, 4999-98 Avenue Edmonton, Alberta T6B 2X3 Canada 3 North Dakota Geological Survey, 600 East Boulevard Avenue, Bismarck, ND 58505-0840 USA ABSTRACT

The EU funded project ENK5-CT-2000-00304"Weybum" is carried out in close co-operation between European and American scientists, with the objective to elaborate, from a case study, a project strategy applicable to European sites. For this target, its primary expected outcome is to enhance understanding of the underground sequestration of CO2 associated with EOR in the context of carbonate reservoir, and to evaluate the impact of this sequestration on the reduction of greenhouse gas emissions. The investigations are more specifically designed to evaluate the potential long-term migration pathways and reactivity of CO2 with the host formation, basically controlled by the regional hydrodynamics and geochemistry of aquifer systems. In a block of 240x230x4.8 Km centred on Weyburn, a first phase of investigation has provided the major structural and hydrogeological features which have been modelled for a set of aquifers. Results demonstrate that flows, mostly updip, are driven both by elevation of recharge area and superimposed effect of salinity and subsequent density.

INTRODUCTION

The Weybum oilfield, operated by PanCanadian, is located in southern Saskatchewan (Canada - figure. 1) and covers -~180 Km 2. It was discovered in 1954, production started in 1955. The peak production was reached in 1965 with 7,500 m3/d. Enhanced oil recovery (EOR) involved successively three fluid drives: primary (water), secondary (water flood in 1962), and tertiary CO2 flood (Sept. 2000). A 330-km pipeline from the Dakota Gasification Company's plant, located near Beulah, North Dakota, USA, supplies 5000 t/d CO2. •!~7........i:.~Li!. :i

%

,,; ,-.,,

Figure 1: Location map of the Weybum field

1634 It is expected that some 20 Mt of anthropogenic CO2 that would otherwise be released into the atmosphere will be permanently sequestered deep underground. Therefore, this site was selected for the Weyburn C02 monitoring project, a current research and demonstration project of the International Energy Agency Greenhouse Gas Programme. GEOLOGICAL

S E T T I N G

From a geological aspect, the Weybum field is located at the northeastern edge of the Williston basin, which is shared between Canada and the U.S. Oil is produced from two reservoir zones, "marly" and "vuggy"(respectively 6 and 15 m thick) within the Mississipian Midale beds at a depth of 1450m. In order to set the Weyburn field in its regional context, structure, hydrogeology and water chemistry were first compiled from published data at the basin scale (e.g.: Alberta Geological Survey [ 1], Bachu and Hitchon [2], U.S.G.S.[3], Rostron et al. [4]). The construction of a reference section and of a correlation chart gives the correspondence of lithostratigraphy and hydrostratigraphy at Weyburn, and throughout the Williston basin, accounting for facies variations through a great number of geological formations. The study, is focused on a block of 240x230 Km 2 (48.5o-50.5 ° lat. N, 102.0°-105.25 ° long. W) centred on Weyburn, and coveting the structural interval from the top of the Precambrian basement to the ground surface, i.e. ~4800m. It extends mainly in Saskatchewan, northward of 49°N lat., but and also in North Dakota and Montana, on 0.5°lat. Structure, pressure and hydrochemical digital data originate from the Saskatchewan Energy and Mines, Alberta Geological Survey and North Dakota Geological Survey. Structural surfaces, total dissolved solid concentrations and potentiometric surfaces were modelled using geostatistics (GDM® BRGM software) and a set of georeferenced grids. The geological structure of the area is roughly a monocline southward or south-westward, with two lowangle major unconformities truncating the strata updip: - the Mississipian subcrop underneath the pre-Triassic (Lower Watrous) unconformity, - the sub-Mannville (Lower Cretaceous) unconformity The oil reservoir in the Midale beds and overall, the Mississippian aquifer (Madison aquifer), are capped by the Midale Evaporite (where present) and shale and anhydrite of the Triassic Lower Watrous. However, the trap is also hydraulic as shown further by the potentiometric surface of the Mississippian aquifer. Water flooding is operated by tapping almost-fresh water from the broad, overlying Mannville aquifer and injecting it into the "vuggy" zone of the Midale beds (figure 2). @- l l r w $

A

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:

:

:

:

i

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~:

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:

i

i

!

.i

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i.

:

.

.

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:

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:

-

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:

i

:

:

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! •: •~

:

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Figure 2: NS cross section through the Weybum field

o ~.

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1635 MODELLING OF STRUCTURE AND HYDROGEOLOGY Structure To reconstruct the structure, formation tops (from the Upper Albian Viking Aquifer to the Deadwood Fm., i.e., Cambro-Ordovician Aquifer), were modelled from well control data (figure 3). Three sets (structure, salinity, hydraulic heads) of eight maps corresponding to the major aquifer systems were produced by krigging: Upper Cretaceous, Albian, Lower Cretaceous, Middle Jurassic, Mississippian, Upper Devonian, Middle Devonian, and CambroSilurian.

Figure 3: Elevation of the pre-Triassic unconformity (m) Total Dissolved Solid (TDS) The Palaeozoic aquifers exhibit high and variable salinity values due to fresh water influx from the northeast and formation-salt dissolution, whereas the Meso-Cenozoic aquifers have low gradients and salinity, except for some Jurassic horizons where anhydrite is present. The TDS map of the Mississippian aquifer (figure 4) shows a steep salinity gradient in the Weybum area. Those values are in agreement with the recent fluid analyses performed within this project. Brines concentrate in the southern zone. Low salinity values in the north are partly superimposed with the area where the Devonian Prairie Evaporite has been dissolved.

Area of

dissolution of the Prairie

evaporite

25 Km

Figure 4: Salinity of the Mississippian aquifer

1636 Hydraulic Heads Hydraulic heads of the eight aquifers were calculated from DST pressures accounting for water density according to the above TDS distribution. Although the overall subsurface flows are dominantly oriented SW-NE, contrasts of density may induce deep local modifications of pathways and hydraulic traps. Horizontal flows and vertical leakage are controlled by both topography and salinity. The potentiometric surface of the Mississippian (figure 5), is deformed by the effect of brine concentration and of fresh water influx by-passing northward. Therefore, the Mississippian aquifer becomes over-pressured compared to the Mannville. This configuration is important to consider when investigating the potential upward CO2 migration and chemical incidence of water mixing by flooding.

Figure 5: 3D view of the Mannville and Mississippian potentiometric surfaces ACKNOWLEDGEMENTS This study is supported by the EU funded project ENK5-CT-2000-00304"Weybum" and the IEA "Weybum CO2 Monitoring Project". Geological setting: thanks to Saskatchewan Energy and Mines. REFERENCES [ 1]

[2] [3] [4]

Alberta Geological Survey (1994) Geological Atlas of the Western Canadian Sedimentary Basin. Compiled by Grant Mossop and Irina Shetsen. http ://www.ags.gov.ab.ca/ags pub/atlas_www/atlas.htm Bachu S. and Hitchon B. (1996) A.A.P.G. Bulletin, 80, 2, pp. 248-264 U.S.G.S (1996) The Ground Water Atlas of the United States, segment 8, Hydrologic investigations Atlas 730-I, U.S. Geological Survey, Reston, Virginia, Rostron B.J., Holmden C. and Kreis L.K. (1998) Sask. Geol. Soc. Sp. Pub. n°13, pp. 267-273

Greenhouse Gas Control Technologies, Volume lI J. Gale and Y. Kaya (Eds.) Crown Copyright © 2003 Published by Elsevier Science Ltd. All rights reserved

1637

USE AND FEATURES OF BASALT FORMATIONS FOR GEOLOGIC SEQUESTRATION B. P. McGrail 1, A. M. Ho 2, S. P. Reidel l, and H. T. Schaef I Applied Geology & Geochemistry Department, Pacifc Northwest National Laboratory- Battelle, P.O. Box 999, Richland, Washington, USA 2 Department of Geology, Eastern Oregon University, La Grande, Oregon, USA

ABSTRACT Extrusive lava flows of basalt are a potential host medium for geologic sequestration of anthropogenic CO2. Flood basalts and other large igneous provinces occur worldwide near population and power-producing centers and could securely sequester a significant fraction of global CO2 emissions. We describe the location, extent, and general physical and chemical characteristics of large igneous provinces that satisfy requirements as a good host medium for CO2 sequestration. Most lava flows have vesicular flow tops and bottoms as well as interflow zones that are porous and permeable and serve as regional aquifers. Additionally, basalt is ironrich, and, under the proper conditions of groundwater pH, temperature, and pressure, injected CO2 will react with iron released from dissolution of primary minerals in the basalt to form stable ferrous carbonate minerals. Conversion of CO2 into a solid form was confirmed in laboratory experiments with supercritical CO2 in contact with basalt samples from Washington State. FLOW TOP

INTRODUCTION Upper

Capture of CO2 from flue gases and subsequent geologic sequestration offers promise for controlling anthropogenic CO2 emissions, reducing the cost of managing climate change, and preserving the viability of fossil fuels. Site assessments for geologic sequestration of CO2 have been conducted for the mid-West to mid-Atlantic region of the U.S. [ 1] and at a few other locations around the world. Surprisingly, basaltic rocks have not attracted attention as potential host formations. Iramense basalt flows occur around the world and are recognized as playing an important role in the global carbon cycle [2-5]. Large igneous provinces (LIPs) represent immense outpourings of marie (iron- and magnesium-rich) magmas and include continental flood basalts (CFBs), volcanic passive margins, geeanic plateaus, and their associated intrusive rocks.

(

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zone

.....

ENTABLATURE FLOW INTERIOR

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columns--" vesicle

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COLONNADE Spiracle -...

Pillow-

f

PatagoniteL

FLOW BOTTOM

The internal flow features in CFB lavas make them attractive Figure 1: Major internal features of a Cotargets for CO2 sequestration. Internal features formed during lumbia River Basalt Group lava flow the solidification of a lava flow result from variations in cooling rates, degassing, thermal contraction, and interactions with water. These features may be continuous for large distances, though their thickness is often highly variable. The uppermost section of a basalt flow (see Figure 1) consists of vesicular or brecciated basalt and is the principal feature into which CO2 would be injected. The thickness of the vesicular portion of

1638 a flow may range from a few centimeters to almost the entire flow thickness, but most vesicular flow tops comprise 15 to 30% of the flow's thickness. Joints are the dominant intraflow structures and form as a result of tensional stress induced from differential thermal contraction during cooling. Colonnade and entablature joints [6] form roughly vertical "columns" of rock that provide a possible pathway for CO2 to leak to an overlying flow. However, saprolites (extensively weathered soil) and low-permeability sedimentary interbeds that occur in most basalt flows form important confining horizons. The interior of a basalt flow is also quite dense and of low permeability, potentially acting as a caprock between flows. Major chemical and isotopic differences between the groundwaters in different Columbia River Basalt Group (CRBG) flows [7] do indicate effective seals between flows that would suggest limited potential for vertical migration of gas stored within deep basalt interflow zones. TABLE 1 AREAL EXTENTAND VOLUMESOF MAJORLIPs LIP

Location

Area, km 2

Volume, kin3

CRBG, ColumbiaRiver Basalt G r o u p

Northwestern U.S.

200,000

224,000

DEC, Deccan Traps

India and Pakistan

600,000

512,000

EME, EmeishanBasalts

Southwest China

>250,000

>300,000

HCB, Hannuoba-ChifengBasalts

Northeastem China

20,000

1400"

2,300,000

9,100,000

160,000

640,000*

1,300,000

6,600,000

500*/400*

50*/40*

KER, KerguelenPlateau

Southern Indian Ocean

KEW, KeweenawanBasalts

Northcentral U.S.

NAVP, North Atlantic VolcanicProvince

UnitedKingdomand Greenland

NB/HB, Newark Basin and Hartford Basin NortheasternU.S. OJP, OntongJava Plateau

Southwestem Pacific

1,900,000

44,400,000

PEP, Paranh-EtendekaProvince

Brazil, Namibia, and Angola

2,200,000

>l,000,000

SIB, SiberianTraps

Eastern Siberia

340,000

400,000

YET, Yemen-EthiopianTraps

Yemen and Ethiopia

>600,000

>350,000

* Estimated. Volumes estimated from area and average thicknesses o f 70 m (HCB), 4 km (KEW), and 1O0 m (NB/HB).

GLOBAL SURVEY OF LARGE IGNEOUS PROVINCES Details regarding the areal extent and volume of LIPs around the world are given in Table 1. Of significance are the large basalt flows located in the U.S., China, and India. Because China and India are already major CO2 emitters and will surpass the U.S. in total greenhouse gas emissions within the next 10 to 25 years [8,9], these formations might provide an important sequestration option for CO2 in these countries. BASALT FORMATIONS IN THE U.S. There are major basalt flows in four regions of the U.S. (see Figure 2) that might be attractive targets for carbon sequestration. Along the eastern margin of North America, the Newark Supergroup contains all sediments and volcanic rocks preserved in these ritt basins. Tholeiitic lava flows are found only in the northern- and western parts of these basins. Of the basins containing basalt, the Newark and Hartford basins are the largest and most studied. Both basins contain three basalt sections separated by sediments and a deep, genetically related sill [ 10]. The Watchung Basalts are interbedded with 170-500 m of sediments [ 11 ]. Individual flow thicknesses are up to 100 m (Holyoke basalt in the Hartford basin); the thickest of the Watchung flows is the Preakness flow (up to 180 m thick) [12]. This group ofbasalts is also located near a significant concentration of fossil fuel power plants (Figure 2). The Central Atlantic Mafic Province (CAMP) is an early Mesozoic province related to the opening of the Atlantic Ocean that extends in the U.S. from the northeast along the Appalachians to the Gulf of Mexico. The South Georgia Rift is a complex terrance of rift basins with subbasins up to 100 km wide and over 7 km deep. The basins are filled with sediments and volcanics. Like the Newark basin, the fill is typically about 6 km thick as interpreted from seismic reflection lines. Much is sediment, but mafic igneous rocks are also

1639

i i ~~II i -?

~ : •: .i•!~

~

i,/~/i~ ~ • .... i¸ "'•iii

Figure 2: Distribution of major sedimentary and basalt formations in the U.S. along with coal, oil, and natural gas power plants. Darker areas represent basalt flows, lighter areas deep sedimentary formations. present [ 13]. Although little is known about the structure and extent of this flow, the region does intersect a concentrated area of power plants (Figure 2). The 2500-km-long mid-continent rift system in central North America comprises the Keweenawan Supergroup. Keweenawan basalts are composed of at least 300 flows extruded into 7 or 8 separate rift basins [ 14]. They are interbedded with sandstone units [ 15]. At Mamainse Point in eastern Lake Superior, over 350 flows are exposed that span most of the volcanic history of the rift system. The CRBG, which is part of the larger Columbia Plateau Province shown in Figure 2, is one of the most well-studied LIPs in the world, despite its small size relative to other known CFBs (Table 1). The group covers more than 200,000 km 2 of Washington, Oregon, and Idaho with a total volume of over 224,000 km 3. Each flow is from a few tens of meters to 100 m thick. Through studies of the basalts and the basalt aquifer systems for nuclear waste remediation at the Hanford Site and for natural gas storage [ 16], a large body of information is available to provide an estimate of the CO2 storage capacity in the CRBG. Assuming an interflow thickness of 10 m with an average porosity of 15% and 10 available interflow zones, at an average hydrostatic pressure of 100 atm the storage potential is greater than 100 Gt CO2. This capacity is more than sufficient to sequester the entire emissions of the northwestern U.S. for the foreseeable future. MINERAL TRAPPING IN BASALT There is insufficient Ca, Mg, and Fe in the rocks that make up a typical sedimentary formation to support significant mineral trapping [ 17]. Consequently, the injected CO2 will be stored essentially permanently in a supercritical state that will be subject to slow leakage processes and to low-probability but high-risk catastrophic releases. Injection of CO2 or an untreated flue gas stream into a basalt aquifer will lower the typical brackish basalt groundwater pH from between 8.5 and 9.2 to 3.5 or lower. Iron-rich phases such as pyroxene, olivine, spinel, and glassy mesostasis are unstable at low pH and dissolve. The ferrous iron released to the aqueous phase reacts with CO2 to form ferrous carbonate minerals such as siderite that permanently sequester CO2. To test this hypothesis and to obtain data on the potential rate of carbonate mineral precipitation, laboratory experiments were performed with CRBG samples. To track CO2 consumption as a function of time, we elected to monitor the change in CO2 pressure as a function of time in a batch reactor system. However, a very important consideration in this approach is to ensure that any observed pressure drop can be attributed to mineralization reactions and not to slow leakage of CO2. To solve this problem, we designed a doublecontained pressure vessel system. A high-pressure reactor is placed inside a sealed aluminum container. The inner vessel can be pressurized to 3000 psi with CO2 and the outer vessel is evacuated and then backfilled with N2 or He at low pressure (1 psi). Over the course of an experiment, the gas composition in the

1640

aluminum vessel is analyzed with gas chromatography. Any leakage of CO2 from the high-pressure reactor is detected from an increase in CO2 concentration.

1600 1400

N2 Pressurization

N 2 Pressurization _ . _ . _ ~ i ~

[

The pressure vessels were packed with 25 g of basalt "~ 1000 and 12 mL of deionized water, thereby forming a wa- ai 800 ter-saturated porous medium in the vessel. A hydraulic syringe pump was then used to pressurize the vessel with CO2 to approximately 900 psi at room tempera- n" 400 ture. The mass change after pressurizing with CO2 200 was recorded, and typically about 4 g of CO2 was o charged into the vessel. The pressure vessel was then o 500 1ooo 1500 2000 placed into its aluminum outer containment vessel, Time, hr which was sealed, evacuated, and then pressurized to 1 Figure 3: Pressure as a Function of Time for psi with N2 gas. The entire assembly was then placed Static Tests with Two Different Basalt Samples into a controlled temperature water bath at 90°C. An electronic pressure transducer connected to the inner vessel was used to track the pressure during the experiment. Figure 3 shows the pressure drop data as a function of time for tests with the different basalt samples. Upon raising the temperature to 90°C, the pressure increased to approximately 1500 psi, which was the target starting pressure for these tests. For the Rocky Coulee sample, the pressure dropped rapidly over the course of the test, as shown in Figure 3, falling below 400 psi after 200 hr. The experiment was terminated at this point and the remaining gas phase CO2 vented, which was measured from mass change to be 0.4 g. The vessel was then immediately pressurized with N2 gas to 1026 psi to recheck for possible leakage through the pressure transducer fittings (no CO2 was detected in the outer containment vessel). The results (Figure 3) show that a constant N2 gas pressure was maintained for over 100 hours after pressurization. Thus, leakage of CO2 from the pressure vessel cannot be the cause of the large pressure drop observed for this test. In contrast, the Sentinel Bluff basalt shows slower reaction kinetics. The Rocky Coulee sample is from a lava flow top and has small micropores that give it a 3X higher overall surface area than the Sentinel Bluffs sample, which is from a flow interior. The larger surface area of the Rocky Coulee sample gives a higher release rate of iron and so more rapid consumption of CO2 in forming carbonate minerals. The data confirm our hypothesis regarding the potential for basalt formations to rapidly convert injected CO2 into solid mineral form. REFERENCES 1. Gupta,N., Wang, P., Sass, B., Bergman, P. and Byrer, C. (2001). In: Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies, pp. 385-390, Williams, D.J., Durie, R.A., McMullan, P., et al. (Eds). CSIRO Publishing, Collingwood, Australia. 2. Varekamp,J.C., Kreulen, R., Poorter, R.P.E. and Vanbergen, M.J. (1992) Terr. Nova 4 (3), 363. 3. Brady, P.V. and Gislason, S.R. (1997) Geochim. Cosmochim. Acta 61 (5), 965. 4. Tajika, E. (1998) Earth Planet. Sci. Let. 160 (3-4), 695. 5. Retallack, G.J. (2002) Philos. Trans. R. Soc. Lond. Set. A-Math. Phys. Eng. Sci. 360 (1793), 659. 6. Tomkeieff,S.I. (1940) Bull. Volc. 6, 90. 7. DOE (1988). Site Characterization Plan, Reference Repository Location, Hanford Site, Washington. DOE/RW-0164, Vol. 2, U.S. Department of Energy, Washington, D.C. 8. Williams,R.O. (1993) Energy Convers. Manag. 34 (9-11), 719. 9. Bach, W. and Fiebig, S. (1998) Energy 23 (4), 253. 10. Seidemann, D.E., Masterson, W.D., Dowling, M.P. and Turekian, K.K. (1984) Geol. Soc. Am. Bull. 95 (5), 594. 11. Puffer, J.H., Hurtubise, D.O., Geiger, F.J. and Lechler, P. (1981) Geol. Soc. Am. Bull. 92 (4), 155. 12. Puffer, J.H. and Volkert, R.A. (2001) J. Geol. 109 (5), 585. 13. McBride, J.H. (1991) Tectonics 10 (5), 1065. 14. Green, J.C. (1982). In: Geology and Tectonics of the Lake Superior Basin, pp. 47-55, Wold, R.J. and Hinze, W.J. (Eds). Vol. 156, Geological Society of America, Boulder, Colorado. 15. Davis, D.W. and Paces, J.B. (1990) Earth Planet. Sci. Let. 97 (1-2), 54. 16. Reidel, S.P., Johnson, V.G. and Spane, F.A. (2002). Natural Gas Storage in Basalt Aquifers of the Columbia Basin, Pacific Northwest USA.A Guide to Site Characterization. PNNL-1396), Pacific Northwest National Laboratory, Richland, Washington. 17. Sass, B.M., Engelhard, M.H., Bergman, P. and Byrer, C. (2001). In: First National Conference on Carbon Sequestration. Washington, D.C., National Energy Technology Laboratory.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1641

EVALUATION OF CO2 SEQUESTRATION IN SALINE FORMATIONS BASED ON GEOCHEMICAL EXPERIMENTS AND MODELING Bruce M. Sass 1, Neeraj Gupta 1, Sandip Chattopadhyay 1, Jennifer Ickes 1, and Charles W. Byrer 2 1Battelle, Columbus, Ohio, USA; 614-424-6315; [email protected] 2National Energy Technology Laboratory, Morgantown, WV, USA

ABSTRACT

This paper presents results of a recently completed study in collaboration with the U.S. Department of Energy's (DOE) National Energy Technology Laboratory (NETL) to conduct research on the feasibility of CO2 sequestration in deep saline formations. The objectives of the study were to: (1) investigate the potential for long-term sequestration of CO2 in a deep, regional host rock formation; and (2) evaluate the compatibility of overlying caprock with injected CO2 with regard.to its effectiveness as a barrier against upward migration of the injectate. Experiments were conducted using rock samples from different potential host formations and overlying caprocks, as well as certain pure mineral specimens to evaluate specific mineral reactions. Reaction vessels containing a pure solid phase or mechanical mixture of phases, and liquid were pressurized with CO2 or a mixture of either N2 and CO2, or N2, CO2, and SO2. The duration of the experiments was one to three months at pressures consistent with deep reservoirs, and temperatures of either 50°C (typical) or 150°C (elevated). It was concluded from the experiments and geochemical modeling calculations that the potential for adverse effects of CO2 injection into capped, sandstone formations is low.

INTRODUCTION

The overall objective of this geochemical study was to enhance understanding of the interactions between injected CO2, formation fluids, and rock media based on laboratory experiments and geochemical simulations. Once injected into reservoirs, a large portion of the CO2 may remain as a separate phase and float towards the top of the reservoir due to density contrasts, while some may dissolve in the formation fluid. The dissolved CO2 can react with formation minerals and, under certain conditions, cause precipitation of mineral phases resulting in mineralogical sequestration or permanent trapping of carbon. It is important to understand both the short-term reactions that may affect injectivity during the injection facilities operation and the longer-term reactions that may determine the ultimate fate of injected CO2. The effect of SO2 impurity in the CO2 stream was also investigated. Geologic disposal of CO2 involves finding geologically suitable formations for sequestering large amounts of CO2 for a long period without significant environmental risk, and at a reasonable cost. Suitable formations are deep, regionally extensive, filled with saline waters, and separated from freshwater aquifers and other formations of economic interest by low permeability caprock. For CO2 disposal applications, a minimum depth of about 800 meters is required to maintain the pressure for retaining CO2 in a dense, supercritical fluid phase. Other site-selection criteria are based on suitable geologic, hydrogeologic, geochemical, and seismic parameters. Because there is a significant overlap in the presence of CO2 emission sources and potential reservoirs for geologic sequestration, the focus of current investigations is on the midwestern and Ohio River Valley regions of the United States. However, due to the fundamental nature of the geochemical

1642 experiments the findings are also applicable to other similar reservoirs. Rock core samples were obtained from six locations that included the Eau Claire, Rome, and Mt. Simon formations, representing formations that could be in immediate contact with injected CO2 if a sequestration facility were operated in the region. The Mt. Simon is generally a fine, to coarse-grained quartz and feldspar sandstone. The formation has a relatively large volume of primary intergranular pore space with lesser amounts of secondary pore space. Minor amounts of detrital and authigenic clay may limit porosity, and a small amount of dolomite cementation may be present. Clay in the formation appears to be mostly glauconite, illite or chlorite. The Eau Claire is a formation with variable lithology. Lower portions often are similar to the Mt. Simon sandstone, especially in Illinois, while upper portions often are shale, dolomite, or siltstone. The dolomitic portions have low porosity and are well cemented with calcite and dolomite cement. Core samples from Ohio that were used in this study were provided by the Ohio Geological Survey. CO2 injection potential at two locations in this formation and the overall economic and implementation issues are discussed in Gupta et al. [ 1, 2]. In addition to the rock cores, commercially available specimens of anorthite, glauconite, kaolinite and montmorillonite samples were also tested. Results of detailed analyzes and compositions of all samples used in the study are presented elsewhere [3].

EXPERIMENTAL Experiments were conducted using rock samples that represent different potential host reservoirs and overlying rocks. Variations in temperature and time were explored, to the extent feasible, because they affect the rate and extent of reaction, respectively, which could have important ramifications for a full-scale injection operation. For example, if the reactions are too slow, the potential for leakage of CO2 into overlying formations may increase. On the other hand, fast reaction rates may adversely affect the porosity and permeability of a formation near the injection well by reducing injectivity and therefore shortening the lifetime of the injection well. Variations in pressure also were explored because pressure controls the concentration of CO2 in the brine and therefore the amount available for reaction. Experiments also were conducted to test the effects of SO2 impurity. Tests were performed using typical concentrations of SO2 found in flue gas from coal combustion when desulfurization is not used. After the experiments were completed, detailed characterization was performed to determine if SO2 impedes carbon sequestration or produces byproducts that may potentially impact the sequestration process. Additionally, the mineral pyrite (FeS:) was added to some experiment mixtures to maintain a chemically reducing environment and to provide a source of iron. In this capacity, it was thought than iron carbonate minerals might be formed by reaction of pyrite with CO2. Pyrite occurs naturally in some parts of the Mt. Simon formation. Experiments were conducted in l-liter pressure vessels designed so that they could be filled with a mixture of a brine solution and solid material, then pressurized with CO2, and equilibrated at constant temperature and pressure. The pressure vessels were made of chemically resistant HasteloyTM C-276 and lined with PTFE-Teflon inserts. The experiments ran for a period ranging from 30 to 90 days. At the end of the reaction period, a small sample of gas was collected in a Tedlar bag and analyzed by GC/FID for CO2, 02, N2, and SO2. The solid and solution phases were separated by decanting the fluid into a capture vessel. Constant pressure during the transfer was maintained to avoid inducing precipitation while the fluid was being transferred. A 2-~tm-pore size frit at the base of the tube inside the reactor prevented carryover of solids into the capture vessel, where the liquid was cooled by a water jacket. After the contents in the capture vessel were cool, the solution was analyzed for total organic carbon, alkalinity, pH, ORP, sulfate, chloride, and metals. The solids were rinsed two times with approximately 100 mL of deionized water that had been adjusted with NaOH so it has a pH between 8 and 9. The pH of the water was adjusted so that any carbonate compound that might have formed would not be dissolved by naturally acid deionized water dried and analyzed in the same manner as the unreacted samples for comparison. TM

Solid samples were analyzed by several different techniques, including optical microscopy, x-ray diffraction

1643 (XRD), scanning electron microscopy (SEM) with energy dispersive spectroscopy (EDS), and x-ray photoelectron spectroscopy (XPS). XRD was performed using a Rigaku Geigerflex X-ray Diffractometer with Cu Ka x-ray radiation. A JEOL 840 SEM was used to collect images. A Physical Electronics Quantum 2000 xPS System was used to collect XPS spectra. The Quantum 2000 XPS was operated at the William R. Wiley Environmental Molecular Sciences Laboratory at Pacific Northwest National Laboratory, in Richland, Washington.

RESULTS Results of experiments with Mt. Simon sandstone indicated congruent leaching of quartz and feldspars into the solution phase. However, no mineral precipitates were found in the products despite use of advanced characterization tools. Eau Claire shale, a potential confining layer, exhibited very little leaching. This shale contains a phosphate-bearing mineral (hydroxylapatite), which is an indicator of bulk dissolution. Low dissolution behavior suggests, from a geochemical perspective, that Eau Claire shale has good suitability as a caprock. Throughout these experiments there were no indications of carbon mineral trapping reactions (i.e., precipitation of carbonates). Mineral trapping can occur only if the reservoir supplies needed divalent elements such as calcium, ferrous iron, and manganese. The Mt. Simon has a limited amount of iron in glauconite that occurs in some locations; however, the short-term experiments conducted during the current project did not show any indication of mineral trapping of CO2 in this formation. Results of the 30 to 90 day tests show no behavior that would adversely affect injectivity. This is encouraging for potential future injection facilities that need to maintain performance over a period of years or decades. However, anhydrite (or gypsum) is a potential mineral precipitate that should be considered before injecting CO2, because of possible injectivity loss due to pore clogging. Any additional calcium supplied by dissolving mineral phases (e.g. dolomite) could force precipitation of gypsum. Anhydrite formed in one test where the sulfate level in the brine was artificially elevated. A small amount of SO2 co-mixed with CO2 increased iron leachability in all samples tested, but had no other effect that could be determined. The potential benefits of co-injecting SO2/CO2 mixed waste could be considered to determine whether this practice is economically favorable.

Geochemical Modeling Geochemical modeling was used to calculate equilibrium concentrations of chemical species in solution and determine the relative saturation of solid phases in equilibrium with a solution. Computer modeling codes were used to simulate interactions between minerals, brine, and CO2/SO2 atmosphere. Three geochemical codes were used in this study, as appropriate for the temperature and ionic strength under consideration. They included PHRQPITZ [4] and The Geochemist's WorkbenchT M [5], which are capable of performing calculations in high salinity conditions. In addition, PHREEQC [6] was used because of its extensive mineralogical database, but was limited to low salinity simulations. The selected rock/mineral and CO2 interactions for the simulations included anorthite, annite (proxy for glauconite [7]), and dolomite. Each of the simulation runs were conducted at three different temperatures: 25°C, 50°C, and 150°C. With increasing amount of CO2 consumed, the reactant materials dissolve into the formation water, which eventually can lead to precipitation of product phases. Once formed, product phases remain in equilibrium with the solution unless they completely react out. The simulation runs terminated when equilibrium had been achieved or when all of the reactant phases had been consumed. It was concluded that anorthite and annite (glauconite) are potential reactants for CO2 in deep formations, where they can form calcite and siderite, respectively. Although precipitation of carbonate minerals is favorable to long-term storage of injected CO2, it was apparent from the experimental studies that significant transformations would require long time periods to take place. In contrast to the slow kinetics of silicate

1644 minerals, reaction rates for carbonates and sulfates are more rapid. The simulations predicted that dolomite dissolves to a greater extent than gypsum precipitates, as CO2 was added to the system, implying that net porosity would likely increase.

CONCLUSIONS

The overarching conclusion of the experiments and computer simulations is that no adverse effects of CO2 injection into Mt. Simon sandstone (host rock) would likely occur over a short-term period (decades). Rock samples that are predominately composed of quartz sand were relatively unchanged by interaction with the CO2. Experiments with samples that contain appreciable amounts of potassium feldspar showed significant dissolution, but no precipitation byproducts. Similarly, dolomite was degraded by CO2-rich brine, resulting in higher levels of calcium, magnesium, and bicarbonate in solution. As a consequence, it appears that gypsum can precipitate when sulfate levels in the brine are very high. However, modeling calculations revealed the volume of dolomite that dissolved was greater than the volume of gypsum precipitated. Therefore, a net porosity increase is expected, which could result in an increase in permeability. Experiments to verify mineral trapping (i.e., conversion of CO2 to a carbonate mineral) showed progress toward that end, but generally were too slow to be completed during short time periods (<90 days). Advanced spectroscopic techniques (e.g., x-ray photoelectron spectroscopy) indicate that elemental compositions at mineral surfaces were modified as a result of the experiments. Moreover, these changes proceeded in the direction that was predicted by equilibrium modeling. For example, when anorthite (calcium aluminosilicate) was reacted in brine, the calcium and aluminum content at the mineral surface decreased, which is consistent with equilibrium modeling that points toward precipitation of calcium carbonate (calcite) and kaolinite (clay). This, and similar types of behavior, indicate that reaction progress was made, but that time limitations prevented reaching equilibrium.

REFERENCES

1. Gupta, N., Sass, B., Chattopadhyay, S., Sminchak, J., Wang, P., and Espie, T. (2002). Geologic Storage of C02 from Refining and Chemical Facilities in the Midwestern U.S. Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies, Kyoto, Japan. October 1-4. 2. Gupta, N., Smith, L., Sass, B., and Byrer, C. (2002). Engineering and Economic Assessment of C02 Sequestration in Saline Aquifers. Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies, Kyoto, Japan. October 1-4. 3. Sass, B., Gupta, N., Ickes, J. and Chattopadhyay, S. (2001). Geochemical Evaluation of Carbon Dioxide Sequestration in Saline Formations. Battelle report prepared for U.S. Department Of Energy, National Energy Technology Laboratory, Contract No. DE-AC26-98FT35008. 4. Plummer, L.N., Parkhurst, D.L., Fleming, G.W. and Dunkle, S.A. (1988). Water-Resources Investigations Report 88-4153. U.S. Geological Survey. p. 310. 5. Bethke, C.M. (1994). The Geochemist's WorkbenchTM, Version 2.0, A Users Guide to Rxn, Act2, Tact, React, and Gtplot. Hydrogeology Program, University of Illinois. 6. Parkhurst D.L. and Appelo, C.A.J. (2001). PHREEQC (Version 2) - A Computer Program for Speciation, Batch-Reaction, One-Dimensional Transport, and Inverse Geochemical Calculations. U.S. Geological Survey. 7. Gunter, W.D., Wiwchar, B. and Perkins, E.H. (1997). Aquifer disposal of C02-rich greenhouse gases: extension of the time scale of experiment for C02 sequestering reactions by geochemical modeling. Mineralogy and Petrology 59:121-140.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1645

CAPACITY INVESTIGATION OF BRINE-BEARING SANDS FOR GEOLOGIC SEQUESTRATION OF CO2 Christine Doughty, Sally M. Benson, and Karsten Pruess Earth Sciences Division Lawrence Berkeley National Laboratory 1 Cyclotron Rd, MS 90-1116 Berkeley, CA 94720

ABSTRACT

The capacity of brine-bearing formations to sequester carbon dioxide (CO2) is investigated using mathematical modeling of CO2 injection and storage. CO2 is injected in a supercritical state that has a much lower density and viscosity than the brine it displaces. In situ, it forms a gas-like phase, and also partially dissolves in the aqueous phase. The capacity factor is defined as the volume fraction of the subsurface available for CO2 storage and is conceptualized as a product of four factors that account for 1) two-phase flow and transport processes, 2) formation geometry, 3) formation heterogeneity, and 4) formation porosity. The key properties that impact the capacity factor include permeability anisotropy and relative permeability, brine/CO2 density and viscosity ratios, brine salinity, the shape of trapping structure, formation porosity, and the presence of low-permeability layering. The space and time domains used to define capacity factor must be chosen carefully to obtain meaningful results. Often, there is no unique choice for the volume on which to base the capacity factor. One possible convention is to define a dynamic capacity factor that makes use of the self-similar nature of the Buckley-Leverett solution for the propagation of the CO2 front away from the injection well.

INTRODUCTION

Geologic sequestration of carbon dioxide (CO2) in brine-bearing formations has been proposed as a means of reducing the atmospheric load of greenhouse gases. For this procedure to have any meaningful impact on the global carbon cycle, vast quantities of CO2 must be injected into the subsurface and isolated from the biosphere for hundreds or thousands of years. We use numerical simulations to investigate the capacity of deep brine-saturated formations to sequester CO2 that has been compressed to a supercritical state and injected over a 20-year period. The subsequent 40-year recovery period after injection ceases is also simulated. The three-dimensional (3D) model includes all flow and transport processes relevant for a twophase (liquid-gas), three-component (CO2, water, dissolved NaC1) system [1,2]. In particular, CO2 may exist in a gas-like supercritical state or be dissolved in the aqueous phase. Salt may precipitate out of the brine, but the rock matrix itself is inert. Thus, chemical reactions between CO2 and rock minerals, which can significantly contribute to mineral trapping of CO2 over long time scales [3], are not considered. The 1km by 1-km by 100-m thick model includes heterogeneity representative of a fluvial geologic setting [4]. Permeability varies by nearly six orders of magnitude, from 710 -13 m 2 (700 md) sand channels to 1018 m 2 (1 ~d) shales, which are arranged in a lenticular fashion, making preferential flow a significant effect as well.

1646 DEFINITION OF CAPACITY FACTOR The capacity factor C is defined as the volume fraction of the subsurface available for CO2 storage and is conceptualized as the product of four factors [5]: C = CiCgCh~,

(1)

where C~ is the intrinsic capacity, accounting for two-phase flow and transport processes, Cg is a correction for formation geometry, Ch is a correction for formation heterogeneity, and ~b is formation porosity. Moreover, Ci can be divided into gas-phase and liquid-phase contributions: Ci = Cig + Cil,

(2)

where Cig = Sg, Cil = SA'ic°2pi/pco2, Sg and S! are gas and liquid saturations, respectively, Sl CO2 is CO2 mass fraction in the aqueous phase, and pl/Pco2 is the density ratio of brine to CO2 [5]. Buckley-Leverett type analyses enable determination of Cig, considering idealized one-dimensional radial flow geometry [6, 7]. Numerical simulations are performed to incorporate dissolution of CO2 in the aqueous-phase (Ci0, buoyancy flow (Cg), geometric effects such as a dipping formation (Cg), and geologic heterogeneities that control sweep efficiency and bypassing (Ch). Figure 1 illustrates the different components of the capacity factor. Homogeneous, no ._qravi

Homogeneous, gravity

Heterogeneous, gravity

X

X

z

X

Figure 1: In the leg frame, Ci¢ = C, since Cs = Ch = 1. In the center frame, Cs < 1, Ch = 1. In the right frame, Cs < 1 and Ch > 1, since heterogeneity has mitigated buoyancy effects. Careful consideration of the capacity factor quoted by other authors [7, 8] indicates that much of the perceived discrepancies can be attributed to different conventions for defining capacity factor. For example, Pruess et al. [7] use a one-dimensional radial flow model with homogeneous properties and report Ci values in the range of 0.2 to 0.4. In contrast, van der Meer [8] considers gravity and a dipping formation and applies a rough heterogeneity correction, yielding the much smaller values of CiCgCh = 0.01 to 0.07. The difference implies CgCh- 0.1, which is near the lower end of the range encountered in our studies.

SIMULATION RESULTS The present modeling studies focus on CO2 injection into a sedimentary formation at a depth of 2,000 m formed by fluvial processes that created strong permeability heterogeneity. The top and bottom boundaries of the model are closed, to represent sealing shale layers, and the lateral boundaries are open, to approximate a laterally extensive formation. CO2 injection takes place at a constant rate through a central well that penetrates the lower half of the 100-m thick model. The simulation shows that CO2 preferentially flows through high-permeability features such as barrier bars, sand channels, splays, and washovers, while avoiding low-permeability flood-plain shale layers (Figure 2). Most shale layers are discontinuous, however, and buoyancy flow is strong, making the interplay between buoyancy flow and formation heterogeneity a key factor in determining the distribution of CO2 in the subsurface, which in turn has important ramifications for the capacity factor. After injection of CO2 ceases, the subsurface distribution of CO2 continues to evolve, primarily driven by buoyancy flow of the gas-like phase out the lateral boundaries of the model. In general, the relative importance of sequestration in the aqueous phase by dissolution can be large if imperfect cap or lateral seals allow the loss of gas-like CO2.

1647 1 year

CrY2

SIXI

P/Pco2

0.07 O.OD 0.0~ I~. 0.04 0.03 i

. i

-.~.;;-.-.....+ ...........................~........................... -"~" ...... 2 :

O.m .............. °°°o

""-'"--"4"-"................ ~ . . . . . . . . . . . . + . . . . . . . . . . 1o

2o

3o

~ ............ 4o

~ .......... 6o

oo

1im,(~

Figure 2" Simulation results for spatial distributions of injected C02 near the beginning (left column) and end (center column) of the 20-year injection period, and after a subsequent 40year recovery period (fight column). CO2 exists in a gas-like phase (top row) and dissolved in the aqueous phase (middle row). The capacity factor (bottom row) provides an integrated, quantitative measure of the fraction of the subsurface being used for sequestration. The space and time domains used to define capacity factor must be chosen carefully to obtain meaningful results. When there is a particular volume associated with the sequestration scenario under consideration (e.g., an isolated fault block, an anticline trapping structure, a volume of the subsurface available to the operator), this is the natural spatial domain to use. In contrast, for a laterally extensive formation with no natural geological boundaries, there is no unique choice for the volume on which to base the capacity factor. In Figure 2, the capacity factor averaging volume is taken to be constant, and to consist of the entire model volume. This choice results in a rapidly increasing C at early times, before CO2 reaches the outer edge of the model, and a gradually decreasing C at late times, after CO2 injection has ceased and buoyant gas-like CO2 escapes out the sides of the model. The strong time dependence of C makes it difficult to choose a single value of C to characterize the sequestration process. One possible alternative formulation is to define a dynamic capacity factor that makes use of the self-similar nature of the Buckley-Leverett solution for the propagation of the CO2 front away from the injection well. As time t increases, the volume V for which capacity factor is calculated also increases, in accordance with a fixed value of V/t. Figure 3 compares C versus t for dynamic (fixed V/t) and conventional (fixed V) capacity formulations. In both cases, for the recovery period (20-60 years), V remains fixed at the value used at the end of the injection period. For the 1 km by 1 km model, the conventional C versus t curve shares the shortcomings of the C versus t curve shown in Figure 2. For a laterally infinite model, the conventional capacity factor (using the same averaging volume as the finite model) does not characterize the entire CO2 plume, only the central part of it. Choosing a larger averaging volume would delay the time at which the CO2 plume outgrows the averaging volume, but not solve the fundamental problem. In contrast, the dynamic capacity factor characterizes a volume that grows along with the CO2 plume.

1648

O'lf''"

':" " ' 1 krr~by 1'i~ ~ ' . ~wentional'capad~ (r :'5()0 m)' ! o Infinitemodel- conventional ca~adty (r = 500 m) ,_ 0.08 .........m m ..!n!initemqdel-.dyn~c ~..ty..(r2/t =.146m2!day)........ t~ LL

.~006 ¢o t~ a.

0

0.04

I-- 0.02 10

20

30

40

50

60

T i m e (yr)

Comparison of dynamic capacity factor, which uses a fixed value of V/t for averaging, and conventional capacity factor, which uses a fixed volume V. For these uniform-thickness models, volume is proportional to the square of radial distance.

F i g u r e 3:

ACKNOWLEDGEMENTS

We thank C. Oldenburg and K. Karasaki for their critical reviews. This work is part of the GEO-SEQ project, which is supported by the U.S. Department of Energy through the National Energy Technology Laboratory (NETL) under Contract No. DE-AC03-76SF00098.

REFERENCES 1. Pruess, K., Oldenburg, C., and Moridis, G. (1999). Rep. LBNL-43134, Lawrence Berkeley National Laboratory, Berkeley, CA. 2. Pruess, K. and Garcia, J. (2002). Environmental Geology, 42, 282-295. 3. Xu, T., Apps, J.A., and Pruess, K. (2002). Rep. LBNL-50089, Lawrence Berkeley National Laboratory, Berkeley, CA. 4. Hovorka, S.D., Doughty, C., Knox, P.R., Green, C.T., Pruess, K., and Benson, S.M. (2001). Evaluation of brine-bearing sands of the Frio formation, upper Texas gulf coast for geological sequestration of CO2, First National Conference on Carbon Sequestration, May 14-17, Washington DC, National Energy Technology Laboratory. 5. Doughty, C., Pruess, K., Benson, S.M., Hovorka, S.D., Knox, P.R., and Green, C.T. (2001). Capacity Investigation of Brine-Bearing Sands of the Frio Formation for Geologic Sequestration of CO2, First National Conference on Carbon Sequestration, May 14-17, Washington DC, National Energy Technology Laboratory. 6. Buckley, S.E. and Leverett, M.C. (1942). Trans. Am. lnst. Min. Metall. Eng., 146, 107-116. 7. Pruess, K., T. Xu, J. Apps, and J. Garcia. (2001). Numerical modeling of aquifer disposal of CO2, Society of Petroleum Engineers, SPE/EPA/DOE Exploration and Production Environmental Conference, San Antonio, TX, 26-28 February. 8. van der Meer, L.G.H.. (1995). Energy Conservation and Management, 36, 6-9, 513-518.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1649

COST COMPARISON AMONG CONCEPTS OF INJECTION FOR CO2 OFFSHORE UNDERGROUND SEQUESTRATION ENVISAGED IN JAPAN Hironori Kotsubo 1, Takashi Ohsumi l, Hitoshi Koide 1, Motoo Uno Takeshi Ito 2, Toshio Kobayashi 3 and Kozo Ishida 3 l Research Institute of Innovative Technology for the Earth (RITE) 9-2, Kizugawadai, Kizu-cho, Soraku-gun, Kyoto, 619-0292, JAPAN 2 SK Engineering Co., Ltd. 3 Japan Drilling Co., Ltd.

ABSTRACT

In connection with CO2 sequestration into offshore aquifers, one of the basic considerations is how the CO2 can be brought economically from the coast to the intended geological formations. Here, RITE, in cooperation with oil industry experts, implemented a preliminary study in which several possible methods were assessed using CAPEX and OPEX, with demolition costs included. Although which method is superior varies, depending on geological, geographical, environmental and several other conditions applicable to each specific project, the outcome of the study explicitly indicates that "extended reach drilling (ERD) from onshore" and "subsea completion" are worth considering when those hypothetical parameters employed in the study are applicable.

INTRODUCTION

At present, Japan is in the process of 5-year R&D program of underground storage of CO2 [ 1], and this study was carried out as part of this program. Offshore saline aquifers are the target geological formation in this program because (1) most of large-scale emission sources of CO2 are located near the coast in Japan, (2) aquifers of large volume are expected to be found more in offshore than on land, and (3) site acquisition is much more costly on land. At present, we assume the total time scheme of the sequestration process as shown in Figure 1, which is based on practical results from similar processes such as large-scale underground storage of natural gas in aquifers [2]. The total system of underground sequestration can be roughly divided into three processes: recovery, transportation, and injection. While quite a few papers regarding the former two categories are publicly available, this does not seem to be the case with the latter. Although the methods of recovery and transportation have been well studied, the injection process has not been established as it is significantly affected by geographic, geological and topographic features of the site. We think that the cost of injection into an offshore aquifer varies with the method applied. One reason is that there are a variety of applicable designs and construction methods of wells and surface facilities (especially offshore) that depend on the conditions of injection site. The other reason is that there are many uncertainties in exploration and operation, as is the case with petroleum development. There are a few works [3, 4] dealing with costs of offshore aquifer storage in several countries, but in Japan, these are few. We have

1650 studied the cost of conditions and stages of injection processes in a Japanese context. This paper shows the results of our preliminary analysis on the costs of injection facilities. FRAME OF E S T I M A T I O N

Configuration of Wells and Wellheads When we think of injecting recovered CO2 into coastal offshore aquifers in Japan, there may be three types of configuration of injection facilities, i.e. wells and wellheads, as shown in Figure 2. They are roughly categorized by location of wellheads.

(A) Extended Reach Drilling (ERD)from onshore The wellhead is situated onshore, near a CO2 source. Wells are drilled underground to a target reservoir by a directional drilling path, similar to the horizontal well drilling method. ERD has been in practical use since the late 1980s and there are a many applications recorded in the petroleum industry. The world's longest ERD deviation length is about 10 km.

(B) Subsea completion The wellhead is installed on the seabed and is connected to a CO2 source by submarine pipeline. Wells are drilled offshore above a target reservoir. Standard Jack-up drilling rigs are applicable in water depth of less than 100 m and semi-submersible drilling rigs are usually used in deeper water.

(C) Offshore platform This case seems most familiar. The wellhead is installed on a fixed platform constructed offshore above a target reservoir. In the area of water depth of less than 1O0 m, the most cost-effective platforms are thought to be of the simple wellhead supporting type, whose wells are drilled with Jack-up figs. In deeper water, platforms equipped with drilling units are thought to be the most economical.

Preconditions and Assumptions for Estimation For cost comparison, it is assumed that large-scale underground storage, such as applicable to a coal-fired power plant of 1000 MW class, and nine cases are set, as shown in Table 1, under preconditions as follows: Injection rate: Total amount of injection: Number of injection wells:

10 Kt-CO2/day 73 Mt-CO2 (Period of injection: 20 year) Case 1: One horizontal well with 2 km perforation Other cases: Two horizontal wells with 1 km perforation

Capital Expenditure (CAPEX), Operating Expenditure (OPEX) and the cost for decommissioning were estimated for each case. The contingency cost was also calculated considering that additional injection wells may be needed in case of problems. In each case, compressors for transportation are to be installed onshore next to the CO2 source. CAPEX and OPEX for compressors are not included in this cost estimation. RESULTS AND DISCUSSIONS Figure 3 shows the result of estimation. 1) Of the cases where source-reservoir distance is 10 km, "ERD from onshore" is the least expensive in both the total cost and the segmental costs of CAPEX, OPEX and decommissioning. Additional CAPEX for Contingency is comparably larger than other cases, but its proportion is small in the total cost. 2) Except for "ERD from onshore", "subsea completion" is economically superior to "offshore platform" in each conditions, i.e. "subsea completion with Jack-up Rig" is less expensive than "offshore platform with Jack-up Rig" at 90 m water depth and "subsea completion with Semisubmersible Rig" is less expensive than "offshore platform with installed Rig" at 150 m water depth. 3) In the cases of "subsea completion", the difference of applicable methods that comes from water depth gives very small differences to estimated total costs, i.e. the estimated total costs for "subsea completion with Jack-up Rig" and "subsea completion with Semi-submersible Rig" are nearly the same. 4) In the cases of "offshore platform", water depth seems to matter because the difference of applicable

1651 methods gives rather large differences to estimated total costs. Some implications can be derived from above results: 1) If there is a suitable reservoir within 10 km form a CO2 source and if it is applicable of "ERD from onshore" method, the method is economically superior to other options. 2) For other cases, "subsea completion" would be the second best option from the viewpoint of cost. But we should take account of the following points in the future estimation study: 1) Degrees of technical difficulty that lie in ERD and subsea completion are not considered in this estimation. Those methods are still improving and we should evaluate their progress and limitation. 2) If monitoring wells were required for safety reasons, design concept for wells and wellheads configuration might be totally changed. We would also like to analyse the costs for exploration and monitoring to enrich basic data for the economic model that is under development [5] to estimate the total costs of CO2 sequestration in Japan.

mcess

R ecovery

Tin hg

Transportation

h)ctbn

I

" Bibliographic Research • Geological Survey

Expbrati)n

• Exploratory Drilling

More

than 10 years C onstmctbn

• Plant Construction

0 peratbn

• Recovery • Maintenance

years

1 year

D ecom m i s s b n J n g

i

.,~.~.~}i~;. e

-,

• Construction of Injection and Monitoring Facilities

• Pipelining

~~ 20 to 40

1

• Injection • Monitoring • Maintenance

• Transportation • Maintenance

.

• Well Decommissioning

• Dismantlement

• Plant Demolition

•

J

,. • M o n i t o r i n g ?

P o s t 0 peratbn

/ ]

Figure 1: Time scheme of sequestration business

~ ) ERD f ~ m onshore

poht soume ofC 0 2 0 cean _ _ _ _

I

. _ _

1

_ _ _ L

___L_.

A quffer reservoir

~ ) S u b s e a corn p l e t b n

Submarhepipeline

) 0 ffshore phffom

~

~

~

7 o~ho~ phtfom

Figure 2: Three categories of well and wellhead configuration

1652

TABLE 1 NINE CASES FOR ESTIMATION

Case 1

Locatbn ofWelhead

Method ofWellDrfllhg

Water Depth

Onshore

ERD fromonshore

90m

1090m

With Jack-up Rig

90m

I090m

With Semi-submersible Rig

150 m

1150 rn

With Jack-up Rig

90m

1090m

With Rig installed on the Ratform

150m

1150m

Case 2 Case 3 Case 4 Case 5

Subsea On a Offshore Fixed Ratform

Case 2' Case 3' Case 4' Case 5'

Subsea On a O ~ e Fixed Ratform

Reservor Depth

With Jack-up Rig

90m

1090m

With Seni-submersible Rig

150m

1150m

With Jack-up Rig

90m

1090m

With Rig installed on the Ratform

150m

1150m

Source-Reservor Distance

10 km

50 km

~illi3n ¥] 0 Case Case Case Case Case

1 2 3 4 5

Case Case Case Case

2' 3' 4' 5' 0

5

I0

15

20

25

30

35

70

140

205

275

345

410

[¥/t--C 0 z] 480

ICAPEX

NOPEX

IDecomm issioning

.'.';Contingency-i

F i g u r e 3: Results of estimation

ACKNOWLEDGEMENT This study was supported by the Ministry of Economy, Trade and Industry (METI) of Japan and New Energy and Industry Technology Development Organization (NEDO).

REFERENCES 1.

Koide, H., Ohsumi, T., Uno, M., Matsuo, S., Watanabe, T. and Hongo, S. (2002). In: Proceedings of

2. 3.

Gaz de France (1997). Safe, Environmentally Sound Underground Storage Solutions. Hendriks, C.A, Wildenborg, A.F.B., Blok, K., Floris, F. and van Wees, J.D. (2001). In: Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies, pp. 967-972, Williams, D., Dude, B., McMullan, P., Paulson, C. and Smith, A. (Eds). CSIRO. Allinson, G. and Nguyen, V. (2001). In: Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies, pp. 979-984, Williams, D., Durie, B., McMullan, P., Paulson, C. and Smith, A. (Eds). CSIRO. Akimoto, K., Kotsubo, H., Asami, T., Li, X., Uno, M., Tomoda, T. and Ohsumi, T. (2002). In:

the Sixth International Conference on Greenhouse Gas Control Technologies.

4.

5.

Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1653

R A T E OF D I S S O L U T I O N D U E TO C O N V E C T I V E M I X I N G IN THE U N D E R G R O U N D S T O R A G E OF CARBON DIOXIDE

J. Ennis-King and L. Paterson Australian Petroleum Cooperative Research Centre CSIRO Petroleum, P.O. Box 3000, Glen Waverley VIC 3150 Australia

ABSTRACT In a typical underground storage project, a proportion of the injected gas will form a layer beneath the caprock due to buoyancy. The saturation of underlying brine with dissolved CO2 creates a density instability, and on long time scales this causes convective mixing, greatly increasing the overall rate of dissolution compared to a purely diffusive mechanism. Two time scales of interest are tc, the time at which the instability occurs, and tmix, the time at which the overlying layer of free CO2 is completely dissolved. Analytical estimates of these time scales are given, and for typical conditions it is shown that t¢ - 1 to 100 years, while tmix "" 10,000 to 100,000 years, so that t¢ << tm~x.The lateral spacing between plumes for typical conditions is 1 to 100 m. These estimates are compared with the results of fine scale flow simulations.

INTRODUCTION

One of the key issues surrounding the underground storage of carbon dioxide is the prediction of the long-term fate of the injected gas, as a means of assessing whether a potential injection site is likely to contain the carbon dioxide for very long time periods. This involves the study of a variety of factors such as seal capacity and geomechanical integrity, but it also depends on the physical process by which carbon dioxide will dissolve in the formation water. After injection ceases, the lesser density of the free carbon dioxide compared to the formation brine causes a vertical migration of the gas, until the gas is distributed between a mobile layer underneath the caprock, and gas trapped at the residual gas saturation throughout the injection zone. For injection into a structural trap, such as might occur in a depleted gas field, the gas cap could be quite thick. However in a regionally extensive saline formation, such as at Sleipner, the gas can easily spread out laterally and migrate beneath the top seal. In this latter case the thickness of the gas layer is initially only limited by capillary pressure, and there is a competition between migration and dissolution of the gas in the formation water. The balance between these effects determines the ultimate distance to which the carbon dioxide will migrate from the injection site. Three mechanisms contribute to the process of dissolution. Firstly, diffusion of the carbon dioxide within the aqueous phase allows further dissolution. Secondly, reactions may occur between the dissolved gas and the host mineralogy, dissolving or precipitating carbonate minerals. In the most favourable mineralogy this could be important, but in clean sandstones it is likely to be a lesser effect. Thirdly, there is convective mixing that occurs

1654 because the density of brine saturated with carbon dioxide is around 1 % greater than unsaturated brine [1]. Thus as the brine underlying the gas phase carbon dioxide beneath the seal becomes saturated with dissolved gas, a density inversion is created. When the layer of saturated brine becomes thick enough (due to diffusion), an instability occurs, and plumes of brine saturated with CO2 migrate downwards, slowly diluting as they go. The importance of convection is that it is typically orders of magnitude faster than pure diffusion at mixing the dissolved gas, and so it accelerates the overall dissolution of the carbon dioxide. In the next section, a mathematical model for convective mixing is analysed to determine the time-scale on which the instability and the mixing occur. These predictions are then compared with detailed numerical simulations of CO2 dissolution by convective mixing. MODEL To avoid the complications of two-phase flow, the gas layer overlying the formation brine is modelled by a boundary condition of constant concentration of dissolved CO2 at the top of the brine phase. The value of this constant is determined by the solubility of CO2 in the formation water, assumed here to be independent of pressure over the thickness of the formation. The governing equations for convective mixing can then be written as follows:

/ zK-Iv=-VP + Pig c~

¢ ~ + .. VC= ¢DV:C

(1)

(2)

where v is the Darcy velocity, /1 is the fluid viscosity, K is the absolute permeability (assumed constant everywhere and isotropic), P is the pressure, pf is the fluid density, g is the acceleration due to gravity, C is the concentration of dissolved CO2, ~ is the porosity (assumed constant), t is time, and D is the effective diffusivity of CO2 in the aqueous phase in the porous medium (i.e. the bulk diffusivity modified by the tortuosity). The fluid is assumed incompressible i.e.V, v =0. The coupling between the equations comes through the effect of dissolved CO2 on the fluid density, in the form Pl = P0(1 + tic C), where Po is the density of the unsaturated fluid, and tic is a numerical coefficient. The dependence of pfon C is only retained in the buoyancy term in Eqn. 1 (the Boussinesq approximation). Consider the medium to be in infinite horizontal slab of thickness H, with z being the vertical coordinate increasing downwards. The upper boundary conditions are then C=Gat at z=0, where Csat is the solubility of CO2 in brine (assumed to be independent of pressure), the initial conditions are C=0 for t=0 and z >0, and there is a no flux boundary condition on C at z=H. This is mathematically equivalent to the well-studied problem of temperature-driven convection in a porous medium [2]. One could include the effects of temperature as well as concentration, since the usual geothermal gradient makes the formation water less dense with depth and so is destabilising, but for most geological storage scenarios, the temperature effects are weak and sub-critical (i.e. these effects alone will not cause mixing) and so they will be ignored here. The usual stability analysis (based on the temperature analogue) assumes a linear vertical profile of concentration across the formation, and shows that this profile is unstable to small perturbations when the dimensionless Rayleigh-Darcy number Raz,= g K Ap H/(,uqkD) exceeds a critical value. Here Ap=/3cCs,,tpo is the density increase due to the dissolved CO2. For these boundary conditions, the critical value of Rat, is 27.10 [2]. This type of analysis has previously been applied to underground storage of carbon dioxide, and it was shown that convective mixing should occur in most cases [3]. However the problem is clearly a transient one, since the equilibrium state would be C=Gat throughout the layer, and the concentration profile prior to instability is not linear but rather a diffusive front. At short times (large H), the profile is C=Csaterfc(z/(2 (D t) 1/2 )), where erfc is the complementary error function. An approximate analysis of the transient problem was given by Elder [4], and detailed analysis by Caltagirone [5]. The scaling

1655 can be obtained by the following argument. Prior to the instability, the concentration across the layer of dissolved gas varies from Csat to 0, which is roughly analogous to the situation of the linear concentration profile (it is possible to take account of the nonlinear profile [2], but the scaling is unaltered). Thus one uses the above stability analysis, but replaces the total formation thickness H with the layer thickness (D t)z/2. The result is that the critical time t~ at which the instability begins to propagate is tieD t c ~ c o (Ap)2g2K 2

(3)

where co is a numerical constant. Published numerical results [5] give a lower bound for the critical time, and indicate that Co is in the range 80-100. The critical wavelength 2c of the most unstable fluctuations is of the order of the layer thickness at instability, so 2c .~ ct/.t~ D/(g K Ap). Fitting again to published results gives Cl in the range 100-120. Note that the formation thickness H does not appear in these formulae, since the argument assumes that Rao significantly exceeds the critical value i.e. that convection occurs at some saturated layer thickness much less than H. The assumption of isotropic permeability K can be relaxed, allowing for vertical and horizontal permeabilities kv and kh respectively, and the corresponding formula can be obtained by replacing K with 4kvkh/((kv)l/2+(kh)ln) 2 (assuming that the result for the linear concentration profile [2] can be carried over to this case). For k~/kh << 1, K~ 4 kv, so t¢ scales as 1/(kv) 2. Once the plumes of CO2 saturated brine begin to form at tc, there is an initial period of exponential growth, then as growth continues, the lower part of the plume is diluted by unsaturated formation water, and the propagation slows down, since the density difference that is driving the plume motion decreases. If the dilution effect is ignored, the time tm~ required to dissolve an initial gas layer of CO2 of thickness L can be estimated as

a~

tm;x ~ ~ kvApg

(4)

where a is the ratio between the density of the gas phase CO2 and the density as a dissolved phase (mass of COz per volume of solution). Mixing by pure diffusion would be on a time scale of (a L)2/D. RESULTS Typical parameter values for likely storage sites are ~=0.2,/l = 5 x 10 -4 Pa s, K=10 14 - 10 "13 m 2, kv = 10 15 - 10 14 m 2, Ap=: 10 kg m -3, L=10 m and a=10. These give tc -- 1 to 100 years, t,,~ -- 10,000 to 100,000 years, 2c ~- 1 to 100 m, and to/t,,~x ~ 10 5 to 10 2. Purely diffusive mixing would take 105 to 106 years, and so is much slower. Thus the dissolution process is dominated by the time taken for the plumes to migrate, rather than the time for the instability to begin. The initial stage of plume development and plume dilution effects, which are ignored here, will increase the estimate for tm~. Numerical simulations were carried out using the multiphase flow simulation code TOUGH2 (with a detailed equation of state for COJbrine mixtures) on a 2D grid 500 m wide (50 grid blocks) and 400 m vertically (100 blocks, refined to 0.5 m at the top). The geological parameters are based on a three zone model of a site in the Petrel Sub-basin off NW Australia, detailed in a companion paper [6]. The top 200 m has kh=5.9 x 1014 m 2 (60 mD) the pressure at the top is 18 MPa and the temperature is 78 C. The initial conditions involve a laterally uniform gas layer of variable saturation 10 m thick (taken from the coarser 3D injection simulation, 300 years after injection has ceased, when vertical equilibrium has been largely achieved). A random variation of the block permeability of amplitude 0.5% was used to seed the perturbations. In Fig. 1, the development of plumes of CO2 saturated brine is shown at the stage when 20% of the initial CO2 has dissolved for kv/kh=O.O1 (Fig la) and kJkh=O.1 (Fig lc). The plume spacing is smaller for kv/kh=O.1 (in fact

1656 the grid is not fine enough laterally to resolve it properly), in accord with the above scaling argument, which gives A~~ 50 m for kv/kh=O.O1 and 2c ~. 6 m for kv/kh=O.1. In Fig. lb, tc, the time at which the curves depart from the diffusion solution, does decrease as k~/khincreases, but the scaling for larger kv/kh is not as predicted. This appears to be because for kJkh=O.1 and 1, the simulation grids are not fine enough to resolve fluctuations on the scale of 2.c, and so the relative coarseness of the grid artificially stabilizes the layer of CO2-saturated brine. This is a serious issue for 3D field scale simulations at long times, since the lateral grid block dimensions of tens to hundreds of meters reduce the rate of dissolution by stabilizing against fluctuations. It may be possible to upscale to coarser grids on a given time scale either by using effective solubilities (based on matching fine and coarse simulations), or by introducing sub-grid block dynamics. The time taken after the instability begins for 20% of the CO2 to be dissolved increases by a factor of 8 when kv/kh is lowered from 1 to 0.1, and increases by another factor of 7 when kv/kh is reduced to 0.01. This indicates that the suggested scaling for tma is approximately fight, but needs some refinement. ........

'~

!

'

' i......

i

.......

' [

i

i

O.2

/

/

k~/k =1 [11.15

i

; II I

. . . . . . . .

I

100

. . . . . . . .

i

10~

.

.

.

.

.

.

.

.

1 1 ~

Time (years)

Figure 1: (a) Dissolved CO2 for kv/kh=O.O1 after 14,400 years (b) Dissolution vs time for three values of k~/kh (c) Dissolved CO2 for kv/kh=O.1 after 2100 years. In (a) and (c) the top 80 m is shown and the width is 500 m. CONCLUSIONS Convective mixing due to the greater density of CO2 saturated brine is the dominant mechanism for long-term dissolution of CO2 in underground storage projects. The time for complete dissolution to occur is dominated by the plume migration velocity, and typical time scales range from hundreds to tens of thousands of years, depending crucially on the vertical permeability. The small width of the plumes (1 to 100 m) poses a challenge for field scale simulations. ACKNOWLEDGEMENTS This study was partly supported by the Australian Petroleum Cooperative Research Centre, as part of the GEODISC project (sponsored by the Australian Greenhouse Office, BP, BHP, Chevron International, Shell Australia, Chervon/Wapet, Woodside and TotalFinaElf). REFERENCES 1. 2. 3. 4. 5. 6.

Hnedovsky, L., Wood, R.H. and Majer, V. (1996) 3. Chem. Thermodyn. 28, 125. Nield, D.A. and Bejan, A. (1999). Convection in Porous Media. Springer. Lindeberg, E. and Wessel-Berg, D. (1997) Energy Convers. Mgmt. 38, $229. Elder, J.W. (1967) 3. Fluid. Mech. 27, 609. Caltagirone, J.-P. (1980) Q. 3. Mech. Appl. Math. 33, 47. Ennis-King, J.P., Gibson-Poole, C.M., Lang, S.C. and Paterson, L. (2002). In: Proceedings of the Sixth

International Conference on Greenhouse Gas Control Technologies.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1657

POTENTIAL EFFECT OF CO2 RELEASES FROM DEEP RESERVOIRS ON THE QUALITY OF FRESH-WATER AQUIFERS P.R. Jaffe 1 and S. Wang 2 ZDepartment of Civil and Environmental Engineering, Princeton University, Princeton, NJ 08540, USA 2Environmental Research Institute, Ewha Womans University, Seoul, 120-750, Korea

ABSTRACT Injection of supercritical CO2 into deep saline aquifers is a promising technique for sequestration of large amounts of CO2. If some fraction of the injected CO2 were to leak and reach shallow groundwater aquifers, it would lead to geochemical alterations that could have detrimental effects on the water quality. A mathematical model was developed to simulate the change in solution pH and the enhanced dissolution of trace metals as carbon dioxide dissolves into the groundwater. The model takes into account the buffeting capacity as different mineral phases dissolved into the aqueous phase and includes the dissolution of minerals with the concomitant increase in dissolved species in the aqueous phase. A series of simulations were conducted for various CO2 release scenarios and different aquifer properties. Results show that CO2 dissolution in poorly buffered aquifers can solubilize trace metals to levels that exceed drinking water standards. This approach allows for a reasonable assessment of the risks on the quality of freshwater aquifers due to the escape of CO2 from deep geological formations.

INTRODUCTION The increase in CO2 emissions from the combustion of fossil fuels has increased the atmospheric CO2 concentration. It is widely believed that the anthropogenic emission of CO2 may be responsible for the current trend of global warming, the 'greenhouse effect' [1]. Capturing CO2 from massive energy production/consumption facilities and storing it securely in geological repositories has been proposed as an immediate solution to significantly reduce the emission of CO2 into the atmosphere [2]. Among the possible storages for CO2, deep brine aquifers, at depths greater than approximately 800m which can provide sufficient pressure and temperature for holding CO2 in a supercritical state, are being considered appropriate repositories given their large capacity and vast availability as well as economic insignificance [3]. Since the complete characterization of deep brine aquifers is not technically possible, however, the possibility that some fraction of the stored CO2 may leak into overlaying aquifers, ultimately upto shallow drinking-water aquifers, still needs to be considered. Since carbonated water and gaseous CO2 are not directly detrimental to drinking water, attention in evaluating the environmental impacts of CO2 leakage into potable aquifers should focus on the secondary effects, namely the geochemical changes caused by the increased CO2 dissolution. Dissolved into groundwater, CO2 increases the concentration of total carbonate and causes a decrease in pH. Such acidic condition can affect the dissolution and sorption mechanisms of many minerals and may cause detrimental effects on groundwater quality by enhancing dissolution and/or desorption of hazardous trace metals. Therefore, risk assessments to be conducted prior to the CO2 injection into deep formations should also include evaluations of the potential impacts of CO2 leakage on shallow groundwater quality.

1658 The objective of this study was to assess the effect of CO2 leakage into potable aquifers on drinking water quality. A secondary goal was to investigate the possible usage of the geochemical changes as an indicator of CO2 leakage from deep geological CO2 repositories. To this end, we developed a reactive transport model coupled with a geochemical speciation model for simulating the fate and migration of trace metal species in groundwater and for quantifying the effect of CO2 intrusion on pH and mineral dissolution in drinking-water aquifers. Based on simulations, we also explored favorable geochemical characteristics in overlaying aquifers that can buffer detrimental impacts of possible CO2 leakage from geological repositories on groundwater quality.

MODELING APPROACH The presented model takes into account the migration of carbonate species resulting from the CO2 dissolved into the aqueous phase and the alkalinity generated from the solid matrix, the corresponding pH change, the enhanced mineral dissolution in the more acidic groundwater, and the transport of trace metals dissolved from various minerals. A system of mass balance equations governing the fate and transport of the dissolved species and mineral phases in a saturated porous medium was formulated as follows:

dissolved species:

(1..I_K;ff)O((~c;q)=V.(D h .V(oc;q))_V.(v((/)C;q))+ERI

(|)

Ot

0

mineral phases:

~ - [ ( 1 - ¢)C~ ] = -)-]Rj

(2)

Where C; q and Cfi are the concentrations of the dissolved species i and the mineral phase j; v is the groundwater velocity vector; Dhi is the hydrodynamic dispersion tensor of dissolved species i; ~ Ri and Rj are the net consumption/production rates of the dissolved species i and the mineral phase j by geochemical reactions; ~ is the porosity; and K eg is an effective partition coefficient for the equilibrium adsorption of species i. The governing equations for each dissolved species and mineral phase are coupled through the geochemical reaction terms and form a system of partial and ordinary differential equations. The rate of mineral dissolution/precipitation is kinetically controlled by the deviation of the solution from its equilibrium [4]. The kinetic dissolution of minerals can be defined as a function of difference in activity product between the current and the equilibrium state. For a given mineral phase, S, composed of N s species, the rate of dissolution/precipitation is formulated as [5]:

s

=ks

(3)

-x;.

Where ks is the dissolution rate coefficient for mineral phase S. FIA i is the dissolved free ion activity of component i from calculations using MINTEQA2 for the aqueous phase only, and cti,s is the stoichiometric N, coefficient of the i-th component of mineral phase S. I--I [FIAi ~~ is the ion activity product representing i

the current state in the aqueous phase without considering the presence of solids. Ks,s is the equilibrium solubility product for mineral phase S from the MINTEQA2 database. Equation (3) implies that mineral dissolution takes place when the groundwater is undersaturated (1-I [FLA. ~"~ < KSp ) at a rate proportional i

to the degree of undersaturation. The corresponding net rate of change in the aqueous phase concentration ]~P/D = -cti,sRsP/D for the i-th dissolved component of the solid S is calculated as -.is

1659 MODEL APPLICATIONS AND DISCUSSIONS Lead poses a significant public health threat through long-term internal accumulation. Galena is one of the main minerals controlling the mobility of lead in the subsurface. As the partial pressure of CO2 in equilibrium with the solution increases, the pH decreases due to the increase of total carbonate concentration and the dissolved Pb concentration due to the dissolution of galena increases in the aqueous phase. In this study, we focus on dissolved lead and galena as an example for a target contaminant and a trace-metal-beating mineral to demonstrate how CO2 intrusion into shallow drinking-water aquifers may affect groundwater quality through an enhanced mineral dissolution process. Two types of simple aquifer mineralogy were considered in the numerical experiments; a very poorly buffered aquifer represented by galena and quartz as the mineral phases, and a very well-buffered aquifer by galena and calcite. Quartz is a widely distributed mineral of many varieties with a relatively small dissolution rate coefficient to range between 10 -14 and 10 -16 mol/m2s [6], while calcite is the most common form of natural calcium carbonate which can buffer solution pH to the presence of aqueous and/or atmospheric CO2 [7] with a dissolution rate coefficient to range between 10.5 to 10.8 mol/m2s [6]. Therefore, in a galena and quartz-based aquifer no significant mineral dissolution occurs at neutral pH and no alkalinity or buffering capacity can be assumed for the initial and boundary conditions, whereas a galena and calcite-based aquifer is expected to have a high alkalinity and hence buffering capacity. The model was applied to two homogeneous shallow drinking-water aquifers. The model is applied to simulate a domain of 400m x 400m at a reference depth of 60m in which groundwater flows horizontally with a velocity at 20 m/yr. The domains contain a single point source of CO2 with a pressure of 5 atm. Prior to the CO2 intrusion, the groundwater and the minerals in the aquifers are assumed to be at equilibrium with dissolved CO2 at a partial pressure of 0.00032 atm. A significant problem in simulating dissolution of mineral species in groundwater is that the dissolution rate kinetics are poorly quantified. From well-mixed batch experiments using graded and often pure mineral phases, the wide range of values that are reported in the literature illustrates the problem. Clearly, in a dissolution problem where water is flowing, the maximum concentrations of the dissolving ions at a specific location are closely linked to the dissolution rate. To select a dissolution rate coefficient for galena for the simulations, a series of numerical experiments with different galena dissolution rate coefficients were performed for the galena-quartz system. A value for the dissolution rate coefficient for galena (ks = 1 x 106/yr) was then selected as the lowest one resulting in an exceedence of dissolved Pb action level by US EPA of 7.24 x 106 M and was applied in all numerical experiments presented here. Figures 1 and 2 show simulation results for the areal distribution of dissolved Pb concentration (a); the cross-sectional profiles of total carbonate concentration (b), pH (c) over 8 years of CO2 intrusion into aquifers with mineralogy consisting of quartz and galena, and calcite and galena, respectively. In Figures 1, due to the low alkalinity and buffering capacity in the galena and quartz-based aquifer, the dissolved CO2 results in a direct increase of total carbonate concentration and the immediate drop in pH from 5.75 to 3.55 at the source point. While the plume of total carbonate evolves into an elliptical shape and migrates downstream through this non-buffered aquifer, the pH decreases rapidly in the zone of increasing carbonate concentration. Since Pb 2+ is the dominant Pb species throughout this pH range, and the solubility of Pb 2+ in equilibrium with galena increases with decreasing pH, the dissolution rate increases. In Figures 2, for the initial as well as inflowing groundwater was assumed to be at equilibrium with calcite and galena under a CO2 partial pressure of 0.00032 atm., resulting in a pH of 7.95. Due to the higher alkalinity of this aquifer system the pH decreases only to 5.41 at the CO2 source, and the pH rebounds much faster to background conditions as compared to the aquifer with quartz mineralogy. It is interesting to note that the peak lead concentration is reached closer to the source in the calcite aquifer, this is because the kinetics of dissolution are accelerated given that most of the dissolved lead is not present as Pb 2+. The dissolved Pb concentration profiles for the two aquifers clearly illustrates how important the aquifer buffering capacity is in terms of the effects of CO2 intrusion on the dissolution of a heavy metal bearing mineral. After 8 years of CO2 intrusion, the peak concentration of dissolved Pb rises from 7.32 x 10-1° mol/L to 7.63 x 10-8 mol/L in a galena and quartz-based aquifer, while in the galena and calcite-based aquifer dissolved Pb raises from 4.54 x 1011 mol/L to 2.81 x 10.9 mol/L. These results show that shallow formations with high alkalinity and pH buffering capacity are better candidates to serve as overlaying

1660 aquifers for deep geological CO2 sequestration than shallow aquifers with a very low alkalinity and buffering capacity. Since increase of dissolved lead concentration is approximately 100 times its background concentration in the quartz, such an increase suggests that local geochemical changes may be used as an indicator of CO2 releases from deep geological repositories. dissolved

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200

250

300

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Figure 2" Effect of C O 2 intrusion over 8 years on groundwater quality in a galena and calcite system; (a) dissolved Pb; (b) total carbonate; (c) pH

CONCLUSIONS Enhanced dissolution of trace metals due to geochemical changes caused by the intrusion of CO2 were incorporated into a dynamic transport model combined with an equilibrium geochemical speciation model to assess the risk of CO2 releases into a shallow drinking-water aquifer from deep reservoirs during geological CO2 sequestrations. The simulations show that CO2 intrusion into the drinking-water aquifer may cause adverse effects on groundwater quality by decreasing the pH and enhancing mineral dissolution of trace metals. The detrimental effect of CO2 intrusion is significantly decreased in aquifers with high alkalinity and pH buffering capacity. The simulation results also suggest that geochemical changes in shallow aquifers, such as the occurrence of trace metals at unusually high concentrations, may serve as an indicator of CO2 leakage from deep geological CO2 repositories. It should be noted that the applicability of the presented model for risk analysis is limited by the incomplete characterization of mineral dissolution kinetics, which is one of the most important parameters affecting the concentration of trace metals resulting from the dissolution of a mineral phase due to elevated CO2 levels. REFERENCES Falkowski, P., Scholes, R.J., Boyle, E., Canadell, J., Canfield, D., Elser, J., Gruber, N., Hibbard, K., H6gberg, P., Linder, S., Mackenzie, F.T., Moore, B. III, Pedersen, T., Rosenthal, Y., Seitzinger, S., Smetacek, V. and Steffen. W. (2000). Science. 290, 291. U.S. Department of Energy (1999). Carbon Sequestration Research and Development. Office of Science, Office of Fossil Energy. Washington, DC. Bachu, S. (2000). Energy Convers. Mgmt. 41,953. Lasaga A., Soler, J.M., Ganor, J., Burch, T.E. and Nagy, K.L. (1994) Geochim. Cosrnochim. Acta. 58, 2361. Smith, S. L. and Jaff6, P.R. (1998). Water Resour. Res., 34, 3135. Gunter, W. D., Wiwchar, B. and Perkins, E.H. (1997). Mineral. Petrol. 59, 121. Bemer, R.A., Lasaga, A.C. and Garrels, R.M. (1983).Amer. J. Sci. 283, 641.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1661

ECONOMICS OF ACID GAS REINJECTION: AN INNOVATIVE CO2 STORAGE OPPORTUNITY Sam Wong~, David Keith 2, Edward Wichert 3, Bill Gunter Iand Tom McCann4 1 Alberta Research Council, Edmonton, Alberta, Canada 2 Carnegie Mellon University, Pittsburgh, PA, USA 3 Sogapro Engineering, Calgary, Alberta, Canada 4 McCann t~ Associates, Calgary, Alberta, Canada ABSTRACT

Acid gas streams, consisting primarily of hydrogen sulfide (H2S) and carbon dioxide (C02), are commonly generated as a by-product of the gas sweetening process used to bring produced gases and solution gases up to pipeline specifications for sales and transport. In the past, the conventional methods for acid gas disposal are to use a Claus process or to flare the acid gas. A new technology called acid gas reinjection has emerged over the past ten years in Canada as an effective way of ensuring that acid gases are not emitted into the atmosphere. There are 38 acid gas reinjection projects presently operating in Alberta. This technology involves compressing the acid gas and injecting it into a suitable underground zone, similar to deep well disposal of produced water. Essentially, the sulfur compounds and CO2 are permanently stored in the deep geological formation preventing their release to the atmosphere. Therefore most acid gas reinjection projects can be considered as existing examples of CO2 geological storage projects. These projects provide important practical experience with CO2 storage. In addition, this technology could be extended to capture a significant fraction of the natural gas-associated CO2 stream at low cost. In this paper, a cursory economic analysis is made on one of the Alberta acid gas reinjection projects relative to sulfur recovery for determining the amount of CO2 avoided. INTRODUCTION

The capture of CO2 from the production and use of fossil fuels and its storage in geological formations may offer the ability to make early and deep reductions in CO2 emissions without abruptly abandoning our fossil-based energy infrastructure [1, 2, 3]. While the economics of COa mitigation are uncertain, to a rough approximation it appears that CO2 capture and storage (CCS) fills the gap between the lowest costs, most immediately available measures of CO2 mitigation, such as moderate energy efficiency improvements, and the higher costs associated with a transition to a non-fossil primary energy supply. Given its intermediate cost, one might expect that CCS technologies would play no role in achieving small, near term reductions in emissions. There is however an important, though limited, suite of technological niches where CCS technologies may be applied at low cost. The most important of these opportunities involve non-combustion sources of CO2. The cost of capturing CO2 and compressing it to the pressures required for geological storage (of order 100 atmospheres) is primarily dependent on the scale and purity of the CO2 stream to be captured. Combustion sources have CO2 concentrations of 5 to 15%; and for these dilute streams the cost of capturing CO2 dominates the cost of storage, accounting for perhaps 3/4 of the overall cost of CCS [4]. For non-combustion sources the cost of capture is smaller, and can be zero for sources of nearly pure CO2.

1662 Although the great majority of CO2 emissions arise from combustion, significant non-combustion sources of CO2 exist. In Canada, the three most important non-combustion sources of CO2 are natural gas processing, hydrogen production and ammonia manufacture. These sources have high concentration of CO2 and they in turn can provide important opportunities for early application of CCS technologies. This paper focuses on an application from the natural gas processing industry. ACID GAS REINJECTION Raw natural gas may contain significant impurities, with CO2, H2S, and N2 being the most important. "Sour gas" by definition is natural gas that contains H2S. In order to meet sales gas contract specification, sour gas must be treated for the removal of virtually all of the H2S. For very low H2S content (ppm level), disposable chemical such as SulfaTreat may be used to remove the sulfur. For higher H2S content, a chemical absorption process with amine may be used. Typically, the amine absorption method captures most of the CO2 in addition to the H2S. The resulting CO2 + H2S (acid gas) must then be processed to eliminate the H2S. The least cost method to eliminate H2S is to flare the acid gas stream burning the H2S to SO2 and releasing the CO2 to the atmosphere, along with the SO2. Over recent decades, concerns for the environmental effects of sulfur emissions have eliminated flaring as an option for all except the smallest facilities. Another option is to process the acid gas in a sulfur recovery unit such as a Claus plant, which produces sulfur as a salable byproduct, but releases the COa as before. In response to falling sulfur prices and increasingly stringent restrictions on residual SO2 emissions, the industry has recently begun to abandon sulfur recovery in favor of acid gas disposal. For the largest plants, the lowest cost route may still be sulfur recovery, but for plants with lower H2S fluxes the lowest cost option is to compress the full acid gas stream (CO2 and H2S) and dispose of it in a suitable geological formation (see Figure 1). Bectncity and other materials Sourgas input

i Gasplant: NGL recove ry, acid gas removal, dehydration, compressionto

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Figure 1. Schematic showing gas plant acid gas going to acid gas reinjection or sulfur recovery. The first acid gas reinjecti6n operation in Alberta, Canada was started by Chevron Canada Ltd. in 1989 at Acheson, where 15% H2S and 85% CO2 were injected into a depleted oil pool. The number of injection sites in Alberta has since increased from 1 in 1989 to 11 in 1995, to 29 in 1998 and to 38 in 2002. There were another 6-8 acid gas reinjection sites in British Columbia, Canada. Acid gas compositions of the 38 Alberta projects range from 4-75% H2S and15-95%CO2, with minor amounts of Cl+ gases making up the balance. The current average injection rates at all sites is -0.4 Mt CO2/year. At 14 sites, acid gas is injected into depleted oil and gas reservoirs, while the remaining 24 sites into deep saline aquifers whose salinity reaches up to 340,000 mg/1. Injection depths vary between 700 and 2,920 m. The injection horizons, of which 14 are in sandstones and 24 in carbonate rocks, vary in thickness from 4 to >200 m. Acid gas reinjection involves three steps: compression, dehydration and injection. The acid gas exit from the amine absorption unit is saturated with water vapor. It is at low pressure and slightly above air temperature. The stream is sent to a compressor located at the plant, which boosts the pressure of the acid

1663 gas to the required injection pressure. The compressors are multistage reciprocating machines, mainly using four stages to boost the pressure of the acid gas to the required injection pressure level. The key to successful operation of injection facilities is the control of the water content. When the gas enters the injection line after compression, its water vapor content must be sufficiently low that the gas remains under-saturated in water content all the way to the bottom of the well. This can be done by dehydration during compression, or by appropriate inter-stage cooling if the final pressure is above about 7,000 kPa. Maintenance of the compressors is normal, similar to the maintenance requirement for sour gas compressors. Most injection lines are designed to operate at very low stress levels in the pipe. Emergency shutdown valves are installed at each end of the injection lines. The injection wells are equipped with sour gas tubing, and in most cases have premium threads. Subsurface safety valves are installed in most wells a few joints below surface. The overall experience of the projects in Alberta has been that the compression and injection of the acid gas into deep formations is readily achieved, and is trouble free. ECONOMICS OF ACID GAS REINJECTION For the acid gas reinjection projects currently operating in Alberta, they are typically small. Data for one such project are listed in the following: Sales gas output: 620 103 m3/day with a CO2 concentration of-1.6% Acid gas compressor inlet pressure: -4). 1 MPa Outlet: 4.5 MPa Acid gas flow: 13 103 m3/day Acid gas composition: at 92.5% CO2, 6% H2S CO2 flow to storage: at 92.5% CO2 is 12 103/d or 22.3 t/d CO2 (8,140 t/year) H2S flow to storage at 6% H2S is 0.8 103 m3/d or 1.1 t/d sulfur (400 t/year) Power consumption for the acid gas compressor: 108 kW Depth of injection zone: 1,500 m This plant had a small Claus unit before, but as sour gas production from the surrounding area declined, it became technically and economically infeasible to run the Claus plant, as the sulfur throughput was reduced to about 1 t/d. With flaring not being an environmentally favorable option, the plant converted to acid gas reinjection. For an acid gas reinjection project of this size, capital costs would be of the order of Can. $ 3.05 million, with the breakdown approximately as follows: Injection well Can. $ 0.80 million (drilling $ 600,000, completion $ 200,000) Compressor package Can. $1.50 million (stainless steel piping, coolers and vessels) Glycol unit for acid gas dehydration $ 0.5 million Pipelining & control Can. $ 0.25 million Using a 10% rate of return over a project life of the 20 years, the capital charges would be about $ 358,000 per annum. Operating costs would be about $150,000 per year, with the majority being electric power cost for running the compressor. Therefore, the annual charge would be $ 508,000. To amortize over the 400 tonnes of sulfur produced, cost of sulfur recovery would be about $1,270/t of sulfur. An altemative to treat sulfur of this size would be a liquid redox process such as LO-CAT. Capital cost for a 1 t/day LO-CAT unit would be about Can. $2 million. The cost of operating the unit was estimated at $340,000 per annum. Therefore, the cost of sulfur recovery using this unit would be of the order of $1,400 /t sulfur recovered. Hence, acid gas reinjection would be preferred.

C02 AVOIDED If the acid gas compressor is powered by off-site electricity (as typically the case) then calculating the net CO2 emissions reductions (CO2 avoided) achieved by acid gas reinjection requires accounting for CO2 emissions from off-site generation of electricity. Given the power rating of 108 kW and the CO2 flow rate of 22.3 t/day, the power consumption of the acid gas compressor would be (108 x 24/22.3) or 116.2 kWh/t of CO2 compressed.

1664 Using a CO2 emission factor for average electricity generation in Alberta of 0.93 kgCO2/kWhr and a transmission efficiency of 90%, the CO2 emitted in the acid gas compression would be (116.2 x 0.93 / 0.9) or 120 kg CO2/t of CO2 compressed. In other words, for every tonne of CO2 compressed and injected into the reservoir, 120 kg or 0.12 t of CO2 is generated in the compression step. This translates to a mitigation efficiency of 88%. The CO2 emissions from compression could be reduced by using natural gas for on-site electric generation instead of power from the grid (effectively substituting coal for gas). It may also be possible to reduce emission even further by driving the acid gas compressor with a combustion turbine with heat recovery for use elsewhere in the plant. Hence, CO2 avoided is dependent on the specific surface facility and the fuel used. The CO1 avoided for the project described above is then 0.88 x 22.3 x 365 or 7,162 t of COz annually. Alternatively, if we consider the project as CO2 storage project only (sulfur removal is a bonus), the cost of the CO2 avoided would be ($ 508,000 / 7,162) or Can. $ 70/t CO2. CONCLUSIONS Acid gas injection is important step towards large-scale capture and geological storage of CO2 emissions. It provides a technological and regulatory experience that could serve as a foundation for mitigating CO2 emissions through geological storage.

Technological experience: Acid gas injection is proven technically and economically for replacing the Claus process. It is being deployed widely in Western Canada. It provides practical, near-term experience with large volume injection of CO2 into a variety of geological structures (in a couple of cases the acid gas is injected into a producing reservoir). Regulatory experience: Technological capability alone is insufficient for geological storage to play a significant role in mitigating CO2 emissions. Geological storage must evolve into a system comprising a suite of technologies linked by a network of institutions, financial systems, and regulations that is able to achieve broad public understanding and acceptance. The regulation of a new activity does not arise in a vacuum; instead it is strongly shaped by the existing regulatory and institutional context. What form these regulations assume: what entities are involved in project approval and ongoing oversight; how co-operative or adversarial the regulatory process is; and how many opportunities are presented for litigation and other third party interventions. These taken together are critically important in determining the economic attractiveness and social feasibility of geological storage. Acid gas disposal provides the best existing analog for CO2 storage. Unlike CO2 injection for enhanced oil recovery, the regulatory framework for acid gas reinjection is centered solely on assuring safe, long-term storage. Considering the wide range of in-situ characteristics and operating conditions, the acid gas reinjection operation in the Alberta Basin constitute a perfect analogue for large-scale CO2 geological storage into onshore continental sedimentary basins, particularly in North America. REFERENCES

1. Parson, E. A. and Keith, D.W. (1998). Fossil Fuels without C02 Emissions, Science 282(5391): 10531054. 2. Herzog, H. (2001). What Future for Carbon Capture and Sequestration, Environmental Science & Technology 35(7): 148 A-153 A. 3. Gunter, W.D., Wong, S., Cheel, D.B. and Sjostrom, G. (1998). Large C02 Sinks: Their Role in the

Mitigation of Greenhouse Gases from an International, National (Canadian) and Provincial (Alberta) Perspective, Applied Energy 61, p. 209-227. 4. Herzog, H. (2000). The Economics of C02 Separation and Capture, Technology 7 (supplement 1): 1323.

OCEAN STORAGE

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1667

ADVANCES IN DEEP-OCEAN CO2 SEQUESTRATION EXPERIMENTS P.G. Brewer l, E.T. Peltzer 1, G. Rehder 2 and R. Dunk 1 Monterey Bay Aquarium Research Institute 7700 Sandholdt Road, Moss Landing CA 95039, USA 2 GEOMAR Center for Marine Research Wischofstr. 1-3, Kiel, D-24148, Germany

ABSTRACT We report on advances made in carrying out small-scale experiments on the direct injection of CO2 in the deep ocean using ROV technology [ 1]. We have developed a carbon-fiber composite accumulator of 56L internal capacity for safe CO2 containment and delivery and have used this for a series of experiments at 3600m ocean depth, thus enabling delivery of sufficient CO2 for biological response studies. We have also developed a time-lapse camera for recording events associated with the CO2 pool. A newly developed laser Raman spectrometer has been used to obtain spectroscopic information in situ, thus enabling detection of the state of the CO2, and the fate of impurities. We have measured a CO2 dissolution rate of 1.7 ~tmol/cm2/sec by direct insertion of a pH probe into the liquid surface, thereby forming a pocket of water. This technique provides confirmation of the very rapid re-building of the hydrate skin reported by Aya et al. [2] in which surface cracks are quickly annealed. The presence of a hydrate skin exerts a strong effect on CO2 chemical and physical properties, and we have observed quasi-chaotic instabilities associated with this phenomenon in which a transformation from thin film to massive hydrate formation has occurred within a few hours.

INTRODUCTION Over the last five years, we have developed and refined the techniques first described by Brewer et al. [ 1] for carrying out controlled releases of CO2 on the ocean floor. The purpose of these experiments is to provide fundamental data on the chemical and physical behavior of the released material and, through a related program, to initiate biological response studies. In earlier work we have successfully carried out studies of small-scale releases of a rising stream of CO2 droplets [3] at relatively shallow depth ( 8 0 0 - 400m), and have determined a dissolution rate of 3 ~tmol/cm2/sec. Here we focus on studies at depths >3000m where the high compressibility of CO2 relative to sea water leads to gravitational stability. Oceanic GCMs show that efficient retention of injected CO2 is a strong function of depth [4] and thus there is great interest in deep injection properties. CURRENT RESEARCH

C02 Containment and Delivery We have developed a 56L carbon-fiber composite piston accumulator (Hydratech, Fresno, CA), 23cm outside diameter, 194cm length, rated at 3000 psig, for ROV operation. Two tandem cylinder pumps, of 128ml and 970ml capacity, provide power for accurate delivery of the contained CO2. Cooling, and compression, of the CO2 during descent to ocean depth occurs so that under typical conditions (900 psig on deck at 16°C; 1.6°C at 3600m) 45.0L is available per dive for experimental purposes.

1668

........... ,i

Figure 1: The 56L CO2 delivery system installed on ROV Tiburon, showing end cap with gauges, delivery pumps on top, and valves to the left. The dispensing valve is attached to the robotic ann in front of the vehicle and is not shown.

Measurement o f Dissolution Rates Early ideas of oceanic CO2 sequestration envisaged "permanent" disposal as a hydrate, however it was soon realized that the saturation condition was not met, and that hydrates would dissolve [5,6]. The saturated boundary layer model is the standard for understanding the dissolution rates of oceanic gases [7] and solids [8], and it may be applied to hydrate dissolution rates in the deep ocean [3, 9]. The solubility of CO2 in contact with a hydrate phase changes only by a factor of-~2 from 800m to 3600m depth [5], and thus we may expect a dissolution rate about 50% of that determined from rising droplet studies [3] or about 1.5 l.tmol/cm2/sec. We have confirmed this by depositing-~ 2L CO2 on the sea floor, and inserting a pH electrode protected by a slotted metal cage (3cm diameter) directly into the surface (Figure 2). The CO2 surface deforms not by elastic stretching, but by rapid re-building of the hydrate film [2]. A water pocket is thus formed in which the pH rapidly drops due to hydrate dissolution/CO2 invasion. We observed a pH drop of 4.19 pH units in 15 minutes. Taking local alkalinity as 2442 ~mol/kg, we calculate a CO2 accumulation rate of 2913 ktmol/kg/sec, and a dissolution rate of 1.7 ~mol/cm2/sec, in close agreement with the estimate above. The lowest pH observed corresponds to a solution of-~2 molar, about a factor of 3 greater than the equilibrium saturation value, and thus unstable with respect to very rapid hydrate formation upon nucleation.

Figure 2: Image of the pH probe inserted into a mass of CO2 on the sea floor at 3600m depth. Hydrate film re-building allows formation of a water pocket -~3cm deep in which pH drops in response to CO2 invasion of the aqueous phase.

1669

Evidencefor Quasi-chaotic Hydrate Dynamics In our first experiment at depth [1] we used a laboratory beaker to contain CO2 on the sea floor. We observed large volume changes, driven by hydrate dynamics, and a series of dramatic spillover events occurred; Aya et al. [10] have established the critical role of formation of a water channel to create the observed convective instabilities. In a later, near identical, field experiment we did not observe these instabilities, and thus this suggested that very small changes in procedure, or in initial conditions, can profoundly affect the outcome of the experiment. These are characteristics of complex systems, but it has been unclear if they are confined to "artificial" systems (such as a beaker experiment on the ocean floor), or whether such instabilities could occur in a free release. We now have two additional examples of rapid, selfdriven convective hydrate formation: one simply in liquid CO~, and the other involving deep-sea sediments. In a repeat of the experiment in Figure 2 (above) we did not observe simple dissolution of CO2 into the aqueous phase. Instead we observed very rapid growth of hydrate lobes on the electrode cage that penetrated far into the liquid CO2 phase (Figure 3).

Figure 3: Image ofpH electrode inserted into a pool of liquid CO2. Hydrate nucleation has occurred, and rapidly growing lobes of hydrate extend several centimeters out into the CO2 pool. In Figure 4 we show an example of CO2 penetration into sea-floor sediments, followed by formation of a "frost heave" from massive hydrate formation within the space of a few hours.

Figure 4: Formation of a massive "frost heave" of hydrate at 3600m in >>12 hours.

1670 At present we can only give a descriptive account of this phenomenon which extends upon the account given by Aya et al. [10]. Sea water in contact with CO2 forms a dense [11,12] saturated, or supersaturated, boundary layer with a thickness depending upon velocity in the bulk fluid. If the condition is quasi-diffusive this boundary layer may become thick enough to flow. If we now add a hydrate nucleation event then salt is rejected and heat released. For CO2 the net effect is an increase in density, enhanced flow, and water from the bulk fluid is drawn in between the hydrate-CO2 interface. This leads to increased hydrate growth, and further fluid invasion in a self-propagating flow. Double diffusive properties may well come into play [ 13]. However we do not know what event triggers this condition. In the case of Figure 3 vibrations in the vehicle arm holding the electrode likely created the initial nucleation event. In Figure 4 no such trigger was present. While both liquid CO2 and its hydrate dissolve in sea water the local changes (salt rejection, large volumetric changes etc.) created are quite different. CONCLUSIONS AND FUTURE RESEARCH The experimental science underlying study of possible deep-ocean CO2 sequestration is advancing rapidly, and is greatly aided by ROV techniques which provide the experimental platform (manipulation, visualization, instrument support, data return). In this paper we focus on the physico-chemical properties of the system; the observations have large consequences for ideas of storage of a lake of CO2 on the ocean floor, and are ripe for further investigation. For future work we have very recently developed and successfully deployed a laser Raman spectrometer [ 14] for in situ investigation of both hydrate formation [ 15], and detection of the fate of secondary chemical species. Companion studies on biological responses are also actively proceeding. ACKNOWLEDGEMENTS We acknowledge the support of the David and Lucile Packard Foundation, and of the U.S. Dept. of Energy Carbon Sequestration Program. This work would not be possible without the skilled support of the ROV Tiburon pilots, and the RV Western Flyer crew. REFERENCES 1. Brewer, P.G., Friederich, G., Peltzer, E.T. and Orr, F.M. Jr. (1999) Science 284, 943. 2. Aya, I., Yamane, K., Kojima, R., Yamamoto, T. and Nariai, H. (2001) Proc. 11th Intnl. Conf. Offshore & Polar Eng. Conf., Stavanger, Norway. 3. Brewer, P.G., Peltzer, E.T., Friederich, G. and Rehder, G. (2002) Environ. Sci. Technol. Submitted. 4. Orr, J.C. et al. (2001) Greenhouse Gas Control Technologies GHGT-5, Elsevier Science. 5. Aya, I., Yamane, K. and Nariai, H. (1997) Energy 22, 263. 6. Mori, Y.H., and Mochizuki, T. (1998) Energy Convers. Mgmt. 39, 567. 7. Broecker, W.S. and Peng, T.-H. (1982) In: Tracers in the Sea, Eldigio Press, pp. 113-130. 8. Santschi, P.H., Anderson, R.T., Fleisher, M.Q. and Bowles, W. (1991) J. Geophys. Res. 96, 10,641. 9. Rehder, G., Brewer, P.G., Peltzer, E.T. and Friederich, G. (2002) Geophys. Res. Lett. In press. 10. Aya, I., Yamane, K. and Kojima, R. (2001) In: Greenhouse Gas Control Technologies GHGT-5, CSIRO, pp. 423-428. 11. Haugan, P. and Drange, H. (1992) Nature 357, 318. 12. Ohsumi, T. (1993) Energy Convers. Mgmt. 34, 1059. 13. Turner, J.S. (1995) In: Geophys. Monograph 94, Am. Geophys. Union, pp. 11-29. 14. Brewer, P.G., et al. (2002) Eos, Trans. Am. Geophys. Union, submitted. 15. Sum, A.K., Burrus, R.C. and Sloan, E.D. (1997) 3". Phys. Chem. 101, 7371.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1671

STUDY ON CO2 HYDRATE FORMATION AS STOCKPILING IN MARINE SEDIMENTS Hironori Hanedal,Yoshitaka Yamamotol,Takeshi Komail,Kazuo Aokil, Taro Kawamura 2 and Koutaro Ohga 2 National Institute of Advanced Industrial Science and Technology, Tsukuba 305-8569, Japan 2 Graduate School of Engineering, Hokkaido University, Sapporo 060-8628, Japan 1

ABSTRACT We have proposed the methane hydrate production system in which carbon dioxide hydrate is used. This includes the original concept of the technique of the formation of carbon dioxide hydrate in sediment layers at the upper part of the methane hydrate reservoir, and the way of construction of artificial roof supports. Both of the landslides at the sea floor and the emission of methane into the sea can be prevented by using the technique. In addition, the geological structure can be reinforced by the formation of a solid CO2 hydrate layer where the methane hydrate was extracted. This also features the sequestration of CO2 gas into the sediment. The experimental data of gas consumption was compared with theoretical data. As a result, the calculated value and the experimental value almost corresponded. INTRODUCTION

Methane hydrate reservoirs are found in marine sediments, and various proposals have been reported to produce natural gas from such reservoirs. The Authors propose their original concept of a methane hydrate production system in which carbon dioxide hydrate is used. In this technique, the CO2 hydrate layer develops in the upper part of the methane hydrate reservoirs, and the artificial roof is constructed to prevent a landslide; it may also prevent the emission of decomposed methane gas into the marine environment. In addition, importantly, the system features the sequestration of COz by the formation of CO2 gas hydrate after the mining of methane gas hydrate. This makes it possible to maintain the stability of sea floor, and to prevent geo-hazards such as sudden landslides. If this technique is put into practice, the energy problem and global environmental problems will be solved at the same time. This paper presents the result of experiments on the formation and the growth of CO2 hydrate using an apparatus that simulates marine sediments.

1672 EXPERIMENTAL METHOD The formation and dissociation behavior of CO2 gas hydrate were investigate experimentally. The experimental apparatus consists of a high-pressure cell, a constant temperature device, gas control device, and data acquisition system. The high pressure cell is made of the polycarbonate with inside diameter 6cm, height 50cm, capacity 1400ml; maximum pressure is 4MPa. Figure 1 shows the schematic diagram. The outer cylinder is installed inside the main chamber in order to control the temperature, and coolant is circulated from a refrigerator. CO2 gas is introduced from the gas cylinder to a high pressure cell through a flow meter, a pressure control system, a pressure sensor, and a high pressure valve. A pressure sensor, a high-pressure valve, and the flow meter were installed in the gas exhaust line. Pressure and temperature in the cell and the flow rate in the gas line were measured at each sensor position, and the data measured and collected using a personal computer. Multi point temperature

II .......

>oling ',e

point

Fig. 1 High pressure cell

E X P E R I M E N T RESULTS AND DISCUSSIONS

Temperature distribution in COz hydrate grows up Figure 2 shows the temperature change at each height of the cell with regard to the formation of CO2 hydrate observed, when CO2 was pressurized from the lower entrance. The pressure was 2.5MPa and the total amount of gas discharged was 350ml/min. It is shown from Figure 2 that the temperature increased soonest at the 23 cm position, and at every 220 minutes elapsed time. CO2 hydrate started to form at this position. The temperature in the entire cell increased after a few minutes. Hydrate growth was found at the base, increasing upwards, and the temperature distribution showed that rapid growth was also found from about 27cm.

1673 It was observed that there were two parts to the temperature increase in the overall domain. The first part was due to heat conduction from the formation point, and another part was around the cell base, by the growth of the hydrate above. The inclination of the isothermal curves during the hydrate growth shows the rate of growth was about 0.5crn/minutes, as shown in Figure 2.

210

220

230

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250

Time

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16-6.5

1 1 3 - 3 . 5 11 3 . 5 - 4 i

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Figure 2: The change with the lapse of time of height direction temperature distribution in center Dart of cell of CO~ hydrate

Amount of gas consumption when COz hydrate grows upwards The speed of growth when the CO2 hydrate grew was examined from the amount of the gas consumption. The theoretical chemical amount of CO2 hydrate is as shown in the next expression. CO2(gas)+8.13H20(liquid) ~ CO2 • 8.13H20(hydrate) ......... (1) The hydrate number 8.13 in the expression is the value that the authors obtained through experimentation. Moreover, the speed of hydrate growth is expressed, in general, by the following expression, including diffusion and adsorption. dng =KOC_feq)nw (2) dt Here, ng is a mole of CO2 molecules intake the hydrate, nw is a mole of water, f is fugacity of the gas under experimental conditions, feq is the fugacity of the gas in three-phase equilibrium pressure. K is reaction rate constant and it has the dimension of (mol • MPa 1 • minl). Empirical formula concerning the amount of consumption of COz per mole of water is derived as follows. Here, the empirical formula, when growing up, becomes the next expression if corrected by the amount of the gas absorption to the formation point. ng = 1 _ [ 1 _exp{_HnKOC_f~q)t}]+ ngf ..... (3) nw,O Hn nw,O Here, nw o are moles of initial water, ng/" is a mole of CO2 that had dissolved in water at the time of formation. Hn shows the hydrate number of only when growing up. Hn shows as follows. Hn=COJ(q l-q2)H20 (4) ql; mole of CO2, which enters one water mole after hydrate is completed. qe; mole of CO2, which enters one water mole at the time of formation. The reaction rate constant K was determined by using the experiment data for the calculation type concerning the amount of the gas consumed in the CO2 hydrate growth. Calculated and experimental

1674 results are compared is in Figure 3. The amount of gas consumption almost agrees with the calculated value; the speed of gas consumption is fast when values of K are large, by high pressure, as shown in Figure 3. When the CO2 hydrate grew upwards because of these conditions, the level of gas consumption showed a tendency (that increased under the experimental conditions) for the gas-water contact area to increase. From these results, the level of gas consumption during the experiment almost corresponded to the calculated value, by which the fugacity difference was assumed to be the driving power. 0.07

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The formation and growth of CO2 hydrate was observed in a model sediment with porous media and solutions saturated with gases. From the experiment and discussion, the following conclusions were obtained. The appearance and the process of growth clearly shows the hydrate growth, in which the temperature distribution can be displayed. The growth rate of CO2 hydrate upwards ranged 0.5-1.0cm/min under the experimental conditions used. When the CO2 hydrate increased because of these, the amount of gas consumption showed the tendency, that increased under the experimental conditions, for the gas-water contact area grows. Moreover, the level of gas consumption during the experiment was almost corresponded to the calculated value, by which the fugacity difference was assumed to be the driving power. In future work, it is intended to obtain fundamental data of CO2 hydrate kinetics, especially on the dissociation process of hydrate, the difference of time growth with vertical and horizontal growth direction. The research results can be used to achieve the CO2 utilization for methane hydrate development. REFERENCE Sloan,E,D,Jr. (1998) Clathrate Hydrate of Nattural Gasea. 2nd edit. pp.586-601. Marcel-Dekker, New York.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1675

M E A S U R E M E N T S OF CO2 SOLUTION DENSITY UNDER DEEP OCEAN AND UNDERGROUND CONDITIONS M. Nishiol, y. Song2 and B. Chen 2 1National Institute of Advanced Industrial Science and Technology (AIST) 1-2-1 Namiki, Tsukuba-shi, Ibaraki 305-8564, Japan 2Research Institute of Innovative Technology for the Earth (RITE), AIST-Tsukuba Branch

ABSTRACT

The increase levels of CO2 emitted from fossil fuel consumption is one of the largest factors to increase the seriousness of global warming. In order to mitigate this huge amount of CO2 from the atmosphere, proposals for ocean sequestration and geological storage of CO2 have been investigated theoretically and experimentally for the past ten years. With emphases on a fundamental and engineering technical study associated with this technology, the understanding of physico-chemical properties of a pure/salt water-carbon dioxide system at high pressure and wide range of temperatures is also necessary as the basic database. The carbon dioxide pure/salt water solution density is one of the key physical properties and is a critical property for estimating numerically the dynamic evolution of carbon dioxide enriched pure/salt water plume. In this study, we report measurement data on carbon dioxide pure/salt water solution density, obtained using the Magnetic Suspension Balance (MSB) system and the Mach-Zehnder (M-Z) interferometry method.

INTRODUCTION

For the last two decades, the impact of increasing concentration of greenhouse gases, particularly CO2, on the earth's atmosphere has become a subject of intense scientific and engineering investigations. Several technologies were proposed for limiting CO2 emissions and mitigating CO2 concentration from atmosphere. From among these, CO2 ocean/geological sequestration was considered to be one of the acceptable options [ 1,2,3]. Part of the work of this project included a study of chemical and physical parameters measurement, and here, we report the results from the last investigations into the density of CO2 dissolved water solution. For either academic investigation or engineering application, the fundamental physical/chemical properties of pure/salt water and carbon dioxide systems at high pressure and low-high temperatures, from the point of environmental impact and technology development, are critical. In this study, the carbon dioxide pure/salt water solution density is measured by using the Magnetic Suspension Balance (MSB) method and the Mach-Zehnder Interferometry(M-Z) method. As a physical property, CO2 water solution density had drawn the attention of Haugan and Drange [4] ten years ago, when they investigated the sinking of CO2 enriched seawater. They conservatively and theoretically estimated the change in CO2 solution seawater density due to change in carbon concentration (mol/m 3) to be 8.0x10 3 kg/mol (about 0.182 g/cm3). Ohsumi [5] obtained the first set of experimental data. He applied the vibrating-type densitometer to a CO2-water solution system and measured the solution density at lower CO2 concentration (less than 1%). For a high concentration case, Aya [6] measured the density change by detecting the pressure drop due to CO2 dissolving into fresh water. Very recently, Song [7,8] reported a set of experimental date of CO2-water and CO2-seawater solution density measured systematically by leaser interferometry with the concentration almost approaching to the solubility. With the

1676 focus on ocean sequestration and geological storage, the density change of CO2 water solution is investigated in this study. The experiment was carried out at temperature of 293°K, pressure from 5 to 20 MPa, and concentration up to 0.045.

EXPERIMENTAL APPARATUS AND PROCEDURE

Magnetic Suspension Balance (MSB) system Wagner [9] developed the fluid density measurement method using the MSB system. We used the FMS-S-HP-100 system made by RUBOTHERM. This system can use maximum temperature-150°C and maximum pressure-40 MPa. Figure 1 shows a schematic diagram of the MSB experimental apparatus. Figure 2 shows a 3 position type MSB measurement system diagram. The high-pressure vessel was made of titanium and designed to withstand safely 20 MPa of pressure. The standard sinker, made of titanium, is freely suspended in sample solutions without contact with the pressure vessel, and the buoyancy change of the sample solutions measured. This pressure vessel can simulate the deep sea and/or the deep underground water conditions, where the temperature is over 100°C and pressure over 20MPa.. Therefore, the density change can be measured under all types of conditions, such as high temperature and pressure. The temperature of the CO2 solution inside the vessel can be adjusted from 273 K to 350 K by a water/oil bath system that can limit the temperature fluctuations within. 0.1 K. To enhance COz dissolution into water and maintain the homogenous temperature inside the vessel, a circulation pump was installed within the vessel. Before the experiment, water is fed into the high-pressure vessel under vacuum, up to the initial pressure, then all valves and pipe connectors are checked to exhaust the remainder of air in the measurement volume. This preparation of the high-pressure vessel was maintained for 24 hours for preliminary leakage tests by monitoring the pressure of water inside the vessel. As the first step of the experiment, an individual liquid CO2 droplet was injected into the water. Once this injected liquid CO2 droplet was completely dissolved (the pressure decreased from that at the completion of the droplet injection because of dissolution) another droplet was injected. These injection and dissolution processes were continued until the solution approached a saturated state, when the dissolution rate became much lower. The state when each droplet had dissolved completely was defined by temperature and pressure. Owing to the liquid CO2 dissolution rate reducing as the experiment progressed, this entire experiment took a few days to complete. .-,...

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(MSB) density measurement system

1677

Mach-Zender interferometry (M-Z)system The fundamental principle applied in this study is laser interference. Physically, the refractive index of the solution will change once carbon dioxide has been dissolved in it. This refractive index difference can be detected and used as primitive data to calculate the density change by an equation derived from the original Lorentz-Lorenz formulation. More details were described in our previous paper. [7,8,10] E X P E R I M E N T A L R E S U L T S AND D I S C U S S I O N This study obtained a set of data of CO 2 water solution density at temperature of 293 K, pressure from 5 to 15.0 MPa, and CO 2 concentration up to 0.045 (in mass fraction). It was found from these data that the density of CO s dissolved water is non-linearly proportional to the CO s mass fraction in general. This relationship seems to be approximately a linear one. However, the ratio of density of CO s dissolved water to that of water with an associated state (water density at same pressure and temperature) and the difference between those densities appears to be a monotonically linear relationship with the CO s mass fraction and seems to be independent of pressure and temperature under the present experimental conditions noted above. The slope of this linear function is 0.32, being calculated by experimental data fitting. Figure 3 gives the data measured and curve fitted. Some deviations may have resulted from measurement error and pressure deviation from the indicated value. Regarding the theoretical estimation, this experiment showed that Haugen & Drange [4] gave a reasonable but a slightly lower slope, based on the data they chose, that are 19,=1.03x10 3 k g / m 3 and partial mole volume of CO s in seawater of 34x10 6 m3/mol. On the other hand, the solution density is directly proportional to the pressure at any given CO s concentration. Following the method of Ohsumi [5], the measured data of CO s seawater solution density p was normalized by seawater density at same thermodynamic state Po. This seawater density 9e was calculated, as a reference value, by pressure and temperature recorded at each experiment point of CO s water solution density measurement. The normalized density (the density difference defined by Ap=p-Pe)is plotted in Figure 3 as a function of CO s concentration. This density difference appeared to be linearly mono-correlative with CO s concentration for all of the experiment data in this study's conditions. With this result, it seems to be reasonable to suggest that the density difference Ap be a linear-monotonic increasing function of CO 2 concentration only and in depending on pressure and temperature. 0.02

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Figure 3: Comparison of density difference of CO2 water solution m e a s u r e d b y MSB and M-Z methods

1678 The mechanism of increasing CO2 solution density with CO2 gradually dissolving into water might, in principle, be expressed by the interaction between water and CO2 molecules. In fact, the size of the CO2 molecular is smaller than the distance between two water molecules, which allowed the former to be inserted into the gaps between water molecules, once dissolved. Furthermore, the molecular number density of CO2 solution becomes higher than that of pure water and leads the CO2 solution density to finally increase. On the other hand, it could, in general, be estimated that the density of the CO2 solution should be the function of pressure, temperature (like that of pure water or pure CO2) and the mass fraction of CO2 dissolved as well. That is true if the data were not normalized by the density of pure water. As had been mentioned above, this conclusion indicates extensively that the ratio of density of CO2 dissolved water to that of pure water will be kept constant at the same CO2 mass fraction and independent on the depth (ie. pressure and temperature) when CO2 ocean sequestration and CO2 aquifer sequestration are applied in practice. This also confirmed the suggestion that CO2 dissolved water will break down the original ocean/aquifer stratification state and produce a negative-buoyancy. The slope of this linear function is 0.273 g/cm3/wt, calculated by fitting the experimental data. For comparison with the properties of the CO2 water solution, two sets of experiment data of density difference for the MSB method and M-Z method are shown in Figure 3. It was found that the slopes of these two linear functions of CO2 concentration were slightly difference. This will not be discussed further here, as it is obviously out of the range of this paper and will be reported individually. CONCLUSIONS CO2 water solution density was experimentally investigated in this study at conditions of temperature of 293 K, pressure from 4.0 - 12.0MPa, and concentration up to 0.045 using the MSB method. The following conclusions were obtained: 1). Carbon dioxide water solution density increased with the increasing of the mass fraction of carbon dioxide in its water solution. 2). The density difference between the carbon dioxide water solution and pure water is monotonically linearly proportional to the CO2 mass fraction and independent of pressure; 3). The slope of this linear function of density difference between CO2-water solution and pure water, with respect to CO2 mass fraction, is 0.32 g/cm3/wt, which is slightly greater than that of the M-Z method result of 0.275 g/cm3/wt. ACKNOWLEDGEMENTS This study is a part of the investigation of the CO2 Ocean Sequestration Project and CO2 Geological Storage Project managed by Research Institute of Innovative Technology for the Earth (RITE) and funded by New Energy and Industrial Technology Development Organization (NEDO), Japan. REFERENCES 1. Marchetti,C. (1977) ClimaticChange; Vol.1, pp.59-68. 2. Haugan, P.M., Thorrildsen, E and Alendal, G (1995)Energy Conversion and Management; 36, pp.461-466. 3. Liro, C.R., Adams E.E., Herzog H.J. (1992) Energy Conversion and Management, 33 pp.667-674. 4. Haugan, P.M. and Drange, H. (1992)Nature; 357, pp.318-320. 5. Ohsumi, T., Nakashiki, N., Shitashima, K. and Hirama, K. (1992) Energy Conversion and Management, 33, pp.685-690. 6. Aya I. (2000) Proc. of Japanese Chemical Engineering Symposium, Miyazaki, Japan, 17 (in Japanese) 7. Song, Y.C., Nishio, M., Chen, B.X. and Akai, M. (2001) Sixth International Carbon Dioxide Conference, Sendai, Japan pp.760-763. 8. Song, Y.C., Nishio, M., Chen, B.X. and Akai, M. (2002) Proceedings of 5th International Symposium on C02 Fixation and Efficient Utilization of Energy, Tokyo, Japan pp.54-58. 9. Wagner, W., Brachthauser K., Kleinrahm, R. and Losch, H.W. (1995) International Journal of Thermophysics, 16, p.399-411. 10. Uchida, T., Ebinuma, T., Narita, H. and Someya, S. (1999) 2"d International Symposium on Ocean Sequestration of Carbon Dioxide, Tokyo, Japan pp.28-63 11. Yamane,K., Aya, I., Nariai, H. (1997) Proceedings of the Second Ocean Mining Symposium, Seoul, Korea.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1679

ESTIMATIONS OF INTERFACIAL TENSIONS BETWEEN LIQUID CO2 AND WATER FROM THE SESSILE-DROP OBSERVATIONS T. Uchida, R. Ohmura, S. Takeya, J. Nagao, H. Minagawa, T. Ebinuma and H. Narita Institute for Energy Utilization, AIST Sapporo 062-8517, Japan

ABSTRACT

The interfacial tension between liquid CO2 and water or NaC1 solution was measured by a simple sessiledrop method at pressures up to 25 MPa and at temperatures of 278 and 288 K. The interfacial tension between liquid CO2 and pure water was approximately 38 mN m -1 at 288 K and 5 MPa with a small pressure dependence, whereas the values between liquid CO2 and 3 wt% NaC1 solution were more than 10 % larger than those between liquid CO2 and pure water. At 278 K, CO2 hydrate is stable and the interfacial tension has larger pressure dependence. This might be related to the supersaturation prior to hydrate formation. INTRODUCTION

Greenhouse gases, such as COz, have become a serious problem for mankind. To offset the CO2 emissions into the atmosphere, sequestration of CO2 in the deep ocean has been proposed. The behavior of CO2 injected into seawater can be predicted from the CO2-H20 phase diagram and a depth profile of the seawater temperature. In addition, the interfacial tension between liquid CO2 and water (or sea water) is an important factor for understanding the behavior of the injected CO2 droplets into deep water. However, CO2 hydrate formation on the droplets at depths deeper than 400 m [ 1] makes the prediction of CO2 dissolution difficult due to insufficient knowledge of the relevant physical parameters. CO2 hydrate is an ice-like clathrate compound formed from CO2 and water under suitable conditions of low temperature T and high pressure P. This crystalline compound will form at the interface between the injected liquid CO2 and seawater and can reduce the dissolution rate of CO2 into seawater. Furthermore, when liquid CO2 is injected into seawater under hydrate-forming conditions, the interfacial tension between these liquids can be difficult to estimate. In general, it is very difficult to measure the interfacial tension at high pressure and low temperature conditions. Uchida et al. [2] measured the interfacial tension between liquid CO2 and water by microscopic observations of pendant water droplets in liquid CO2 at T = 266.3-284.9 K and P = 2.7-6.0 MPa. They determined the temperature-dependent interfacial tension between liquid CO2 and water. Also, Uchida et al. [3] determined the interfacial tension between water and both CO2 vapor and COz liquid at T = 274.7-290.6 K and P < 5 MPa from observations of sessile drops. They found that the interfacial tension of water and liquid CO2 was about a half of that between water and CO2 vapor. For the present study, we used a simple method to estimate the interfacial tension between liquid CO2 and water by improving the method used by Uchida et al. [3] so it could be used at higher pressures. This method allowed us to measure not only the interfacial tensions at arbitrary P-T conditions and for various solutions, but also the variation of the interfacial tensions when the P-T conditions were changed.

1680 EXPERIMENTAL PROCEDURES A high-pressure vessel equipped with two optical windows was used for the observations. The inner volume of the vessel was approximately 10 cm 3. The vessel was filled with commercially available CO2 (purity of about 0.99) through a double-plunger, high-pressure pump, which controlled the pressures between 5 and 30 MPa. Distilled, de-ionized water or 3 wt% NaCI solution was then injected into the vessel through the stainless steel tube using another pump (FLOM Type 301). A sessile drop of the solution formed at the flared, cone-shaped end of a stainless steel tube equipped on the vessel bottom. The size of the sessile drop was several millimeters in diameter. Temperature was controlled to within + 0.2 K by a cooling jacket connecting the cooling bath, and was measured with a T-type thermocouple. The pressure was measured by a pressure-transducer (Kyowa type PH-300KB); its accuracy was --0.15 MPa. The experimental temperature was set at 278 K and 288 K with pressures ranging from 5 to 25 MPa. The shape of the water droplet was observed through a backlight, microscope-CCD camera system and recorded by an S-VHS video system. Figure 1 shows a schematic of the sessile drop and its shape parameters. Liqu

Figure 1: A sessile drop with the coordinates system.

Figure 2: Typical image of the sessile drop of pure water (T = 278 K, P - 5 MPa).

The interfacial tension ~LWbetween liquid CO2 and water (or ~?LSfor 3 wt% NaCI solution) was estimated from the shape parameters of the sessile drop with the following equation [4]: ~'LW= Ap g (H~ / G(Ht~/D~))2 where Ap is the density difference between liquid CO2 and water, g is the gravitational acceleration, H~ and D~ are the shape parameters shown in Figure 1 and G is the shape function. To make the estimation process easier, we measured the shape parameters only for ~ = 90 ° and used a computer system. The density differences between liquid CO2 and water were estimated from data obtained by interferometric measurements [5] and solubility data of CO2 in water [6]. The density differences between liquid CO2 and 3 wt% NaC1 solution were estimated from experimental and theoretical data [7]. In both estimates, we assumed that the density of liquid CO2 was same as that of pure liquid CO2 because the solubility of water in liquid CO2 is small. The densities of both pure liquid phases were calculated from the experimental data by using the commercially supplied PROPATH program [8]. The resulting accuracy of 3, is strongly affected by the accuracy of Ap, especially at higher pressures due to the small value of Ap. Since we cannot measure Ap directly in the present study, the estimated error is larger at higher pressures. RESULTS AND DISCUSSIONS Figure 2 shows a typical image of a sessile drop. Our stepwise increases of pressure every 20 minutes gave

1681 the interfacial tensions at various pressures and the slight change in the interfacial tensions with time due to the change of conditions. Figure 3 shows (a) YLW and (b) ?LS at 278 K (circles) and 288 K (triangles) with pressure. Open and solid marks indicate the data measured just after a pressure increase and just before the next pressure increase, respectively. The minimum error of y is estimated at approximately __+3.5% at T = 288 K and P = 5 MPa as shown by the error bar, whereas the maximum is - 2 0 % at T = 278 K and P = 20 MPa. Figure 3(a) shows that YLWranges between 20 and 32 mN m -1 at 278 K and between 30 and 38 mN m t at T = 288 K, both of which depend on pressure: higher pressures have lower interfacial tension values. The pressure dependence is larger at 278 K than at 288 K. It also shows that 7LW dropped immediately after the pressure change and gradually increases with time. 50

50

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25

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Pressure, MPa

Figure 3: Pressure and time dependence of interfacial tensions between liquid CO2 and (a) pure water (b) 3 wt% NaCI solutions. The solid square indicates the value obtained by Uchida and Kawabata [2]. Other open marks indicate the values immediately after the pressure increase, and solid marks are measured 20 minutes after the pressure change. The observed values of ]tLW in the present study agreed with those obtained previously [2, 3]" the average value of 7LW was estimated to be approximately 30 mN m ~ at T = 278 K and P = 4 MPa. This agreement indicates that the interfacial tension from both methods agree quantitatively within experimental accuracy. Figure 3(b) shows that ?LS ranged between 30 and 37 mN m -I at 278 K and between 39 and 50 mN m ~ at 288 K. These values are approximately 10% larger than those observed in pure water system at P = 5 MPa. This change likely results from the effect of ions Na + and CI in water, which can change the structure of the solution. The figure also indicates that both interfacial tensions generally depend on pressure; in particular, that observed for NaCI solution at 278 K is weaker than for pure water, whereas the interfacial tension for NaC1 solution at 288 K increases with pressure. It is known that the decrease in liquid-fluid interfacial tension accompanies with increase in mutual solubility [9]. The pressure dependences of the CO2-water interfacial tensions indicated in Figure 3 coincide with such general feature of the interfacial tensions in systems of two-fluid phases, as the mutual solubility in the liquid-CO2-water system increases with an increase in pressure. The pressure dependence of interfacial tension at 278 K is larger than that at 288 K, which might be due to the difference in the stable conditions at the two temperatures. 288 K is higher than the equilibrium temperature of CO2 hydrate at each pressure of the present interest. Thus, at 288 K the liquid phases can be in stable equilibrium condition. However, at 278 K the stable condition for the two liquid phases are

1682 metastable or supersaturation with respect to CO2 hydrate formation. Under metastable conditions, the mutual solubility is higher than that in stable equilibrium with hydrate, and the pressure dependence in the mutual solubility might be larger than that at higher temperatures where two liquid phases can be in stable equilibrium conditions. This argument may be supported by the aqueous phase viscosity measurements before and after the CO2 hydrate formation [10]. The viscosity of CO2 aqueous solution increases before hydrate nucleation and drops just after the nucleation. This implies that the mutual solubility increases prior to the hydrate nucleation, which is under metastable conditions. The difference between open and solid marks at each pressure apparently indicates time dependence of the interfacial tension. It should be noted, however, that the apparent time-dependence is not dynamic variation in interfacial tension in the system, but rather artifact in the experimental scheme employed in the present study. The density of liquid water saturated with CO2 is used in the present calculation to determine the interfacial tension. But the saturation or dissolution of CO2 into liquid water, i.e., diffusional or convective mass transfer of CO2 into liquid water, does not cease quickly but proceeds for a certain long time. Therefore, A9 gradually changes and the resulting g also gradually increases. In conclusion, the interfacial tensions between liquid CO2 and water and between liquid CO2 and NaC1 solution were measured by a simple sessile-drop method at pressures up to 25 MPa and temperatures of 278 and 288 K. The interfacial tension between liquid CO2 and pure water is approximately 30 mN m 1 at T = 278 K and P = 5 MPa with a large pressure dependence. Within experimental accuracy, these values agree with previous measurements. The interfacial tension between liquid CO2 and 3 wt% NaC1 solution is more than 10% larger than that in pure water. However, when the temperature is above that for CO2 hydrate dissociation, the interfacial tension has little pressure dependence compared with that at T = 278 K. The large pressure dependence at 278 K might be related to the supersaturation prior to hydrate formation. ACKNOWLEDGEMENTS This study was done with the collaboration of Professor Y. H. Mori in the Department of Mechanical Engineering, Keio University. This work was partially managed by the Research Institute of Innovative Technology for the Earth (RITE) and supported by the New Energy and Industrial Technology Development Organization (NEDO) through the Research and Development on CO2 Ocean Sequestration Project. Another part of this work was supported financially by the NEDO-grant (00B60016d). We also thank Professor E. D. Sloan, Jr., Professor K. Ohgaki, Dr. T. Ohsumi, Dr. S. M. Masutani, Dr. M. Ozaki and Dr. H. Ohyama for their fruitful discussions, and to Ms. M. Akaike for her help on the data analysis.

REFERENCES 1. Lund, P. C., Shindoh, Y., Nakashiki, N. and Ohsumi, T. (1995). Energy Convers. Mgmt., 36 827. 2. Uchida, T. and Kawabata, J. (1997). Energy, 22, 357. 3. Uchida, T., Ebinuma, T.. and Narita, H. (2000). Proc. Int. Syrup. Deep Sea Sequestration of C02, Tokyo, Feb. 1-2, 2000, 1-4-1-6. 4. Prokop, R.M., del Rio, O.I., Niyakan, N. and Neumann, A.W. (1996). Can. J. Chem. Eng., 74, 534 5. Song, Y.C., Nishio, M., Chen, B.X., Someya, S., Uchida, T., Akai, M. and Masuda, S. (2001) Proc. 6 th Int. C02 Conf., Sendal, Oct. 1-5, 2001, 760. 6. Dodds, W. S., Stutzman, L. F. and Sollami, B. J. (1956). Ind. Eng. Chem., Chem. Eng. Data Ser, 1, 92. 7. Teng, H. and Yamasaki, A. (1998). J. Chem. Eng. Data, 43, 2. 8. PROPATH-a Program Package for Thermophysical Properties of Fluids, Ver. 7.1. Corona Publishing, Tokyo, Japan, 1990. 9. Donahue, D.J. and Bartell, F.E.. (1952). J. Phys. Chem., 56, 480. 10. Ohyama, H., Ebinuma, T., Shimada, W., Takeya, S., Nagao, J., Uchida, T. and Narita, H. (2002). Proc. 4 th Int. Conf. Gas Hydrates, Yokohama, May 19-23, 2002, 561.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1683

LETHAL EFFECT OF ELEVATED pCO2 ON PLANKTONS COLLECTED FROM DEEP SEA IN NORTH PACIFIC

Y. Watanabe 1'2, A. Yamaguchi 3, H. Ishida l, T. Ikeda 3, j. Ishizaka 4 1 Kansai Environ. Engineer. Center Co., ltd., Azuchi-machi, Chuo-ku, Osaka, 541-0052, Japan 2 Graduate School of Marine Science and Engineering, Nagasaki University, Bunkyo-machi, Nagasaki 8528521, Japan 3 Graduate School of Fisheries Sciences, Hokkaido University, Minato-cho, Hakodate 041-0821, Japan 4 Faculty of Fisheries, Nagasaki University, Bunkyo-machi, Nagasaki 852-8521, Japan

ABSTRACT

We observed the lethal effects of high partial pressure of CO2 (pCO2) to the pelagic zooplankton. The experiments were performed from the sub-arctic to the sub-tropical region and compared the sensitivities to the high pCO2 between surface organisms (0 - 500 m) and deep-sea organisms (500 - 1,500 m). When organisms were exposed at a pCO2 from 500 to 100,000 ~tatm, half the organisms died within 1 day to 2 weeks after exposure. From the half lethal time (LT50) calculated from the survival curve, higher pCO2 resulted in earlier death of the zooplankton. However, deep-sea animals in the sub-arctic region were less sensitive to the increasing of pCO2 compared with the others. The apparent LT50 on higher pCO2 showed that deep-sea organisms are more tolerant than surface ones.

INTRODUCTION

Ocean sequestration of CO2 has great potential for the mitigation of the increasing levels of atmospheric CO2, but there is little information about the environmental effects, especially to deep-sea organisms. These appear to be more sensitive to the environmental change than surface organisms[ 1,2], as the environmental fluctuation in the deep sea is less than that of the surface layer. If deep-sea organisms have high sensitivity to high CO2, it is necessary to compensate in order to apply the experimental results for deep-sea organisms. However, there is no information to evaluate the above problem. To assess whether deep-sea organisms have higher sensitivity to high pCO2 than surface ones, we conducted exposure experiments using zooplankton collected from the surface and deep layer in the Pacific.

EXPOSURE EXPERIMENT

Experiments were conducted from the subarctic (44N) to the subtropical region (11N) in the westem North Pacific. Zooplankton were collected from 500 m to surface, and from 1,500 m to 500 m by the vertical towing of a modified NORPAC net and VMPS-6000 (Vertical Multiple Plankton Sampler, Fig. 1), respectively. Healthy animals were selected and kept in several concentrations of pCO2 controlled with mixed gases (N2, 02 and CO2). The survival rate in each bottle was observed during the experiment.

1684

Figure 1: Vertical Multiple Plankton Sampler (VMPS-6000) for collection of deep-sea zooplankton

In the subarctic region, Euchaeta marina, Metridia pacifica and Calanus pacificus in surface and Neocalanus cristatus, Paraeuchaeta birostrata, Gaidius variabilis, and Heterostylites major in deep-sea group were exposed. In addition, in the subtropical region, we could not separate each species because of their small size and large diversity; we then took animals with the epipelagic (surface) group and mesopelagic (deep) group. Compared with zooplanktons exposed in intact pCO2 (for example, 8001aatm in E. marina, 8601aatm in N. cristatus), zooplankton with higher pCO2 died sooner. There was a difference on the mortality time between animal species; for example, E. marina died earlier than N. cristatus (Fig. 2). Because a high concentration of C O 2 in sea-water causes a low pH, the effects of CO2 were estimated from the results of the experiment exposed in low pH[3]. To evaluate the data, we calculated the half lethal time (LT50) and compared this with the LC50 resulting from the HCI exposure experiment[4] on pelagic zooplankton. The LT50s in high pCO2 exposure were shorter than those in the low pH exposure experiment, at converted pH. This shows that the estimate of the effect of high pCO2 from the results of the low pH experiment tended to underestimate the impact. It is important to experiment actually using CO2 for the assessment of the sequestrated CO2 in the ocean. In our poster, the vertical comparisons between the surface and deep layer are discussed from the LT50 calculated from the actual experiment. Neocalanus cristatus

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--e-pco2=800/z arm (pH7.88) pCO2=llOO/zarm (pH7.74) -~- pCO2=5500.u at,In IpH7.11) --'--pC02=8800 U arm pH6.89) ~pC02=21000~ arm t,p|t6.58)

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AKNOWLEDGEMENT

This study is a part of WEST-COSMIC (Western north Pacific Environmental Study for CO2 sequestration for Mitigation of Climate change) conducted by NEDO (New Energy Development Organization) supported by the Ministry of International Trade and Industry. We thank the crew of Hakureimaru No.2 for their great help.

REFERENCES

Omori, M., Norman, C. P. & Ikeda, T. Oceanic disposal of CO2: potential effects on deep-sea plankton and micronekton- a review. Plankton Biol. Ecol. 45, 87-99 (1998). Shirayama, Y. Biodiversity and biological impact of ocean disposal of carbon dioxide. Waste Management 17,381-384 (1997). Auerbach, D. I., Caulfield, J. A., Adams, E. E. & Herzog, H. J. Impacts of ocean CO2 disposal on marine life: I. A toxicological assessment integrating constant-concentration laboratory assay data with variable-concentration field. Environ. Model. Assess. 2, 333-343 (1997). Yamada, Y. & Ikeda, T. Acute toxicity of lowered pH to some oceanic zooplankton. Plankton Biol. Ecol. 46, 62-67 (1999).

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1687

THERMODYNAMIC RELATIONSHIP TO ESTIMATE THE EFFECTS OF HIGH CO2 CONCENTRATION ON THE CO2 EQUILIBRIUM AND SOLUBILITY IN SEAWATER C.S. Wongl, p.y. Tishchenko 2 and W.K.Johnsonl lInstitute of Ocean Sciences, 9860 West Saanich Road, Sidney, BC V8L 4B2, Canada 2Pacific Oceanological Institute, 43 Baltiyskaya St., Vladivostok 690041, Russia

ABSTRACT

The effects of high CO2 concentrations on carbonate equilibrium are important in studies related to the disposal of liquid CO2 into the oceans. Using available thermodynamic data of liquid CO2 and CO2 solubility in seawater, an equation of solubility of liquid CO2 in seawater was developed as a function of temperature, pressure, and salinity. It is shown that the non-ideal behavior of acid-base species subjected to high CO2 conditions can be accounted for by Pitzer's parameters. The solubility of liquid CO2 in seawater between values from calculation using thermodynamic equations and those from literature was presented. The pH of seawater equilibrated with liquid CO2 was calculated to be elevated by approximately 0.20 pH unit due to the non-ideal effects of dissolved CO2 on acid-base equilibrium. Effects of high CO2 on seawater alkalinity are discussed. INTRODUCTION

The interaction of liquid CO2 with seawater results in high CO2 concentrations. Technical assessment of environmental condition for a pool of liquid CO2 has to include measurements of two parameters of the carbonate system as a minimum, in order to calculate the others. The commonly accepted procedure for the calculation of the carbonate system of seawater includes equilibrium constants which were determined at trace concentrations of dissolved free CO2 in seawater where [CO2] = [CO2]aq + [H2CO3]aq. (1) This paper uses a theoretical approach, which permits us to take into account the effects of high CO2 concentrations on acid-base equilibrium using the ionic interaction approach or Pitzer method [Pitzer, 1973, 1991].

Solubility of liquid C02 in the seawater Here, we develop a thermodynamic approach for estimation of the solubility of liquid CO2 in seawater as a function of temperature (T), pressure (P), and salinity (S). This approach includes using Henry's Law for solubility of liquid CO2 along boiling T°, pb line, because there is CO2-gas phase for such case and taking into account P V - work from pb to given P. Superscript "b" refers to boiling conditions of the liquid CO2. The equation for solubility of liquid CO2 is as follows:

1688

ln[C02°]=-34.22346 -0.0317715 • T + 5357.744 / T + 0.000004810 • T 2 + 23.3585-ln(T /100) + S. [0.021486 -0.022291 • T /100 + 0.0044787 • (T /100) 2] + (2) (-0.0277106 + 0.00005508 • T + 3.67376 / T). 10 -5 • P + (0.030013 -0.00005818 • T - 3.9489 /T). 1 0 - t 3 • p2 where P is in Pa. There is a relationship between two concentration scales, as follows:

[CO:,] = [C02°]/(1 + 0.04401 .[C02°]), where, [CO2] is moles of CO2 in lkg seawater which contains CO2. Comparison between our calculations and direct measurements of solubility of liquid CO2 is presented and discussed Using equation (2) we calculated a profile of CO2 concentration in seawater for a column equilibrated with liquid CO2 (Figure 1). From this figure we see that CO2 concentrations varied from 1.29 (400 m) to 1.67 mol-(kg-soln)l (4282 m). Such high CO2 concentrations should change the constants of the carbonate system. [CO2I, mol(kg-soln) "l 1.2 0

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Figure 1:CO2 concentration of column seawater equilibrated with liquid CO2. Calculations were carried out using eq.(2) and CTD data for "Papa" station, Cruise 9910. DISCUSSION Alkalinity can be measured accurately in a given region before C O 2 injection and alkalinity is not affected by the addition of CO2. Using measured alkalinity data at Station P (50 ° N, 145°W) in the Northeast Pacific and the predicted CO2 concentrations (Fig.l) we calculated pH profiles at Ocean Station "Papa" using thermodynamic equations. Fig.2 demonstrates pH profiles with (a) and without (b) taking into account effects of CO2 concentrations on equilibrium constants. Differences between the two profiles changed with increasing depth by 0.173 to 0.247 pH units. Brewer et al. [2000] made direct pH measurements of the interaction of liquid CO2 and seawater at 619 m depth and t = 4.25 °C in the NBS scale. Their pH value is about 4.25 (original value converted into total concentration scale). For similar conditions, our predicted pH value is about 3.46. Apparently, the main difference between measured and predicted value is explained by the fact that full equilibrium between liquid CO2 and seawater was not reached because experimental conditions are meta-stable for liquid C O 2 - seawater equilibrium [Brewer et al., 2000]. The behavior of the carbonate system at high CO2 concentration has the distinct feature, that concentrations of the HC03 species are higher than alkalinity as is seen in Figure 3.

1689 p H 3.1 0

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Fig.2. pH profiles of"Papa" station (Cruise 9910) calculated with (a) and without (b) taking into account effects of CO2 concentration on the equilibrium constants. TA, [HCO3] , umol(kg) "1

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Figure 3: TA measured (1) of the "Papa" station (Cruise 9910), and concentration of riCO3 profiles calculated with (2) and without (3) taking into account effects CO2 concentration on equilibrium constants.

CONCLUSIONS Using Henry's Law and PV-work, the thermodynamic equation (2) for the solubility of liquid CO2 in seawater was derived. This equation was parameterized as a function of temperature, pressure and salinity using available thermodynamic data. It is shown that CO2 concentration of seawater equilibrated with liquid CO2 exceeds more than 1.3 moles.(kg) 1. Very high CO2 concentration results in low pH of

1690 seawater (less, than 4 pH unit). Under these conditions CO2 partly converts S042- a n d / r ions to HSO4and HF. Therefore, concentrations of HC03- will exceed total alkalinity. The effects of high CO2 concentration on the constants of the carbonate system were taken into account using combined approaches - Pitzer method and method of concentration constants. Non-ideal properties of dissolved CO2 in seawater shift the carbonate equilibrium with increase in pH. This shift is more than 0.20 pH unit when seawater is equilibrated with liquid CO2. REFERENCES

Brewer. P.G., Peltzer, E.T., Friederich, G., Aya, I., and Yamane, K.(2000) Mar.Chem., 72: 83. Pitzer, K.S., (1973) J.Phys.Chem, 77: .268. Pitzer, K.S., (1991). pp. 75-153, In: Activity Coefficients in Electrolyte Solutions. K.S.Pitzer (Ed), 2nd Edition,: CRC Press, Roca Raton. Teng, H. and Yamasaki, A., (1998). J. Chem.Eng.Data, 43:.2.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1691

THE GOSAC PROJECT TO PREDICT THE EFFICIENCY OF OCEAN CO2 SEQUESTRATION USING 3-D OCEAN MODELS

James C. Orr 1, Olivier Aumont l, Andrew Yool 2, Gian-Kasper Plattner 3, Fortunat Joos 3, Ernst MaierReimer4, Marie-France Weirig 5, Reiner Schlitzer5, Ken Caldeira 6, Michael Wickett, Richard Matear 7, Bryan Mignone 8, Jorge Sarmient08, and John Davison 9 ILSCE/CEA Saclay, CEA-CNRS and IPSL, Gif-sur-Yvette, France 2Southampton Oceanography Centre (SOC), Southampton, UK 3Climate and Environmental Physics, Physics Institute, University of Bern (PIUB), Switzerland 4Max Planck Institut fuer Meteorologie (MPIM), Hamburg, Germany 5Alfred Wegener Institute for Polar and Marine Research (AWl), Bremerhaven, Germany ULawrence Livermore National Laboratory (LLNL), California, USA 7CSIRO, Hobart, Australia 8AOS Program, Princeton University, Princeton NJ, USA 9IEA Greenhouse Gas R&D Programme, Stoke Orchard, Cheltenham, GL52 7RZ, UK

ABSTRACT To evaluate the efficiency of the ocean in retaining purposefully sequestered CO2, eight ocean modeling groups made a set of standard injection simulations. Injection was made simultaneously at seven separate sites; separate 7-site simulations were made for injection at 800 m, 1500 m, and 3000 m. For injection at 3000 m, all models showed 85% or greater global efficiency in year 2200, i.e., 100 years after the end of the specified 100-year injection period; at the same time, the 1500-m injection is 60-80% efficient and 800-m injection is only 42-61% efficient. Most of the CO2 injected at 3000 m was lost from the Southern Ocean (the principal region by which the deep ocean is ventilated); at shallower depths, relatively more was lost sooner, from the northern hemisphere and the tropics. The simulated global injection efficiency at 3000 m is correlated with both the simulated global mean CFC-11 inventory and deep-ocean natural inc. Based on these correlations, the global observational constraints for these two tracers, and model diversity, it appears likely that the range of model-predicted efficiencies would bracket real ocean behavior under the same 3000m injection scenario.

INTRODUCTION A quarter of a century ago, it was proposed that one could help limit increases in atmospheric CO2 by diverting CO2 emissions from near-coastal power plants into the deep sea [ 1]. However, uncertainty remains concerning the science of such a strategy. A fundamental question is, how efficient would the ocean be in retaining purposefully sequestered CO2? Ocean models offer the only quantitative means to answer this question due to the century time scales involved for deep-ocean circulation. Simple ocean box models have been used to provide estimates of the ocean's mean retention efficiency [2]. Simulations with 3-D models can distinguish site-specific efficiencies. However until recently, only one 3-D model had been used for such studies and thus uncertainties had not been addressed. That changed with the initiation of the GOSAC

1692 project (Global Ocean Storage of Anthropogenic Carbon). Here we describe results from that project where standard simulations in seven different 3-dimensional global ocean models and one 2.5-dimensional zonal basin average model were systematically compared to provide measures of uncertainty about the ocean's efficiency at retaining purposefully injected CO2. Previously, we quantified global and site efficiencies for deep injection [3]. For example, the 3000-m injection is 85% or more efficient in all models in year 2200. At the same year, 1500-m injection is 60-80% efficient and 800-m injection is 42-61% efficient. We further showed that injection at 1500 m was most efficient at sites in the Pacific Ocean (San Francisco, Tokyo) and least efficient at sites in the Atlantic Ocean (New York, Bay of Biscay, and Rio de Janeiro). Here we outline why the most and least efficient sites differ, provide details about the 300-m injection, and assess if simulated global efficiencies are realistic.

MODELS AND SIMULATIONS The eight global ocean models used in this project have been described previously [3,4]. All models were first integrated to reach a steady state, equivalent to a pre-industrial state with atmospheric pCO2 at 278 ppm. Then the models were forced to follow observed atmospheric CO2 during years 1765-2000. Subsequently during 2000-2500, models followed IPCC future scenario $650, which eventually stabilizes atmospheric pCO2 at 650 ppm. Injection occurred only during years 2000-2100, with 0.1 Pg C year-1 (1 Pg C = 1015 g) injected offshore at each of seven sites (Bay of Biscay, Bombay, Jakarta, New York, Rio de Janeiro, San Francisco, and Tokyo). For each injection simulation, we used a separate tracer to track the each site's injected DIC plume. Nonlinearities due to this multi-tracer approach are negligible [5]. These standard injection simulations are further detailed elsewhere [3], with protocols at http ://www.ipsl.j ussieu, fr/OCMIP.

RESULTS For 1500-m injection San Francisco was generally the most efficient site and New York was the least efficient. Much of CO2 injected at 1500 m at New York was transported northward by the lower part of the Gulf Stream to the North Atlantic in the Norwegian and Greenland Seas. There it was brought back to the surface by deep winter mixing, where it could exchange with the atmosphere. In the North Pacific, some of the injected CO2 escaped back to atmosphere in the North Polar sub-polar gyre. Yet, winter convection in the North Pacific is shallower and less intense than in the Atlantic, thereby explaining its improved efficiency. The efficiency of the Rio de Janeiro site varies most among between models. As most of the CO2 injected at this location is lost in the Southern Ocean, this large predicted range reflects the large discrepancies between models in this region. Injection at 3000 m resulted in smaller differences between site efficiencies for a given model. The southern hemisphere sites (Rio de Janeiro and Jakarta) were generally the least efficient. The New York site efficiency improved dramatically, relative to the 1500-m injection, because the plume took a longer pathway to the surface by moving southward to the Southern Ocean. In the 3000-m injection simulation, all sites lost most of their injected CO2 south of 30°S (Fig. 1) even though five of the seven injection sites are located in the Northern Hemisphere; conversely, around half of CO2 from both shallower injections was lost from the northern hemisphere. With time, ocean mixing homogenized the distribution of injected CO2 in the deepocean, thereby enhancing loss from the Southern Ocean, which dominates deep-water ventilation in all the models. Although the southern region occupies about 31% of the surface area of the global ocean, loss is enhanced there owing to generally more efficient surface-deep water exchange.

1693 t~t~tud, ao's .toos ~o's ao-,~ ........ .t............... , ............... ~.............. ~............... ~............... L.............. ~............... ~............... J.......... 1.z 'i

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Figure 1: Zonal integral, cumulative loss of injected CO2 from ocean to the atmosphere (Pg C degree -l) DISCUSSION Comparison of simulated vs. observed ocean tracers provides a benchmark of model performance that helps to weigh model predictions. Radiocarbon has been measured extensively and its radioactive decay helps us assess the rate at which deep waters are ventilated. This ventilation rate may be related to injection efficiency. The group of models used in this study includes those that have deep waters that are too old to those that have deep waters that are too young. Therefore it would seem likely for the range of results to bracket the real behavior of the global ocean, if purposeful CO2 injection were actually carried out under the same scenario at 3000 m. Furthermore, natural C-14 and injection efficiency are correlated. For the 3000-m injection, the correlation has an R 2 of 0.57 (Fig. 2). The correlation is lower for the 1500-m injection and there is no correlation for the 800-m injection. Additionally, there is strong correlation (R 2 = 0.81) between the global inventory of another tracer, CFC- 11, and the global efficiency of the 3000-m injection (Fig. 2a). Conversely, there is no correlation with the global CFC-11 inventory for 800-m injection and only a slight correlation (R 2 = 0:31) for the 1500-m injection. Although, we expected to find some correlation with natural lac, a tracer of deep-ocean circulation, CFC-11 is a man-made transient tracer that only started being released to the atmosphere in the 1930's. The correlation of the 3000-m injection efficiency with the global uptake of CFC-11 (R 2 = 0.81) is even stronger than it is for natural ~4C (R 2 = 0.57). One reason may be that surface-to-deep ocean exchange limits CFC uptake as well as loss of injected CO2 to the atmosphere. Further, most of this CFC-11 uptake and most of the loss of CO2 injected at 3000 m occur in the Southern Ocean. Another reason is that both CFC-11 and injected CO2 are transient tracers, and natural 14C is not a transient tracer. The transient tracer argument by itself does not explain the increase in correlation with injection depth, but it does seem to help explain the better correlation of the 3000-m injection efficiency with CFC- 11 than with natural ~4C. The observational constraint for the global mean 14C below 1000 m is about -150 permil [6], and the model results bracket -150 permil. There is not yet an observational constraint for the global inventory for CFC-11" however, the OCMIP-2 CFC-11 model-data comparison along available sections suggests that the models

1694 also bracket the CFC-11 observations. Therefore based on these observational constraints and correlations from two tracers, the range of GOSAC/OCMIP-2 simulated efficiencies for the 3000-m injection would be likely to bracket real ocean behavior given the same injection scenario. 100

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--260

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Figure 2: Comparison of the simulated global efficiencies in year 2500 for injection at 800 m (dash-dot), 1500 m (dash) and 3000 m (solid) vs. simulated CFC-11 and 14 C. The R 2 is given in parentheses with corresponding depths in italics for CFC-11 (top panel) and natural 14C below 1000 m (bottom panel). ACKNOWLEDGEMENTS Analysis was funded by the IEA Greenhouse Gas R&D Programme. The AWl, IPSL, MPIM, and SOC modeling groups were funded by EC Contract ENV4-CT97-0495. PIUB was funded by the Swiss NSF and the Swiss Fed. Office for Science and Ed. (grant 97.0414). LLNL was funded through the U.S. DOE. Opinions which may be drawn from this work do not necessarily reflect those of any of the funding agencies. REFERENCES 1. Marchetti, C. (1977), Climatic Change 1, 59-68. 2. Hoffert, M.I., Wey, Y.-C., Callegari, A.J., and Broecker, W.S. (1979), Climatic Change 2, 53--68. 3. Orr, J. C., Aumont, O., Yool, A., Plattner, K. Joos, F., Maier-Reimer, E., Weirig, M.-F., Schlitzer, R., Caldeira, K. Wickett, M., and Matear, R. (2001). In: Proceed. Fifth Int. Conf. on Greenhouse Gas Control Tech., pp. 469--474, CSIRO, Collingwood, Australia. 4. Dutay, J.-C., et al. (2002). Ocean Modelling 4, 89-120. 5. Orr, J.C. and Aumont O. (1999), In: Greenhouse Gas Control Technologies, pp. 281-286, Eliasson BE, Reimer, P., and Wokaun A., Elsevier, Oxford. 6. Toggweiler, J. R., Dixon, K. and K. Bryan (1989). J. Geophys. Res. 94, 8217-8242.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1695

EFFECTS OF CO2 ON MARINE FISH J. Kita l, 2, A. Ishimatsu 3, T. Kikkawa l, 3 and M. Hayashi 3 i Marine Ecology Research Institute, Onjuku, Chiba 299-5105, JAPAN 2 Research Institute of Innovative Technology for the Earth, Kizugawadai, Kyoto 619-0292, JAPAN 3 Marine Research Institute, Faculty of Fisheries, Nagasaki University, Nagasaki 851-2213, JAPAN

ABSTRACT To provide basic information useful in assessing the impacts of ocean sequestration of C02 on marine fish, we studied 1) acute CO2 tolerance during early life stages, 2) long-term effects of sublethal hypercapnia, 3) physiological responses of adults to hypercapnia, and 4) compared the effects of hypercapnic water and acidic water. These experiments clarified tolerance levels of elevated CO2 and gave insights into compensatory mechanisms at different developmental stages.

INTRODUCTION Increased atmospheric concentrations of CO2 will cause not only global warming but also raise the partial pressure of CO2 and lower pH of oceanic water. These environmental alterations are likely to affect shallow-water marine organisms. On the other hand, feasibility studies recently suggested that sequestration of anthropogenic CO2 in the deep ocean could help reduce atmospheric CO2 concentrations [ 1]. However, implementation of this strategy could have significant environmental impacts on deep-sea life. Hence there is an urgent need for detailed studies on the effect of CO2 on marine organisms. Fish are a central component of the marine ecosystem, and constitute an important protein source, particularly for countries such as Japan. Our literature survey [2] demonstrated that the majority of work concerning effects of hypercapnia on fish has focused on freshwater species and little is known for marine species. Thus, to provide basic information useful for assessing the impacts of ocean sequestration of CO2, the following studies were conducted.

1696

ACUTE CO2 TOLERANCE DURING EARLY LIFE STAGES OF MARINE FISH We adopted a conventional toxicity test design to obtain relationships between CO2 concentrations and survival of eggs, larvae and juveniles. For the two species we studied, LCs0 peaked about 10 days alter fertilization (preflexion stage, Fig. 1). We conducted an immunocytochemical study on chloride cells using an antiserum specific for Na+,K+-ATPase to examine possible involvement of the cells in compensatory mechanisms under hypercapnia. Chloride cell size significantly increased in response to 24 h exposure to 1%CO2 in juveniles of red sea bream (rsb). A similar trend was confirmed for embryos of silver whiting (sw), though statistical comparison was not conducted because of low N (N = 2), suggesting that chloride cells play a compensatory role under hypercapnia even in embryonic stage (Fig. 2). ,

| A: 360 min exposure

itIe ~2 .l fi~l~ / ,~1%

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1'0 Days at~r

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fertilization

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CO2

concentration (LCs0) during early life stages.

if- 600-] Embryoof [" 500t silverwhiting~L~ l

re

4°°1ii I -- 300 ~ 200 100 0 ~

Air

1% CO2

Air

1% CO2

Exposure group

Figure 2: Mean size of chloride cells in yolk-sac membrane (left,

N =

2) and in gill filament (fight,

N =

5)

under normal and hypercapnic (1% CO2) seawater for 24 hours. Vertical bars indicate SD. Asterisk indicate significant difference (P < 0.05) from control (one-way ANOVA).

LONG-TERM EFFECTS OF SUBLETHAL HYPERCAPNIA ON FISH Juveniles of rsb and sw were cultured under sublethal CO2 concentrations. Although growth of rsb was unaffected by CO2 concentrations used after one month, branchial chloride cell became significantly larger at higher CO2 concentrations (Fig. 3). Alter five months, mean body weight was significantly lower in

1697 hypercapnic groups of sw than in the control group. There was no difference in gonad development between the two groups of sw. 2°° /

~15° 1 ~ lOO1

0

.

.

.

.

Group

Figure 3: Mean size of chloride cells in gill filament of young red sea bream reared under control (normal seawater, pH 8.1), low CO2 (0.25% CO2, pH 7.3), mid CO2 (0.5% CO2, pH 7.0), high CO2 (1% CO2, pH 6.8) conditions for 4 weeks. Vertical bars indicate SD. Asterisks show significant difference (P < 0.05) from control (Dunnet test, N=3). PHYSIOLOGICAL RESPONSES OF ADULT FISH TO HYPERCAPNIA Blood acid-base variables were measured under control conditions and subsequent hypercapnic conditions up to lethal level for Japanese flounder, yellowtail and gummy shark. Acid-base disturbances were compensated in all fish while the rate and extent of compensation varied among them (Fig. 4). COMPARISON OF THE EFFECTS OF HYPERCAPNIC WATER AND ACIDIC WATER CO2

exposure resulted in consistently higher mortality than exposure to acidified water (Table. 1).

Acid-base responses were markedly different between the two conditions (Fig. 5). The results indicate that experimental data on acidic water cannot be used to assess the impact of Ocean Storage of CO2.

TABLE 1 COMPARISONOF LETHALEFFECTOF HYPERCAPNICWATER(pH6.2) ANDACIDICWATER(pH6.2) ON FISH Animal Exposure time Mortality by C02 Mortalityby acid Adult of Japanese flounder 48h 100% 0% Egg (embryo) of red sea bream 6h 86% 4% Larva (preflexion)of red sea bream 24h 62% 1% ACKNOWLEDGEMENTS This work was partially supported by the Research Institute of Innovative Technology for the Earth (RITE), as a part of the Research & Development on CO2 Ocean Sequestration Project supported by New Energy and Industrial Technology Development Organization (NEDO).

1698 a.o

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.

.

.

.

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Figure 4: Arterial pH of the Japanese flounder (0), the yellowtail (A), and the gummy shark (v') during exposure to hypercapnic water equilibrated with 1% (A), 3% (B), 5% (C) and 7% CO2 in air (D) (flounder; N = 6, yellowtail and dogfish; N = 5). Open symbols indicate significant differences from 0-h values (P < 0.05). N was decreased due to mortality at 5% and 7% (m), to which no statistical comparison was applied.

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Figure 5: Arterial haematocrit (A), arterial pH (B), blood Pco2 (C), and plasma [HCO3-] (D), [C1-] (E) and [Na+] (F) of the Japanese flounder during exposure to hypercapnic water ( 0 ) and acidic water (A) (hypercapnic water exposure; N = 6, acidic water exposure; N = 5). Open symbols indicate significant difference from 0-h values (p < 0.05). N was decreased due to mortality at hypercapnic water exposure (11), to which no statistical comparison was applied. REFERENCES Handa, N. and Ohsumi, T. (1995) Direct ocean disposal of carbon dioxide. Terra Scientific Publishing Company, Tokyo. Ishimatsu, A. and Kita, J. (1999) Japan. J. Ichthyol. 46, 1.

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1701

ANALYSIS OF WAYS OF ENERGY C O N S U M P T I O N REDUCTION WHILE CARBON DIOXIDE RECOVERY FROM FLUE GAS BY ABSORPTION METHODS TO SOLVE THE GREENHOUSE PROBLEMS Iosif L. Leites Laboratory of gas purification of State Institute for Nitrogen Industry 12-84 Donetskaya Street, Moscow, 109652, Russia

ABSTRACT The objective of this report is to show several possibilities of considerably reducing energy consumption for CO2 recovery from flue gas. Methods have been analysed that'can be used under specific conditions, namely, a low partial CO2 pressure, often with a high oxygen concentration in the initial gas: 1. The use of MEA (monoethanolamine) absorption with modernized flow sheets, by dividing of absorbent streams and integration of heat and mass transfer processes. The commercial experience at many plants under other conditions confirms the possibility of reducing specific heat consumption under these conditions, down to 4000 kJ/m 3 CO2. 2. The use of mixtures of MEA with the organic diluent and water in combination with multiflow networks. This method has been proven in commercial conditions and allows for the reduction of the specific heat consumption, with CO2 recovery from flue gas down to 3500-3600 kJ/m 3 CO2.

INTRODUCTION - THE ACHIEVEMENTS IN REDUCTION OF HEAT CONSUMPTION TO CO2 RECOVERY FROM DIFFERENT GASES It is well known that the main results in energy saving absorption technology of CO2 recovery have been solved, if the partial CO2 pressure in the gas to be purified is high. For example, the specific heat consumption at many monoethanolamine (MEA) units used for synthesis gas purification for ammonia production (Pco2 in initial gas is near 0.5 MPa) has been reduced in former USSR down to 4000 kJ/m 3 CO2 between 1974-1990 [1-4] due to changes in the flow sheets and the process conditions, only without substitution of MEA (Fig. 1). Subsequently, the use of methyldiethanolamine (MDEA) [5-6] gave the possibility of reducing the specific heat consumption down to near 3000 kJ/m 3 CO2. These results cannot be used to reduce heat consumption for CO2 recovery from flue gas as a consequence of some of the peculiarities described below.

1702 THE PECULIARITIES OF CO2 RECOVERY FROM FLUE GAS The following problems are arising when treating flue gas. •

•

• • •

The partial CO2 pressure in raw gas is low, i.e. CO2 concentration is near 3-10% and the pressure is near atmospheric. Therefore, physical absorption is useless in this case, as well as high carbonisation of the chemisorbent. The high concentration of oxygen in gas - up to 4-13%. It leads to increased of side reaction of chemisorbent oxidation rate, and as a result, excessive losses of chemisorbent, corrosion, reduction of heat transfer coefficients through deposition, etc. Large volume of gas. The presence of impurities such as sulphur oxide. The demand to reduce pressure drop in the absorber.

H2+ a)

5 ~ 002

H2+ N2

14

b) 3

~

.d

7

2

)H2+N2 + C02

6

H2 + N2 + CO~

v .

7

Figure 1: Some industrial flow sheets of CO2 recovery by MEA solutions. 1 - absorber; 2 - desorber; 3 - heat exchangers; 4 - cooler; 5 - condensers; 6 - boiler; 7 - pump. a-The flow sheet with 3 streams of the rich solutions and 2 streams of lean solution. b - The flow sheet with full integration of solution regeneration and heat exchange. THE SECOND LAW OF THERMODYNAMICS BASIS OF ENERGY SAVING T E C H N O L O G Y OF CO2 RECOVERY AND THE C O M M E R C I A L F L O W SHEETS OF SUCH PROCESSES The most fruitful methods of reduction of heat consumption of technological processes resulting from the Second Law are, in the Author's opinion, the so called "driving force" method and "quasi static" one [4]. The first is based on the examination of driving forces of all processes, especially of absorption and desorption (stripping, regeneration). In order to reduce heat consumption it is necessary to reduce driving forces. The driving force must be low and uniform [7,8-10]. In order to reduce heat consumption, it is necessary to bring together the operating and equilibrium lines. It is possible to change temperature, CO2 concentration in a lean solution and change the simple one-stream flow sheet by two- or multi-stream flow sheets (see for example Fig. 1). At the limit, the Second Law advises to input and take out all streams of energy and substances from the particular apparatus, throughout its the entire height (within limits). In order to be more concrete, let us analyse the result of a quasi-static analysis of one of the version of absorption. The quasi-static analysis is analysis of the ideal process, which would be run with zero driving force, i.e. along the equilibrium line (the operating line coincides with equilibrium one). Now we are comparing the real absorbent temperature (Fig. 2, line 1) with the quasi static one, i.e. temperature of solution, if the CO2 partial pressure would be equal to equilibrium one in each point of absorber (Fig. 2, line 2). It is seen from Fig. 2 that the real absorbent temperature is increasing regularly from the top to the bottom of a conventional absorber as the result of heating by heat of absorption.

1703 160 ....

..................I . ..... ..

:

I

I

I

"'""-,°,.... °'-..%.

130

"-...,.

...

100

70-

40-

0.15

Figure

0.25

0.35

0.45 0.55 0.65 x, mole CO2/mole MEA

2: Temperatures of absorbent during CO2 absorption by 20% MEA aqueous solution. 1 - The real process, the conventional flow sheet. 2 - The quasi-static process.

However, the quasi-static temperature reduces from the top to the bottom over most of the absorber and has a maximum near the top. However, the main feature of the quasi-static curve is the considerably higher temperature of absorption in the upper part of the absorber. This gives the possibility of using part of the absorption heat for desorption of part of the CO2. The analysis of the desorption process (see Fig. 3) gives a similar results, i.e. excess driving force and as a result, the necessity of dividing streams of rich and lean solutions (see, for example, Fig. 1) or to integrate heat transfer processes and mass transfer ones (Fig. 1, b). 6o

!

I

I

48 ~, 36 --

o

24 --

-,°,

12 ~

0.1

0.2

0.3 0.4 0.5 X, mole CO,/mole MEA

Figure 3: The equilibrium (1) and operating (2) lines for CO2 desorption from 20% M ~ A solution at fine regeneration of MEA solution. The system realized in industrial versions (Fig. 3) allowed the reduction of specific heat consumption for CO2 recovery from synthesis gas from 9000 kJ/m 3 CO2 down to 4000 kJ/m 3 CO2.

O R G A N I C D I L U E N T S F O R M E A AS A M E T H O D O F R E D U C I N G O F H E A T C O N S U M P T I O N The detailed information of investigation, advantages and use in industry has been published previously [ 11 ]. Here it is expedient to give a brief resume in order to estimate the possibility of using such mixed absorbents for CO2 recovery from flue gases. Let us remember the well-known equation to approximate calculation of specific heat consumption (per 1 m 3 CO2)" Q = A H + C A t / A x + rP*abs/P*co2(top)

(1)

1704 It is seen from Eq. 1 that the more absorptivity Ax = X l - x 2 , the less heat capacity C and vapour pressure Pabs and more CO2 equilibrium pressure at regeneration conditions, the less the heat consumption. The examination of literature and own experimental data has shown that absorptivity of many of non-aqueous MEA solutions in analysed conditions is near absorptivity of aqueous MEA solutions although absolute values xl and x2 are more for aqueous MEA solutions. The other properties of mixtures of MEA with organic diluents are more advantageous. It is important that the effect of substitution of water gives the most effect under low partial CO2 pressure, i.e. for flue gas. The most energy saving effect with minimal investments can be obtained by combining three methods: 1. Use of organic diluents to chemisorbents 2. Use of flow sheets with divided streams of absorbent. 3. Integration of heat and mass transfer (desorption) processes. The final result may be near 3500-3600 kJ/m ~ CO2. Further, the calculations have shown that there is the possibility of obtaining CO2 during desorption under pressure, i.e. to store it without needing a special compressor.

SOME OTHER PROBLEMS IN CO2 RECOVERY FROM FLUE GAS.

One of the above mentioned problems is the oxidation of the absorbents. Two methods of reduction of oxidation of MEA and organic diluents when treating of 02 containing gases have been developed. One of them is based on the addition of an oxidation inhibitor. The other method is based on a special change of flow sheet. The next problem is the absorption of vapours and splashes of absorbent by reflux. It has been proved that the right design allows minimizing the absorbent losses. Some details of methods used for solving the problems are not described here because they are subjects of know-how.

REFERENCES

1.

The purification of technological gases. Moscow, Chimia (1977), Semenova T.A, Leites I.L. (Eds) (in Russian). 2. The Handbook of nitrogen engineer. Moscow, Chimia (1986) (in Russian). 3. Leites, I.L., Berchenko, V.M., Proc. of the International Conference ENSEC'93, Energy Systems and Ecology. Poland, July 5-9 (1993) 771. 4. Leites, I.L., Proc., Universiteit Twente, Nederland. Part 3. Process Integration, 1235. 5. Savage, D.W., Funk, E.W., Yu, W.C., Astarita, G., Ind. Eng. Chem. Fundam., (1986) 25, 326. 6. Cross, C., Edwards, D., Santos, J., Stewart, E., CAN Energy, 90, May (1990). 7. Leites, I.L., Sosna, M.H., Semenov, V.P., Moscow, Chimia (1988) (in Russian). 8. Petliuk, F.B., Platonov, V.M., Khim. Prom. (1964) 723 (in Russian). 9. Sama, D.A., Qian, S., Gaggiolli, R., Proc. of International Symposium, Beijing, China. June 5-8 (1989) 520. 10. Sama, D.A., Proc. of the International Conference ENSEC'93, Energy Systems and Ecology, Poland, July 5-9 (1993) 1. 11. Leites, I.L., Energy convers. Mgrnt. (1998) 39, 16-18d, 1665.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1705

M A K I N G T O U R I S M IN N E W Z E A L A N D E N E R G Y - E F F I C I E N T M O R E THAN T U R N I N G OFF THE LIGHTS S. Becken Environment, Society and Design Division, PO Box 84, Lincoln University, Canterbury, New Zealand

ABSTRACT Energy use associated with tourism has rarely been studied, despite a potentially considerable contribution to global or national energy demand. This study analysed three New Zealand tourism sub-sectors (transport, accommodation, and attractions/activities), and alongside the travel patterns of domestic and international tourists. From this, total energy demand was estimated and options to reduce energy demand were identified. Transport is by far the most important source for energy demand of tourism. For domestic tourists almost all energy use is for transport, mainly by private car or plane. International tourist's energy demand is more diverse, although still dominated by transport. A segmentation analysis based on tourists' individual travel choices revealed that there exist different clusters of tourists characterised by 'typical' travel patterns and, hence, energy use. The understanding of different tourist types provides a valuable basis for energy conservation and efficiency strategies. It is also important for balancing energy use with other factors, such as the economic returns or social impacts.

INTRODUCTION

Only recently, tourism, energy use and climate change feature as a topic of discussion at international institutions, such as the United Nations Environment Program and the World Tourism Organization, and national bodies, such as the Tourism Industry Association New Zealand. This paper presents results from a doctoral study on energy use of New Zealand tourism. The overall finding was that tourism consumed 25.35 PJ in 2000, which is equivalent to 5.6% of national energy demand in New Zealand. CO2 emissions from tourism amounted to 1,549 kilo tonnes, or 5.1% of all CO2 emissions in New Zealand. Domestic tourists are the larger energy consumers (70% of total energy use) as a result of tourist volumes compared with international tourists. In the light of New Zealand's ratification of the Kyoto Protocol it is important to develop strategies for reducing energy use overall, and in particular in the fossil fuel dependent tourism sector. This is even more pressing given projected growth numbers of tourism. Selected results are presented here that are believed to be valuable for developing mitigation strategies.

1706 ENERGY USE OF THE TOURISM INDUSTRY Transport Transport is the dominant contributor to energy use in the New Zealand tourism sector, making up 85% of a domestic tourist's total energy use and 69% of the internal energy use of international tourists. Airplanes and cars are the most widely used transport modes, both of which require considerable input of energy on a per passenger kilometer basis. Air travel, the infrequently used sea transport, camper vans and cars are the most energy-intensive forms of transport.

Several options to decrease transport energy use exist. These target, for example, transport providers, such as rental vehicle companies who could change their renting schemes or modernize their fleet to include vehicles with altemative fuel sources. Regional or local government plays a role in that they could encourage public transport systems, shuttle buses to key tourist attractions, develop programs to increase tourists' length of stay, and establish cycle networks. Tourists themselves have a large range of options to change their transport behavior, for example in choosing more energy-efficient modes or decrease travel distance. The implementation of many of these measures could be supported by government initiatives, either in the form of 'carrots' or 'sticks'. In New Zealand, the 'sticks' are currently discussed by the Government in the form of an emission tax at $25 per tonne of CO2 equivalent. Accommodation In New Zealand, there is a large range of accommodation providers. Hotels are the largest accommodation businesses and consequently consume most energy in total, mainly electricity [ 1]. Hotels also require large energy inputs on a per visitor-night basis (155 MJ/visitor-night). It is believed that (large) hotels have the greatest potential to become energy efficient for several reasons. They are often part of a hotel chain, have more capital than smaller providers, employ more specialized personal, and provide a wide range of functions to which energy saving measures could be applied. The small Bed & Breakfast businesses operate comparatively inefficiently (110 MJ/visitor-night). B&Bs are often family businesses where occupancy rates are low and profit maximization is not the overriding goal. Hotels and B&Bs have been described as 'service-oriented' accommodation. In contrast, the more energy efficient motels, campgrounds and backpackers were named 'purpose-oriented' accommodation, because they mainly seek to provide the basic service of a place to spend the night.

Tourist Attractions and Activities Tourist attractions and activities constitute an important part of the holiday experience; however, they contribute less to tourists' energy use. Generally, tourist attractions and entertainment attractions consume less energy per visitor (about 6 MJ per visit) than tourist activities (96 MJ) [2]. Activity packages offer an individual style and service orientation that requires energy at different stages. Most energy use in attractions is associated with building functions, which makes it easy to introduce energy measures (e.g. improving insulation). Despite the relative efficiency of most built attractions, they are most important in terms of overall energy use, because of their visitation levels. Activities often rely on the use of motorized vehicles, either to get to the location where the activity takes place or for the activity itself (e.g. jet boat tides). Generally, the input of petroleum fuels is typical of 'activities', while 'attractions' rely on electricity for their buildings. These findings are important, given New Zealand's strong marketing focus on tourist activities.

1707 TOURIST B E H A V I O U R AND E N E R G Y USE

A tourist's trip comprises different travel choices across the three sub-sectors discussed above. Domestic tourists in New Zealand differ from international tourists in that they take many short trips, mainly by their private car and by air. The diversity of domestic trips is small, and manifests mainly in different travel distances. In contrast, international tourists make many different travel choices to compose their trips. 'Coach tourists', for example, travel by coach and domestic air, and tend to stay at hotels. These tourists are also attracted by tourist icons and built attractions (e.g. farm shows). A large proportion of international tourists are 'touting tourists', which means that they visit more than one place, whereas domestic tourists tend to travel to a single destination. Multi-destinational travel is often associated with a large total energy use, due to significant transport energy requirements and also because of longer trip durations. Different travel styles require different energy inputs. Domestic tourists consume about 1,108 MJ per trip and 457 MJ per day across different types of trips. This compares to 4,055 MJ in total and 387 MJ per day for international tourists. Domestic tourists travel less efficiently, mainly because of large travel distances per day. Both the domestic and the international market were segmented into tourist types with typical travel patterns and, hence, energy use. The most energy intensive types are air-based trips, for example domestic business trips. International 'coach tourists' also rely on air travel and therefore consume most energy per day (654 MJ) compared with other international tourist types, for example the 'visiting friends and relatives type', who consumes 183 MJ per day.

CONCLUSION AND I M P L I C A T I O N S As a result of current greenhouse gas accounting regulations, the primary focus of energy management is on destination-based energy use. It is, however, important to keep in mind that policies may change and emissions from international travel will be allocated to nations' accounts by one form or another. For this reason, in the long-term, New Zealand will also have to regulate energy use of international air travel [3]. The analysis of the New Zealand tourism industries showed that energy consumption is a result of complex and multiple interactions between management practices, technological standards and human behaviour. It appears therefore most promising to develop a framework that allows tailoring individual solutions to different business situations. To this end, stakeholders will need to cooperate at business, industry and government levels. In New Zealand it is essential to take into consideration the large number of small and family-operated businesses, where possible costs, lack of knowledge and advice, high staff turn-overs and a general absence of feeling responsible for environmental impacts impede the implementation of energy saving measures [4]. Tourist types and their energy profiles both between and within domestic and international tourists were derived to enable planners to implement energy programmes most effectively. From this typology several questions arise: First, how can we reduce energy use of each type? Second, what tourist types require most urgent action? Third, are there tourist types that are more 'desirable' than other types? Finally, what indicators other than energy use should an assessment of 'desirability' include? These questions each compel need for further research. Reducing energy use by tourists could be theoretically achieved in two ways, namely reducing the need to travel and making travel more energy efficient. Given the popularity of travelingmanifested in increasing tourist numbers worldwide - and the difficulty of reversing present

1708 structures (e.g. cheap flights, the perceived need for business or conference travel etc.), the solution of making travel more efficient remains. Based on the analysis in this study it is suggested that changing tourist itineraries would have the largest effect on reducing energy use. The tourist itinerary determines the travel distance, and influences to some extent the overall travel pattern. It is, however, extremely difficult to alter individual behavior towards more environmentally friendly actions [5], and tourists only adopt new travel styles when they recognize personal advantages (e.g. cost benefits). To alter travel patterns in the future it is essential to understand the tourists' motivations, expectations and decision-making processes that lead to present travel behavior. REFERENCES 1. 2. 3. 4. 5.

Beckens, S., Frampton, C. and Simmons, D. (2001) Ecolog. Econ. 39 (3), 371. Becken, S. and Simmons, D. (2002) Tourism Manage. 23 (4), 343. Becken, S. (in press) 3". Sustain. Tourism 10 (2) Carlsen, J., Getz, D. & Ali-Knight, J. (2001) J. Sustain. Tourism 9 (4), 281. Stoll-Kleemann, S., O'Riordan, T. Jaeger, C. (2001) Global Environ. Change 11, 107.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1709

STUDY OF HIGHLY EFFICIENT GAS ENGINE DRIVEN HEAT PUMP SYSTEM WITH C A S C A D E D USE OF E X H A U S T HEAT F R O M ENGINE Kazumi Takahata and Takeshi Yokoyama Technology Development Dept, Tokyo Gas Co. Ltd, 3-13-3, Minami-Senjyu Arakawa-Ku, Tokyo, Japan

ABSTRACT With their background of energy-serving and environmental attributes, the gas-engine driven heat pump (GHP) is growing in popularity. Of course, the high efficiency of GHP is demanded to able to cope with environmental problems and energy issues. As for GHP, not only more highly efficient devices such as the engine and compressor, but also exhaust heat recovery forms an effective method for improving efficiency. This paper describes the high efficient system, utilizing exhaust heat from GHP, in both cooling and heating operations.

INTRODUCTION

The problem of global warming is now getting serious, and reducing CO2 emissions is one of the most important factors. As for air-conditioners, improvements in energy efficiency are needed to decrease energy consumption. In Japan, the Gas-engine driven heat pump (GHP) was first commercialized in 1987 for the commercial market. Since then, the market has grown, with the result that GHP has become one of the major air-conditioning systems in Japan, especially for commercial use. It means that GHP has a responsibility to reduce CO2 emission, and help to solve the global warming problem. This study is focused on the utilization of exhaust heat from a gas-engine, to increase COP, both in cooling and heating operations.

1710 EXHAUST HEAT U T I L I Z A T I O N OF PRESENT GHP Currently, GHP does not use any exhaust heat in cooling operation. Figure 1 shows a typical diagram of a present GHP which uses an exhaust heat. The P-h diagram of refrigerant in a heating operation is shown in Fig.2. Engine cooling water collects exhaust heat through an exhaust heat exchanger and an engine jacket, and the temperature increases to around 80 degrees C. In cooling operation, the engine cooling water is led to a radiator, and heat is radiated to the ambient air. Conversely, in heating operation, it is led to a water / refrigerant heat exchanger, where it evaporates some of the refrigerant. Thus, the following benefits are obtained. 1) Performance is not influenced by outdoor temperature. 2) The pressure of the evaporator increases, which assures higher heating capacity. However, as shown in Fig.2, since about 50% of the amount of heat to evaporate the refrigerant is covered by the exhaust heat, the amount of heat from the ambient air decreases. For this reason, heating COP of the conventional GHP does not increase considerably. Exhaust gas

I Heat exchanger Exhaust

ediato

...... /

Condenser

R

/I

Evaporator

Expansion valve

aml:ientair

~es~ he~

..............................................................

~nl~l'd

q~le

h Figure 1: Heating Cycle of GHP

Figure 2. P-h diagram of GHP

HIGHLY EFFICIENT GAS ENGINE DRIVEN HEAT PUMP SYSTEM W I T H CASCADED USE OF EXHAUST HEAT

The new system is aimed at improving efficiency and performance of GHP, both in cooling and heating, by means of exhaust heat from the gas-engine. Figure 3 shows a new GHP system. (Figure 6 shows a P-h diagram for new system). Exhaust heat is used as a heat source to operate a Rankine cycle, which uses the refrigerant of the GHP as the working fluid; thus, the GHP refrigeration cycle and Rankine cycle converts exhaust heat to power, which is used to compress the refrigerant.

1711

Exhaust gas ~Exhaust gas/waler I[ ] ]I'~atexchanger _~ :

i:

I

~

[

Subcompression turbine -.J I

2 " ~

~~r--J

Water/refrigerant Water/Refrigeran~ ?valEXPv~

I ~on

heatoxch~.r

~,,~'~r

.i

.

. . . . .

ii

Refrigerant

,~ ~onoenser

,I,

:

water

High

temperaure water Figure 3: Diagram of New GHP system In order to evaluate this cycle, a simulation study were conducted on the following conditions. Refrigerant

R-407C

Heating Capacity

Fixed in All system

Engine efficiency

30%

Exhaust heat recovery efficiency

50%

Total turbine efficiency (expansion turbine and compression turbine)

50%

Pressure loss of piping and heat dissipation is not taken into consideration The operation condition of the standard cycle was as follows. Saturation temperature at condenser

45degree []

Saturation temperature at evaporator Superheating at evaporator outlet

-2degrees [] 5degrees []

Superheating of evaporate turbine

5degrees []

Subcooling

5degrees []

Compressor adiabatic efficiency

80%

Compressor mechanical efficiency

80%

Outdoor temperature conditions

7DB / 6WB degrees C (heating)

Indoor temperature conditions

20degrees [] (heating)

35 degrees@ (cooling) 27DB/19WB in cooing

1712 RESULTS The simulation results are shown in Figs. 4 and 5. As a result of the simulation, it has been proved that the COP of the new system can achieve 1.4 (that of current system is 1.2) in cooling operation, and 1.8 (that of current system is 1.4) in heating operation. The average COP of the new system in cooling and heating operation is 1.6.

1.8 [~i~ii~i

1.2 ..-. 0 . 9

i;,<,~,:~'~,

i~i. . . . : ~

'~

!

~i!i~:..;i

~!i:i!ii!i!2~:~il

~;~t,~:i

~ 0.90.6 ............

~ ~ ;

"g 0.3

0.3

~o

~ o C u r r e n t system

Current system

New syst em

New system .___

Figure: 4. COP comparisons The following points are mentioned as to this factor.

Figure 5: COP comparisons

1) Reduction of net work of the compressor (in both cooling and heating operation). The Rankine cycle converts exhaust heat to power, which is used to compress the refrigerant, thus reducing the net work of the compressor so that it can increase cooling and heating COP. 2)

Provide exhaust heat directly to an indoor unit (in heating operation). Since exhaust heat recovery efficiency is added to the COP of a heat pump cycle, COP of this

system increases. Low t e m p e r a t u r e

High temperature

b compression

turbine

Fig. 6. P-h Diagram of New GHP system

CONCLUSIONS We studied and analyzed a new GHP system which has cascaded use of the exhaust heat. The simulation proves that the COP of the new system GHP improves in both cooling and heating cycle. The GHP of the new concept, which convert exhaust heat to power, was studied and evaluated. The result of the simulation showed that the COP of the new system improves by 0.2 in cooling and 0.4 in heating. Further research will be required to address such issues as selection of the turbine, heat exchanger, etc.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1713

ANALYSIS OF C O G E N E R A T I O N N E T W O R K S Y S T E M S EFFECTIVE FOR R E D U C I N G G R E E N H O U S E GASES Kei KAWAKAMI, Takemi CHIKAHISA and Yukio HISHINUMA Division of Mechanical Science, Hokkaido University, N-13 W-8, Sapporo 060-8628, JAPAN

ABSTRACT This paper presents effects of networking cogeneration systems (CGS) for the reduction of greenhouse gases and economy. Analysis was made on the effect of availability in power-grid connection, heat network with hot-water line, heat storage, and operation modes. The result shows that houses have a great potential of reducing greenhouse gases and grid connection is essential for realizing the potential. Networking heat in an area has an advantage mostly in reduction of cost. House-hotel (or hospital) combination has an apparent effect for the reduction of greenhouse gases, but the house-office combination has little effect when grid connection is possible. The paper also presents the best combination of building types and pipeline routes of heat network for a specific example area. INTRODUCTION Cogeneration is expected to be one of the most prospective system for the reduction of greenhouse gases. However, depending on the building types and operating conditions of the system, the effect varies significantly and it may even increase greenhouse gases in some cases. The paper is part of the work trying to reveal general characteristics of cogeneration systems in these complicated relationships, from energy and economical aspects [ 1-3]. The buildings analyzed here are thus limited to social buildings (not industry), whose energy demand patterns can be specified.

ANALYTICAL M E T H O D AND BASIC DATA The following index of CRF (Cost Reduction Factor) is introduced for the economic advantage of cogeneration:

CRF :

$cv-

~

where $cv and $c~ represent annual costs of conventional and cogeneration systems respectively. The cost includes initial investment costs as well as running cost by means of their payback time. The conventional system receives electricity from power grid and heat from a boiler. Similarly, ACO2 (CO2 Reduction Factor) is defined as an index of CO2 reduction rate. The carbon dioxide emission from power plant for the grid electricity is also included. As natural gas is used for CGS fuel, power plant emission is calculated with the same fuel to identify best energy utilization. In this analysis, five types of buildings (house, office, hotel, store, and hospital) are analyzed. Hourly rate patterns of energy demand of each building are given for three seasons. The annual energy demand for an unit floor area are decomposed to monthly energy demand, and the hourly energy demand is determined from the monthly demand and the above hourly rate patterns. Peak energy demand, which is used for determining the system capacity, is obtained from the summations of the hourly patterns of peak energy demand of buildings in the cogeneration area. The capacity of the CGS is expressed by cy value, which is defined as the maximum heat output of the cogeneration relative to the peak heat demand. The ~ value was set 30% in this analysis, as the previous

1714 work indicates the value is the best from the balance of carbon dioxide reduction and economical benefits. The capacity of backup boiler was set equal to the peak heat demand. Table 1 is the fuel cost and CO2 emissions used in the analysis. Detailed data are presented in Ref. [2,3]. RESULT AND DISCUSSION

Difference for Building Types andfor Operation Patterns Figure 1 shows the CRF and ACO2 for different building types and operation modes. Cogeneration can be operated correspondingly either to heat demand or to electric demand. The CO2 operation mode is the case when the hourly operation patterns are set to give the maximum CO2 reduction rate, while the economy mode is to give the maximum CRF. In either case, the excessive power generated by the CGS can be returned to the grid with the cost of 75% of buying. For the CO2 mode, when most of the operation pattern is of heat demand control, the ACO2 is high in houses, hotels, and hospitals. The CRF is also relatively high for these building types. On the contrary, the ACO2 and CRF are low in offices and stores, whose electric/heat demand ratio is high with large fluctuations compared to the above buildings. It should be noted here that the ACO2 can be negative in some cases: economy mode in offices in the figure. This is due to the fact that CGS is operated with electricity demand control, to have better economy, even with discarding excessive heat generated. Thus, the introduction of CGS must be made in appropriate buildings with the right operation patterns to have an effective reduction of greenhouse gases. It can be also said that the houses have the largest potential to reduce greenhouse gases due to their ACO2 itself and the large total floor areas. The Effect of Power Grid Connection and Heat Storage Comparison was made on the effect of power grid connection and heat storage capability on CO2 reduction and economy. Table 1 is the list of the four different cases compared. Case 1 is the base case with no reverse flow of electricity to the power grid ("no power grid connection" in the paper). CGS is basically operated with CO2 mode within this limitation. Case 2 has a heat storage system with no grid connection. CGS is operated in the time zone of high electric demand and the excessive heat is stored for the high heat demand time. Case 3 has power grid connection, and CGS is operated in CO2 mode all the time without limitation of electric demand. Case 4 has heat storage system together with the grid connection. CGS is operated in full load in the time zone of high electric demand.

Figure 2 is the result of the analysis, showing great potential of power grid connection for the CO2 reduction in houses. The carbon dioxide reduction increases about 3 times of the base case of no power grid connection. It is also effective for the CRF in houses with this electric price condition, i.e. sell/buy ratio of 75%. In offices, however, the grid connection does not have apparent difference on CO2, but it does on CRF. This is because the electric/heat demand ratio is high in offices and excessive electricity is little when operation of CO2 mode is selected. Additionally, the high peak in heat demand can be covered by the heat storage system without assistance of backup boiler with this system. In this analysis, the electricity price is set to be constant, independent of time. The figure shows that the heat storage significantly affects the economy but not significantly CO2 reduction. TABLE 1 RUNNING COST AND EXHAUST CO2 Fue1C0stD'en/kWh] 3.4 016GWh/year)-4.6 ~23GWh/year) 20 Elactrizityc0st[yen/kWh] 130 {~ctVc~) 56 ~oibr& CG) C0 2 [~-C/kWhI

F---IC RF (C 0 2-M ode) - - ~ C 0 2 (C0 2-M ode)

/ +

C RF~Eco.-M ode) ] C 0 2 ~co.-M ode) _ _ J

30

2s .n 20

15

TABLE 2 FOUR TYPES OF CONDITIONS IN COMPARISON

lO 5

Meaning Case Case Case Case

1 Base 2 Heat S. 3 Grid Con. 4 Both

Power Grid Connection Heat Storage x x o o

x o x o

¢3

o house

office

hotel

store

hospital

Figure 1: CRF and CO2 reduction for two different operation patterns

1715

The Effect of Heat Network It was shown in previous work that networking heat among houses and hotels (or hospitals) gives great advantage in both CRF and CO2 reduction rate [ 1]. In this section, a combination of houses and offices are investigated, because both buildings have large total floor area in most cities and have opposite characteristics in electricity/heat ratios. The heat storage system may also increase effects of combination. Figure 3 shows changes in CO2 emission and annual costs for combination ratio of office/house floor area. Comparison is made for the two cases: Case 2 with no grid connection and Case 4 of grid connection. All cases have heat storage systems, and the values are shown, relative to the no heat-network case, in which heat is supplied by the individual CGS system. The figure indicates that the networking heat is effective for CO2 reduction in the case of no grid connection, but no effect can be expected when grid connection is possible. The latter result is due to the fact that the combination averages the peak heat demand, and it becomes smaller for unit floor area, resulting in smaller CGS size for the same s value. This fact results in increased CRF with slightly deteriorated CO2 reduction, which generally increases with larger size of CGS. It can be said that the optimum combination ratio of office/house floor area is around 80% in the case of no grid connection. The result is limited to the case of house-office combination, and in the case of house-hotel combination significant CO2 reduction by the networking can be expected as shown in the next section.

The Optimum Arrangement of Energy Network in a City The authors have reported on the methodology of determining optimum network zones and pipeline routes of district heating with CGS [1, 2]. The result showed that the combination of houses and hotels has significant benefit on both economy and CO2 reduction. This section introduces an effect of network and optimum arrangement of zones in a city. In this example, four types of area blocks of given numbers are provided, as shown in Table 3. These types and number of zones are allocated based on the characteristics of Sapporo City in Japan. Zone A is an area with a high density of hotels and hospitals, and Zone B is the area of hotels; these two areas have the highest CRF as an individual zone. Zone C is an office area and Zone D is a residential area with large apartment buildings. 50

1.1

i

House/]CO2 01 t~

"7" v

¢.9

m 00

0

"13

,~ o

"o t-

U_

-50

H

to

t,.)

ol

t.)

1

i_ O ID

z

o

-r-

0.9

Case1 (Base)

Case2 Case3 (HS) (Grid Con.)

Case4 (Both)

0

Figure 2" CO2 and cost reduction effects of cogeneration for the four cases

20 40 60 80 Office/House Area Ratio (%~

Figure 3: Effect of house-office combination with heat network: values are compared relative to no network case

TABLE 2 ZONE TYPES AND FLOOR AREAS USED IN THE ANALYSIS Zone Type and num bets

Fi m m Hi!

l | [

[m2/m

House 0.57 1.65 2.86

0 ~e 0 0 0.57

100

2 ofhnd] Hotel Store 0.57 0 2.35 0 0 0.57

/]C02 CRF Hospital 2.86 29.56% 13.10% 0 2 6 . 5 6 % 6.15% 0 2 9 . 0 5 % -7.25%

1716 I

I

Rnllrm

I ,/]CO 2

W[/! ,ill ,; lira lltl

i~ ~ ,

IINil

,,

'

BD~II][

-$11H!

Bia

la=mm

ill

i|ml| NI|

0 05

0

CRF

r

I

i

20 40 60 80 Number of zone added in cluster

Figure 4: Final map of zone types and pipeline

Figure 5: CRF and ACO2 change in the

routes after clustering with heat network

clustering process

100

In this analysis, the zone with the largest CRF is placed in the center of the town, where CGS plant is located. Around this pivot zone, a zone giving the highest CRF after combination is added, forming a cluster. Repeating this process the town design is established. In this process pipeline route and the diameter of the pipe is determined to give the best CRF. No jumping of the zone in the cluster is allowed so that the cluster is connected continuously. Detail of the clustering methodology is shown in Ref [ 1, 2]. Figure 4 shows final result of the zone distribution together with pipeline routes as a best design of heat network with CGS. Figure 5 is the changes in CRF and ACO2 in the clustering process. As the growth of the cluster, CRF and CO2 reduction rate increases, reaching the maximum CRF of 25% at 48 zones clustering and ACO2 of 37.5% in the case of 59 zones combination. It should be noted here that the maximum CRF and ACO2 is apparently larger than the initial pivot zone, which has the highest value of CRF (and possibly of ACO2) for individual zone. This indicates that by well designing the heat network CRF and CO2 reduction rate can be significantly larger than the CGS of individual building. Networking houses and hotels or hospitals has large advantage in this aspect. However office is hardly combined in the cluster as shown in Fig. 4, where Zone C is added in the cluster after all the other types of zones are involved in the cluster. The CRF and ACO2 start decreasing when Zone C is added in the cluster. CONCLUSIONS (1) Introduction of CGS must be made in appropriate buildings with suitable operation patterns in order to have an effective reduction of greenhouse gases. In some cases, it is possible to even increase CO2 when economic advantage only is concerned. (2) Houses have great potential for reducing CO2, and a power grid connection is essential to maximize the potential. The heat storage system does not have a significant effect of CO2 reduction, but it is effective for economy and for flexible operation co-operating with a power plant. (3) District networking of heat has advantage when a cluster is formed with hotels, hospitals, and houses. However, offices are hardly connected with the cluster when power grid connection is feasible. When grid connection is limited, networking heat among houses and offices gives apparent effect for the reduction of C02. REFERENCES 1. Chikahisa, T., Georgiades, G., Hishinuma, Y., and Fujiwara Y. (2000) Trans. of JSME, 66-642 B, pp539-546 2. Georgiades, G., Chikahisa, T., Hishinuma, Y., and Fujiwara, Y. (1999) Proc. of Int. Joint Power Generation Conference (IJPGC'99), pp 153-160. 3. Nanba, T. Chikahisa, T, and Hishinuma, Y. (2001) Proc. of 20th Annual Meeting of Japan Society of Energy and Resources. pp 13-18

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1717

LOGICS AND LOGISTICS OF LIFE CYCLE ASSESSMENT (LCA) FOR MINIMIZING GREEN HOUSE GAS E M I S S I O N S - AN INDIAN CASE STUDY OF AUTOMOBILE SECTOR

Sita Anand 1 and Surendra Kumar 2 1 Environment Systems Coordinator, PACD, Nuchem Weir Limited, 119 LSC, Pocket D&E, Sarita Vihar, New Delhi, e-mail: [email protected] 2 Head, PACD, Nuchem Weir Limited, 119 LSC, Pocket D&E, Sarita Vihar, New Delhi

ABSTRACT

Environment Management Plans use Life Cycle Assessment (LCA) of various products for development of clean technologies, resource conservation and eliminating areas/activities where there are chances of environmental degradation or pronounced emissions at any stage of extraction of raw materials, transfer, storage or use in manufacturing of product or by-product development. LCA considers the environmental impacts along the continuum of a product's life (i.e. from cradle to grave) from raw materials acquisition to production, use, and disposal or recovery. The environmental impacts considered include resource depletion, human health, energy use and ecological health. The concept of life cycle thinking is a unique way of addressing environmental problems from a system or holistic perspective. In this way a product is evaluated or designed with a goal of reducing environmental impacts over its entire life cycle. Automobile sector in the Indian scenario had taken a long time to transform with the changing scenario. The need for overall cleaner means of transportation was acutely felt in the metropolis of the country. This provoked environmentalist and public to trigger activities with the help of judiciary to set up stringent norms so that precious lives are protected. Some of the well known environmental interventions used LCA of various products, to set up and trigger action planning for introduction of clean fuel to reduce emission of Green House Gases and other pollutants even at the cost of restricting/withdrawing non conforming vehicles especially public transport which is the major contributor to the pollution in the cities.

INTRODUCTION

India is the focus of attraction to the world community for a number of reasons. First, it may be the world's most populated country by 2025 and its green house gas (GHG) emissions would rise subsequently. Despite the fact that India emits only 0.2 tons per capita of carbon dioxide from fossil fuels (compared to 5.2 tons for the US and a world average of 1.2 tons), it is now the world's sixth largest carbon dioxide emitter. Second, the major share of India's energy comes from coal, which will continue to provide over 60% of the total energy in the future. But coal emits the highest amount of carbon dioxide. Thus, a high population, predominance of coal in energy use, low energy efficiency and a high potential economic growth because of current low-income level is causing concem in intemational

1718 circles about India's future GHG emissions. Under such circumstances, India would need to adopt sustainable energy efficient methods to reduce GHG emissions. Vehicular pollution is the major cause of pollution in major metros of India. In Delhi, the capital city of India, more than 60% of air pollution is caused due to vehicular emissions. Hence, besides the adoption of efficient energy generation and utilization techniques for coal, it is imperative that steps be taken to reduce the air pollution from vehicular fleet in the cities. Keeping in view this objective an exhaustive Life Cycle Assessment study for automobile sector in India was carried out which helped identify the major air polluting phases of automobile's life cycle and suitable steps to mitigate the same were taken thereafter.

Life Cycle Analysis Life cycle assessment is a systematic approach used to manage the environmental impacts of product and services systems, and it is applied at two levels. It is applied: • Conceptually, as a thought process to guide the selection of options for design and improvement. • Methodologically, to build a qualitative/quantitative inventory of environmental burdens or releases, evaluate the impacts of those burdens or releases, and consider alternatives to improve environmental performance. In any application, LCA considers the environmental impacts along the continuum of a product's life (i.e. from cradle to grave) from raw materials acquisition to production, use, and disposal or recovery. While performing a LCA three component models are developed: 1. An inventory of materials and energy used and environmental releases arising from all stages in the life of a product or process, from raw material acquisition to final disposal. 2. An impact assessment examining potential environmental and human health effects related to resource consumption (energy and materials) and environmental releases. 3. An important assessment of the changes needed to effect environmental improvements in the product or process. LCA helps identify the major polluting activities/materials used in each phase hence the industries can take cue from it to substitute an activity or material to make the overall life of the product cleaner. For example:

a) Materials production Environmental considerations on material specifications with regard especially to avoid toxic substances, to use renewable/recycled/recyclable materials, to reduce material usage, to use low energy content materials, to reduce transport and packaging.

b) Manufacturing and assembly Environmental requirements in vendor qualification/inspection with regard to the valuation of the suppliers' Environmental Management System (as per ISO 14001 guidelines) and Ecolabelled Products (as per ISO 14020-1) even by auditing activities (as per ISO 14011). Environmentally conscious manufacturing design should consider alternative production techniques, fewer production steps, low/clean energy consumption, less production waste, few/clean production consumables. c) Vehicle use Environmental design for utilization should consider low energy consumption, clean energy source, few consumable needs, clean consumables, reliability and durability, environmental instructions for the consumer. Alternative fuels for internal combustion energy: Liquid Petroleum Gas (LPG), Compressed Natural Gas (CNG) and Alcohol can be analyzed as substitute for petrol/kerosene.

1719

d) End of life management Environmental design for end of life management should consider reuse of the product (component), disassembling, recycling, re-manufacturing and safe incineration.

LCA OF INDIAN AUTOMOBILE INDUSTRY- CASE STUDY The Life Cycle Assessment (LCA) carried out for the Indian automobile sector covered the following phases of the life cycle of an automobile: • Sourcing Phase- Production and sourcing of materials (steel, aluminium, plastics, fuels etc.) • Sourcing, Production and Conversion Phase- Production of various parts and components and their finishing and assembly • Use Phase- Environmental performance of the product during use • Disposal/Recycling/Reuse Phase - Retirement and final fate of the product The Key stakeholders over the life cycle were material suppliers, parts fabricators, Original Equipment Manufacturers (OEMs), customers, service and repair professionals, dismantlers, shredders, nonferrous processors, waste managers, regulators, insurers and investors and, as an extension, the environment. In order to determine the environmental loads of various phases of automobile's life cycle a number of factors like: Automobile Sector Operations, Control equipment and Actual Emission, Material composition rating, Fuel Used, Design for recycling, Recycling program, Emission/effluents, Waste, Procurement policy and Supply chain management, Consumer education, Environmental standards for service station, Manufacturing, Raw material extraction and processing, End of life Use, Engine and vehicle design, Environmental Policy and management systems were considered. The extensive questionnaires filled in by the automobile industries, visits to industry by the team of experts carrying out the LCA, Recycling manual, Proactive initiatives manuals etc. were marked as the boundary for the Automobile Sector LCA. During the analysis it was found that there was not much data available for analyzing various life cycle phases hence alternative criteria were built to analyze the phases. For example: For Raw material/input sourcing phase no data on material sourcing and its impact during production and on actual pollution generation in supply-chain was available with automobile industries hence the phase was analyzed based on the Procurement policy and its implementation, Management of supply chain and initiative for its greening, Similarly, for production and conversion phase there was no concrete and comparable data available due to different processes/ techniques at different plants and absence of any benchmarks hence Captive processes based on specific consumption/environmental load (Body fabrication, painting, assembly), processes meeting captive as well as spare market demand, based on process characteristics and ratio based indicators (machining, casting, plating etc.) were made as the criteria for rating. For the use phase Environmental performance of all vehicles produced assessed in terms of corporate fuel and engine performance and Age factor were considered while assigning weightages and for disposal/recycling phase subjective assessment of recyclability performance based on product design, material composition of selected models and Publication of recycling manual and marking of recyclable parts were made as the analysis criteria. According to the study it was found that materials, parts and components production, painting, finishing, machining, facility clean up and usage phase maintenance contributed to most of the Water Pollution. Product usage phase (about 85% of total), painting, casting, energy generation, transportation etc. contributed to air emissions Fossil fuels (use phase) and mining materials contributed to Non-renewable inputs, Mining waste from energy and ore production, Casting, metal works, finishing, painting, ETP sludge etc., Waste generated during use, Residues from auto shredding contributed to Solid and hazardous wastes sources. As a result

1720 of the LCA study it was concluded that the use phase accounts for the majority of the energy consumption and hence air emissions. Hence in order to curb the air pollution and the Green House Gases emission from the automobile's life cycle it was very important that proactive steps be taken up in this area. The Government of India took some major decisions regarding automobile sector in order to reduce the GHG emissions, some of them are: Supreme Court Directives to Promote Energy Efficient and Clean Vehicles: Order by the Supreme Court of India, disallowing registration of all private non-commercial vehicles in the National Capital Region (NCR) failing to conform to Euro II fuel emission norms from Ist April 2000. This meant that any new four wheeled petrol driven passenger vehicle to be registered after 31 st March 2000 in the national capital region (areas in and around the city of Delhi) would have to meet mass emission norms which, for carbon monoxide, were 2 to 3 times more stringent than the then prevailing emission norms. Similarly, for new four-wheeled diesel passenger vehicles, the new carbon monoxide emission norms were made 1.2 to 2 times more stringent compared to then prevalent levels. Old and Polluting Vehicles Ordered off the Road: Buses, Taxis and Three wheelers more than 8 years old were taken off the road and only CNG taxis were registered after the year 1998. These enforcements led to reduction of CO emissions, in the year 2000, by a factor of more than 0.40 per vehicle (considering the overall vehicular population as a whole), as compared with the year 1998*. LCA carried out for the Indian Automobile sector has helped the vehicle manufacturers substantially, not only in improving their workshop and vendor facilities but also to equip themselves in a pronounced manner to face the consumers and society at large. The brand names, which were forerunners after the study, had clear marketing edge over their competitors while the others had the satisfaction of knowing their performance status. The status of leading companies in the rating was taken up as benchmark and other companies started devising various steps for improvement. It was for the first time that such a rigorous analysis was carried out which generated enough heat and enthusiasm to accelerate and maintain the pace of sustainable development in the automobile sector. The maximum beneficiary of the LCA study has been the environment, where reduction in GHGs emission was not only been achieved but more of it promised for the days to come.

REFERENCES 1. 2. 3. 4.

www.cseindia.org www.climatechangeindia.org Ghosh Sajal (1998), Sustainable energy policies for clean air in India. Straut A. Batterman, William O. Mattick, Lawrence I. Ranka, Environmental Performance of Passenger Vehicles. 5. Anderson, Frederick R. 1994, "From voluntary to regulatory pollution prevention" in: The Greening of Industrial Ecosystems, NAS. 6. *Anand Sita (2001), Comparative Study of Air Pollution for Delhi City with Pollutant Source Apportionment (Dissertation project). 7. Indian Standards, Environmental Management- Life Cycle Assessment- Principles and Framework (IS/ISO- 14040:1997)

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1721

ENERGY SAVING IN ENERGY SECTOR OF THE REPUBLIC OF KARELIA (NORTH-WEST RUSSIA)

S. Y. Kulagin JSC Proconsul, 26a-83, Parhomenko st, Petrozavodsk, Karelia, 185007, Russia

ABSTRACT The paper presents the status of energy saving activities in Karelia. It gives a short description of the main players and key figures in the energy sector and estimates the potential of CO2 emission reduction. There is analysis of the problems in the energy sector and reasons for high emission of greenhouse gases. These are mainly a results of: old and depreciated technology equipment, low investment activity, and unattractive terms for energy conservation. Local government makes attempts to change the situation, approves new energy saving laws, creates the special programs, and tries to improve the environment. An energy audit of energy consumers shows ways to prevent CO2 contamination via energy savings. These ways are as follows: use of local energy sources (wood chips, hydropower and windpower), automation of combustion process at boilerhouses and CHP plants, modernization of small inefficient boilerhouses, application of engine frequency control, etc. The last part of the paper presents the World Bank project in Petrozavodsk.

INTRODUCTION The Republic of Karelia is located in the North-West of the Russian Federation and has a border with Finland. The total area is 172.4 thousand sq. km. The population is 770,000 people. The power system of the Republic of Karelia is part of the North-West Power Pool of Russia. The governmental Regional Energy Commission is responsible for energy policy and strategy in the region. JSC "Karelenergo", the main regional energy producing company, provides heat and power to large industrial consumers as well as to local municipal distributing units. At the municipal level, there are 18 local power grid units, 4 district heating network enterprises and 6 combined heat and power distributing companies. The electricity balance of the Republic of Karelia in 2000 is shown below.

TABLE 1 ELECTRICITYBALANCEOF KARELIA

Total electricity consumption Internal electricity production incl: hydropower combined heat and power Electricity supply from outside

mill kWh 7643.8 4334.4 2949.4 1385.0 3309.4

1722 Power is produced mainly at 5 Combined Heat and Power plants and 19 hydropower stations, which belong to JSC "Karelenergo" and industrial enterprises. The total installed electricity capacity is 1063,8 MWh. Heat is produced at the above mentioned CHP plants and 619 boilerhouses. Owners of the boilerhouses are mainly local municipalities. The total heat capacity is 6517,7 MWh. Domestic fuels for heating (peat and biofuel) are used restrictedly. Heavy fuel oil and coal are imported from other regions of Russia. Only since 1997 has gas been used as a fuel for power and heat production in Karelia. Fuels used for energy production in 2000 are shown in Table 2. TABLE 2 USE OF DIFFERENTFUELSIN KARELIA MTOE 1.238 0.442 0.380 0.385 0.231 0.087

Fuel Heavy fuel oil Natural gas Coal Diesel oil Biofuel Other

According to the federal antimonopoly legislation, the governmental Regional Energy Commission approved electricity and heat tariffs for JSC "Karelenergo" as follow in Table3.

TABLE 3 ELECTRICITYTARIFFSOF THE JSC "KARELENERGO" Type of consumer Industrial consumers bigger then 750 kVA Basic charge for capacity, rur/MW/month Charge for electricity, rur/MWh Industrial consumers less then 750 kVA, rur/MWh Agricultural consumers, rur/MWh Electric transport, rur/MWh Municipal distributing units, rur/MWh

1999

2000

2001

2002

163 180 80 330

200 000 100 408

274 300 170 627

337 315 380 840

182 190 80

225 225 104-188

391 462 160-254

653 653 209-402

The energy saving potential in heating and domestic hot water supply [1] is estimated as 30-40% of the existing consumption. Energy saving of 25-30% could be reached in industry sector. ENERGY SAVING IN KARELIA Problems o f Karelian energy sector and reasons for high emission of C02 An energy audit of industrial enterprises in Karelia reveals the following reasons for high energy consumption: • use of old and depreciated technology equipment • shortage of the heatmeters and adjustment equipment • lack of the skilled energy managers • lack of the motivation of the employees for energy conservation There is low investment activity in Karelia because of the relatively low energy tariffs and non-stable economic situation in Russia as whole. In spite of growing tariffs, last year's payback periods for energy efficiency projects were mainly longer than 8 years. Foreign and domestic investors could not start long term business under non-stable and unpredictable economic conditions. It is impossible for foreign investors who

1723 act in Karelia to get federal government guarantees for investment return and it is rather difficult to get local government guarantees. The City budget has to cover 40% of heat tariffs for people, hence there is no motivation for them to save heat in residential houses. State-owned and municipal organizations are not interested in energy conservation, i.e. their budget will be cut off if they save energy. Transport of imported fuels cause additional losses as well as emissions of CO2. High customs duties and VAT for machine imports impede foreign co-operation in the energy sector in Karelia. Often, it is more attractive to buy rather cheap, but not efficient, domestic equipment than to get modem ones from abroad, because it is necessary to pay 20% VAT and in average 15% customs dutes on board. Some times it is impossible to use foreign equipment directly due to different existing technical solutions; for example, the so-called "open" district heating system in Petrozavodsk differs from European. In the "open" system, hot water from CHP plants comes directly to an inside heating system of the buildings, but there is no transfer of heat through a heat-exchanger at the heating substation. Besides, injectors are used for mixing and circulating heating water inside the buildings, but not pumps. Therefore, in this case we must provide indirect costs to adapt foreign equipment to Russian heating systems. See Figure 1 for a scheme of building's heating substation in the "open" district heating system in Petrozavodsk. _~

To hot water supply system

4

Outside district heating network

Inside heating system

3

[ ~

[~

1.Injector 2.Regulator

~---

'~....

Return of circulating hot water

3.Armature 4.Measuring units

Figure 1: Typical heat substation in Petrozavodsk Local government energy conservation policy, existing law and program The local government supports energy conservation in Karelia. An energy saving local law which was approved in February 22, 1998 by the chairman of the Government of the Republic of Karelia foresees: • participation of the governmental structures in Energy Conservation Program creation, consideration and proving • providing of the obligatory energy audit of largest energy consumers in Karelia • compulsory installation of the heat and electricity meters in new and reconstructed buildings • foundation of the Regional Energy Conservation Fund • privileges and incentives for institutions participating in energy saving • penalties for organizations which use energy resources inefficiently • training of the energy managers

1724 • informational support for energy saving activities. In 1997, an Energy Conservation Program for 1997 - 2000 was created. It was planned, through energy savings, to decrease CO2 emissions in the Republic by 3.06 mt. In fact, the result [2] reached only 26% of the level planned. Now, a new Program is under consideration for 2002 - 2005, and the previous mistakes will be taken into account.

Possibilities for improvement of the present C02 emissions situations There are several ways to improve present CO2 emissions situations via energy savings: • right tariff policy providing • use of local energy sources (wood chips, peat and windpower) • construction of new hydropower plants and reconstructing of the old one • extension of existing CHP plants • automation of the combustion process at boilerhouses and CHP plants • transferring ofboilerhouses from oil- and coal-firing to gas-firing • modernization of small inefficient boilerhouses • application of engine frequency control • heatmeters installation • preinsulated pipes application JSC "Karelenergo" plans to construct 4 new hydropower plants with 617 MW total installed capacity. Just this substitution of oil energy resources for environmentally-friendly hydropower will decrease CO2 emissions by 446.5 thousand tones. Three industrial enterprises in Petrozavodsk will convert their boilerhouses from oil to gas in the near future. This measure will prevent emission of 85 thousand tonnes of C02.

World Bank energy saving project in Petrozavodsk The loan sum of the World Bank project is 23.5 mln USD. 7.7 mill USD has been used so far. The implementation period is 1996 - 2003. The loan return period is 10 years after completion of the project. The following works were carried out under the frame of the WB Project: • installation of heat and water meters in 47 buildings • implementation of energy saving measures in 47 buildings • construction of two 1.5 and 6 MW modem boilerhouses The local administration plans to implement energy saving measures in 67 buildings during this year and in 87 buildings next year. The German Company AAB with Russian "Neftegazstroy" are responsible for implementation of the energy saving measures in 67 buildings in 2002. The energy audit has to be done before implementation of energy saving measures. Mainly, the measures are the following: • insulation of the roof, basement, outside walls, pipes • sealing and replacing of the doors, windows • fixing and renovations of pipes, armatures, radiators • installation of modem heat substations with control equipment • mounting of the thermostatic valves, radiator's reflecting pannels • using of the water saving shower heads • balancing of the inside heating system • reconstruction of the ventilation system When the whole project is implemented, there will be saving of 73 MWh heat energy and decrease of CO2 emissions by 43 tones per year. REFERENCES 1. Finnish Energy Conservation Group. (1993). Energy Master Plan for Karelia, Report. Helsinki. Finland. 2. Energonadzor. (2001). Analytical Report. Petrozavodsk. Russia.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1725

R E D U C I N G G R E E N H O U S E EMISSIONS BY I N H E R E N T L Y SAFE N U C L E A R R E A C T O R S A R Kenny Energy Research Institute, Department of Mechanical Engineering, University of Cape Town, South Africa

ABSTRACT

Nuclear power provides a large scale source of electricity with no greenhouse emissions during operation and minimal amounts during construction, fuel preparation and decommissioning. Moreover, nuclear power has an unrivalled safety record in the West. The disadvantages of nuclear power at present are poor public perceptions and high capital costs because existing designs need elaborate safety systems. A new generation of simple and small reactors offers inherent safety, where safety is built into the design, so dispensing with the expensive safety systems and greatly reducing costs. One of these is the South African Pebble Bed Modular Reactor (PBMR). This is a small reactor (about 120 MWe), with helium coolant, graphite moderator and fuel in the form of uranium oxide pellets embedded in carbon spheres ("pebbles"). It operates in a Brayton cycle where the heated gas from the reactor drives a gas turbine. It has low power density and passive or inherent safety. No human error or equipment failure can cause an accident that endangers the public.

INTRODUCTION

Nuclear power has been in operation for 45 years and now provides 17% of the world's electricity. Its safety record has been outstanding. The worst ever nuclear power station accident in the West, at Three Mile Island in the USA in 1979, killed no one, injured no one and had no ill health effects. By contrast, accidents in oil, gas, coal and hydro-power that kill tens or evens hundreds of people are common.[1] The Chernobyl accident in the USSR was caused secondarily by the operators violating procedures but primarily by bad reactor design which would never be allowed in the West. Nuclear radioactive waste is small, solid, stable, of finite life and technically easy to dispose of safely. By contrast coal waste is massively larger in mass and lasts much longer. It includes sulphur and nitrogen gaseous compounds, organic compounds, heavy metal toxins such as arsenic which last forever and radioactive substances such as thorium with half-lives of billions of years. Coal waste is hurled into the air we breathe or dumped onto huge open tips. In operation, nuclear power releases no greenhouse gases. Over its complete life, including mining of the uranium, fuel enriching, fuel preparation, operations and decommissioning, nuclear power releases among the lowest of any generating technologies, including solar, wind and hydro-power. Figure 1 shows the range of greenhouse emissions for various electricity generation technologies over the full life cycle of each. The units are grams of carbon equivalent per kilowatt-hour of electricity generated. The figures come from numerous studies of varying examples of each type of generation

1726 i l l

Lignite

Ill

Coal

/I

Oil Nat gas

I i

Solar PV Hydro Biomass

!

Wind Nuclear 0

100

200

300 400 gCeq I kWh

500

600

700

Figure 1: Greenhouse Gas Emissions for Different Electricity Generation Technologies. [2] However, public perceptions about nuclear power are poor. A second problem is that in existing designs capital costs of nuclear reactors are high. This is because they require complicated active safety systems which are expensive to make. They also require long lead times for construction and licensing which adds severely to costs. The most popular nuclear power reactors around the world use pressurised water as the coolant and normal water as the moderator. These are the Pressurised Water Reactors (PWRs), which provide 58% of world nuclear power capacity, and the Boiling Water Reactors (BWRs), which provide 20% [3] Both use large units (typically 400 MWe or larger) and have high power density (50 to 60 kW/litre). In both there is a measure of passive safety but this must be supplemented with elaborate, active safety mechanisms, such as water injection systems for cooling There are two types of dangerous nuclear reactor accidents. The first is an uncontrolled rise in reactivity. This is what happened at Chemobyl. The second is a failure to remove decay heat before the fuel elements are damaged. This is what happened at Three Mile Island. In the ideal nuclear power reactor, neither danger would exist. The PBMR is just such a reactor.

SOUTH AFRICA'S PEBBLE BED MODULAR R E A C T O R (PBMR) South Africa is now developing a PBMR nuclear reactor. It is based on the German AVR, a 15 MWe demonstration pebble bed reactor which ran successfully for 21 years. The PBMR will keep the same reactor design as the AVR but will use a gas turbine to drive the generator. The huge, proven advantages of the AVR were twofold. First, the reactor physics were such that you had a large negative temperature coefficient of reactivity at all power levels. This made it impossible to have runaway reactivity, as happened at Chemobyl. Second, the low power density and the large ratio of surface area to mass prevented the fuel from reaching temperatures which would damage it. Both of these advantages have been retained in the PBMR. The PBMR design is for a unit of about 120 MWe. The coolant will be helium, which will leave the reactor at about 900°C and 7 MPa. Helium is inert chemically and radiologically. The moderator will be graphite. The fuel will be pellets of uranium oxide enriched to about 8%. The fuel pellets will be embedded in

1727 graphite sphere or "pebbles" about 50 mm in diameter. The reactor core will contain about 380,000 fuel pebbles with an additional 150,000 pure graphite pebbles for additional moderation. The reactor vessel is steel. After leaving the reactor, the gas will pass through two turbo-compressors, the power turbine, a recuperator, an intercooler and then two turbo-compressors before returning to the reactor. Much of the heat is recuperated to raise thermal efficiency. The design keeps a low temperature gradient across walls bearing high pressure. The outline of the PBMR unit is shown in Figure 2 below.

Reactor Vessel Fuel "Pebbles" Turbogenerator Fuel Handling System

Turbo comoressors

Bvoass Valve

Intercooler

Recuoerator Intercooler

Figure 2: Helium Flow Path through PBMR The reactor will always run at the same temperature, about 1100°C, regardless of load. This is maintained naturally by the Doppler Effect in the fuel. The reactor is load following. Short term control comes from altering the angle of the stationary turbine blades. Long term control comes from adding or subtracting from the helium mass in the circuit (increasing or decreasing the helium pressure). This is done by injecting from or ejecting into helium tanks at various pressures. The control rods are merely trim devices, to adjust to the state of the fuel. The fuel pellets are about 1 mm in diameter. Each consists of a core of enriched uranium oxide surrounded by layers of pyrolytic carbon and silicon carbide. These layers seal in the radionuclides and can withstand high temperatures. Each fuel pebble contains 15,000 fuel pellets. Rigorous testing has shown that the fuel pebbles do not suffer any damage at temperatures below 1600°C. Above that the damage increases incrementally with time and temperature. Even in the case of the worst accident, with complete loss of coolant, the temperature of the fuel will never exceed 1400°C. Radiant heat, removed naturally because of the large ratio of surface area to mass, will ensure this. Once introduced into the circuit, pebbles can never be removed for the life of the plant. During operation, each one is automatically and periodically sampled. If it is spent, it is sent to a waste fuel tank. If not, it is returned to the reactor. Because of the very tough barriers around each fuel pellet, spent fuel is better contained than fuel from a PWR and is even more difficult to reprocess into fissile material. Table 1 summarises some of the characteristics of the PBMR. [4]

1728 TABLE 1 SOME CHARACTERISTICS OF THE PBMR NUCLEAR REACTOR Unit size Coolant/moderator/fuel Max gas temp / pressure Power density Thermal cycle Safety Control

Expected efficiency Refueling Waste disposal Bum-up Building size Capital costs Electricity costs Construction time Life

about 120 MWe. Helium / graphite/uranium oxide enriched to 8%. 900°C / 7 MPa about 6 kW / litre. Brayton cycle (gas turbine). Passive or inherent. No active safety systems. Constant reactor temperature maintained by Doppler. Short term control by angle of stationary turbine blades. Long term control by changing helium mass in circuit. Control rods are adjusted to state of fuel. Above 40%. On-line. Fuel pebbles are automatically sampled, rejected to a waste tank or returned to the reactor. Fresh pebbles are added when necessary. Spent fuel never leaves the unit until the end of plant's life. 80,000 megawatt days per ton of uranium metal. 59 x 36 x 57 high metres for one unit (half of height underground). Aiming for USA $1000/kW. Aimin~ for less than 3 USA cents / kWh. 24 months. 40 years.

The small size of the reactor and the short construction time will allow power utilities flexible planning for increasing their capacity. The simplicity and inherent safety will make licensing easier and quicker. The units are modular and can be stacked together in batteries to provide large amounts of generating capacity. In South Africa the Environmental Impact Assessment for the PBMR has been completed. If the National Nuclear Regulator and the Department, of Environmental Affair approve, the PBMR Company will be free to build the first PBMR. If it so chooses, construction is likely to begin by about 2005.

A Clean, Safe, Reliable Source o f Electricity which can Greatly Reduce Greenhouse Emissions The PBMR is one of a new generation of proposed nuclear reactors which can provide clean, safe, reliable, economic electricity with no greenhouse gas emissions in operation and few in construction, fuel preparation and decommissioning. The PBMR, because of its small unit size and quick construction time, is well suited to a de-regulated electricity market. It will find wide application in rich and poor countries. In a world where the demand for more electricity generating capacity is growing, the PBMR can meet such demand without adding to the greenhouse gases in our atmosphere.

REFERENCES 1. Hirschberg, S., Spikerman, G. and Dones, R. Severe Accidents in the Energy Sector. Paul Scherrer Institut. PSI Bericht Nr.98-16 2. Spadaro, J.V., Langlois, L. and Hamilton. Greenhouse Gas Emissions of Different Electricity Generating Chains. International Atomic Energy Agency. 3. Nuclear News. March 2002. 4. Plant details from the PBMR Company.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1729

INTEGRATED CARBONATION: A NOVEL CONCEPT TO DEVELOP A COz SEQUESTRATION MODULE FOR POWER PLANTS M. Mercedes Maroto-Valer, Matthew E. Kuchta, Yinzhi Zhang and John M. Andrrsen The Energy Institute and Dept. Energy & Geo-Environmental Engineering, The Pennsylvania State University, 405 Academic Activities Bldg., University Park, PA 16802. e-mail: [email protected]

ABSTRACT

Mineral carbonation has been proposed as a promising CO2 sequestration technology, and serpentine minerals have been identified as suitable feedstocks for mineral carbonation. However, current mineral carbonation studies using serpentine minerals require pulverization of the raw minerals, long reaction times and extremely high partial pressures. Consequently, mineral carbonation will only become a viable costeffective sequestration technology through innovative development of fast reaction routes under milder regimes in a continuous process. The work reported here focuses on surface activation studies of serpentine minerals to accelerate the carbonation reaction efficiency. The work presented has shown that it is possible to increase the surface area of the serpentine minerals to -~330m2/g, compared to only ---8m2/g for the raw serpentine. The SEM studies show that the structure of the activated serpentines has been significantly altered. The TGAs profile for the activated serpentines, particularly the physically activated sample, show significantly smaller weight loss than the parent untreated sample (3wt% vs. 15 wt%).

INTRODUCTION

Anthropogenic emissions have increased the CO2 concentrations in the atmosphere with over 30% compared to preindustrial levels [1]. Furthermore, it is estimated that future global CO2 emissions will increase from ---7.4 GtC (billion tons of atmospheric carbon)/year in 1997 up to - 26 GtC/year in 2100 [2]. Although there is a passionate debate regarding the impact of increasing CO2 emissions on global climate change and global warming, there is a general agreement in the scientific community that doubling the CO2 emissions will have a serious detrimental effect on the environment. Most of these anthropogenic emissions are caused by fossil fuel utilization, where around one third of these emissions is due to electricity generation from fossil fuel combustion [3]. Furthermore, fossil fuel electricity generation units rank as the first target to reduce anthropogenic emissions due to their stationary nature. Mineral carbonation, that involves the reaction of CO2 with non-carbonate minerals to form stable mineral carbonates, is a promising CO2 sequestration technology [4-6]. This is due to the vast natural abundance of the raw minerals, the long term stability of the mineral carbonates formed, and the overall process being exothermic, and therefore, potentially economic viable. However, carbonation efficiency is being considered a major hurdle for the development of economically viable sequestration technologies, where present studies require extensive mineral particle communition (<75 ktm), high pressures (>115 atm) and prior capture of the CO2. Accordingly, this work focuses on the development of an active carbonation process that can promote and accelerate reaction rates and efficiencies through surface activation to the

1730 extent that extensive mineral particle communition and CO2 capture from flue gases are not required prior to sequestration [7]. Serpentine, a magnesium-rich mineral, was used for this study as carbonation feedstock material. The minerals were chemically and physically activated to increase their surface area. N2 and CO2 adsorption isotherms, SEM, and TGA studies were conducted to characterize the properties of the samples prior and after treatment.

BODY OF PAPER

Experimental Surface activation studies were conducted on a serpentine sample to promote its inherent carbonation reactivity. The physical activations were performed using steam, while the chemical activations utilized various acids at room temperature over a time period of-~24 hours. A Quantachrome Autosorb-1 Model ASIT adsorption apparatus was used to characterize the surface area and porosity of the samples, where adsorption isotherms were conducted under N2 and CO2 at 77K and 273K, respectively. The SEM studies were conducted using a HITACHI S-3500N, where the accelerating voltage was 20KV and magnification was 1500X. The raw and activated serpentine samples were characterized by thermogravimetric analyses (TGA) to evaluate their weight loss upon heat treatment. TGA profiles under N2 and CO2 were obtained using a Perkin Elmer TGA 7 at atmospheric pressure in the temperature range of 25°C to 900°C with a constant heating rate of 10°C/minute.

Results and Discussion

Adsorption isotherms (N2-77K) conducted on the raw and treated serpentine samples showed that the adsorbed volume increases significantly for the activated samples compared to that of the raw serpentine sample, indicating that the activation process has increased the porosity of the activated samples. Table 1 lists the BET surface area, pore volume and average pore size for the raw serpentine and its activated counterparts. The BET surface area went up at least one order of magnitude up to -~330m2/g for the activated serpentines, compared to only---8m2/g for the raw material. The chemical activation seems to be more effective than the physical activation in terms of increasing the surface area. The pore volume shows a similar trend, where the activation increases the pore volume to values up to 0.234 mug compared to only 0.017 mug for the parent untreated sample (Table 1). The pore diameter of the chemically activated samples is smaller than the parent serpentine, particularly for the chemically activated samples, whose diameter is only 2.8 nm compared to 8.5 nm for the parent sample.

TABLE 1 BET SURFACE AREA, PORE VOLUME AND AVERAGE PORE SIZE OF THE SAMPLES

Sample Untreated--

BET surface area m2/g

Pore Volume

Average Pore Diameter

mug

nln

8.5

8.2

0.017

Steam Treated

15,8

0.035

8.8

Acid-1 Treated

329.5

0.234

2.8

Acid-2 Treated

79.5

0.085

4.3

CO2 adsorption isotherms at 277K were also conducted on one of the activated serpentine samples and the raw Saml~le, and the Langmuir reported surface area of the activated serpentine was 242m2/g, compared to only 9m'/g for the raw sample. Therefore, compared to the raw serpentine, the chemically activated samples have developed significant microposity.

1731 Figure 1 shows the SEM pictures of the raw and one of the chemically activated serpentines. The SEM studies show that at the same magnification level, the activated sample presents more needle-like particles than the raw material. Images taken at greater magnification level showed that the structure of the activated serpentine had been significantly altered.

Figure 1: SEM images of the raw (left) and chemically activated (fight) serpentine samples.

Thermogravimetric analysis in N2 and CO2 were also conducted on the parent serpentine and its activated counterparts, and Figure 2 shows the TGA profiles in N2. The parent serpentine lost around 15wt%, where this weight loss can be attributed to the removal of hydroxyl groups that are known to inhibit the carbonation reaction by occupying active sites on the mineral surface [6]. In contrast, the chemically activated samples lost -1 l wt%, and their weight loss is shifted to higher temperatures indicating that the activation process acted selectively removing low-temperature (< 600°C) hydroxyl groups. The TGA profile of the steam activated sample shows that most of the water has been removed during the high temperature activation (Figure 2), and its weight loss is only-3%. Therefore, physical activation is more effective than chemical activation in terms of removing the weight loss.

100 98 96 94 92

- - A c i d l Treated 88

Acid-2 Treated Steam Treated

0

I00

200

300

400

500

600

700

800

Temperature, °C

Figure 2:N2 TGA profile of the raw and activated serpentines.

1732 ICP and X-ray diffraction results are being conducted to confirm the constituents of the mineral that were removed during the activation process. Results on carbonation experiments using the activated serpentines will also be presented.

CONCLUSIONS

Serpentine minerals have been identified as suitable feedstocks for mineral carbonation, which involves the reaction of CO2 with non-carbonate minerals to form stable mineral carbonates. However, current studies require pulverization of the minerals, high partial pressures, prior separation of CO2 from flue gases, and long reaction times - all energy intensive operations. By activating the raw minerals to accelerate the carbonation reaction efficiency, these obstacles may be overcome. The work presented here has shown that it is possible to increase the surface area of the serpentine minerals to 330m2/g, compared to only -8m2/g for the raw serpentine. Chemical activation seems to be the preferred method to increase the surface area, while physical activation is the preferred method to reduce the weigh loss.

ACKNOWLEDGEMENTS

The authors wish to thank the Department of Energy, University Coal Research Program, and the Department of Energy and Geo-Environmental Engineering and the Energy Institute at Penn State University for supporting this work. The authors are also grateful to Y. Soong and D. Fauth from DOE/NETL and W. O'Connor from Albany Research Center for providing samples and helpful discussions.

REFERENCES

1. Keeling, C.D., and Whorf, T.P., Trends: A Compendium of Data on Global Change, Oak Ridge National Laboratory, 1998. 2. Houghton, J. T., Meira Filho, L.G., Collander, B.A., Harris, N., Kattenberg, A. and Makell, K., IPCC (Intergovernmental Panel on Climate Change) 1996. Climate Change 1995: The Science of Climate Change, Cambridge University Press, Cambridge, U.K., 1996. 3. Energy Information Agency, Emissions of Greenhouse Gases in the United States 2000, 2001, DOE/EIA0573(2000/ES) 4. Department of Energy, Office of Science, Office of Fossil Energy, US DOE Report: Carbon Sequestration: Research and Development, 1999. 5. Fauth, D.J., Baltrus, J.P., Knoer, J.P., Soong, Y., Howard, B.H., Graham, W.J., Maroto-Valer, M. M., Andrrsen, J.M., Conversion of Silicate Minerals with CO2 Producing Environmentally Benign and Stable Carbonates, Prepr. Syrup. Am. Chem. Soc., Div. Fuel Chem., 2001, 46(1), 278-279. 6. Fauth, D.J., Baltrus, J.P., Soong, Y., Knoer, J.P., Howard, B.H. Graham, W.J., Maroto-Valer, M.M. and Andrrsen, J.M., Carbori Storage and Sequestration as Mineral Carbonates, Chapter in "Environmental Challenges and Greenhouse Gas Control for Fossil Fuel Utilization in the 21st Century", Eds: MarotoValer, M.M., Soong, Y. and Song, C., 2002, In Press. 7. Maroto-Valer, M. M., Fauth, D. J., Kuchta, M. E., Zhang, Y. Andrrsen, J. M. and Soong, Y., Study of magnesium rich minerals as carbonation feedstock materials for CO2 sequestration, 18th Annual International Pittsburgh Coal Conference, 2001, Paper 23-01.pdf (CD-ROM publication).

ECONOMICS

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1735

E C O N O M I C S O F CO2 C A P T U R E F R O M A C O A L - F I R E D POWER PLANT - A SENSITIVITY ANALYSIS D. Singh l, E. Croiset l, P.L. Douglas 1 and M.A. Douglas 2 ~Department of Chemical Engineering, University of Waterloo, Waterloo, Ontario, Canada, N2L 3G 1 2CANMET Energy Technology Centre, Natural Resources Canada, 1 Haneel Dr., Nepean, Ontario, Canada, K1A 1M 1

ABSTRACT

The focus of this paper is on the economics of the capture of CO2 from an existing pulverized coal-fired power plant. Two configurations are considered: (1) CO2 capture from the flue gas using an amine-based absorption process and (2) O2/CO2 recycle combustion. At GHGT-5, we presented results pertaining to the integration and heat management of the CO2 capture processes into the overall plant. In this paper we present a sensitivity analysis on the cost of CO2 captured ($/tonne of CO2 avoided). In particular, we look at the effect of improvement in solvent performance and oxygen separation cost (O2/CO2 recycle case) on the overall cost of capturing CO2. The sensitivity analysis provides the economic benefits from possible cost reductions in the two CO2 capture technologies covered here. Preliminary results indicate that the O2/CO2 recycle combustion process offers greater potential savings over the use of amine scrubbing.

INTRODUCTION

Coal-fired power plants are regarded as major emitters of pollutants, in particular of carbon dioxide. However, because of cheap, large and widely distributed reserves, coal is still a very attractive fuel. Increasing the efficiency of the coal plant will contribute to the reduction in the emissions of CO2. But it is unlikely that increased efficiency alone is sufficient to significantly reduce CO2 emissions. A method to dramatically reduce the emissions of CO2 in the short to medium term is the capture and sequestration of CO2. In this paper, the retrofit of an existing pulverized coal-fired power plant for C02 capture is considered for two configurations: (1) CO2 capture using MEA absorption and (2) O2/CO2 recycle combustion. The basis of this work is a TransAlta power plant located in Alberta, Canada. This is a 400 MWe plant burning a sub-bituminous coal. The MEA absorption process, as applied to CO2 capture from flue gas has been described extensively in the literature [ 1,2,3,4,5,6]. Some articles have also been dedicated to 02/C02 recycle combustion [5,7,8]. When air leaks inside the system in the O2/CO2 case, the purity of CO2 captured would be at most 90%. Therefore, additional purification equipment, usually low temperature processes, would be required to reach higher CO2 purity. In this study, 02/C02 recycle

1736 combustion is combined with a low temperature flash (LTF) to achieve 98% CO2 purity [9]. Both the MEA process and the O2/CO2 recycle combustion require a significant amount of energy. There are several ways of supplying this additional energy; one possibility, for the MEA case, is to extract steam from the existing steam cycle, with the consequence of significantly reducing the output of the plant. An important constraint we imposed in this work was to maintain 400 MWe to the grid without modifying the existing steam cycle. To do so, the incremental energy to capture CO2 was supplied by natural gas-fired turbines and by natural gas boilers [7,9].

ECONOMIC

EVALUATION

Assumptions Key assumptions are as follows: -

-

-

-

All values are in 2001 USD. The main power plant is paid off (approximately 20 year old plant). 7% interest rate. 20 year project life. Assume the plant will be completely retired after 20 years. $0 salvage value. Assume that the assets of the plant and new equipment have no value at the end of their life. Cost of natural gas for auxiliary power units is $4.00/MMBtu. Operating and Maintenance (O&M) costs are 4 % of the capital investment. The plant operates for 8000 hours/year.

The main sources of information related to cost are vendor input (e.g. Air Liquide Canada for air separation unit), published sources (e.g. [6,10]) and Icarus Process Evaluator, an engineering sizing and costing software package. Note that in the case of published sources, the costs were converted into 2001 USD.

Summary of Annual Costs Due to the constraint in the size of the paper, only overall annual costs are presented here. They are shown in Table 1 for both MEA and O2/CO2 cases. TABLE 1 SUMMARYOF ANNUALCOSTS MEA Case Amortized capital cost (S/year) $ 27,775,116 (Total capital cost) $ 294,249,975 $ 28,246,531 Operating cost (S/year) Annual natural gas cost (S/year) $ 50,258,989 Total annual cost $ 106,280,636

$ $ $ $ $

O2/CO2 with LTF 29,855,736 316,292,097 13,599,325 32,978,153 76,433,214

From Table 1, it is worth mentioning the high costs of natural gas required to run the auxiliary power associated with CO2 capture. They represent 47% and 43% of the total annual cost in the case of MEA scrubbing and O2/CO2, respectively. Table 1 shows that both configurations result in very high annual cost. Yet, the O2/CO2 recycle combustion configuration is about 30% cheaper than the MEA case. The main difference between these two configurations resides mostly in the higher natural gas demand for the MEA case, as well as in the higher cost due to chemicals required in the MEA process (large part of the

1737 operating cost). These annual costs translate into $55/tonne of CO2 avoided and $35/tonne of CO2 avoided, for the MEA process and O2/CO2 recycle combustion, respectively.

SENSITIVITY ANALYSYS The sensitivity analysis has been performed on the oxygen cost for the O2/CO2 recycle combustion case and on the solvent performance for the MEA case. Solvent performance is associated with various aspects of the MEA scrubbing process, such as its resistance to degradation due to the presence of SO2. However, in the case of scrubbing CO2 from power plant flue gas, the most important parameter affecting the cost is the amount of energy required to regenerate the solvent in the stripper column. Therefore, the solvent performance is characterized here as the "kg of steam required per tonne of CO2 recovered". The amount of steam required is directly linked to the consumption of natural gas in the auxiliary power units. The result of the sensitivity analysis is shown in Figure 1. $60 i - - O2/CO2 --AMINE.]

$55 $50

~~'~

_~

,mprovementof 30O/o

$45

o m

® e-

Improvement t o ~ solvent performance

$40

~'~.~,,,~ $38

0 0

$35

.=3?

eo

$30 Reduction of 02 production costs

$25

.

$26

... $24

$20 0%

10%

20%

30% 40% % Improvement

50%

60%

Figure 1" Sensitivity analysis on solvent improvement and reduction of 02 costs. Chakma [ 11 ] states that amine solvent performance could be improved as much as 30% by the use of mixed solvents. An improvement of 30%, as indicated on Figure 1, would reduce the amine capture costs from $55/tonne of CO2 avoided to $45/tonne of CO2 avoided. However, even with 30% improvement in amine performance, the original O2/CO2 case is still less expensive.

CONCLUSION Both, amine scrubbing and O2/CO2 recycle combustion, are expensive processes to capture CO2 from an existing pulverized coal power plant. However, it appears that the O2/CO2 recycle combustion is less expensive than amine scrubbing for retrofitting an existing coalfired power plant. Note that this study has focused only on the implementation of CO2 capture process on an existing plant. The incremental cost for CO2 capture in the case of a

1738 new plant will probably be lower, especially in the case of the amine solvent where the energy required in the stripper is likely to be extracted from the plant steam cycle.

ACKNOWLDGEMENTS

Funding from the CANMET Energy Technology Center and its CO2 consortium is gratefully acknowledged.

REFERENCES

.

10. 11.

Riemer, P. (1993). The Capture of Carbon Dioxide From Fossil Fuel Fired Power Stations. IEA Greenhouse Gas R&D Programme, Report IEA/GHG/SR2, Cheltenham, England. Hendriks, C. (1994). Carbon Dioxide Removal From Coal-Fired Power Plants. Kluwer Academic Publishers. Dortecht, The Netherlands. Desideri, U. and Paolucci, A. (1999). Energy Convers. Mgmt. 40, 1899. Simbeck, D.R. and McDonald, M. (2000). In: Proceedings of the Fifth Conference on Greenhouse Gas Control Technologies (GHGT-5), pp. 103-108, Cairns, Australia. Nsakala, N., Marion, J., Guha, M., Plasynski, S., Johnson, H. and Gupta, J. (2001). In: Proceedings of the First Conference on Carbon Sequestration, Washington D.C., USA. Simbeck, D.R. (2001). In: Proceedings of the First Conference on Carbon Sequestration, Washington D.C., USA. Singh, D., Croiset, E., Douglas, P.L., Feng, X., Douglas, M.A., Kilpatrick, D-J. and Thambimuthu, K. (2000). In: Proceedings of the Fifth Conference on Greenhouse Gas Control Technologies (GHGT-5), pp. 109-114, Cairns, Australia. Wilkinson, M.B., Boden, J.C., Panesar, R.S. and Allam, R.J., In: Proceedings of the Fifth Conference on Greenhouse Gas Control Technologies (GHGT-5), pp. 179-184, Cairns, Australia. Singh, D. (2001). Ph.D. Thesis, University of Waterloo, Canada. Mariz, C.L., Ward, L., Ganong, G., Hargrance, R. (1998). In: Proceedings of the Fourth Conference on Greenhouse Gas Control Technologies (GHGT-4), pp. 229234, Interlaken, Switzerland. Chakma, A. (1997). Energy Convers. Mgmt. 38(S- 1), 51.

ENERGY MODELLING

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1741

MODELLING CLIMATE CHANGE AND POPULATION GROWTH ON GHG EMISSIONS FROM THE ENERGY SECTOR IN THE TORONTO-NIAGRA REGION, CANADA Q. G. Lin 1, B. Bass 2, and G. H. Huang 3 l, 3-EVSE_ Faculty of Engineering, University of Regina, Regina, SK $4S 0A2, Canada 2- Institute for Environmental Studies, University of Toronto, Toronto, ON M5S 3E8, Canada

ABSTRACT

Climate change will affect the greenhouse gas (GHG) emissions by affecting energy consumption. Population growth, on the other hand, will increase GHG emissions in the absence of new technologies or an emissions reduction policy: This study uses the MARKAL model to evaluate the impacts on energy demand and the associated GHG emissions caused by variations of temperature and population in the Toronto-Niagara Region (TNR) from 1998 to 2032. One Business as Usual (BAU) case and three scenarios are developed and analyzed. The BAU case models the energy system and GHG emissions based on extrapolations from the current level of social and economic development. The first scenario reflects variations of GHG emissions level in response to a mean temperature change. Scenario 2 incorporates population growth into scenario 1. Scenario 3 combines population growth with changes in the summer maximum temperature and the winter minimum temperature rather than mean temperature.

INTRODUCTION

Most of the recent increase of GHG emissions can be attributed to the anthropogenic activities associated with the consumption of energy. It is recognized that variations in temperature will affect energy consumption and hence GHG emissions associated with this behaviour. When the air temperature rises, the energy demand for space heating in winter decreases while the demand for air conditioning (A/C) and refrigeration increases during the summer. Population growth will also increase GHG emissions in the absence of new technologies or a reduction policy. During the period 1981-1996, the TNR has experienced a substantial growth in population. From 1996 to 2001, the annual net population growth in TNR was 1.2%. This research explores the impacts of increasing temperatures and population on GHG emissions in the Toronto-Niagara Region (TNR) a small, but economically important region in Canada.

1742 T N R M A R K A L M O D E L and A P P L I C A T I O N

MARKAL is a cost-minimizing, energy-environment system-planning model used to explore long-term responses to emissions limitations, climate and socio-economic policy scenarios. The GHG emissions are integrated into the system as the coefficient of the energy resources and technologies. The TNR MARKAL model is developed with a time horizon from 1988 to 2032 in 5 year periods with each period referred by its midpoint. The energy demand sector is categorized into four blocks: residential, commercial, industrial, and transportation. Space heating and cooling consume most of the demand in the residential and commercial sectors, including industrial space heating, which is attributed to commercial sector. Population growth affects the energy consumption of the entire sector of transportation, residential and commercial. It is assumed that in the absence of other changes, energy consumption increases at the same rate as population growth, which is 1.2% annually from 1996 to 2001. A business as usual (BAU) case is used as a reference from which to compare the impacts of climate change, population growth and the Kyoto targets on GHG emissions from the energy sector in the TNR. The output of the Canadian Climate Centre General Circulation Model (CGM1), obtained from the Canadian Climate Impacts Scenarios (CCIS), is used to develop the increase in the mean temperature in scenarios 1 and 2 and the increasing maximum temperature and minimum temperature in scenario 3.

RESULTS AND DISCUSSIONS GHG Emissions in the Business as Usual (BA U) Case

In the BAU case, the GHG emission can be generated in any sector of the model with the energy supply and consumption chain which is 92.77 million tones of CO2 equivalent in 1990. Electricity generation accounts for 28% of the emissions, or 25.98 million tones in amount. Refineries contribute 6.8 % of the total emissions or 6.30 million tones. The remaining is attributed to the end-use demand sector. Residential consumption accounts for 9.8%, or 9.13 million tones. The commercial sector is responsible for 5.3%, or 4.89 million tones. Industrial consumption contributes 25.6% of emissions, which is only less than those from electricity sector, while transportation consumption accounts for 24.5%, or 22.71 million tones. Emissions from crude and gas production are too small to be considered in this study.

Scenarios: Impacts of Temperature and Population Growth In scenario 1, the total GHG emissions changes are different in each period because the increase in temperature is not constant throughout the 45 year time frame. While the emissions of electricity increase in all time periods due to the increased demand by air conditioning and refrigeration in residential and commercial sector, it is partly offset by the decreased demand for space heating in the winter. In period 2010, the emissions increase only 1.03 million tones and 0.62 million tones in period 2030. Emissions from the residential and commercial sectors decrease in each time period after 2010. In period 2010, the emissions from the residential and commercial sectors decrease by 0.42 and 0.33 million tones, respectively. And in period 2030 they decrease by 0.72 and 0.74 million tones. Population growth is considered together with the mean temperature increase in scenario 2. Unlike the impacts of mean temperature alone, population growth affects emissions from

1743

not only the residential and commercial sectors, but from the transportation sector as well. In this scenario, total emissions increase in comparison to the BAU case from period 2010 to 2025, by 1.25 million tones in 2010 and 0.81 million tones in period 2025. In period 2030, emissions actually decrease by 0.2 million tones but are still higher than those in scenario 1. The emissions of electricity increase 5.1% in period 2010 and 1.6% in period 2030. Emissions from residential and commercial consumption decrease due to reduced fuel consumption in the winter, while those from transportation increase 1.2% in response to population growth. Recognizing the role of minimum and maximum temperatures in driving the demand for space heating in winter and cooling in summer, scenario 3 reflects these changes in combination with population growth. Total emissions of each period are higher than those in the BAU case from period 2010 and those in scenario 2 with exception of period 2020 due to the decreased emissions from electricity. Comparing the BAU case and the other scenarios with scenario 3, the emissions of electricity increase with the exception of period 2020, which is much higher than that in BAU case but a little bit lower than those in scenario 2. In period 2020, the emissions of electricity in scenario 3 are 33.20 million tones while they are 34.55 and 31.76 million tones in scenario 2 and the BAU case, respectively. Similarly, emissions from the residential and commercial sectors in scenario 3 are higher than those in BAU case but less than those in scenario 2. Emissions from transportation still increase by 1.2% over the BAU case in response to the increased population. (Table 1) TABLE 1

GHG EMISSIONS BY SOURCE IN 1998-2032 (Million Tonnes) Time Total Scenario 1 Scenario 2 Scenario 3 Electricity Scenario 1 Scenario 2 Scenario 3 Refinery Scenario 1,2,3 Residential Scenario 1 Scenario 2 Scenario 3 Commercial Scenario 1 Scenario 2 Scenario 3 Industry Scenario 1,2,3 Transportation Scenario 1 Scenario 2 Scenario 3

1990 92.77 92.77 92.77 92.77 25.98 25.98 25.98 25.98 6.30 6.30 9.13 9.13 9.13 9.13 4.89 4.89 4.89 4.89 23.74 23.74 22.71 22.71 22.71 22.71

1995 89.87 89.87 89.87 89.87 20.21 20.21 20.21 20.21 6.30 6.30 10.11 10.11 10.11 10.11 5.38 5.38 5.38 5.38 23.62 23.62 24.22 24.22 24.22 24.22

2000 96.34 96.34 96.34 96.34 23.06 23.06 23.06 23.06 6.30 6.30 10.26 10.26 10.26 10.26 5.82 5.82 5.82 5.82 25.35 25.35 25.54 25.54 25.54 25.54

2005 101.31 101.31 101.31 101.31 26.07 26.07 26.07 26.07 6.30 6.30 10.09 10.09 10.09 10.09 6.27 6.27 6.27 6.27 25.79 25.79 26.76 26.76 26.76 26.76

2010 107.57 107.55 108.82 110.15 28.78 29.51 30.25 31.30 6.30 6.30 10.17 9.75 9.86 10.02 6.67 6.34 6.42 6.54 27.32 27.32 28.33 28.33 28.67 28.67

2015 115.40 115.19 116.54 116.80 32.36 33.35 34.13 34.32 6.30 6.30 10.45 9.79 9.91 9.95 7.16 6.62 6.70 6.73 28.54 28.54 30.59 30.59 30.96 30.96

2020 118.66 119.01 120.50 119.69 31.76 33.73 34.55 33.20 6.30 6.30 10.82 9.96 10.07 10.36 7.68 6.93 7.02 7.27 29.74 29.74 32.36 32.36 32.82 32.82

2025 124.94 124.31 125.75 126.32 35.74 36.34 37.18 37.46 6.30 6.30 10.84 10.20 10.32 10.47 8.21 7.60 7.70 7.83 30.81 30.81 33.05 33.05 33.45 33.45

2030 131.59 130.75 131.39 131.72 39.84 40.46 40.48 40.48 6.30 6.30 10.99 10.27 10.39 10.55 8.80 8.06 8.15 8.32 31.91 31.91 33.76 33.76 34.16 34.16

total 4892.22 4885.41 4916.39 4924.77 1318.97 1343.51 1359.52 1360.37 283.30 283.30 464.25 447.72 450.71 454.69 304.36 289.52 291.66 295.21 1234.17 1234.17 1286.66 1286.66 1296.50 1296.50

CONCLUSIONS In the period 2008-2012, the total emissions will decrease 2% with mean temperature increase, and will decrease 1.5% if population growth is included. Replacing the mean temperature with maximum and minimum ones, it will decline 0.7% from the BAU case.

1744 In the electricity sector, the most obvious impacts will be on coal-fired capacities. With an increase in the mean temperature, emissions from coal-fired capacities will increase 0.7% in the period 2008-2012 and increase 1.5% when population growth is included in the simulation. The variations of the impacts between mean temperature and maximum/minimum temperature are not significant. Some other important and interesting factors that will be considered in future research include: 1. The impacts of other climate variables such as humidity, precipitation and extreme events. Fore example, when precipitation declines, the fluctuation in water levels will be reflected in the generation of hydro-electricity. 2. In this model, the increased demands in summer cooling will be offset by the decreased demands in winter heating since the demands are considered in whole year. Thus, the peak power generation and demand can not be reflected and the impacts on associated GHG emissions may be underestimated. 3. Forecasting energy price is fraught with difficulties and uncertainties. To analyze the uncertainties, it is necessary to modify the model to incorporate stochastic, fuzzy and interval parameters and interrelationships.

REFERENCES

1. Analysis and Modelling Group(AMG) (1999), "Natural Resource Canada Canada's Emissions outlook: An Update", Ottawa, Canada 2. Berger, C., D. Fuller, A. Haurie, R. Loulou, D. Luthra, and J. P. Waaub, (1990) "Modelling Energy Use in the Mineral Processing Industries of Ontario with MARKAL-Ontario", Energy, Vol. 15, No. 9, p. 741-758. 3. G. A. Goldstein, (1995), "Markal-Macro: A methodology for Informed Energy, Economy and Environmental Decision Making", New York, USA 4. James J. McCarthy, Osvaldo F. Canziani, and Neil A. Leary (2001), "Climate Change 2001: Impacts, Adaptation and Vulnerability", http ://www.ipcc.ch/pub/tar/wg2/index.htm 5. Kanudia A. and Loulou R. (1999), "Advanced Bottom-up Modelling for National and Regional Energy Planning in Response to Climate Change," International Journal of Environment and Pollution, Vol. 12, Nos. 2/3, pp. 191-216. 6. Loulou, R., and Kanudia A. (1999), "The Kyoto Protocol, Inter-Provincial Cooperation, and Energy Trading: a Systems Analysis with integrated MARKAL Models", Energy Studies Review, Vol. 9, No. 1, pp. 1-23. 7. Loulou R., Kanudia A., and Lavigne D. (1998), "GHG Abatement in Central Canada with Inter-provincial Cooperation," Energy Studies Review, Vol. 8, No. 2, pp. 120-129. 8. Chioti Q., (2001). "Climate Change, Energy and Sustainability: Lessons from the Toronto-Niagara Region", http://www.cns-snc.ca/events/CCEO/graphics/3b chiotti_paper.pdf

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1745

DEVELOPMENT OF DATABASE ON JAPANESE SECTORAL ENERGY CONSUMPTION, CO2 AND AIR POLLUTANT EMISSIONS INTENSITIES BASED ON THE INPUT-OUTPUT TABLES

Keisuke Nansai 1, Yuichi Moriguchi I and Susumu Tohno 2 INational Institute for Environmental Studies 16-2, Onogawa, Tsukuba, Ibaraki, 305-8506, Japan 2Graduate School of Energy Science, Kyoto University Gokasho, Uji, Kyoto, 611-0011, Japan

ABSTRACT This study produced a database on Japanese embodied emission intensities of NOx, SOx and suspended particulate matter (SPM) responsible for regional environmental issues outside of energy consumption and CO2 emissions using the Input-Output tables in 1990 and 1995. Consumptions of about 20 fossil fuels and 5 other fuels were estimated according to approximately 400 sectors. Air pollutant emission factors for stationary sources were calculated from the results of a survey on air pollution prevention in Japan. Pollutant emissions from mobile sources were estimated taking into consideration vehicle types, traveling speed and distance. As a result, the total energy consumptions in 1990 and 1995 were estimated to be 16.6 GJ and 18.3 GJ, respectively, and calculation of CO2 emission resulted in 1.15 Gt-CO2 in 1990 and 1.26 Gt-CO2 in 1995. Similarly, increment of air pollutant emissions from 1990 to 1995 was demonstrated quantitatively. NOx emission increased from 3.37 Mt to 3.51 Mt, SOx emissions in 1990 and 1995 showed almost same values of 1.87 Mt. As for SPM emission, its amount changed from 0.30 Mt to 0.32 Mt. All data on embodied intensities calculated by application of input-output analysis was compiled into the data book.

INTRODUCTION The input-output analysis was developed by W.W. Leontief and has been applied to various research fields. Energy analysis based on the economic input-output tables is one of the most representative examples of the application [1,2]. Embodied energy intensity in the energy analysis gives the total amount of direct and indirect energy related to a unit production activity of a sector. Since this characteristic of the intensity can be applied to life cycle inventory data in Life Cycle Analysis/Assessment (LCA), case studies using the embodied CO2 emission intensities started in Japan at the early stage of LCA research [3]. LCA is appropriate to comprehensively evaluate environmental impacts of a product, technology and so on. It is therefore necessary to enrich the content of data on embodied intensities. The objective of this study is to prepare for

1746

the database on embodied intensity of air pollutant emissions besides energy consumption and C02 emission.

MATERIALS AND METHODS The Input-Output Tables for 1995 and 1990 were used for estimation of energy consumption and air pollutants emissions. The estimation process for them is illustrated in Figure 1. The 1995 Input-Output Tables consisted of 519 rows and 403 columns in rectangular matrix form for the basic sector classification. We then consolidated several sectors to convert the matrix into a perfectly square matrix with 399 rows and 399 columns for calculation of the embodied intensity based on the input-output analysis. Next, gross consumption, expressed as physical amount for 400 sectors including the Households sector of final demand sector, was estimated for 6 coal-based fuels, 12 petroleum-based fuels, 3 natural gas-based fuels, and 5 other fuels. The Tables of Values and Quantities, attached to the Input-Output Tables, give the main data on consumption of these fuels; however, some values include large errors due to the characteristics of the estimation method. We therefore corrected the errors by using other public statistics and a questionnaire survey. The net contribution rate to environmental burden was then set for each combination of fuel type and sector to exclude fuel consumption that was converted into another fuel type (secondary energy) or used as feedstock, and accordingly which was not a direct cause of the burden. Energy consumption of fuels contributing to environmental load was obtained by multiplying the gross fuel consumption by the net contribution rate and calorific value for each fuel. This allows calculation by fuel type. Energy supply from non-thermal power generation sources was also taken into account.

I

............... ,,, ,,,,, .............................................. Consolidation of basicsector classification in the Input-Output Tables into 399sectors JIF_ ......... H

Est~tation of coal-has ed fuel consum pfion

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.

Estimation of natural gas-based fuel cons um ption

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,

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ption by multiplying by calorific value fo . . . . h fuel

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<.N O x >.

Estimation of limestone consumption with CO 2 emissions

, .

.

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Estimation of electric power consumption by electric furnaces

_

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Estimation of metal ore consumption

burning of waste agricultural biomass

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Estimation of the amount of air pollutant emissions from mobile

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sources

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Calculation of energyconsumption, CO 2 and air pollutant emissions in each sector

/ .........

.,,.,_~11~. 1~

- ...

~, . . . . . . . . . . . .

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~ .....................

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Calculation of embodied energy, CO 2 and air pollutant emissions intensities in each sector

Figure 1: Calculation process for embodied energy and emission intensities by sector

[

I Estimation of emission originating in tire wear

1747 Emissions of CO2 were calculated by multiplying the obtained energy consumption for each fuel type by its corresponding CO2 emission factor. Furthermore, we estimated CO2 emissions from limestone, an emissions source separate from fossil fuel. Emissions of NOx, SOx, and SPM were classified into either that from stationary sources or from mobile sources. Emissions from stationary sources were obtained by multiplying energy consumption by emission factor, taking into account Japanese removal technologies for denitrification, desulfurization and dust collection. In addition, NOx emissions from electric furnaces, SOx from non-ferrous ores and SPM from incineration of agricultural bio-wastes (open burning) were taken into consideration as emission sources originating in non-fossil fuels. Emissions from mobile sources, especially from automobiles, were estimated in detail, based on vehicle type and driving conditions. For SPM, emissions from wearing away of tires were also included. However, SPM in these estimates took into account only primary particles, not secondary particles. Finally, energy consumption and pollutant emissions by source were totaled for each sector in the Input-Output Tables. We regarded the total value as direct environmental burden of the sector, and calculated embodied intensities by applying the input-output analysis. RESULTS AND DISCUSSION The total energy consumptions in 1990 and 1995 were estimated to be 16.6 GJ and 18.3 GJ, respectively. Similarly, increment of air pollutant emissions from 1990 to 1995 was also demonstrated quantitatively. NOx emission increased from 3.37 Mt to 3.51 Mt, SOx emissions in 1990 and 1995 showed almost the same values of 1.87 Mt. As for SPM emission, it changed from 0.30 Mt to 0.32 Mt. Here, for convenience of display, all 399 sectors were consolidated into 17 sectors and we explain the sectoral contribution of CO2 emission in 1995. Calculation of CO2 emission resulted in 1.15 Gt-CO2 in 1990 and 1.26 Gt-CO2 in 1995. The proportion of direct CO2 emissions for each sector was similar to the energy consumption as shown in Figure 2. Emission from the "Electric power, gas and heat supply" sector was the greatest, representing about 30 % of the whole, or 0.38 Gt-CO2, followed by 0.21 Gt-CO2 and 0.15 Gt-CO2 in the "Transportation" and "Households" sectors, respectively. The "Ceramic, stone and clay products" sector, which includes cement industry-consumed limestone, accounted for 7 % of total CO2 emissions, in spite of accounting for only 3 % of total energy consumption. Also, the "Iron and steel" sector, in which limestone is consumed and large amounts of coal-based fuels are used, dominated, accounting for 8 % of energy consumption and 11% of CO2 emissions. I

Agriculture, forestry and fisheries Mining

Food Textiles Pulp, paper and wooden products Chemical products Petroleum refineries and coal

!

• Coal-based fuel [] Petroleum-based fuel • Natural gas-based fuel [] Other

i

Ceramic, stone and clay products Iron and steel

I I -I

Non-ferrous metals Machinery and other products Construction and real estate

Electric power, gas and heat supply 7

Finance and trade Transportation

ia=

Communicationsand services Households

m 0

0.05

0.1

0.15

0.2

0.25

0.3

Amount of CO2 emission (Gt-CO2)

Figure 2: Sectoral direct CO2 emissions in Japan for 1995

0.35

0.4

1748 On the other hand, TABLE 1 shows an example of the embodied intensities calculated by'the input-output analysis using the estimated sectoral direct consumptions and emissions. Values on the upper section in each sector's intensity are calculated by the (I-A) 1 type inverse matrix and those on the lower section are based on the {I-(I-M)A} -1 type inverse matrix which can exclude emissions related to import commodities. Every data on the embodied intensities was complied into the data book [4]. TABLE 1 SAMPLE OF EMBODIED ENERGYAND EMISSION INTENSITIES IN 1995 Sector number 1 2 3 4 5

Sector name

Embodied energy and emission intensity on a producer price basis Energy CO2 NOx SOx SPM GJ/MY* Gg-CO2/MY kg/MY k~MY kg/MY

21.836 19.347 36.695 31.412 24.621 Potatoes and sweet potatoes 21.258 24.982 Pulses 20.369 32.471 Vegetables 29.657 Upper section: (I-A)l type inverse matrix basis Lower section: {I-(I-M)A}1 type inverse matrix basis Rice

(I-A)-I type {I-(I-M)A}1 type Wheat, barley and the like

1.446 1.282 2.429 2.079 1.649 1.425 1.678 1.370 2.180 1.998

5.010 4.645 7.428 6.645 6.547 6.113 6.135 5.400 7.953 7.555

1.484 5.385 1.271 5.346 2.317 2.317 1.926 2.193 1.869 0.901 1.610 0.852 1.916 0.656 1.552 0.575 4.691 1.045 4.441 1.000 * MY=Million yen

CONCLUSION This study calculated Japanese embodied energy and air pollutant emissions intensities by sector using the input-output analysis, and compiled them into the data book [4]. ACKNOWLEDGMENTS This research was supported by the Global Environmental Research Fund provided by the Ministry of the Environment of Japan. This project also received support from the "Research for the Future" Program, the Japan Society for the Promotion of Science (JSPS) "Distributed Autonomous Urban Energy System for Mitigating Environmental Impact" Project (JSPS-RFTF97P01002) and the Sumitomo Foundation (Grants No. 013243). We are grateful for their help. REFERENCES Wright, D. (1974). Energy Policy 2, 307. Bullard, C. W. (1975). Energy Policy 3, 268. Moriguchi, Y., Kondo Y. and Shimizu, H. (1993). Industry and Environment, 16, 42. Nansai, K., Moriguchi, Y. and Tohno, S. (2002). Embodied Energy and Emission Intensity Datafor Japan Using Input-Output Tables (3EID)." Inventory Datafor LCA. Center for Global Environmental Research, National Institute for Environmental Studies.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1749

ANALYSIS OF MARKET GROWTH CONDITION FOR FUTURE TYPE OF VEHICLES BASED ON CONSUMER CHARACTERISTIC MODEL Takemi Chikahisa and Yukio Hishinuma Division of Mechanical Science, Hokkaido University, N-13 W-8, Sapporo 060-8628, JAPAN

ABSTRACT

Increasing CO2 emissions from vehicles is becoming a major concem in automotive society, and a variety of future types of cars are being intensively developed. This paper investigates the possibility of market growth of future cars, as hybridcars, electric vehicles and fuel cell cars, based on the consumer selection model for their performance and cost. The consumer model was calibrated using statistics of past data. The cost and performance of each type of car were estimated based on data from literature. The result of the analysis shows that during the next 20 years hybrid vehicles with an engine and electric motor will take a major market share, as well as conventional gasoline cars. The paper shows the critical cost of fuel cell vehicles to have a 10% share in 2020. Estimation of CO2 emission change is also made for variety of scenarios.

INTRODUCTION

Emissions and fuel consumption by automobiles are major concerns, and low emission vehicles are intensively investigated. A variety of types of vehicles operating on natural gas, electric, hybrid or fuel cell are being developed. However the future of such cars and the conditions necessary for the introduction of these altemative vehicles are not clear. The objective of this paper is to evaluate the CO2 emission reduction potential of these vehicles, and also to compare the composition of vehicle types and emissions for a variety scenarios of consumer characteristics, economic growth, fuel price, performance of cars, and carbon tax control measures. It should be noted that the work does not predict the future state but shows the state for each assumed condition of scenario. From the analysis it becomes possible to understand how technological development affects the future composition of vehicle types and what measures must be taken to reduce greenhouse gases. In this kind of research it is difficult to eliminate uncertainty factors, but the results for the limited conditions assumed in the analysis are elucidated.

A MODEL OF CONSUMER CHARACTERISTICS FOR PURCHASING VEHICLES

Prior to the establishment of consumer model, analysis was made of the relationship among performance, cost and number of cars sold, based on past statsfical data. The analysis showed correlations in initial cost and in power relative to vehicle weight for each of gasoline and diesel engine cars. A strong correlation was also found between the growth rate of total vehicle kilometers traveled (VKT) and GDP growth rate [1]. The VKT is the total traveled distance of all cars in a year and it is necessary to calculate the market size of the vehicles. The items, which consumers are concemed about when purchasing vehicles, may be initial price, running cost, engine power, vehicle size, nmning range, safety factors, styling, color, etc. This study tries to compare the acceptability of different types of vehicles, and it is not concemed with styling and color of the cars. Thus the main items considered in this study were the initial price, maintenance costs including nmning costs and quality. Quality may include room size,

1750 luxury, and power. As correlation can be assumed between the quality and power, engine power was taken as a reference of quality. Running range was not taken into consideration in this analysis because of limited available data for calibration. To express the degree of satisfaction, logistic function curves shown in Fig. 1 were applied. The Type 1 curve corresponds to the initial price of the vehicles and maintenance costs, and Type 2 is for the power output. Equation 1 is the formula for the Type 1 curve:

1

f,,J = (1 + exp(Z,.) )

(1)

where Z is the normalized cost including weighting factor to deal with different parameters of cost and power, suffix i is type of vehicle, andj is parameter items. All the satisfaction values are multiplied to give total satisfaction degree. Then the purchasing potential/-'is calculated as a logistic function of the total satisfaction degree. The share of the type i vehicle is then determined with the following equation:

Si-

Fi

(2) i

Detail of the model is presented in Ref. [ 1]. There are four major constants to be adjusted in the model [1]. Calibration was made on the sales statistics of passenger cars in Japan to simulate sales number of vehicles categorized by engine displacement. Figure 2 is the result of the simulation with the model, comparing sales numbers of variety category of cars between simulation and actual statistics from 1994 to 1999. It shows that the sale in the past is well simulated by the model.

RESULTS AND DISCUSSION

Conditions with the Analyzed Scenarios Analysis was made for six types of cars: gasoline, diesel, compressed natural gas (CNG), electric (EV), methanol fuel cell (FCEV), and gasoline hybrid (HEV). The initial cost, efficiency, maintenance cost, and power were estimated from literatures detailed in Ref. [2]. Figure 3 shows the initial price change for the 6 types of passenger cars in the future. Fuel prices were estimated from the empirical relationship among fuel price, reserve capacity, and accumulated production calculated from future demand forecasts [1]. The initial cost of hybrid cars becomes cheaper than diesel cars at 2010 because of stringent emission regulations. The fuel costs increase gradually without significant changes until 2030.

0.5 0.4 tO

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~- High

J I

0

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Figure 2: Correlation between statistics and simulations on shares of all types of gasoline cars from 1994 to 1999

1751 Table I is the list of scenarios analyzed in this paper. Each type of car consists of three classes with different power: 50, 100 and 150kW. In the table "M" denotes 100kW class vehicle as the reference vehicle of satisfaction, and "S" of 50kW vehicle. The reference vehicle is chosen for the highest total satisfaction degree at the moment, and the normalized value of the each item, Zij in Eqn 1, was set to give 70% forj~j value for the vehicle. Case 1 is the BAU case with same consumer characteristics with the present, i.e. 70% satisfaction is obtained with 100kW gasoline cars for cost, power, and maintenance cost. Case 4 is maintenance cost conscious with requiring "S" maintenance cost with acceptance of"M" initial cost for "S" power; i.e. if electric vehicle has the highest total satisfaction degree for the condition, normalized Zi,j is adjusted to give 70% satisfaction in maintenance cost for 50kW electric vehicle. Future type of vehicles has large share in this case, and the case is termed "maintenance cost conscious" in the paper. In the result of Case 3 small gasoline cars were dominant with little acceptance of future type of vehicles due to the requirement of"S" initial cost. Case 5 and 6 are the cases when carbon taxes are applied to Cases 1 and 4. The tax rate is set to be equal to the value proposed by the Advisory Committee for Energy Japan in 1997, i.e. 30 Yen/kg-C in 2005 and linearly increased to 120 Yen/kg-C in 2020. The analysis was made for the GDP growth rate of 1%.

Results on Future Mix of Vehicle Types and CO2 Emission Figure 4 is a comparison in vehicle shares in 2020 between BAU scenario of Case 1 and maintenance cost conscious scenario of Case 4. It indicates that hybrid and gasoline cars of medium size take a large share in BAU case, when the consumer characteristics are same with the present. This is mainly due to the fact that hybrid cars have the most balanced characteristics for this type of consumers in power, price, and rtmning cost among the future type of vehicles. Other types of future vehicles would not take apparent share in this case even in 2020. It should be stressed that substantial number of gasoline cars are still sold in the market in this scenario. However when consumer characteristics are changed to be maintenance cost conscious, variety types of future vehicles have significant share in the market. CNG and electric vehicles also take substantial share, while fuel cell car is still minimum in share due to their high vehicle cost. In this scenario most of the car becomes small cars. Table 2 is the critical cost for fuel cell cars to have 10% share in 2020 for the each scenario. If the consumer characteristic is the same with the present, the vehicle cost must be reduced to less

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0

1

+

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Figure 4: Estimated shares in 2020 in case 1 (upper: BAU) and in case 4 (lower: maintenance cost conscious with accepting M size cost for S power) scenarios TABLE 2 CRITICAL VEHICLE COST OF FCEV RELATIVE TO A GASOLINE CAR TO HAVE 10% SHARE IN 2020

lCase3 ICase4 ICase5 ICase6 I 1.851 1.471 2.321 2.031 2.521 ICasel1.471ICase2

1752

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than 1.47 times of gasoline cars to have 10% share. When consumers become maintenance cost conscious, the cost can be 2.32 times of gasoline cars for the same share. The sensitivity analysis of the model constants on the market share were examined, and confimaed to be low sensitive. Figure 5 is the CO2 emissions calculated from literatures for variety types of vehicles in 2020 [2]. It can be seen that electric vehicle and fuel cell cars have lower emission characteristics. With this emission dala~ Fig. 6 shows CO2 emission changes for the scenarios. In Case 1 CO2 increases initially, but it stays constant from 2005 till 2020 due to the improved fuel economy of each vehicle. In Case 4 CO2 emission decreases significantly due to shifting to smaller cars and replacement by more efficient vehicles. The CO2 reduction starts right after the present moment: this is because the consumer characteristic is changed suddenly in this analysis. Application of carbon tax in Cases 5 and 6 does not show significant effect compared to no-tax case. This indicates taxation of the above-mentioned rate is insufficient to be effective if the consumer characteristics are constant. Carbon taxation, however, will have effect on CO2 reduction through affecting on consumer characteristics in actual case.

CONCLUSIONS Based on the literature and a consumer model developed in the present study, the future composition of the vehicles and carbon dioxide emissions are evaluated for a limited number of scenarios. Within the range of conditions analyzed in the present research, the following estimates were obtained: (1) Hybrid cars have balanced characteristics for satisfying consumers in power, vehicle price, and running cost, and they form a large portion of the coming market as well as gasoline vehicles, if the consumer characteristic is same with present. (2) When consumer characteristics becomes maintenance cost conscious, i.e. requiting "S" maintenance cost with acceptance of"M" initial cost for "S" power, future type of vehicles take large portion of the market share and number of gasoline vehicles will decrease. In this case most of the cars becomes compact small vehicles. (3) Among the variety of vehicles in development, electric vehicles and fuel cell cars have the best CO2 reduction potential when including the fuel conversion process. (4) Carbon taxes at the extent applied in the research would not directly affect the promotion of low CO2 emission vehicles, but it may be effective through changes in consumer characteristics. (5) The CO2 emissions will be almost same with present in BAU case due to improved efficiency of vehicles until 2020 in the case of GDP growth rate of 1%. When consumer characteristics could be changed to be maintenance cost conscious the emission decreases apparently due to down sizing of cars and replacement by the more efficient cars.

REFERENCES

1. Fukui, H., Chikahisa, T., and Hishinuma, Y. (2002) Proc. of 18th Conference on Energy, Economy, and Environment in Japan, pp549-554 2. Chikahisa, T., Ito, H., and Hishinuma, Y. (2000) Proc. ofFISITA, (CD-ROM) P412:ppl-8

POLICY

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1755

TRANSPORTATION, CDM, AND GHG EMISSION REDUCTIONS Ming Yang (PhD) l and Xin Yu (PhD Candidate) 2 ~Energy Economics and Technology, 12 Kiah Street, Glen Waverley, Victoria, Australia, email [email protected] 2Department of Management, Monash University, Australia, Email: [email protected]

ABSTRACT This paper aims at presenting information on how transport technology, management and clean development mechanism (CDM) facilitate GHG emission reductions in urban passenger transport. Efficiency factors of urban passenger vehicles are analysed. Emissions from various transportation fuels and vehicles are demonstrated. The paper also shows two case studies about transportation planning and CNG vehicles motoring towards cleaner city environment. Then, this paper briefly introduces CDM of the United Nations Framework for Climate Change Convention (UNFCCC) and describes how CDM will leverage additional financial resources from Annex B parties to the developing countries. This paper concludes that governments in developing countries have various opportunities to mitigate climate change, and that integrated transportation planning and clean transport technology combined with clean development mechanism will assist government decision makers of the developing countries to better develop their transportation systems.

INTRODUCTION Of all human activities, driving motor vehicles produces the most intensive CO2 emissions and other toxic gases per capita. A single tank of gasoline releases 140---180 kilograms of CO2. Yang [ 1] indicated that over 25% of transportation-related GHG emissions originate from urban passenger travel. Throughout major cities in Asian developing countries, unsustainable trends in urban transportation have already manifested in frequent congestions, periodic gridlock, a lack of funds for desired road rehabilitation and maintenance, and evidence linking respiratory illnesses and deaths to poor air quality. Many city governments in Asian development countries still have opportunities to make things better. In Hanoi and Ho Chi Minh City in Vietnam for example, urban passenger transportation is currently dominated by motorbikes. The city governments are just about to develop buses. With the development of Vietnamese economy, people would shift from motorbikes to cars. Two options, i.e. private or mass public transportation modes are facing Vietnam. Urban passenger travel presents unique challenges and opportunities if it is to contribute to achieving GHG emission reductions. Private cars and motorbikes, often with only a single occupant, dominate personal

a Contact by September 2002: Efficiency Adviser, Asian Development Bank, 6 ADB Avenue, Mandaluyong Oty, 0401 Metro Manila, The Philippines, email: mvanz~adb.or~. However, the viewpoints expressed in this article are solely those of the authors, and they do not represent those of the Asian Development Bank

1756 travel. However, compressed natural gas (CNG) vehicles releases about one quarter less CO2 than gasoline vehicles. Some of other noxious emissions are even less than this ratio. This paper presents emissions from various transportation fuels and vehicles, shows the city governments on how to initiate economically sustainable and environmental friendly transportation modes by two case studies in China. In addition, the paper demonstrates how to access additional capital investment in transport sector via CDM from the developed countries to support sustainable development in developing countries. This paper is descriptive and experimental rather than academic research. It may interest policy makers in developing countries, who are less aware of climate change and urban passenger transportation efficiency. This paper will help them better understand how to reduce GHG emissions and local pollutions in developing their urban transportation systems.

V E H I C L E EFFICIENCY FACTORS Vehicles efficiency factors varies on the basis of different assumptions and methodologies. Generally speaking, buses are most energy and GHG-emission intensive in per vehicle-100 km travel; but motorbikes and cars are the most intensive in terms of per-person per 100 km traveled. See Figure 1.

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Figure 1: Average Fuel Efficiency Factors for Urban Travel (Canada)

The left chart in Figure 1 shows energy intensity of buses, cars and motorbikes in Canada in 1999. Gasoline and diesel buses rank the highest at the range of 40 to 50 liters per 100 km traveled. The least energy intensive vehicle is motorbike, consuming less than 10 liters per 100 km. Diesel and gasoline cars burn about 10 to 20 liters per 100 km. However, in terms of per-person kilometer traveled, the energy intensities order is in opposite direction. The right hand chart of Figure 1 shows energy intensity in liters per person per 100 km. We assume that all the vehicles are half loaded, i.e., 25 people for a bus, 2.5 for a car and one person for a motorbike. Then, energy intensity range order will be inversed when compared with the case in the left chart. Gasoline motorbike requires 7-9 liters per person-100 km travel, but a bus rider consumes no more than 2 liters. Diesel and gasoline cars are in the range between 4 to 7 liters per person-100km. In Asia, mass transportation will be more efficient than the scenario described in the right chart, because buses in Asia are usually more than half-loaded and cars are less than half-loaded.

1757 EMISSION FROM FUELS TABLE 1 shows the weighted GHG emissions in moles of CO2 equivalent per vehicle-mile traveled (VMT) which is equal to the un-weighted quantity multiplied by the global warming potential per mole of each gas, relative to carbon dioxide. One can see that compressed natural gas (CNG) and liquefied petroleum gas (LPG) vehicles emit least GHGs among all the transportation fuels and alternatives. TABLE 1 WEIGHTED MISSIONS FROM FOSSIL FUELS (Unit: Moles Of CO2eq Per VMT (Weighted) Gasoline

Diesel

Compressed Natural Gas

Carbon Dioxide (CO2)

7.9

7.88

5.64

Methane (CH4)

0.22

0.22

0.91

0.17

Nitrous Oxide (Y20)

0.54

0.54

Nitrogen Oxides (NOx) Carbon Monoxide (CO)

1.06

1.06

0.99 10.71

Greenhouse Gas

Total

Liquefied Petroleum Gas

0.54

0.54

0.99

0.97 0.97

0.92 0.98

10.68

9.03

8.61

.

Source: Wang [3] and USEIA [4]," Note." one Mole contains 6.023 x 1023 molecules or atoms

The above two sections show that buses are the most energy efficiency mode among all transportation means in terms of person-km traveled, and that CNG and LPG are the least carbon emission fuels per vehicle mile traveled (VMT) if the fuels' GHG emissions are calculated in weighted moles. We would conclude that CNG and LPG buses are one of the best modes in urban passenger transportation. This argument is also supported by two case studies in China.

CASE STUDY 1: INTEGRATED TRANSPORTATION PLANNING IN XIAMEN A project was undertaken in 1997 aiming at solving the traffic congestion and air pollution problems in Xiamen by an integrated transportation planning. The project team analyzed policies adopted by the Xiamen municipal government to improve the transportation conditions and air quality. A detailed description of the project is available in Yang [ 1]. In the following, we present the key results of the study. Eight main components in the Xiamen's integrated transportation planning are presented: 1. Deciding system boundary; 2. Forecasting transportation demand; 3. Integrating all possible elements related to transportation system focusing on mass transportation and CNG vehicles; 4. Using access not just mobility; 5. Designing alternative scenarios; 6. Using linear programming model to carry out system optimization; 7. Evaluating planning results; and 8. Implementing the plan. Figure 2 shows the relationships and steps of the components. The following measures were adopted by the Xiamen municipal government to reduce vehicle transportation demand: 1. Improve the city outline plan for new city development zones. Tourism industrial facilities, commercial and entertainment facilities, schools and hospitals will be developed in each zone; 2. Design special transportation means for residential areas, where large trucks are not allowed to enter; 3. Focus on public transport development and establish alternative modes of transport. These include: pavement; bicycle lanes; bus lanes; high-occupancy vehicle lanes; integrate system with trains, bus and bicycles; pricing measures; and market based parking measures; 4. Leave lee-ways in road planning; 5. Build express roads across the city and high way around the city; 6. Reduce the number of one-way streets and roads; 7. Towing system should be pout into operation in the main roads of the city; 8. Adopt special policies to attract investment in transportation infrastructure, levy fuel consumption taxes and inspect

1758 vehicles regularly; 9.Levy high penalty on those whose vehicle tail gas does not m~et the standards; 10.Construct parking lots with the development of new roads and buildings; and 11. Develop high efficiency and least carbon emission vehicle technologies in the city.

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Figure 2: Methodological Framework for Integrated Transportation Planning

CASE STUDY 2 - COMPRESSED NATURAL GAS VEHICLES IN BEIJING In 1995 in Beijing, 800,000 vehicles daily produced an estimated 24,000 tons of CO2, 320 tons of hydrocarbons, 12 tons of oxides of nitrogen (NOx), 67 tons of non-methanol carbide, 24 kilograms of benzene and lead Guo [5]. The Beijing Municipal govemrnent manages about 70,000 fleet vehicles, 10% of total vehicles in Beijing in 1996. These fleet vehicles include buses, taxies, post trucks, and the trucks used by environmental and sanitary sectors and by Beijing transportation companies. A project team funded by the USEPA worked with North China Vehicle Research Institute, which would be willing to invest in gas filling station development and importing retrofitting technology from New Zealand. Detailed information on the project is available in Yang [6]. In the following, we briefly present the results: 1. It needs 350 gas fill stations in Beijing, and each feeds 200 at 500 M3/hr; 2. Using New Zealand (NZ) CNG Vehicle technologies to reduce conversion investment; 3. Comparing the NZ CNG vehicles with gasoline vehicles in Beijing: (1) CO reduced by 97%; (2) Hydro-carbon reduced by 72%; (3) NOx reduced by 39%; and (4) CO2 reduced by 25%; 4. GHG emission reduction for one gas fill station (for 200 vehicles) is about 39,000 tons of CO2 per year. Since 1997, CNG vehicles have been developing very quickly in Beijing. About one third of the city buses were run by CNG engines in Beijing by September 2001 i.

CDM FACILITATES CLEAN TRANSPORT Clean Development Mechanism (CDM) is a modified version of Joint Implementation that was included in the Kyoto Protocol for project-based activities in developing countries. In Article 12.2 of the Protocol, the Source: Author's on-site surveyin Beijing in September2001.

1759 parties established the CDM for the purposes of assisting developing countries in achieving sustainable development and helping Annex B parties meet their emissions limitation and reduction obligations. Under the supervision of an Executive Board of CDM, private and public funds may be channeled through this mechanism to finance projects in developing countries. With CDM, countries co-operate in an emissions mitigation project in a developing country with the donor country acquiring the Certified Emission Reduction Units generated by the project while the host country benefits from the contribution of the project to sustainable economic development through investment in environmentally sound technologies. It is estimated that US$ 1.2 billion will be transferred as CDM funds from Annex B countries to the developing countries each year during the next decade. In the following, as an example, we present the willingness to pay of the government of Netherlands as a simple example of the funding source. Under the Kyoto Protocol the Dutch obligation is to reduce its GHG (green house gases) emissions by 6%, compared to the reference year 1990. Already in 1999 the Dutch government decided to score 50% of this obligation on a national level and the remaining 50% (125 million tonnes of CO2) abroad by application of the Flexible Mechanisms CDM, JI (Joint Implementation) and lET (International Emissions Trading) CERUPT [7]. The government of Netherlands also is willing to pay the CER at the price of about US$ 4. See TABLE 2. If the Netherlands acquires the 125 million of CERs by CDM, the total funding source from the Netherlands will be about US$ 600 million. TABLE 2 WILLINGNESS TO PAY COa CREDIT BY THE NETHERLANDS GOVERNMENT . CDM Projects Renewables energy (excluding biomass): Energy production by using clean, sustainable grown biomass (excluding waste) Energy efficiency improvement Others, among which fossil fuel switch and methane recovery

Prices EUR 5.5 US$ 4.8 EErR: 4.4 US$ 3.8 EUR: 4.4 EUR 3.3

US$ 3.8 US $ 2.9

Source: CERUPT [8]; Note to exchange rate: On Feb 15, 2002,1 EUR = 0.873 US$, Source: http ://goeurope.about.com/gi/dynamic/offsite.htm? site=http%3 A %2 F%2 Fwww.x-rates.com%2F

POSSIBLE CDM TRANSPORT PROJECT EXAMPLES IN ASIA Substitution of passenger buses for motorbikes in main cities of Vietnam In Hanoi and Ho Chi Minh City, motorbikes are currently dominant in passenger transportation. As indicated early in this article, motorbikes are one of the most energy and GHG intensive means of transportation. Mass transportation system does barely exist in the two cities. If the city governments would develop mass transportation, CNG buses for instance, it will definitely benefit global and local environment conservation.

Developing mass transportation needs to be well planned. Without a good plan, bus and train system may not be able to work due to traffic congestions. The development of bus lanes, regulations on the use and registration of motorbikes should go hand in hand. Consequently, an integrated transportation planning, followed by government policy and regulations on vehicle uses, and implementation of mass clean fuel vehicle development may be good steps for the municipal governments in Vietnam to adopt.

CNG vehicle promotion in Bangladesh Bangladesh is rich in natural gas resources but short of petroleum supply. In 2000, Bangladesh imported about 58,400 barrels of oil per day [9]. Developing CNG vehicles will not only benefit environment, but also reduce burden of foreign currency expenditure. The government of Bangladesh is preparing to convert and replace about 100 thousand petrol and diesel vehicles with CNG vehicles. Evidently, CDM will add extra benefits to the CNG project and make the project financially and economically viable.

1760 CONCLUSIONS A survey shows that transportation modes from most energy efficient one to least efficient one are: buses, cares and motorbikes. Furthermore, CNG and LPG vehicles are the least emission technologies so far. We would say that developing CNG buses is one of the best options to promote environmental friendly urban passenger transportation for those countries where domestic natural gas resources are available. Two case studies show that the substitution of CNG vehicles for petrol or diesel vehicles will not mitigate GHG emissions but also benefit local pollution reductions. Government policies and regulations should have a good transport plan, encourage the use of mass transportation and discourage the use of private cars and motorbikes. CDM will facilitate advanced technology and fund transfer from the developed countries to the developing countries. It may change some financially distractive projects into attractive ones. Future CDM projects in Asia may include the substitution of CNG buses for motorbikes in major cities in Vietnam and CNG vehicle development in Bangladesh. CNG vehicles and CDM are motoring towards cleaner cities in Asia.

REFERENCES

.

Yang M., (1998) Transportation and Environment in Xiamen, Transportation Research D, Elsevier, UK, Vol. 3, No. 5, pp. 297-307. Hagler Bailly (1999), Strategies to Reduce GHG Emissions from Passenger Transportation in Urban Canada, Final report for National Climate Change Process, Transportation Table Passenger (Urban) Sub-group, Toronto Ontario. Wang M. (1995) Measurement of Emissions: Greenhouse Gas Estimates for Alternative Transportation Fuels, Unpublished final report prepared for the Energy Information Administration, Vienna, VA, December. USEIA (1993), Emissions of Greenhouse Gases in the United States 1985-1990, DOE/EIA-0573, Washington CD, September, p 15. Guo X. Y. (1996) Pre-feasibility of Developing Compressed Natural Gas Automobiles in Beij'ing, China North Vehicle Research Institute, Beijing Yang M.. Kraft-Oliver T., Guo X. Y. and Wang T. M. (1997), Compressed Natural Gas Vehicles Motoring Towards a Cleaner Beijing; Applied Energy, Elsevier, UK, Vol. 56, Nos. ¾, pp, 395-405. CERUPT (2001), Implementation of the Clean Development Mechanism by the Netherlands, Ministry of VROM, Netherlands. CERUPT (2001) Terms of Reference for CDM project development, Ministry of VROM, Netherlands. USDOE (2001), http://www.eia.doe.gov/emeu/cabs/bangla.html

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1761

EMERGING CARBON OFFSET MARKETS: PROSPECTS AND CHALLENGES Patrick Karani 1 Chief Executive Bureau of Environmental Analysis (BEA) International Ngong Road, Ngong Lane, offNgong Road. P.O. Box 66263 Nairobi, Kenya. Te1.(254)2-570361 Fax(254)2-241663 www.BEAINTERNATIONAL.ORG e-mail: [email protected]

ABSTRACT

This paper offers concise, concepts for emerging Carbon Market. It outlines basic market conditions of price and quantity on the basis of fundamental economic principle of Cost-Effectiveness. Based on economics of integration, the paper suggests that regional co-operations can form cartels for carbon offsets and influence price and also through competition enhance market-based innovative systems for project financing and development. The paper discusses Perspectives on carbon offset markets, Prospects and challenges, and Approaches to a carbon offset market. The paper concludes by combining theory and practice through innovative systems that put development as a priority and seeks market-based solutions to providing additional technological and financial resources to capacity building necessary for development.

INTRODUCTION A carbon market in this paper, is defined as a place where exchange of carbon offsets take place. An offset is an offer of money to less polluting sources to consider alternatives to clean industrialization path that is emission free. The carbon market is emerging at a fast rate and most evidently with the establishment of global Carbon Investment Funds including the UK Carbon Trust, The Dutch Carbon Credits, The World Bank Prototype Carbon Fund among others. P R O S P E C T S AND C H A L L E N G E S Carbon offsets offer a natural source of leverage for carbon investors. When the carbon offset moves up in price, the value of a unit of carbon rises by some percentage. But a carbon generator with total costs of production of a unit of a carbon offset realizes almost a double increase to a unit of carbon. 1

Patrick Karani is the Chief Executive of the Bureau of Environmental Analysis (BEA) International, Nairobi, Kenya, e-

mail: [email protected] a consultant to the World Bank/IFC, Washington DC. He has a Ph.D. in International Political Economy, a Masters in Development Economics, and a Bachelors of Education in Economics and Business Studies. His interests are in development issues, technology transfer and climate change. His recent publications include: Introduction to Emerging Carbon Offset Markets: Prospects and Challenges for Development in Africa (2002), Lessons Learned from AIJ Program of the World Bank and Government of Norway under the Pilot Phase of the United Nations Framework Convention on Climate Change (2000), The World Bank's Experience with the AIJ Pilot Phase: The Case of Burkina Faso Sustainable Energy Management(1999).

1762 This means that investors who do not hedge (minimizing risks and maximizing returns) and have full exposure to the carbon price, have benefited. Investment in Clean Development Mechanism is one of the benefits. The issue of benefiting from a carbon offset market is supported by the United Nations Framework Convention on Climate Change (UNFCCC) and the Kyoto Protocol. The Protocol's main features include: (i) the placement of a cap as a binding agreement by industrialized countries to reduce greenhouse gas emissions to 1990 CO2 or equivalent levels; (ii) establishment of Joint Implementation (JI); Clean Development Mechanism (CDM) and Emissions Trading (ET) for the exchange of inventory and project-based emission reductions among Parties; (iii) the controlled use of forests and agricultural sinks to meet commitments; (iv) establishment of strict measures for inventory, reporting and registry of offsets; (v) enacting a compliance regime with distinct branches for facilitation and enforcement as well as punitive measures for non-compliance; and (vi) enhancing flows of finance and technology transfer to developing countries for capacity building on climate change mitigation and adaptation. The so called small scale projects with higher costs per unit of carbon will also benefit because of exposure to the carbon offset price is magnified by the operating leverage. Small scale producers of carbon offsets experience a proportionately greater rise in earnings for each rise in a dollar in the carbon price. Even investors with less or no carbon investments are benefiting. Emerging carbon offset markets are appreciating because essentially are the most leveraged operations on international scale. Carbon in storage is seen as an option of an offset, and is re-priced accordingly. In support of implementation of the Protocol, the Dutch has established A Carbon Credit Scheme, the UK has set up a Carbon Trust, Norway has a Domestic Trading Scheme and Germany as well. Other Annex 1 countries with obligation to implement the Protocol are in the process of planning and implementing various schemes to achieve the Protocol's target in the period 2008--2012. But are the carbon offsets sustainable? The challenge remains as long as the USA remains the biggest emitter of greenhouse gases in the world and is declined participation in the carbon offset market. Its support to implementation of the Protocol would enhance volume of exchange and increase flow of financial and technological resources. Without USA participation, a lot of people are saying the carbon prices in the range of US$0.60-US$5 per ton of CO2 equivalent are looking pretty low and unless carbon takes another step up the market could come off balance. The market seems to have factored in a higher carbon price than the current spot rate of about US$2.5 per ton of CO/equivalent. A majority of Carbon offset market analyst think the market is anticipating arise to about US$10-US$15 per ton of CO2 equivalent in some regions of Economies in transition speculate price average rise of US$30-US$40 per ton of CO2 equivalent. There is continued confidence that, given the structural changes experienced in the evolution of carbon market over the past few years, there is a likelihood of further appreciation. At the moment, carbon supply is tight and changes in global investment risk will tend to have a strong influence on carbon prices. An onward participation by some industrialized countries and willingness to do a little of profit taking also helped the boost of the carbon market and will continue to influence prices as well. APPROACHES TO A CARBON OFFSET MARKET Integration in form of a cartel is one of the approaches with potential for a Carbon Offset Market. A cartel is a combination of participants whose objective is to limit the competitive forces within a market to minimize costs and maximize profits. A cartel may take the form of open collusion, in which the member participants enter into contracts about price and other market variables. On the other hand, the cartel may involve secret collusion among members. Or it can operate like a trade association or a professional organization. At this time, the most famous cartel is Organization of Petroleum Exporting Countries (OPEC), a cartel of major oil-producing countries. OPEC evolved in response to stabilizing prices of oil in the world market. Cartels may have an enforceable contract or they may not. In this paper, cases of organized collusions to influence the price of carbon offsets and maximize benefits are referred to as cartels. Let us consider an 'ideal' case. Suppose a group of participants producing a homogeneous commodity forms a cartel. A central management body is appointed, its function being to determine the uniform cartel price. The task, in theory, is relatively simple, as illustrated in the figure below. Market demand for the homogeneous commodity is given by the demand curve, so marginal revenue is given by the curve MR. The cartel marginal cost curve must

1763 be determined by the management body. If all firms in the cartel purchase all inputs in perfectly competitive markets, the cartel marginal cost curve (MC) is simply the horizontal sum of the marginal cost curves of the member participants. Otherwise, allowance must be made for the increase in input price accompanying an increase in input usage; MC will stand further to the left than it would if all input markets were perfectly competitive. Cartel Profit Maximization

ost Curve (MC)

Price & Cost

" Marginal Revenue (MR)

x

Q

Quantity per Unit of Time In either case, the management group determines cartel marginal cost, MC. The profit maximization problem is the simple one of determining the price that maximizes cartel profitDthe monopoly price. From the figure above, marginal cost and marginal revenue intersect at the level a; thus, the market price p, is the one the cartel management will establish. Given the Demand Curve, buyers will purchase x units from the members of the cartel. The second important problem confronting the cartel management is how to distribute the total sales of x units among the members. CONCLUSION The development of a carbon market should be viewed as one of considerable change--in borrower countries and in the development system. Carbon offset market undertakings, while timely and relevant, will continuously "raise the revenue" on what is expected of both investors and its borrowers. It is therefore commendable that the carbon offset values be in compliance with high economic, market and financial returns. Carbon offset market establishes that participants should significantly improve their portfolio performance, become more selective in borrowing, recast their vision to address market based solutions to poverty reduction, strengthen the development strategy cycle, enhance their responsiveness to investors and partners' needs, augment their business presence and diversify their borrowing instruments. With the help of a carbon market, a number of borrowers are in a better position now to achieve broad-based growth and poverty reduction through innovative market-based solutions. Carbon offset is purely a market-based approach that could provide additional resources. Carbon offset market performance is only one of the factors that affects the results to be observed on the ground. Exogenous factors, the pace of borrowers' reforms and the quality of non market based assistance also intervene. On the whole, in relation to the ambitious objectives of country and sector programs, the outcome of market-based solution programs could be partially satisfactory to the development agenda.

1764 REFERENCES

•

Econergy International Corporation (EIC). (2001). "Off Balance Sheet" Project Finance for Carbon Offset Projects. EIC, Washington DC., USA.

•

Goldberger, Dan. (2001). Investing in Energy Efficiency: Financing Strategies for Municipalities. ICLEI, USA.

•

Netherlands Government. (2001). Carbon Credits Scheme. Department of Economic Affairs, The Hague, Netherlands.

•

Rosenzweig, R., M. Varilek and J. Janssen. (2002). The Emerging International Greenhouse Gas Market. Pew Centre on Global Climate Change. USA.

•

Schaeffer, Gerrit, Jan. 2001. NL Experiences with Tradable Certificates: The Erupt Program and the Green Label System.

•

UK. 2001. Carbon Trust launched in March 2001.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1765

PLANNING FOR THE DIFFUSION OF TECHNOLOGIES TO CAPTURE AND DISPOSE OF CARBON Elizabeth L. Malone Joint Global Change Research Institute Battelle - Pacific Northwest National Laboratory 8400 Baltimore Avenue, Suite 201 College Park, Maryland 20740

ABSTRACT Issues important to the diffusion of large-scale technologies for capturing and disposing of carbon dioxide include the extent/size of the system to be replaced, whether or not the new technology substitutes one-for-one for the old technology, the number of competing technologies, whether a market is an early or late adopter, specific initial conditions (e.g., societal and consumer preferences for comfort, convenience, and safety), the availability (specifically technological readiness and social acceptability) of complementary technologies and affordable fuels (for energy systems), and the ability of inventors and entrepreneurs to solve problems that arise. These issues must be considered in planning for the diffusion of carbon capture and disposal systems.

INTRODUCTION Analysts can often describe why a technology became successful (or failed), but cannot predict success or failure. Analysis of the diffusion process becomes more complex and acute when environmental considerations feature prominently in the design of new technologies and when government-supported technology "push" is the dominant factor, rather than some known or presumed consumer need.

DISCUSSION Diffusion of large-scale technologies requires coordination among (1) manufacturers of both the technologies, and supporting structures and products, (2) consumers/buyers of the technologies, and (3) governments who must support the diffusion process (initiate regulations or standards, clear legal obstacles, etc.). This coordination must provide niche markets, within which the parties have the opportunity to develop the new technologies, shaping and correcting them so that they fulfill needs without creating new, insoluble problems. The clear advantages of the new technologies often appear only after their introduction and use in niche markets, that is, after a period of"learning-by-doing." The history of the introduction of electricity systems in the latter half of the nineteenth century demonstrates that the diffusion of completely new systems requires an initial champion or champions (most notably Thomas Edison in the United States), financial backers, initial niche markets,

1766 government support, and a period when consumer feedback and rapid technical and infrastructural advances reveal new and expanded uses and products for the system. The first niche market was lighting, but, through the efforts of consumers and innovators, electricity quickly became all-purpose energy carrier and eventually an enabling technology for mass production (allowing machines to be placed as they were needed on the assembly line, rather than grouped by type of machine, powering the assembly line itself). The diffusion of the automobile at the turn of the twentieth century also involved the same elements. Initial niche markets included luxury travel and professional transportation for doctors. In the United States, Henry Ford realized his vision of low-cost, mass-produced vehicles that in a rapid transformation replaced horses with motorcars (from 10% to 90% of the market in 12 years [ 1]). With carbon capture and disposal technologies, we are considering large-scale technologies within an existing even larger scale system, the electricity supply system. Comparable technologies may include combined cycle gas turbines, electric cars, and wind generation technologies. The introduction of efficient gas turbines, based on earlier jet engine technology, is an example of diffusion of new technology in an existing energy system, in some ways parallel to introducing carbon capture and disposal technologies into the existing system. The advantages of lower cost, shorter installation time, more flexible unit size for peak generation, and higher efficiency ensured the speedy diffusion of this technology in a one-for-one substitution within a familiar electricity generation system. Electric vehicles were contenders in the automobile market of the early twentieth century, but they lost out to combustion engine vehicles despite some initial technical advantages (2). In the past two decades, renewed interest in electric vehicles was prompted by a desire to reduce dependence on and emissions from oil. In California, development and deployment of electric vehicles was mandated, but diffusion results have been disappointing. Consumers evidently do not have individual needs for less-polluting cars if the cars do not meet other needs such as convenience, comfort, and reliability. The diffusion of wind arrays may be relevant to the prospective market situation for carbon control technologies. The technical and market issues (sufficient wind, space, noise, variation of power, etc.) are balanced by the advantages of wind power in niche markets, in which "learning-by-doing" and some government subsidies have enabled technical advances (including offshore wind arrays) that in turn have increased the market share of wind. Wind arrays are becoming larger, electricity from wind is becoming cheaper, and there is a large potential for wind energy that is yet to be realized (3). To generalize, the time required for technology diffusion depends upon several factors (1,4): • The extent (size) o f the system to be replaced. In the United States, canal-based transportation systems diffused (from 10% to 90% of the greatest extent) in 31 years. Railroads, 10 times larger, took 55 years. Road networks, 100 times larger than the canal system, took 64 years for diffusion. • Whether or not the new technology substitutes one-for-one f o r the old technology. The diffusion of motorcars was relatively fast because they were one-for-one substitutes for horses. • The number o f competing technologies. Although town gas and oil lamps were strong competitors for electric lighting, central stations that provided reliable electricity for better lighting gave the new technology powerful dominance. This aided the diffusion process by allowing for the back-and-forth of seeing new uses, adjusting features, and so on. • Whether a market is an early or late adopter. Later adopters have faster adoption rates because they can appropriate some of the learning from the diffusion process of the first

1767

•

•

•

adopters. However, later adopters often have lower end levels (300 automobiles per 100 people in Japan versus 600 per 100 people in the United States [ 1]). Specific initial conditions, such as societal and consumer preferences for comfort, convenience, and safety. Users must be able to see advantages to the new technology. Flink (5) describes the improvement of roads in the United States after the bicycle became popular as a necessary precondition for people to realize the potential for fast, independent travel provided by the automobile. The availability of complementary technologies and, in the case of energy systems, affordable fuels. For example, stoves did not replace fireplaces for heating in the US until wood became more expensive, coal became more available (in part because of transportation improvements), and stoves were made of a type of steel less likely to explode from the heat of the stove. The ability o f inventors and entrepreneurs to solve problems that arise. "Reverse salients" may be solved by adjustments to the new technology (e.g., material substitution) or by alternatives such as AC (alternating current) replacing DC (direct current), which could not be transmitted economically (6).

How can we apply these generalizations to prospective technologies for carbon capture and disposal? First, there are two types of technologies: (1) capture technologies added to coal-fueled (and eventually natural gas fired) electricity plants, and (2) an entirely new system for carbon dioxide transport and disposal. The diffusion of these two types must be considered both separately and together. Furthermore, there are two types of consumers: (1) the utilities who will (or will not) purchase the systems, and (2) the end users of electricity, who may (or may not) demand "cleaner" energy. Together, these factors combine technical, economic, and cultural considerations in a sociotechnical system. The coal-fueled electricity generation system is global, with many operating nodes. Carbon capture technologies are one-for-one additions to coal-fired plants. From this angle, diffusion is relatively simple and may proceed faster than if the new technology constituted something entirely new. However, carbon disposal is entirely new and subject to the uncertainties of identifying appropriate reservoirs, transporting carbon dioxide, and ensuring minimal environmental damage and leakage. Since disposal is paired with capture, the entire system loses its potential advantage as a one-for-one addition and must convince its consumers (at both levels) that the uncertainties/risks are acceptable. Carbon capture and disposal technologies will be competing with other emissions-reducing strategies, such as renewable energy technologies, hydrogen-fueled power (especially fuel cells), and perhaps nuclear power. For the utility purchasers of these technologies, economics and business decision-making processes will be of crucial importance in determining whether multiple carbonreducing strategies will exist or if only one will become dominant. Coal-fired plants with carbon capture and disposal technologies will likely be an enduring electricity source in some places, but if other, less expensive power sources are developed in other locations, new coal-fired plants and associated systems may not be built. End-user preferences may be important in deciding which strategies for carbon reduction will be adopted in specific locations. Strong lobbying against the injection of carbon dioxide into the oceans may hinder or preclude the diffusion of this specification of carbon capture and disposal technologies (7), for example, unless key uncertainties are resolved and/or consumers understand and accept the risks (a stakeholder involvement issue). The likely early adopters will be Japan, the United States, Canada, and some European countries, as well as other industrialized countries. The resources of these countries allow them to develop, demonstrate, and "learn-by-doing" large technological systems. Technology diffusion to less industrialized countries is otten unsuccessful, since their social/cultural institutions and industrial structures do not correspond well to those of industrialized countries. Therefore, carbon capture and disposal technologies must be adapted to less industrialized countries before they can diffuse there.

1768 Countries that have large domestic reserves of fossil fuels, such as China would benefit from these technologies, but other countries may benefit more from alternative emissions-reducing strategies. Specific initial conditions will affect how carbon capture and disposal technologies are implemented in different locations. Geography, economics, organizational structure, existing laws and regulations, history, and entrepreneurial conditions all play roles in technology diffusion. For instance, it may be easier to introduce these technologies in countries that rely heavily on coal-fired plants and have expressed government and/or consumer interest in mitigating the effects of associated greenhouse gases. In such places sunk capital costs may make capture-and-disposal systems economical to install relative to new, low- or no-emitting systems. Certainly geography plays an important role in the cost of operating these systems. Proximity to either disposal sites or other industrial uses, such as coalbed methane recovery, will reduce costs. Whether or not people living in the area have some history of environmental advocacy or concern about air pollution will affect their attitude toward a plant's prospective adoption of carbon capture and disposal technologies. Residents may oppose the new technological system either because of its cost, its potential for adverse environmental impacts, or the adherence to "old" and "dirty" fossil fuel technology. Or they may welcome the system for its environmental benefits and give credit to the utility implementing it. Stakeholder involvement may help to explain the technology, its risks, and its benefits. The "hardware" of carbon capture and disposal technologies is only the most visible part of a sociotechnical system that must include transportation infrastructure and vehicles, methods for determining adequate storage sites, machines and methodologies for inserting and containing the carbon dioxide, strategies for minimizing adverse environmental and social effects, and so on. Many of these complementary technologies will be unfamiliar to utility managers. Furthermore, politics may play an important role by setting constraints on business operations, rights of way, etc. Those guiding the diffusion process must provide for the detailed processes involved.

CONCLUSIONS No innovation has completed the process of diffusion without encountering problems - technology that does not work or does not work as planned. Meeting these challenges and capitalizing on the opportunities they sometimes offer is an essential part of the diffusion process. Therefore, the commitment of inventors, innovators, manufacturers, policymakers, and other stakeholders is of primary importance in a successful diffusion process. Problems that seem technical may in fact be institutional and value conflicts. Each of the participants must have strong reasons for seeking to solve these "reverse salients" by continuing the innovation and learning process throughout diffusion.

REFERENCES

1. G~bler, Arnul£ (1996). Daedalus 125(3), 19-42. 2. Kirsch, D.A. (2000). The Electric Vehicle and the Burden of History. Rutgers University Press, New Brunswick, NJ. 3. American Wind Energy Association (AWEA) 2002. Global Wind Energy Market Report. http://www.awea.org/faq/global2000.html 4. Nye, David E. (1999). Consuming Power: A Social History of American Energies. MIT Press, Cambridge, MA. 5. Flink, James J. (1988). The Automobile Age. MIT Press, Cambridge, MA. 6. Hughes, Thomas. (1983). Networks of Power. Johns Hopkins University Press, Baltimore. 7. Gewinn, Virginia. (2002). Nature 417 (27 June), 888.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1769

AN ANALYSIS ON CO2 REDUCTION EFFECTS OF INTRODUCING GREEN TAXATION TO CAR OWNERSHIP TAX Yoshikuni Yoshidal, Akira Morishita 2, Ryuji Matsuhashi 2 and Hisashi Ishitani 3 l Department of Geosystem Engineering, The University of Tokyo, 7-3-1 Hongo, Bunkyo-ku, Tokyo 113-8656, Japan 2 Department of Environmental Studies, The University of Tokyo, 7-3-1 Hongo, Bunkyo-ku, Tokyo 113-8656, Japan 3 Graduate School of Media and Governance, Keio University, 1-11-5-801 Hiroo, Shibuya-ku, Tokyo 150-0012, Japan

ABSTRACT Green taxation is one of the most effective economic policies for CO2 suppression with a small burden for taxpayers. A car type preference model is developed, based on a detailed database on sales and characteristics of cars in the 1990's. The preference model adopts the framework of nested logit. Additionally, we propose a methodology to find the coefficient estimate of an underlying explanatory variable that is not apparently significant. The preference model enables us to analyze the CO2 reduction effects of green taxation on car possession. We simulated the effect of the new tax, imposed in proportion to fuel efficiency, instead of the present tax with revenue-neutral taxation, assuming the minimum tax level is not less than 7200 yen/year, the tax charge of the class under 660 cc. As a result of imposing such taxation, the preference of consumers' shifts to more fuel-efficient cars, then CO2 emissions can be reduced. Estimated CO2 emissions reduction is by approximately three percent in the flow base.

INTRODUCTION

CO2 reduction in the automobile sector is difficult, since the regulation is not easily applied to the consumers sector. Green taxation is considered to be an effective option as a measure for the automobile sector, which reduces taxes for fuel-efficient automobiles. The green taxation policy, which has already started in Japan, does not seem to be effective enough for CO2 reduction since the car models that benefit from the tax reduction are limited and the abatement is limited to only two years. A more effective method on green taxation is required for CO2 emission reduction in the automobile sector so as to achieve the goals of the Kyoto Protocol. This paper aims at evaluating the effect of the tightened green taxation plan in which taxes are imposed in proportion to the fuel efficiency. For the purpose, we develop a car type preference model based on a detailed database on sales and characteristics of cars from 1998 to 2001. The model enables us to analyze the CO2 reduction effects of green taxation of car possession. Hasuike [1 ] evaluated the effect of green taxation by developing a partial equilibrium model. Tanishita [2] analyzed the policy including modal shif~ to the railway utilizing an equilibrium model. Hayashi [3] indicates the effectiveness of green taxation on car ownership tax. Fullerton [4] analyzed the effect of tax and subsidy on the automobile market in USA. The difference between these studies and the present study is that the car type preference model developed in the present study is more detailed and therefore enables us to evaluate the green taxation reliably. This is the second report following Yoshida [5], in which green taxation is evaluated based on the data from 1993 to 1996. In this paper, the analyzed period is updated to from 1998 to 2001 and the model is improved utilizing the framework of nested logit.

1770 GREEN TAXATION CO2 emissions from automobiles have been constantly increasing in 1990s. However, the trend of increase seems to have halted in the past a few years because of the sluggish growth in the number of vehicles owned and the enforcement of fuel efficiency standards under energy-saving laws. Is it unnecessary to take measures for CO2 reduction from automobiles if the trend in these years continues? In this section, we discuss the reason why green tax policy is required in the context of the goals of the Kyoto Protocol. The Japanese government announced an outline concerning the promotion of measures to cope with global warming in March 2002. The outline shows CO2 emission target in the transport sector in 2010 is less than 250 M-ton, which is almost the same level as the 1995 emissions. CO2 emissions from personal passenger cars is crucial for the achievement of the target since these cars account for more than half of the total emissions in the transport sector. Here, we describe the conditions to curb the CO2 emissions from personal passenger cars below the 1995 level. CO2 emissions (ton/year) are expressed in the product of following four characters: CO2 emission intensity (ton/liter), fuel efficiency (liter/km), distance driven per year (km/number/year) and number of vehicles owned (number). First, CO2 emission intensity is constant. Then, the enforcement of fuel efficiency standards under energy-saving laws will improve the fuel efficiency in 10.15-mode of the passenger cars to be sold in 2010 at least by 22.8 percent on the average compared with 1995. The figure of 22.8 percent in 10.15-mode is converted into the improvement by 15.1 percent in terms of actual fuel consumption since the fuel efficiency of actual driving is about 40 percent worse than 10.15-mode (Sagawa [6]). In addition, this figure is converted into the average improvement of fuel consumption on a stock base in 2010, which is estimated at 10.5 percent, taking into account the lifetime curve of passenger cars. Next, distance driven per year is expected to grow by the improvement of fuel efficiency. By assuming the fuel price elasticity of distance driven is 0.23 (Sagawa [6]), the distance driven in 2010 increases by 2.1 percent compared with 1995. Finally, the number of vehicles owned is obtained so as to satisfy the condition that CO2 emissions in 2010 are less than 1995. The number of vehicles owned should be less than 9 percent. The number of vehicles owned has already increased by 12 percent between 1995 and 2001. Therefore, it is indicated that reducing CO2 emissions below the 1995 level will be a difficult goal unless some measures are taken. Nevertheless, there is a possibility that CO2 emissions could decrease without measures since the preference of consumers is changing toward cars with higher fuel efficiency. Small cars whose displacement is less than 1500 cc have sold well in recent years. However, it is shown that the change of preference is limited to the class of small cars. The change of preference can be analyzed by utilizing the car type preference model that is described in the next section. Table 1 shows the estimates of coefficients of yearly fuel cost (logarithm) in the utility function of each year. The values indicate the sensitivity of fuel cost on the market share of car models. The larger absolute value implies the higher sensitivity of fuel cost. Apparently, the hypothesis that the preference is changing toward higher fuel efficiency is not statistically significant. The displacement class of 660-1500 cc seems to show a slight sign of change. In the other displacement classes, however, it is impossible to find a trend between years. As a result, it is indicates that measures for CO2 reduction in the automobile sector should be taken. Considering the difficulty in reducing the number of vehicles owned as mentioned above, it is desirable to improve the average fuel efficiency more than the fuel efficiency standards under energy-saving laws. The green taxation plan is one of the most promising options that enables improvement of the average fuel efficiency, not by technical innovations, but by manipulating consumers' preference toward higher fuel efficiency. TABLE 1. ESTIMATES OF COEFFICIENTS OF YEARLY FUEL COST (LOGARITHM) IN UTILITY FUNCTIONS Recreational vehicle Year Sedan and Hatchback 660-1500 1500-2000 Over 2000 660-1500 1500-2000 Over2000 -1.2 1993 -4.8 -4.0 -5.1 -5.6 -2.4 1994 -10.9 -3.0 -2.9 -3.3 -1.0 1995 -5.1 -2.8 -2.3 -2.4 -0.9 -4.6 1996 -10.2 -1.5 -3.1 -2.7 -0.9 -0.5 1998 -9.7 -1.7 -0.5 -4.2 -7.6 1999 -0.5 -1.2 -0.7 -7.7 -0.9 2000 -1.0 -2.1 -1.2 2001 -0.4 -0.6 -0.3

1771 P R E F E R E N C E M O D E L AND SIMULATION The car type preference model is developed with the framework of nested logit (NL) model (Ben-Akiva [7]). In addition to the method of traditional NL model, we propose a methodology to find the coefficient estimate of an underlying explanatory variable that is not statistically significant because the available sample data do not reveal enough attributes on the preferences. Our method additionally utilizes another sample data that apparently reveal the lacking attribute so as to find the coefficient estimate of the attribute. That is, we have two-step procedures of parameter estimation. One is the traditional parameter estimation of NL model and the other is the estimation of an underlying attribute. The two-step procedures are specifically explained below by utilizing the car type preference model. The hierarchical structure of the model is shown in Figure 1. Level 1 shows the choice of specific car models. The sample to be utilized for estimating parameters is a database that contains the number of yearly sales and various characteristics of all models from 1998 to 2001. The preference model is developed for a period of four years. Hence, three models are built for three displacement classes. Candidates for explanatory variables are previous year's sales (logarithm), new model dummy (0 or 1), fuel efficiency (km/1; logarithm), interior volume (m3; logarithm), engine power (PS; logarithm) and price (yen; logarithm). The results of parameter selection and estimation are as follows (Coefficient estimates are in parentheses.): For the class of 660 to 1500 cc, significant attributes are previous year's sales (0.95), new model dummy (9.90) and fuel efficiency (1.61). For the class of 1500 to 2000 cc, previous year's sales (1.00), new model dummy (10.18), fuel efficiency (0.59), interior volume (0.58) and engine power (0.52) are selected. For the class of over 2000 cc, previous year's sales (0.92), new model dummy (8.05), interior volume (0.45), engine power (0.63) and price (-0.61) are selected. Correlation between estimated and actual share is over 0.85 through all the results and all t-values are significant at 95 percent level. Level 2 shows the choice of the displacement. The explanatory variable of three alternatives that have lower levels is logsum variables. For the class of under 660 cc, average width of vehicles is selected considering the deregulation for the vehicle size in 1998. The coefficient estimates of logsum variables are 0.25, 0.27 and 0.59 for 660 to 1500 cc, 1500 to 2000 cc and over 2000 cc. The coefficient of average width of "Kei" cars is estimated at 0.67. In the second step, the coefficient of an underlying attribute is estimated. In this study, the underlying attribute is the tax because no tax revision between 1998 and 2001 prevents the attribute from being selected as a significant variable. The term of taxes is added to the utility function f/ of each car models as f i --" Vi "]- r T m

where i and m shows a car model and displacement class,

Tm

(1) is the amount of change of tax compared

with previous year, and r is the coefficient of tax to be estimated. The addition of the term does not influence on the choice in Level 1. In Level 2, however, the term of taxes affects the choice of the displacement. The logsum variable S m of the displacement class m is expressed using the former logsum variable

S m,

S-m = In ~ exp(V/+

(2)

rTm) = S m + rT m

keB m

The coefficient r is estimated by applying the statistic of market share around 1989 when the tax system is reformed. As a result, the estimate of r is -0.24 (104yen/year)-1. Level 2

Level 1

~ 'all Over 2000 cc

I

Model i I Mod(~,';I ,l

' ~l/...J 1500to 2000' ~ . ~ Model 1 ]

[ Passenger~"'~1

,c_) l

CC

I~!

cc

66om15oo'

, Model

1 ]

Model n I

c(:"l ("Ker'car) I

Under 660

Figure 1: Nested logit model on the car type preference

1772 The model developed is applied to the simulation of a green taxation scenario that the new tax in proportion to the fuel efficiency is substituted for the present car ownership tax. We assume a revenue-neutral taxation is adopted and the minimum tax level is not less than 7200 yen/year that is the tax charge of"Kei" cars. The tax rate is determined based on the market of 1996 and the simulated period is from 1998 to 2001. The taxation of "Kei" cars is assumed as the same as present. Figure 2 depicts the comparison between the present and simulated tax in 2001. As a result of imposing such taxation, the preference of consumers shifts to more fuel-efficient cars and then CO2 emissions can be reduced. Table 2 shows that CO2 emissions can be reduced by about three percent in the flow base. The market share of each displacement class in 2001 changes as shown in Table 3. The number of big-size cars is replaced with small-size cars. 120000 "" 100000 80000 "~ 60000 40000 20000

• k

0

• Simulated L]

10

20

30

40

10.15-mode fuel efficiency(kin/I)

Figure 2: Comparison between the present and simulated tax Present TABLE 2 ESTIMATED CHANGES OF CO2 EMISSIONS BY GREEN TAXATION (MTON-C) Without green taxation With green taxation 1998 4.00 3.88 1999 3.78 3.67 2000 3.96 3.84 2001 3.71 3.62 TABLE 3 ESTIMATED CHANGES OF MARKET SHARE OF EACH DISPLACEMENT CLASS Year 2001 actual Year 2001 with green taxation Under 660 cc 0.27 0.26 660 to 1500 cc 0.20 0.22 1500 to 2000 cc 0.32 0.34 Over 2000 cc 0.21 0.19 CONCLUSIONS A car type preference model is developed for the purpose of analyzing the CO2 reduction effects of green taxation of car possession. While the preference model basically adopts the framework of nested logit, we propose a methodology to find the coefficient estimate of an underlying explanatory variable that is not significant apparently. The model developed is applied to the simulation of a green taxation scenario that the new tax in proportion to the fuel efficiency is substituted for the present car ownership tax. Assuming the minimum tax level is not. less than 7200 yen/year, we estimate that CO2 emissions reduction is by approximately three percent in the flow base. REFERENCES 1. Hasuike, K. (2001) MEc Thesis, The University of Tokyo, Japan 2. Tanishita, M., Kashima, S. and Endo, K. (2000) Infrastructure Planning Review, 23, 587. 3. Hayashi, Y, Kato, H. and Ueno, Y. (1999) Transport Policy Studies' Review, 2, 002. 4. Fullerton, D. and West, S. E. (2000) Working Paper 7774, National Bureau of Economic Research, USA 5. Yoshida, Y., Nakatsuka, S., Matsuhashi, R. and Ishitani, H. (2002), The Transactions of the Institute of Electrical Engineers of Japan, 122-C, 868. 6. Sagawa, N. and Sakaguchi, T. (2000), Proceedings of the 16th Conference on Energy, Economy, and Environment, Japan. 7. Ben-Akiva, M. and Lerman, S. R. (1985). In: Discrete Choice Analysis: Theory and Application to Travel Demand. The MIT Press, Cambridge.

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1773

A F R A M E W O R K FOR GREENHOUSE GAS RELATED DECISION-MAKING WITH INCOMPLETE EVIDENCE A. J. P. Fletcher ~, J. P. Davis 2, W. W. Shenton 1, B. Han 1 and J. Pang 3 l CSIRO Petroleum, PO Box 1130, Bentley, WA, Australia 2 Dept of Civil Engineering, University of Bristol, Queens Building, University Walk, Bristol, UK 3 CSIRO Petroleum, PO Box 3000, Glen Waverley VIC, Australia

ABSTRACT The complex decisions involved in managing greenhouse gas mitigation strategies have many facets. They involve many types of data and shades of opinion. Even when the decision has been made, its explanation and elucidation amongst stakeholders is always contentious, partly because of the difficulty of showing how the decision was made. The data input to a policy or strategic decision will vary from the output of complex computer models, through empirical studies to arguments from analogues and the codification of expert opinion. If we want to manage these disparate elements to produce a coherent and explainable decision, then a framework which will allow the mixing of the various data inputs (the 'chalk and cheese') is required. It is proposed that the hierarchical process modelling approach can be used to encapsulate all these various forms of information and structure them into a coherent whole. The approach is based on Koestler's ideas of holons. When an uncertainty calculus is embedded into the process model the users can express the dependability of the various items of information and the weight they have in the decision making process. The idea has now been used in a variety of contexts and has proved very valuable in allowing teams to come to a common understanding of the state of their data and to communicate it to partners, superiors and other stakeholders.

INTRODUCTION Decision-making is fundamental to management of the environment. Decisions range across technical, economic, commercial and political issues. Yet traditional science and the associated tools have very little to offer when issues of judgment, interpretation and choice of action arise. Decision-making should take account of the full context within which the decision is made but often it does not. We want to make "reasonable" decisions that will allow the management of the uncertainty within that context, addresses the qualitative as well as the quantitative, is transparent and auditable, and allows learning. At present there are two distinct approaches. On the one hand, narrow reductionist and quantitative models address 'hard' issues, sometimes becoming a slave to numerical techniques and abstractions giving 'paralysis through analysis.' On the other hand, a perception that some problems are too complex to analyze systematically, results in fragmented and inconsistent decisions made on ad hoe or purely personal bias. In

1774 other words, decision-makers are often trapped between approaches designed to address clearly defined, well structured, 'technical' problems and the complex and dynamic real world. We believe there is a coherent middle way to decision-making, and this paper focuses on a modeling approach and philosophical framework that allows explicit incorporation of vagueness and incompleteness into decision-making. The approach is called Juniper and is rooted in epistemic probability. We assess uncertainty at all levels and seek insight - not necessarily answers or optimality. Most of all we adopt a coherent modeling approach that captures the problem as a w h o l e - resulting in common framework for discussion, agreement and action.

SUMMARY OF THE JUNIPER APPROACH

The methodology of the approach known as Juniper has been presented previously [1,2]. There are three main elements in this approach: • •

•

A process model of hierarchical structure that encapsulates the systems framework used to determine a particular result. The second is an interval probability calculus that allows the uncertainty in the processes to be expressed in a rich 'open world' manner and then enables it to be combined as evidence for the success of the top process of the hierarchy. The third is a system (developed from Grounded Theory and Deconstruction methods) that provides a commentary on the way the data and information is elicited and put together, illustrating where the major uncertainties lie.

The systems framework for decision-making is both critical, and unique to the Juniper approach. It is descriptive rather than prescriptive. The framework is 'open world' which allows issues of completeness, alternative hypotheses, and relevance to be addressed. Techniques such as discounted cash flow, decision tree, Monte Carlo, Portfolio Theory and Real Options Theory address the quantitative side of economics focused decision-making with great success. The 'hard' numbers and prescriptive solutions have a considerable track record of success in some industries. Yet this is not the whole story. While structured quantitative analysis is part of the decision-making process, qualitative intuition and judgment are extremely important. Everyone recognizes the importance of intuition in management. Do we believe in this decision? Have we done enough to make this project a success? In this type of subjective assessment, intuition (or 'gut feel') is very valuable. It draws on the judgement and insight built up through years of experience. The aim has been to provide the decision-maker with realistic information on the state of knowledge about the project - how dependable is it? For instance - the reliability that can be placed on containment properties of a geological sequestration site, or the dependability of the models predicting changes to global weather patterns. It acts like an uncertainty simulator allowing "what if" scenarios to be played on the processes involved in a particular decision. We can demonstrate we've made a 'reasonable' decision. However, a lack of tools prevents this kind of systems approach from being implemented. The problem is to encapsulate the whole of the problem, linking in all aspects. Koestler's [3] solution to this is his view of the world as being hierarchical. Or to be more precise, a world made up of a series of interconnecting hierarchies. The elements of the hierarchy he refers to as holons - parts but also wholes. Dias & Blockley [4] defined the core concepts of a systems approach as being; "the interconnectedness of hierarchically arranged concepts (after Koestler's holons); and process loops which included the participation of the change agent to produce learning". The natural extension of this is to make the processes be the holons. An important feature of Juniper is the recording of attributes. This information gives a full description of the why, when, where, what, who and how history of decision-making (and project management), essential for corporate memory and learning. The attributes of the process include:

1775 People issues - Players & Points o f View, Client, Stakeholders. • Objectives & Criteria for Success- How will we know if this has been a real success? • Hazards & Vulnerabilities - What are the 'banana skins 'on which we might slip up? • Timing & Resourcing - What is required o f us and what are the constraints? •

Interval Probability Theory [5,6] forms the mathematical basis of the Juniper approach and gives an expression of uncertainty and provides the means of propagation. It is derived from axioms of classical probability with the exception of the additivity condition: p(A) ~ 1 - p(not A): The evidence for a process meeting its objectives is separate from the evidence against it doing so, as opposed to the classical way of giving a single probability figure for success and assuming the evidence against it is 1 - (single figure). The an interpretation of this is shown in Figure 1. A basic Juniper model for ocean disposal of carbon dioxide is shown in Figure 2. Social, economic and technical issues are decomposed and judgments of sufficiency, S (the weight that the parent succeeds if the child succeeds), necessity, N (the weight that the parent fails if the child fails, dependency (commonality of the sources of evidence), and the evidence for success of the process (green) and failure of the process (red), are input as discussed elsewhere [ 1,2]

Evidence that A is successful

Lack of Evidence

Evidence that A is not successful

I

II

II

I

0

Sn(A)

Sp(A)

1

Sn(A) 1- Sp(A) Sp(A) - Sn(A)

= Evidence that A is successful = Evidence that A is not successful = Uncertainty in the evidence

Figure 1: Representing uncertainty and lack of evidence.

1776

ll

m

i

1

l

l

Figure 2: Juniper model; ocean disposal of carbon dioxide. REFERENCES

I.

2.

3. 4. 5. 6.

J P Davis and A J P Fletcher, (2000), Managing Assets Under Uncertainty, Paper presented at the SPE Asia Pacific Conference on Integrated Reservoir Modelling for Asset Management, Yokohama, Japan, April 25-26, (2000). A J P Fletcher, (1997), A New Approach to Handling Reservoir Uncertainty- A Juniper Programme Update, paper presented at the CMPT Emerging Technology for E & P Forum, held at the Aberdeen Exhibition and Conference Centre, March 20-2 l, (1997). Arthur Koestler, The Ghost in the Machine, Arkana Books, ISBN 014 019192 5. W P S Dias and D I Blockley, Reflective Practice in Engineering Design, Proc. Instn. Civ. Engrs, Civil Engmg, 108, Nov., 160-168, (1995). W Cui and D Blockley, Interval Probability for Evidential Support, Int. J. of Intelligent Systems 5, 183192, (1990). J Hall, D Blockley and J Davis, (1998a), Uncertain Inference Using Interval Probability Theory, Int. J. of Approximate Reasoning 19, 247-264, (1998).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1777

COMPLEX PROBLEMS WITH INCOMPLETE EVIDENCE: MODELLING FOR DECISION-MAKING A. J. P. Fletcher 1, j. p. Davis 2, W. W. Shenton l, B. Han I and J. Pang 3 l CSIRO Petroleum, PO Box 1130, Bentley, WA, Australia 2 Dept of Civil Engineering, University of Bristol, Queens Building, University Walk, Bristol, UK 3 CSIRO Petroleum, PO Box 3000, Glen Waverley VIC, Australia

ABSTRACT A wide variety of models are generally used to help in decision making. With reference to the parameters and structure of a model, four basic types can be identified depending on the degrees of vagueness and completeness. We propose that epistemic probability, firmly rooted in the concept of probability as an attribute of opinion and argument, is an appropriate way to handle problems where there are significant issues of incompleteness and vagueness in the modeling. Uncertainty is handled in an effective manner through argument and justification.

INTRODUCTION Green house gas mitigation is a complex environmental problem. Although there are clear scientific and engineering problems, there are also major social and economic issues that need to be addressed. We need to consider environmental issues in an appropriate manner. We propose to structure the issues in terms of models that range from 'hard' scientific models to 'soil' narrative structures in the spirit of Toulmin [1]. 'Hard' models involve abstract concepts, and the insistence on explanations in terms of universal l a w s - with formal, general, timeless, context-free, and value-neutral arguments. 'Soft' models include the study of factual narratives about particular situations, in the form of substantive, timely, local, situation-dependent, and ethically-loaded argumentation.

FOUR TYPES OF MODEL We define a problem as a doubtful or difficult question to which there may be a number of answers. It is possible to characterize these problems in terms of models which are used to address these problems with their input / output parameters and their structure. For each type of model, specific approaches and techniques are often appropriate. Following Blockley [2] and Collingridge [3] we distinguish four types of model as summarized in Table 1. Type 1 models are deterministic and characteristic of much hard science and engineering. Under well defined circumstances, such as making carbon dioxide sequestration site capacity estimates with high quality data in sufficient quantity, they can give dependable answers. Type 2 models allow for inputs to be known only as distributions. These models are probabilistic and the basis of probabilistic capacity assessment, probabilistic risk analysis and many economic models. However, these models are applicable to closed world problems - in other words the sample space is closed. An important

1778

consequence of closed world models is that no possibilities outside those identified a r e ' c o n s i d e r e d - and therefore dependent on the ability of the decision-maker to imagine them all. The final probability figures are then relative measures in comparison with the total set. In a closed world all things are either true or false and there is no provision for any other state such as 'we don't know'.

Parameters

Structure

Table 1" Four Types of Model Consequences Examples

Type 1

Precisely Defined

Precisely Defined

All the consequences of adopting a solution are known

Type 2

Distributions

Precisely Defined

All consequences of adopting a solution have been precisely identified but onlythe probabilities of occurrence are known

Type 3

Relationsand Ranges

Imprecise but substantially complete

Type 4

Impreciseand Incomplete

Imprecise and Incomplete

All the consequences of adopting a solution have been approximately identified so the possibilities of ill defined or fuzzyconsequences are known Where only some of the consequences (precise or fuzzy) of adopting a solution h a v e been identified

• Individualchemical reactions • Deterministicequations in science, engineeringand economics • Probabilisticcapacity estimates • Probabilisticrisk assessment

Notes • Adequacyof these models depends on relationship of the model to reality

• Commodity price predictions • Globalwarmingand other environmental models • Geomodelsof subsurface structure from seismic

• Closedworld models in the sense that the sample space closed. • Dependenton the decision-maker identifying all possibilities. • Can handle vaguenessin the overall structure of the model • Detailedrelationships between parametersneed not be known

• Futuretechnologies • Valueof alternative energytechnologies. • Economicstabilityof regions and countries

• Real world 'messy', complex or 'wicked' problems • Issuesof relevance and completeness critical

Type 3 models are characterized by vagueness in the overall structure and with the input parameters expressible only as ranges and limits. Techniques such as imprecise probabilities (fuzzy logic's and Interval Probability Theory) have been developed to handle these models. In these models it is possible to talk in terms of probabilities of fuzzy events (probability of something being 'big') and o f fuzzy probabilities (a 'high' probability). Type 4 models are real open world problems where some things m a y be true, some m a y be false and some unknown. Type 4 models are characteristic of many complex situations where actions in the future and / or issues of relevance and completeness are central. M a n y of the problems concerning environmental issues and investment decisions are Type 3 and Type 4, as are all problems that include elements of human judgment, interpretation and choice. One of the great challenges to both science and philosophy is to provide a rational coherent account of the perceived uncertainty surrounding the events of human judgment and interpretation as discussed by Casti [4]. The role of classical probability and newer approaches is discussed below, however first we need to recognize that most of the uncertainty we experience about decision-making in the real world cannot usually be attributed to the influence of random mechanisms at all. Rather it seems to stem from an inherent vagueness, or lack of information, either in the linguistic description or in other circumstances surrounding the situations we find ourselves confronting [4]. The main problem we need to address is the belief that you can apply classical probability and Bayesian probability (Type 2 approaches) to Type 3 and Type 4 problems without reference to context - the where and the when as discussed by Toulmin [ 1]. Many of the problems concerning the environment are Type 3 and Type 4 and the Juniper approach has been specifically designed to address these types of problems.

1779 Some Differences Between Classical Probability and Theories of Evidence The development of the mathematical formalism known as Bayesian Probability has strong roots in the statistical analysis of games of chance [5]. This approach both imposes a strict discipline on knowledge engineering, and provides a useful tool for representing and updating subjective probabilities. It will serve us if we are satisfied that: •

• • •

Knowledge can reasonably be assumed to satisfy the axioms of subjective probability [5] (for example, that all the propositions are well defined, that a degree of belief can, in principle, be assigned empirically to all atomic and conditional propositions); There is access to the appropriate source (e.g. experts) from whom both a qualitative domain model and the relevant probabilities can be elicited; In the domain it is not necessary to reason explicitly with non-probabilistic sources of uncertainty (such as contradictions, vague propositions etc.); The domain is reasonably constrained in its size, yet there is sufficient data to generate prior probability assignments followed by sufficient data to update the priors so that the outcome is not overwhelmed by the prior assessment.

Theories of evidence (TOE) or epistemic probability have two key distinctions from Bayesian or classical probabilistic approaches. The first is the rejection of the law of additivity for belief in disjoint propositions or sets of propositions. In one form the law of additivity states that the belief in a proposition and the belief in the negation of the same proposition should sum to one. This implies that the absence of belief in a proposition necessarily implies a corresponding belief in the negation of that proposition. This is rejected as too strong a constraint in the context of most 'real' world problems; I may only have weak evidence that supports the belief in a geological sequestration sight being faulted to a degree that seriously affects storage characteristics, but have no evidence at all that the geological storage efficiency will not be affected by faulting. Consequently, TOE admits a second form of expression of ignorance; complete non-commitment to the truth of a proposition or it negation. The second distinction is that TOE have operations for the pooling of evidence from a variety of sources. Belief from one argument may be transferred to a hypothesis set supported by a second argument, and combined with that arguments belief. This notion of pooling of evidence, or the aggregation of arguments, has foundations that predate the development of the Bayesian model of probability, and have no natural counterpart in that model. [Pooling of evidence is traced back to Ancient philosophy, but is a particular feature of medieval and Renaissance philosophy [6]. It has been argued [5] that empirical studies of human reasoning to date tend to support the view that Bayesian probabilistic reasoning is prescriptive rather than descriptive as a model of human reasoning. Are there lessons that can be learned from a more descriptive model? In the absence of trustworthy numerical estimates of the frequency of occurrence of an outcome in a given situation, one will often find oneself weighing up the arguments pro and con to assess the likelihood of the outcome of interest. This intuitive approach is open to certain biases[5]. Nevertheless, this view of probability as being based on the assessment of prior knowledge, epistemic probability, has a very different motivation to probability based on the analysis of games of chance. Epistemic probability need not be numerical; it is an attribute of opinion, and not of the mathematics of randomness or chance. The probability of a proposition does admit of degree, but this degree is a function of the number and weight of the arguments for and against that proposition. We believe that epistemic probability, firmly rooted in the concept of probability as an attribute of opinion and argument, is the most appropriate way to handle Type 3 and Type 4 problems. Uncertainty when associated with incompleteness and vagueness is handled more satisfactorily through argument and justification than the concept of chance. This is what Juniper seeks to achieve.

1780 REFERENCES

1. 2. 3. 4. 5. 6.

Stephen Toulmin, (2001), Retum to Reason, Harvard University Press, ISBN 0-674-00495-7. D I Blockley, (1992), Uncertainty Analysis in Structural Engineering, Anal. Acad. Nac. Cs. Ex. Fis. Nat., Buenos Aires, tomo 44, (1992). D Collingridge, Milton Keynes, The Social Control of Technology, The Open University Press, (1980). J Casti, Reality Rules - Picturing the World in Mathematics, Vols I & II, John Wiley & Sons, ISBN 0417 184365 Paul Krause and Dominic Clark, Representing Uncertain Knowledge, Intellect Books, ISBN 1 871516 17X. B Russell, George Allan and Unwin, History of Western Philosophy, London, (1961).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1781

THE NEED FOR RENEWABLE E N E R G Y WITH EMPHASIS ON SOLAR IN RURAL U G A N D A Robert Kabaseke National Co-ordinator, Uganda Association for Child Affairs and Social Environmental Development

Uganda has a population of 22 million of which 80% live in the rural setting whereby they cannot easily access the national grid. Uganda lies along the Equator, which means it gets at least eight hours of solar radiation, making it easy to have a good level of electrification through the use of solar panels. The level of national personal incomes makes it difficult for many people to afford electricity for all purposes and means that even those cormected to the grid need to use solar power for water heating. It will be observed that the increased use of solar energy contributes to the reduction in GHGs. The other benefit is the improved quality of life achievable by the rural population. In 1998, the Government of Uganda started a project known as the Photovoltaic Pilot Project for Rural Electrification (UPPPRE) funded by the United Nations Development Programme/Global Environment Facility. The main objective of the project is to develop markets and establish a foundation for sustainable use of solar PV for rural electrification in areas remote from the national grid. The project had several components as outlined below. •

Public awareness

With the introduction of the credit mechanism through village banks, public awareness emphasis moved from general sensitisation to target groups, particularly the potential consumers such as bank customers and bank officials. Following the first batch of installations, the village banks have reported an increase in customers opening bank accounts to benefit from the credit facility. To date, of the 2612 systems installed, 506 have been installed by end-user credit through these village banks. •

Capacity building

Sixteen local technicians were trained in provision of a•r-sales services to the end users in major trading centres in the pilot zone. These technicians have been introduced to companies that sell PV systems.

1782 •

Establishment of standards

Standards, which had been under development, were gazetted. The areas covered are:o o

Lighting Code installation

Other areas for which standards are in the process of development are for:o o o •

Batteries Regulators and inverters Testing procedures

Financing

a. Vendor loans These loans, whose interest rate is 12%, have contributed to the visible increase of the PV stock with vendor companies and, possibly the 30% or so reduction in the price of PV systems over the last 3 years. b) End User Loans The terms of borrowing for end users have been improved through the utilization of the village banks. Two more banks will have funds disbursed to them in the near future. The repayment rate is currently 100%.

Solar Water Heating The following is being undertaken in the field of the application of passive solar energy for purposes of water heating: •

Increase public awareness about the value of using Solar Water Heaters (SWHs).

•

Building capacity among the Uganda Renewable Energy Association (UREA) members to manufacture SWHs.

•

Setting up 20 demonstration solar water heaters across the country.

•

Manufacture of 50 SWHs by UREA companies to be sold on a cost-sharing basis.

The Linkages Between Solar Energy Application and Greenhouse Gases - The Uganda Case Rural homes in Uganda have previously relied on paraffin, a petroleum product, to provide their lighting requirements. These sources of fuel have the following inherent effects:

1783 • • •

The emissions arising out of their combustion are a mixture of gases, some of them having direct immediate health impacts such as various chest infections. The other effects due these gases are components such as carbon dioxide, a greenhouse gas. Other effects that arise are the loss of productive times that result from the need for treatment for those affected, not forgetting the costs involved.

Way Forward •

To increase the level of rural electrification through the application of solar energy would several benefits such as: 1. Have a situation of avoided emissions, because of the nature of the energy source. 2. Improve the general health of the people and their productivity. 3. Allow people to access modem technology and information since the means to power the will be available.

•

To continue with the programme outlined earlier and source the means to finance them in a sustainable manner.

Constraints •

Competition for the available funds by different sectors.

•

The incomes of the rural population are low, as earlier indicated, and this makes it hard for them to afford paying for the systems easily.

CONCLUSIONS The need to reduce emissions of greenhouse gases is paramount and therefore calls for joint implementation of the Kyoto Protocol. The Government of Uganda is making every effort to make provisions in its budgets so that rural people can benefit from electrification programme. Solar energy must be made affordable to even the poorest of the poor and this is geared towards combating excessive emission, which pose several present and potential hazards to communities, countries and the entire globe.

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NON C02 - GASES

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1787

THE NON-CO2 GREENHOUSE GASES NETWORK John Galel, Francisco de La Cheshnaye 2 and Matti Vianio 3 1. IEA Greenhouse Gas R & D Programme, Cheltenham, Glos. GL52 7RZ, UK 2. United States Environmental Protection Agency, Washington DC 20460, USA European Commission, Directorate General Environment, Wetstraat 200, B 1049, Brussels, Belgium

ABSTRACT The IEA Greenhouse Gas R&D Programme, United States Environmental Protection Agency (US EPA) and the European Commission, Directorate General Environment have co-operated together to form a Non CO2 Greenhouse Gases Network. The objective of the a network is to bring together an international team of leading researchers and policy advisors to compare data, mitigation technology analyses, economic modelling approaches and empirical results on the Non CO2 greenhouse gases. This poster paper outlines the activities that the network has undertaken since its inception and June 2001 and outlines plans for future work.

INTRODUCTION The IEA Greenhouse Gas R&D Programme (IEA GHG), United States Environmental Protection Agency (US EPA), the Environment Directorate of the European Commission (EC DG Env.) have all undertaken extensive work to assess technology options for reducing the Non CO2 Greenhouse Gases. Some examples of the work undertaken by these groups can be found on their respective web sites [ 1,2,3]. The technology options are expressed as marginal abatement cost curves for the Non CO2 Greenhouse gases. An example of such a cost curve is given in Figure 1. WORLD (2010 1 2020) 100

¢~ 0 O

80 2010

~ 4o ,..,.

~

~o

100

200

300

400

500

600

700

8:

-20

Abated emissions [MT CO2 eq per year]

Figure 1: Global Cost Abatement Curve for High Global Warming Potential Gases 1

t Source: IEA GreenhouseGas R&D ProgrammeReportNo. PH3/35, February2002.

1788 Such curves are based on technology developments and are referred to as "bottom up" marginal cost abatement curves. It was felt by the three the organisations concerned, that there was considerable merit in working together and sharing data so that an understanding of the different approaches used the development of technology based marginal abatement cost curves could be derived. In this way, a common approach could be made to the economic modelling community who are now making efforts to include the Non CO2 greenhouse gases cost curve data in their "top down" economic models. The decision was therefore taken to establish a network of those groups working on the Non CO2 greenhouse gases. In this way the aim was to bring together an international team of leading researchers and policy advisors to allow them to: • • • •

compare their data sets, review their respective analyses of mitigation technologies, compare their economic modelling approaches, and compare their empirical results on the Non CO2 greenhouse gases.

One of the objectives was also to identify areas where there were gaps in the understanding of the role of the Non CO2 greenhouses gases and so aid the development of research strategies to address these gaps.

N E T W O R K M E E T I N G SUMMARIES To date the Network has held two meetings with a number of subsequent meetings to be held in the future. Summaries of the meetings held to date are presented.

InauguralMeeting The first meeting of the Non CO2 Greenhouse Gas Network was held in Brussels, Belgium on the 14th and 15th June 2001. The workshop was entitled "Mitigation technologies and economic analyses". The workshop was well attended with 45 delegates drawn from Europe, United States, Canada, Japan and South East Asia. There was a broad range of participation from governmental bodies, public research institutes, policy institutes, consulting groups and academia. The first meeting of the Network concentrated on establishing the state of research on mitigation technologies and economic analyses of the abatement options. In particular, the aim was to compare the different methodologies used by various workers to express the economic indicators, e.g. marginal abatement cost curves. In addition, the meeting aimed to consider the best way for this data to be incorporated into economic models for predictive purposes. The workshop was divided into two sections. On the first day, a series of presentations were made by organisations that had undertaken work on the development of "bottom up" marginal abatement cost curves. The presentations allowed a detailed comparison of the methodologies applied by each of the organisations in the development of their abatement cost curves. On the second day, a series of papers were presented that dealt with how Non CO2 greenhouse gases data had been utilised to date in the development of "top down" economic models. The workshop succeeded in establishing how the "top down" models had applied some of the cost curve data that was available now. The modellers indicated that more data was required and it was agreed that an action would be taken to identify the best methodology for providing the cost data. Overall, the workshop was considered to have been extremely successful. It was agreed that a second meeting would be held in conjunction with the Third International Symposium on Non CO/Greenhouse Gases (NCGG-3) to be held in Maastricht from 21 st to 23 rd January 2002 [4]. This meeting would be led by US EPA, who themselves would have a small group discussing how best to present the "bottom up" cost

1789 data for application in the "top down" economic models. This exercise would then be reported at the next meeting to be held in Maastricht.

Second Network Meeting The second meeting of the Network was held in Maastricht on 24 th and 25 th January 2001. The meeting was held jointly with a new working group established by the Energy Modeling Forum (EMF) to address multiple-greenhouse gas issues. The EMF (Energy Modelling Forum) was established in 1976 to provide a structured forum within which energy experts from government, industry, universities, and other research organizations could meet to study important energy and environmental issues of common interest. Further details of EMF activities can be found on their web site [5]. The EMF group will focus on modeling of Non CO2 gas abatement measures. working group will be a joint activity of EMF and the Network.

It is proposed that this

The objectives of this new working group are to: • • •

conduct a new comprehensive, multi-gas policy assessment, improve the understanding of the effects of including Non CO2 Greenhouse gases in short- and longterm mitigation targets, and advance the state-of-the-art in integrated assessment modeling.

This working group will also allow for improved cross-disciplinary relationships between "top-down" modelers, involved in integrated assessment modeling, and those involved in analysis and development of the "bottom up" Non CO2 greenhouse gas abatement measures. The joint meeting was very useful in helping the members of the Network inform the energy modelers about the state of knowledge on Non CO2 greenhouse gases, and to learn from the modelers about their interests and needs in respect of data on Non CO2 greenhouse gas abatement measures. The first day of the meeting was mainly devoted to presentations by top-down modelers interested in Non CO2 greenhouse gases. The second day focused on Non CO2 greenhouse gas emissions and assessments of specific abatement measures. The meeting agreed to proceed with the multi-greenhouse gas working group activity. A number of economic modelers expressed interest in participating in this activity including, Copenhagen Economics, RIVM 2 (IMAGE model), IAE 3 of Japan, PNNL 4, MIT 5, EPRI 6, ABARE and the POLES modeling group. The project will take some 18 months to complete; a follow-on meeting was scheduled for May 2002.

F U R T H E R N E T W O R K ACTIVITIES

Economic Modeling Study The joint EMF/Network activity to include the Non CO2 greenhouse gases data in the economic models is now underway. The activity is the latest in a series that have been completed by the EMF and is referred to as EMF21 [5]. As a first step in the exercise, experts from US EPA, EC DG Env. and IEA GHG as well as a number of consultants (who have been involved in the development of the respective cost curves for the organisations concemed) are engaged in developing a common data set to be included in the economic models. The data sets will then be utilised by the different modelling groups taking part in the EMF21 study and their results compared.

2National Institute for Public Health and The Environment, the Netherlands 3The Institute of Applied Energy, Japan 4 Pacific NorthwestNational Laboratory 5Massachusetts Institute of Technology 6 Electric Power Research Institute

1790 The EMF21 activity will be carried out between July 2002 and September 2003. The results of the study will be published as an EMF report and will be available on their vceb site when completed.

Agricultural Sector Studies For greenhouse gases like nitrous oxide and methane the agricultural sector make a significant contribution in global emissions of the anthropogenic greenhouse gases. It is recognised that there are considerable uncertainties with regard to emissions of the Non CO2 Greenhouse gases in the agricultural sector and how these emissions can be mitigated effectively and at what cost. It was agreed by the Network that the agricultural sector should be the focus of further additional work. The aim of such work would be to develop new estimates of the potential agricultural GHG mitigation, especially those related to rice, ruminants and soils and with a particular emphasis on Latin America and Asia. To begin this activity, it is proposed to hold a third workshop of the Network in November 2002, in Washington USA. The aim of the workshop will be to identify key mitigation options for greenhouse gas emissions from agriculture along with their cost and potential for reduction is important because of the large contribution these gases make to the emissions profiles of many countries. This information is necessary in developing marginal abatement cost curves and understanding the likely cost to meet specified emission reduction targets. It is hoped that the results of the workshop would contribute to a special report associated with broader projects, for example EMF 21 and the 3rd International Methane & Nitrous Oxide Mitigation Conference to be held in China in September 2003.

REFERENCES 1. IEA Greenhouse Gas R&D Programme - http://www.ieagreen.demon.co.uk 2. US EPA- http://www.epa.gov/globalwarming/publications/emissions/index.html 3. European Commission, Sectoral Studies Reportshttp://europa.eu.int/comm/environment/enveco/studies2.htm 4. van Ham, J. et al, (2002) Proceeding of the 3rd International Symposium on Non CO2 Greenhouse Gases, Millpress Science Publishers, Rotterdam, Netherlands 5. http://www.stanford.edu/group/EMF/home/index.htm

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1791

REDUCTION OF METHANE PRODUCTION FROM DAIRY COWS BY DECREASING RUMINAL DEGRADABILITY OF CONCENTRATED INGREDIENTS M. Kurihara l, T. Nishida 1 and A. Pumomoadi 2 1Department of Animal Physiology and Nutrition, National Institute of Livestock and Grassland Science, Tsukuba, Ibaraki 305-0901, Japan 2On leave from: Diponegoro University, Semarang 50241, Indonesia

ABSTRACT

Enteric fermentation by the global population of ruminant livestock is the largest single contributor to anthropogenic methane (CH4) emissions. Furthermore, CH4 gas produced in the rumen represents a significant loss (2-15 %) of gross energy from feed. To clarify the effects ofruminal degradability of protein (soybean meal or extruded soybean meal) and carbohydrate (whole steam-rolled corn or whole steam-rolled barley) sources on CH4 production, three lactating Holstein cows were fed 4 different treatments in a 3 x 4 Youden square experiment. Each cow was assigned one of 4 dietary treatments (2 x 2 factorial). The effect of the dietary treatments was not significant for milk yield (mean: 22.9 kg/day). CH4 production was highest (22.3 g/kg-Dry matter intake) for cows fed on soybean meal and barley, and was lowest (19.4 g/kg-Dry matter intake) for cows fed on extruded soybean meal and corn. Cows fed on extruded soybean meal tended to produce 0.9 g/kg-Dry matter intake, or 5% less CH4 gas than those fed on soybean meal (p<0.1). Cows fed on corn produced 1.9 g/kg-Dry matter intake, or 9 % less CH4 gas than those fed on barley (p<0.05). The degradability of Italian ryegrass hay in the rumen of cows fed on soybean meal (mean: 55.6 %) tended to be higher than that of cows fed on extruded soybean meal (mean: 51.3 %). Our results suggest that CH4 production from lactating dairy cows is associated with ruminal degradability of protein and carbohydrate sources.

INTRODUCTION

The enteric fermentation of the global livestock population is the largest contributor to anthropogenic CH4 emissions from all sources, with cattle being responsible for 73 % of total livestock methane emissions [ 14]. CH4 gas also represents a significant loss (2-15 %) of gross energy from feed [3]. Methane is produced in the rumen, mainly, from hydrogen and carbon dioxide by hydrogenation [4]. For digestion to precede normally, the partial pressure of hydrogen in the rumen needs to be kept below 10-3 atmospheres [7]; the formation of CH4 gas eliminates this disruptive factor. CH4 production is affected by various nutritional factors including level of intake, type of carbohydrate, forage processing, addition of chemical agents in the diet, and changes in the ruminal microflora [6]. Many different chemical agents have been shown to reduce CH4 production, including ionophores [13], unsaturated fatty acids [2,8,13], and a

1792 chemical complex of bromochloromethane (BCM, halogenated methane analogues) and alpha-cyclodextrin [9,13]. In many countries, however, increasing numbers of consumers are choosing organically raised foods. In developing CH4 mitigation strategies for ruminant livestock, researchers need to avoid compromising food safety as well as animal productivity. As protein and carbohydrate are the major nutrients supporting microbial growth and animal productivity, the objective of this experiment was to determine the effects of ruminal degradability of different sources for these nutrients on CH4 emissions from lactating dairy cows and on their productivity.

MATERIALS AND METHODS

Three Holstein lactating cows, age 6 - 7 years, initially weighting 600 - 720 kg and initially producing 20 30 kg of milk per day, were used in a 3 x 4 Youden square experiment conducted over four periods. During each period each cow was assigned one of 4 dietary treatments (2 x 2 factorial). Each treatment matched one of two protein sources (soybean meal (SBM) or extruded soybean meal (ESBM)) with one of two nonfibrous carbohydrate sources (whole steam-rolled corn (SRC) or whole steam-rolled barley (SRB)). The ESBM was passed through an extruder and dried at 135 C for approximately 10 minute. The cows' total diet consisted of approximately 50% Italian ryegrass hay, approximately 50% concentrate (i.e., one of the 4 dietary treatments), and a vitamin-mineral mixture--a diet designed to meet 110% of the metabolizable energy requirements for maintenance and milk production [ 1]. Cows were fed on each diet for two weeks. They were subjected to gaseous exchange measurements in open-circuit respiration apparatuses [5] during the last four consecutive days of each treatment. Data were gathered at Japan's National Institute of Livestock and Grassland Science and were analysed by least squares ANOVA using the general linear models procedure of SAS [11] with dietary treatments and period as factors. The significance of the difference between dietary treatment means was determined using a Tukey's studentized range test.

RESULTS AND DISCUSSIONS

TABLE 1 LEAST SQUARE MEANS OF LIVE WEIGHT, INTAKES AND DIGESTIBILITY OF NUTRIENTS, AND MILK YIELD AND COMPOSITION AT 4 DIETARY TREATMENTS SBM-SRC ESBM-SRC SBM-SRB ESBM-SRB SEM Live weight, kg 651 653 648 651 6 Intake, kg/day Dry matter 19.6 19.8 19.4 19.9 0.09 NDF 7.9a 8.1a 7.6b 7.9 0.04 Digestibility, % Dry matter 69.0 70.4 67.8 67.3 0.6 NDF 58.7a 61.6a 55.5b 54.2b 0.4 Ruminal degradability, % Italian ryegrass hay 55.8 52.8 55.5 49.7 1.7 Milk yield, kg/day 23.1 23.5 22.2 22.8 0.5 Milk composition, % Fat 3.85 3.69b 3.80b 4.20a 0.08 Protein 3.33 3.33 3.37 3.27 0.03 Dietary treatments: Cows were fed soybean meal (SBM) or extruded soybean meal (ESBM) as their main protein source, with whole steam-rolled corn (SRC) or whole steam-rolled barley (SRB) as their main nonfibrous carbohydrate source. SEM, standard error of means; NDF, Neutral detergent fiber; a, b, p<0.05.

1793 The crude protein, ether extract, neutral detergent fiber (NDF) and non-fibrous carbohydrate (NFC) consumed by the cows in this experiment were 16.3 - 17.3 %, 2.1 - 2.9 %, 39.4 - 40.8 % and 30.8 - 32.1 %, respectively. The content of these nutrients did not differ significantly among the four treatments. The live weights of dairy cows did not differ significantly among the 4 treatments (Table 1), nor were dry matter (DM) intake and digestibility affected by the dietary treatments (mean: 19.7 kg/day and 68.6 %). NDF intake and digestibility were lower for cows fed on SRB (mean: 7.8 kg/day and 54.9 %) compared to that for cows fed on SRC (mean: 8.0 kg/day and 60.2 %). Dietary treatments did not significantly affect milk yield (mean: 22.9 kg/day) or milk protein content (mean: 3.33%). Milk fat content of the ESBM-SRB treatment (4.20 %) was highest of all treatments. However, milk fat contents of the other treatments (mean: 3.78 %) were also fairly high.

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Figure 1: Daily methane (CH4) production (A: g/day), CH4 production per unit of dry matter intake (B" g/kg-DMI) and CH4 production per unit of 4% fat corrected milk (C: g/kg-4%FCM) by cattle at 4 dietary treatments Daily CH4 production tended to be highest for cows fed on SBM and SRB (430 g/day), and was significantly lower for cows fed on SRC (391 g/day) (Figure 1). CH4 production per unit DM intake was highest for cows fed on SBM and SRB (22.3 g/kg-DM intake), and was lowest for cows fed on ESBM and SRC (19.4 g/kg-DM intake). From the predictive equation of Shibata et al. [12], which is based on data collected from sheep, goats, heifers, fattening steers, and dry and lactating cows, the CH4 production of cows in the present experiment should be 1 6 - 21 g/kg-DM intake. The CH4 production of lactating dairy cows fed on a range of 30 % forage and 70% forage diets have been reported at 18.5 - 23.8 g/kg-DM intake [8]. These reported values are not different from our measured values (17.9 - 22.5 kg/-DM intake). Cows fed on SRC produced 1.9 g/kg-DM intake, or 9 % less CH4 gas than those fed on SRB (p<0.05).

1794 Cows fed on ESBM tended to produce 0.9 g/kg-DMI or 5% less CH4 gas than those fed on SBM (p<0.1). CH4 production per 4% fat corrected milk (FCM) tended to be lower for cows fed on SRC (17.5 g/kg4%FCM) (p=0.11). However, the effect of the protein source on CH4 production (g/kg-4%FCM) was not significant. From the predictive equation of Kurihara et al. [8], which is based on data collected from lactating dairy cows, the CH4 production of cows in the present experiment should be 16 g/kg-4%FCM. This predicted value is within the range of our measured values (15 - 24 g/kg-4%FCM). Although there were no differences in ruminal degradability of Italian ryegrass hay among the 4 dietary treatments (mean: 53.5 %), the hay degradability of SBM treatments (mean: 55.6 %) was consistently higher than that of ESBM treatments (mean: 51.3 %)(Table 1). This means that cows fed SBM, which contains more rumen degradable protein than ESBM, were also able to digest more fibrous carbohydrates. Similarly, cows fed SRB, which contains more rumen degradable starch than SRC [ 10], experienced more non- fibrous carbohydrate fermentation than those fed SRC. Therefore, in the rumen of cows fed on SBM and SRB, rumen microbes seem to ferment more carbohydrates, producing more hydrogen and carbon dioxide, the major precursor gases of CH4 in the rumen [4]. In the present study, the CH4 production of SBM-SRB treatment was the highest of all 4 treatments. Our results suggest that CH4 production from lactating dairy cows is associated with ruminal degradability of protein and carbohydrate sources. Further investigation is required to identify the optimal ruminal degradability for concentrated ingredients (i.e. mixtures of concentrate ingredients) for increasing feed conversion efficiency and decreasing CH4 emissions.

REFERENCES

10. 11. 12. 13. 14.

Agriculture, Forestry and Fisheries Research Council Secretariat. (1994) Japanese Feeding Standard for Dairy Cows. Chuouchikusankai. Tokyo. Blaxter, K.L. and Czerkawaski, J. (1966) Jr. Sci. Food Agric. 17, 417. Czerkawski, J.W. (1969) World Review of Nutrition and Dietetics 11,240. Hungate, R.E. (1967) Arch. Microbiol., 59, 158. Iwasaki, K., Haryu, T., Tano, R., Terada, F., Itoh, M. and Kameoka, K. (1982) In: Bull Nat. lnst. Anim. Indust. 39, 41. Jhonson, K.A. and Johnson, D.E. (1995) J. Anim. Sci. 73, 2483. Joblin, K.N. (1999) In: Meeting the Kyoto Target. Implication for the Australian Livestock Industries, pp50-55, Reyenga, P.J. and Howden, S.M. (Eds.). Bureau of Rural Sciences, Canberra. Kurihara, M., Shibata, M., Nishida, T., Pumomoadi, A. and Terada F. (1997) In: Rumen Microbes and Digestive Physiology in Ruminants, pp. 199-208, Onodera, R. and et. al. (Eds). S. Karger, Basel. McCrabb, G.J., Berger, K.T., Magner, T., May, C. and Hunter, R.A. (1997) Aust. J. Agric. Res. 48, 323. Nocek, J.E., and Tamminga, S. (1991)J. Dairy Sci. 74, 3598. SAS Institute (1988) User's Guide: Statistics, Version 6.03 Edition. SAS Institute, Inc. Cary, NC. USA. Shibata, M., Terada, F., Kurihara, M., Nishida, T. and Iwasaki, K. (1993) Anim. Sci. Technol. (Jpn.) 64, 790. Van Nevel, C.J. and Demeyer, D.I. (1996) Environ. Monitoring Assessment. 42, 73. United States Environment Protection Agency. (1994) International Anthropogenic Methane Emissions: Estimates for 1990. (Office of Policy Planning and Evaluation, Washington DC).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1795

D Y N A M I C M O D E L FOR THE M E T H A N E EMISSION FROM MANURE STORAGE M.A. Hilhorst & R.M. de Mol IMAG, P.O. Box 43, 6700 AA Wageningen, The Netherlands ABSTRACT Methane emissions from agricultural sources should be calculated in accordance with the IPCC good practice guidelines, based on emission factors and activity data. Emission factors are based on the volatile solids content, biodegradability and methane conversion factor (MCF), which differ per management system and climate region. Not included in the IPCC models are dynamic factors of storage systems, like storage time, loading and unloading rates and temperature. A new dynamic model has been developed to include these factors and the effect of the temperature. A slurry pit stora/~e is an accumulation system. Experimental results of Zeeman (1991) showed that the emission velocity (m~/h) is linearly increasing with filling time, i.e. the relation between emission (m 3) and filling time is quadratic. The model is used to derive values for the MCF, depending on filling time and temperature. The dynamic model has been applied to a typical dairy and pig farm, with a large effect on the emission figures. The proposed model can be used to improve calculations of national emissions. INTRODUCTION

The methane emissions from liquid manure are an important source of greenhouse gases from agriculture. Methanogenic bacteria produce methane when manure decomposes in an anaerobic environment. Manure management practice is a dominant factor that determines the methane emissions (IPCC, 1996). Emissions of methane from agricultural sources should be calculated in accordance to the IPCC Reference Guide (IPCC, 1996) and Good Practice Guidance (IPCC, 2001). Emission factors are based on the volatile solids content, the biodegradability and methane conversion factor (MCF) which can be different per management system and climate region. Not included in the default IPCC methodology are the dynamic factors of storage systems like storage time, loading and unloading rates and temperature. It is suggested in the Good Practice Guidance to include these factors (IPCC, 2001). A new dynamic model for the methane emissions from liquid manure storage has been developed to facilitate the inclusion of these factors and the temperature effect. The dynamic model is used to adapt the MCF in manure management systems typically used in the Netherlands (slurry pit storage). Resulting methane emissions will be compared with emissions based on default values of MCF.

BACKGROUND

The IPCC methodology for estimating national emissions is based on activity sectors (e.g. agriculture) and categories (e.g. CH4 emissions from manure management). The annual emission factor (EF) in kg CH4 per

1796 m 3 manure, from manure management is defined by (Eq. 4.17 in IPCC, 2001): EFi =

WS

i •

365 days. B0 . 0.67 kg . E(MCFjk "MSijk) year i ~ jk

(1)

where i is the livestock population, j is the management system and k is the climate region. VSi are the volatile solids produced daily by an animal within the defined livestock population i (kg) and B0, represents the biodegradability, i.e. the maximum CH4 producing capacity in m3/kg of VS; MCFjk is the CH4 conversion factor for manure management system j in climate region k. MSijk is the fraction of manure of the i's animal species/category handled using manure system j in climate region k. This equation implies the application of default values of VS, MCF and Bo. Typical parameter values for Dutch livestock systems (slurry) are given in Table 1. The MCF values used for the Netherlands appear to be too low. Also the VS values are not valid for the Netherlands, as they are inconsistent with other sources on manure characteristics. The choice of parameters has a large affect on the emission factors. Application of the default MCF values according to the IPCC guidelines, instead of the Dutch practice values, results in higher values for the emission factor. Application of practical values of VS, instead of the IPCC values results in lower emission factors. The combined effect is shown in Table 1. EFI is the official national CH4 emission estimate, but EF2 is closer to Dutch practice. TABLE 1 EMISSION FACTORS FOR SLURRY (EF) BASED ON DIFFERENT SOURCES FOR VOLATILE SOLIDS (VS) AND METHANE CONVERSION FACTORS (MCF). VS: IPCC (1996) VS: Dutch practice (Van Dijk, 1999) MCF: Van Amstel (1993) MCF: IPCC, cool climate (2001) Livestockpopulation B0 VS MCF EFI VS MCF EFE (m3 CH4/k~VS) (%) (%) (ks CH4/m3 slurry) (%) (%) (kg CH4/m3 slurry) Cattle (>1 month, no pasture) 0.17 12.4 5 0.70 6.6 39 2.93 Pigs 0.45 10.1 10 3.05 6.0 39 7.06 The default IPCC values for MCF may be replaced by country-specific values which can include factors like (IPCC, 2001): timing of storage or application, length of storage, manure characteristics, determination of the amount manure left in the storage facility (as a methanogenic inoculum), temperature of indoor and outdoor storage or daily and seasonal temperature variation. In this paper, a dynamic model is proposed that can include such factors.

M A T E R I A L AND METHODS

Dynamic emission model A common system for manure management in the Netherlands is slurry storage in the pit below animal confinements. Such slurry pit storage can be viewed as an accumulation system with continuous filling. The methane emission in such a system depends on the filling time and the inoculum. The emission over time in accumulation systems has been measured in several experiments of Zeeman (1991). Based on these experiments we assume for this paper that the emission velocity (m3/h) in an accumulation system is linearly increasing with the filling time. We also assume 1 m 3 ~ 1000 kg slurry and 1 m 3 CH4 = 0.67 kg CH4. The emission velocity of cattle and pig slurry in an accumulation system at 15 °C is: mcattle 15°c(t) = 0.335"t and mpigs15oc(t) = 6.7 + 0.335"t (2) where m(t) is the emission velocity of methane in g CH4 per m 3 slurry per day and t the filling time in days. This implies that the relation between emission and filling time is quadratic. The methane emission as a function of time in g CH4 per m 3 slurry manure can be found from:

1797

M(t)= ~=om(x)dx

(3)

According to Zeeman's experiments Eq. (2) and Eq. (3) yield for cattle slurry Mcattle 15°c(t) = 0.167"t 2

(4)

and for pig slurry Mpigs 15oc(t) = 6.7"t + 0.167"t 2 (5) These equations are valid within the experimental range and conditions of Zeeman (1991), with filling times of 180 days.

Relationship between IPCC model and dynamic methane emission model Both the IPCC model (1) and the dynamic emission model (4) for cattle and (5) for pigs, describe the methane emission of slurry storage. The dynamic methane emission model can be compared with the IPCC model. Substitution of MCF(t) for ~ MCFjk • MSijk in Eq. (1) and equating Eq. (1) with (4) (thus equating jk

EF to M) gives for cattle slurry: MCFcattle ~5°c(t) = 0.022-t 2

(6)

and equating Eq. (1) with Eq. (5) gives for pig slurry: MCFpigs 15°c(t) = 0.372"t + 0.0093"t 2 (7) To illustrate the consequences of Eq. (6) and Eq. (7) on the MCF, in Table 2, the MCF is calculated for different filling times for cattle and pig slurry at a constant temperature of 15 °C. TABLE 2 CALCULATED MCF'S FOR SLURRY FOLLOWING THE DYNAMIC MODEL AT DIFFERENT FILLING TIMES AT 15 °C. Filling time t (days) 60 120 180

MCF cattle (%)

MCF pig (%) 6 18 37

Temperature of slurry storage facilities in the Netherlands The emission depends on the storage temperature, Eq. (6) and (7) are valid at 15 °C; there is no emission below 4°C. Due to climate control in pig housing, the average temperature of the indoor stored pig slurry is around 17°C (Novem, 1991) during the year. However, since the data of Zeeman is valid at 15°C, we assume for these illustrative calculations, the pig slurry is to be stored at 15°C. This may imply an underestimation of the MCF. The temperature of the slurry pit in cattle housing will be a little higher than the outdoor temperature. The average temperature of a cattle slurry pit is assumed to be 15°C during June, July, August and September, and 10°C during the other months. The methane emission at 10°C is assumed to be half the emission at 15°C. With the latter, Eq. (6) is rewritten as: MCFcattle 10°c(t) = 0.011.t 2 (8)

RESULTS The dynamic model describes the relation between methane emissions and filling time. As an illustration, the emission factors of a common cattle and pig farm will be calculated. For both farms, a slurry production of 100 m 3 per month is assumed (yearly production 1200 m3). Due to coveting and the low temperature of the silo, the emission of methane is considered to be negligibly low, compared to the emission from the slurry pit storage. It is assumed that at least 10% of the slurry in the pit will remain in the pit because it is

1798 practically impossible to empty the pit completely. To calculate the methane emission on a yearly basis the emission should be calculated using the dynamic model for each storage period, starting with the remaining (inoculum) of the last period until the pit is emptied. In Table 3, the resulting MCF and emission factor EF3 are given. For pig farms, all manure is stored in the slurry pit (typical capacity 400 m 3) of the pig housing. When the pit is full, manure is pumped to the outdoor silo. In the case of manure application, manure is taken first from the pit and from the silo if the pit is empty. Most manure will be transported to other farms and the rest will be applied on the farm in February and in August (2x50% of the stored manure). Here, Eq. (7) will be applied. The manure application times for the cattle farm are observed average values for 2 years at 12 farms, which include grazing during May until October. In the case of grazing, 50% of the manure is assumed to be dropped on pasture. The average manure application, expressed as a percentage of the manure stored in the pit, is 10% in February, 20% in March, 15% in April, 20% May, 15% in June, 10% in July and 10% in August (application is prohibited during the other months). Eq. (8) will be applied for the period October till May and Eq. (6) during the other months. TABLE 3 THE METHANE CONVERSION FACTOR MCF WITH RESULTING EMISSION FACTOR EF1, CALCULATED FOR PIGS AND CATTLE, ACCORDING TO THE STATIC IPCC MODEL OF EQ. (1) COMPARED WITH THE MCF AND EF3 CALCULATED USING THE DYNAMIC MODELS OF EQ. (6) AND (8) AS PROPOSED IN THIS PAPER.

livestock Bo (m3CH4/kgVS) population cattle (> 1 month, pasture) 17 pigs 45

using IPCC static model MCF EFI (%) (kg CH4 / m3 slurry) 5 0.70 10 3.05

using dynamic model: Eq. (6) - (8) MCF EF3 (%) (kg CH4 / m3 slurry) 9 1.21 19 5.79

CONCLUSIONS

Emissions of methane from agricultural sources are normally calculated in accordance with the IPCC good practice guidelines. A new dynamic model has been proposed to include dynamic factors such as slurry storage time, loading and unloading rates and temperature. Research by Zeeman (1991) suggests that the emission velocity linearly increases with filling time, i.e. the relationship between emission and filling time is quadratic. As an illustration, the model is used to derive values for the methane conversion factor MCF, and the emission factor EF, depending on filling time and temperature. The model has been applied to a typical pig and cattle farm. The results show that the procedure to determine the MCF can have a great influence on the EF. The model can be used to improve calculations of national emissions and to define policies that can reduce methane emissions from manure storage. REFERENCES

1. IPCC, 1996. Revised 1996 IPCC guidelines for national greenhouse gas inventories: Reference manual. 2. IPCC, 2001. Good practice guidance and uncertainty management in national greenhouse gas inventories. 3. Novem, 1991. Commersialisering van koude vergisting van varkensdrijfmest onder stal met behulp van kapjessysteem, Novem/RIVM, Sittard/Bilthoven The Netherlands, no 9134, 50 p. 4. Van Amstel, A.R., R.J. Swart, M.S. Krol, J.P. Beck, A.F. Bouwman & K.W. van der Hoek, 1993. Methane. The other greenhouse gass. Research and policy in the Netherlands. Report no: 481507001, RIVM. 5. Van Dijk, W., 1999. Adviesbasis voor de bemesting van akkerbouw- en vollegrondsgroentegewassen. PAV, Publicatie nr. 95, maart 1999. 6. Zeeman, G., 1991. Mesophilic and psychrophilic digestion of liquid manure. Thesis Agricultural University Wageningen.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1799

SEPARATION PROCESS OF H Y D R O F L U O R O C A R B O N S (HFCs) BY CLATHRATE HYDRATE FORMATION Taku Okano l, Kazuhiro Shiojiril, Minoru Fujiil, Akihiro Yamasaki 2, Fumio Kiyono 2, and Yukio Yanagisawa I i School of Frontier Sciences, The University of Tokyo, 7-3-1 Hongo, Bunkyo-ku, Tokyo 113-8569, Japan 2 Institute for Environmental Management Technology, National Institute of Advanced Industrial Science and Technology, 16-10nogawa, Tsukuba 305-8569 JAPAN

ABSTRACT

A new gas separation process of HFCs (hydrofluorocarbons) from nitrogen by the formation of clathrate hydrates in the pores of a porous glass membrane was proposed. A gaseous mixture of an HFC and nitrogen was introduced to one side of the porous glass membrane (feed side), and pure water was introduced to the opposite side (permeate side). The temperature and pressure on the feed side was maintained such that only HFC hydrate was stable, while that of the permeate side was maintained outside of the hydrate formation region. Under such conditions, a thin hydrate film was formed at the interface of the gas mixture and water in the pores. The HFC was enriched in the hydrate phase due to the large difference in the hydrate formation tendency between the HFC and nitrogen, and the HFC-enriched gas permeated through the hydrate film to the permeate side. Thus, a continuous separation process could be achieved. The above concept was examined experimentally for the mixture of nitrogen and HFC-134a by using porous Vycor glass with a mean pore diameter of 4 nm; it was found that the HFC-134a could be enriched on the permeate side to 55% of the mole fraction for the feed gas, with 2.5 % of the mole fraction of HFC-134a.

INTRODUCTION Clathrate hydrate is an inclusion compound, where a guest molecule is included in a cage-like structure formed by hydrogen-bonded water molecules. The hydrate formation conditions depend on the properties of the guest molecules such as size, hydrophilicity, and the intermolecular forces, and could consequently vary under a wide range of pressure and temperature. When a gaseous mixture was contacted with water and formed a hydrate phase, under milder hydrate formation conditions, there would be enrichment in the hydrate phase, and separation would occur between the gas phase and the hydrate phase. Considering a

1800 gaseous mixture of nitrogen and HFC-134a, nitrogen hydrate is stable in the pressure range higher than 335 bar for 280 K [1], while HFC-134a hydrate is stable even at 3 bar at the same temperature [2]. When the mixture of nitrogen and HFC-134a formed a hydrate at 280 K and 3 bar, almost all the hydrate cages were occupied by HFC-134a molecules; HFC-134a could be enriched in the hydrate phase. The gas mixture enriched with HFC-134a in the hydrate phase could be recovered by dissociating the hydrate crystals after separation from the fluid phase. Based on the above concept, several attempts have been conducted on separation processes of gaseous mixtures. However, it is difficult to design a continuous separation process because a batch type process needs to be used for a solid (hydrate)-liquid (water and remaining gas) separation. In addition, the hydrate formation and dissociation process involves a large amount of heat, which increases energy loss in the process. To overcome the above difficulties, here, we propose a novel separation process of gaseous mixtures using hydrate formation in the pores of porous membranes. In this study, a separation process of HFCs (hydrofluorocarbons) from mixtures with nitrogen was targeted. HFCs, which were developed as an alternative to chlorofluorocarbons (CFCs), have been used widely as refrigerants, propellants and foaming agents for plastics. Since gaseous mixtures of HFCs with nitrogen have been used widely as foaming agents for plastics, and large percentage of the mixture remains in waste plastics, it is necessary to separate HFCs from mixtures with nitrogen, in order to facilitate the appropriate treatment of HFCs and prevent their release into the atmosphere. HFCs have high global warming potentials (GWP), some 3400 times greater than CO2. OUTLINE OF THE PROPOSED PROCESS

The conceptual drawing for the proposed process is shown in Figure 1. The pores of the porous ceramic, such as porous Vycor glass membrane, were used as the hydrate formation field. A gaseous mixture of nitrogen and HFC-134a was introduced on one side of the porous glass membrane (feed side), and pure water introduced to the other side (permeate side). The pressure and temperature on the feed side was maintained in the hydrate formation range for HFC-134a, but out of that for nitrogen. The condition on the permeate side was maintained out of the hydrate formation range for both components. The gas mixture and water penetrated into the pores of the porous glass, and upon contact, the hydrate phase formed at a certain location within the pore, under the appropriate pressure and temperature conditions. HFCs were enriched in the hydrate phase. Since the mass transfer process in the hydrate phase is relatively small, enough guest molecules could not be supplied from the gas phase, to the opposite side of the hydrate phase, contacted with pure water, and the hydrate phase dissociated, releasing gas to the water phase. Under steady-state conditions, the formation rate of hydrate at the feed side equilibrated with the dissociation rate of the hydrate at the permeate side, and the permeation through the hydrate film, with apparently constant thickness, occurred. The selectivity depended on the equilibrium partition of the components between the hydrate phase and gaseous phase. The advantages of the proposed process are as follows. •

A continuous separation process is realized under steady-state conditions, as no solid-fluid separation process is necessary in the separation.

1801 •

Energy loss due to the hydrate formation-dissociation cycle could be reduced because the cycle would proceed in small scale pores.

Gaseousmixtureof I HFC-134aandnitrogen" HFC-134ahydraS/ 1 1 ! P°r°usvyc°r~ ~ Water[ ~

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,I

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V~x/~_ Sampling ~ theFeedSide [ I

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...... 'i!!i!!~ ;ubstitution

Figure 1: The conceptual drawing for the proposed separation

V-5

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Figure 2: Schematic drawing for the experimental setup

EXPERIMENTAL

Materials Tube type porous Vycor glass (#7930) was purchased from the Coming Co. The inner diameter was 10 mm and the outer diameter was 12 mm, with 150 mm length, and the mean pore diameter was reported as 4 nm, with a sharp pore size distribution. High-grade nitrogen and HFC-134a were used from cylinders and de-ionized water used without further purification.

Experimental Apparatus and Procedure Figure 2 shows a schematic drawing for the experimental apparatus used for the separation. Nitrogen and HFC-134a were fed from gas cylinders and pre-mixed before being introduced into the permeation cell at a constant pressure. The permeation cell was a pressure-bearing vessel of stainless steel, in which a porous glass tube was mounted; both sides sealed by O-rings. The permeation cell was immersed in a constant temperature bath in which the temperature was controlled within +0.1 K. The feed gas was introduced to the outer side of the porous glass tube, and pure water was introduced to the inner side. In the permeate side, a flow of pure water was introduced to remove the permeated gas at the atmospheric pressure, and collected by a water substitution technique. The permeation rate was calculated by the volume measurement of the captured gas and the composition was analyzed by gas chromatography.

Separation Performances Figure 3 shows a typical separation performance for HFC-134a and nitrogen under the conditions of 5.1 bar and 280 K, which satisfies the hydrate formation condition for HFC- 134a. The composition of the permeated gas mixture, as well as that in the feed gas, changed with time. Within 50 minutes, however, the permeation reached a steady state; the mole fraction of HFC-134a in the permeate side was about 52 % while that in the

1802 feed side was 2.5 %. Thus, the separation factor, ct was as high as 47. The flow rate of the permeated gas was 7.9x10 -6 mol/s. Conversely, under the conditions of 5.1 bar and 298 K, which is not in the hydrate formation region for HFC-134a, the mole fraction of HFC-134a in the permeate side was found to be about 4% for the feed gas of the same composition (ct = 1.8). The permeation rate was 4.0x 10-4 mol/s, which is two orders of magnitude higher than the case with hydrate formation. These results indicate that the higher selectivity for HFC-134a could be realized under the hydrate formation conditions, and suggest that the separation would take place by the hydrate phase formed in the pores of porous glass membrane. 50 1 I ............................................................................................................................... 4.~K ' - 7

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HFC-134a and nitrogen by the formation of

Figure

4:

Results

of

separation

hydrate in the pores of porous glass membrane

experiments about the various mole

(Temperature = 280 K, and pressure = 5.1 bar)

fractions in the feed side.

Figure 4 shows the relationship between the mole fraction of HFC-134a in the feed side and that in the permeate side. When the feed side mole fraction was lower than 0.4, HFC-134 was enriched in the permeate side, while nitrogen was enriched in the permeate side for the conditions with the mole fraction of HFC-134a in the feed side higher than 0.7. More experimental results will be necessary in order to rationalize these effects of the feed side mole fraction on the separation performance. CONCLUSIONS A new concept of gas separation process by the formation-dissociation in the pores of porous membrane was proposed. The separation performance of HFC-134a and nitrogen was examined by using porous glass membrane and found the separation factor reached as high as 47 for a hydrate formation condition, while 1.8 for the condition without hydrate formation. Thus, the proposed process is highly feasible from the viewpoint of selectivity for HFC-134a. REFERENCES Moil Y. H., Mori, T. (1989).

AIChE. J., 35 1227.

Sloan, E. Jr. (1998). Clathrate Hydrate of Natural Gases, 2nded., Dekker.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1803

LOW TEMPERATURE PFC DESTRUCTION SYSTEM USING SURFACE DISCHARGE PLASMA WITH CATALYST

Toshiaki Kato 1,Tatsufumi Mori 1,Ryu-ichiro Ohyama2, Jun Tamaki 3

'KashiyarnaInstruments, INC., 4051-3 Negishi, Saku, Nagano, Japan 385-0062 2Tokai University 1117 Kitakaname, HJr'dmd~ Kanagawa, Japan 259-1207 3Ritsumeikan Universityl-l-1 Nojihigashi, Kusatsu, Shiga, Japan 525-8577

ABSTRACr We have developed a room temperature PFC destruction system using atmospheric pressure plasma with catalytic technology. We use non-equilibrium plasma discharge to create a trigger reaction to remove fluorine from PFC. Then, a CFx radical is adsorbed on an active site of the PFC catalyst. Water vapour and oxygen are added to this system in order to produce H, OH, O, 02 radicals or ions. These radicals and ions produced from rich water vapour and oxygen occupy carbon bonds, then produce stable cong~ounds such as HF, OF2, COF2, CO2, CO. 90% DRE (destruction efficiency) of CF4was obtained at N2:20 slm, CF4:50 sccrn, H20:200 sccrn by our prototype system. Surface discharge was produced by high frequer~y rectangular pulse. The catalyst was composed of Aluminum Phosphate. As it stands, this technology has some practical applications.

INTRODUCTION The global warming problem is getting more serious year by year. Not only is CO2 but also PFC gases are important because of their very long lifetime in the environment. PFCs (perfluoro-v.ar~ns) are CF4, C2F6,C4Fs,C3Fs,C5F8.etc. It is particularly important to decompose CF4 as it is the most stable of the PFCs. Most of PFCs are decomposed at temperatures lower than 1000°C, but CF4 is stable enough not to decompose; the decomposition temperature of C F 4 is greater than 1000°C. Buming methane releases significant amounts of NOx at temperature greater than 1000 °C. Some PFCs, apart from CF4,often generate some CF4 as a by-product through disposal of via buming or altemative methods. High temperature exhaust gas also forms a problem. This requires considerable cooling water or air, and high cost pipe-work materials. It makes initial and nmning costs expensive. Thus, we propose a new PFC destruction technology, with no NOx generation and a low temperature exhaust gas.

1804

PROCESS

Principleof the Technology 1) Catalyst Many types of catalysts to destroy fluorocarbons have been researched previously by many researchers. All of them need high tempemttres in excess of 700°C. This means that the first reaction (1) requires energy greater than 700°C. CF4 )CF3+F (1) CF3+H20 (+Cat.) ~/~_,O2+HF (2) CF3tO 2 (-P-Cat.) ------~COF2+F2 O) After reaction (1), the next reaction (2) or (3) proceeds quickly at a lower temperature than 700°C. In addition, expensive anti-corrosion materials are needed in order to tolerate fluoride products.

2) Plasma Non-equilibrium surface discharge is effective in decomposing chemical compounds. This technology has been applied to a number of ozone generators. Reaction (4) can be generated without difficulty. CF3+F(+e) (4) CF, (+e) ~ CF3I-F ~) CF 4 (5) On the other hand, the reverse reaction (5) can also happen frequently.

02 6---->20* (6) 1-I20 <----->H+OH (7) When additional gases exist in the plasnaa, reactions (6) and (7) will occur simultaneously. These products play an important role in the pax:ess towards desmmtion. However, reverse reactiom also happen. This is the reason why the destruction efficiency of fluomcad~om cannot be high enough with plasma alone.

3) Catalyst in plasma Our technology uses both of these. We use non-equilibrium surface discharge plasma to remove the fluorine atom from the fluorocadxm through reactions such as (4). Reactive f l u o ~ n s such as CF3 reacts with active atoms generated from H20 or Oz, which are pre-mixed to help decomposition. The catalyst helps this reaction using its active rite. The ten-qaerature of the catalyst does not need to be high if it is installed in a plasma atmosphere because the reacting gases are active enough. This technology needs no exlmafive anti-corrosive materials, nor much electric power, this results in a catalyst with a long life.

Estimation of PFC CatalystLife The catalyst we use must be highly effective, and have a long life, low cost, and hopefully, be less toxic. Finally, aluminum phosphate was selected from many options considered. Some of its characteristics are shown below: 1) Evaluation system of aluminum phosphate The catalyst was installed in a Ni cylinder, heated and temperature controlled. Effluent gases were bubbled into water to remove the HF. Following this, gaseous components were analyzed by GCMS. 1-120concentration in the inlet gas was controlled by controlling the t~npemture of the pure water through which the nitrogen was passed. 2) C H F 3 Destruction with Aluminum Phosphate

Fig.1 shows the relationship between the catalyst's temperature and CHF 3destruction efficiency. Fig.2 shows the transition of destruction efficiency throughout the continuous gas treatment test. The DRE of CHF 3 rose immediately at first, and maintained 100% for a long time (about 1000 h), then fell gradually at 600°C. When CF4was passed through the plasma, many CF 3 radicals were generated. This makes it possible to estimate the catalyst's life. When the catalyst is used in a plasma stream, the temperature will be much lower than 600°C. Therefore, it can be predicted that the actual lifetime will be much longer.

16OD

Structure of Plasma Reactor 1) Plasma type - Fig.3 shows the basic ~acture of the general surface discharge. A dielectric plate is sandwiched between a ground plate and a mesh discharge electrode. A ground plate is led to the earth. A mesh discharge electrode is connected to a pulse generator. When a pulse voltage is added to the mesh, its surface will be covered with plasma. Porous catalyst granules cover the mesh side of the dielectric plate. Most of the reaction is carried out around the mesh electrode. 12 pairs of surface discharge plates make a set installed in a frame. These are all connected in parallel. lOO 90

......................................................

80 70

30 20 10 200

300

41?0

500

600

700

T ~gree C) Figure 1: DRE of CHF3 with AIPO4 catalyst (Catalys~ 1.00g; Total F ~ r : ll~cm; G'F4:0.NP/o; 02:10%; 1-t20: ~/o; 1',12:balance)

,oo I 95 (

i

I

'.

)

'

!

i

i

:,

j

200

400

90 85

75 70 65 60 O

600

800

104)0

1200

400

Figure 2: Continuous treatment of CHF3 with AIPO4 at 600°C (Catalyst: 2.00g; Total Flow: 10seem; CF4 0.53%; 02:10%; H20: '~/o; N2: balance)

Gas

2 2 ~ Gas

r---

flow

flow

Discharge

Dielectric

electrode Plate

Ground ~

Figure 3: Basic structure of saaffac.edischarge reactor 2) Pulse Electric Source Detail of the pulse to generate plasma is shown in Fig.4.

Pulse Height: 2kV Pulse Width: 6 micro-sec Pulse Frequency: 10kHz Shape of pulse: Rectangle

÷

1

Figure 4:

Pulse to generate plasma

1805 PFCAbatement System 1) Evaluation - Fig.5 shows the prototype PFC abatement system (with four-frame type) that was made to evaluate its performance. There are two wet scrubbers, one for pretreatment the other for after treatment. Measurement of PFC concenWationwas achieved by GCMS for gas sampling before and after this system. 2) Performance - Fig.6 reports the performance of CF4 destruction using this system (with two-frame type). Measurement was performed under the condition: N2 20slm, 40slm, H20 Humidity 1% (200seem, 400seem), CF4 50,100,150sccm. Maximum DRE was 92% at N~ 20slm, H20 200seem, CF4 50seem. This result indicates the reasonable results obtained. The DRE of CF4 decreases with the total flow rate and CF4 flow rate. These values were higher than the data treated using only either technology at room tempemaLre.No other PFCs or HFCs other than CF4 were analyzed in the sampling gas.

Pre~ent Wet Scrubber

I 12 pairs of discharge ~L platesare inside

Four Frame TyI: Plasma Reactor

Downstream Wet Scndgber Aluminum phosphate granules are inside:3mm(d)*10mm(L) Figure 5: Prototype PFC abatement ~ - ®

To~fi~:~ 20L - T o ~ l ~ 40LL_

60 ¢~40 •. ~

................

®~,

110

150

0 50

70

90

130

C F 4 F b w Rate ~ c m ]

Figure 6: Performance of the prototype system CONCLUSIONS

We could produce a successful m~xtltby this R&D. Some dry etching processes use less CF4 than 50sccm, and some dry pumps need less nitrogen than 20slm. This technology can now be applied to such practical applications.

ACKNOWLEDGEMENTS

This R&D has been supported by the Japanese SBIR system through JASMEC (Japan Small and Medium Enterprise Corporation) 1999-2001.

Greenhouse Gas Control Technologies, Volume lI J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1807

SIMPLIFIED MONITORING TECHNIQUE OF HFC MIXED GASES IN A COOLANT RECYCLE SYSTEM Yoshiya Iida I and Makoto Morita 2 ~ Pacific Basin Institute, 1-7-18 Sasuke, Kamakura, 248-0017, Japan 2 Department of Applied Chemistry, Seikei University, Kichijoji, Musashino, Tokyo 180-8633, Japan

ABSTRACT Luminescence of dye-sensitized polymer films was investigated in order to develop a phosphor-based film sensor for hydro fluorocarbon (HFC) gases. The film shows a broad emission band at 560 nm. By flushing the HPC, the spectrum is drastically quenched by a factor of 500 in intensity, relative to new film. From infrared absorption spectra and experiments using reference films, this distinct quenching is ascribed to structural changes of the dye molecules. The findings give a clue towards developing on-site monitoring techniques for HFC mixed gases.

INTRODUCTION

According to the recently updated guideline report, the total emission of three groups of fluoride gases in 2001 has increased +2%, with respect to the value for 1995. As for the countermeasures, we are asked to carry out "Leakage protection, coolant retrieval from retired equipment, and review the action plan for reuse and destruction of coolant gases" [ 1]. Recently, a greenhouse gas effect has been caused by the so-called Freon® substitutes (hydrofluorocarbon: HFC). This effect has now resulted in increased impact. Since HFC gases do not contain a chloride component, they are free of an ozone depletion effect. Therefore, HFCs are now used widely as Freon® substitutes in cooling facilities. In consideration of the problem of Global Warming Potential (GWP), reduction of the HFC

1808 emission and recycle/reuse of HFCs is necessary. In developing a very simplified gas analyzer system, we have to understand two points: chemical properties of gases and novel aspects of technology.

HFCs are often composed of mixed gases. The composition providing the best

coolant performance is not always azeotropic. This situation is different from those with CFCs and HCFCs. Usually, HFC gas mixtures are chemically detected through the use of gas chromatography (GC), mass spectrometry (MS), electron capture (ECD), atomic emission (AE) etc. Detection limits for HFC gases are ng by ECD, and pg by MS, AED technology [2]. These methods are expensive and also unable to be implemented in real time. So, there is a strong practical need to develop an on-site monitoring system for coolant gas mixtures in their various states, that can be manufactured at a reasonable cost. Flow gas leak in a system is often detected practically by fluorescent lamp and phosphors [3]. For this reason, we are now developing a new type of phosphor-based chemical sensor. The design policy and other details will be described elsewhere, in consideration of the situation with patents pending. EXPERIMENETAL RESULTS AND DISCUSSION We have prepared a new type of chemical sensor, a polymer film doped with organic dye molecules, for detection of R 407 C gas. The dye-sensitized film and a non-doped polymer film as reference were exposed to flush gas R 407 C for some minutes. Optical properties of the films were investigated by infrared absorption spectra, luminescence and time-resolved luminescence spectra (TRS) at room temperature. Under a N2 laser (337.1 nm) excitation, luminescence of the gas-exposed films was measured by employing the spectrophotometric system based on the Intensified Charge Coupled Device (Andor ICCD, DH520) combined with an optical fiber. Luminescence spectra of the dye-sensitized films with flushing (sharp solid line) and without flushing (broad solid line) are shown in Fig. 1. Both spectra are normalized in intensity at the peak to compare the spectral shape function. The latter spectrum is centered at 560 nm with a lifetime of less than 0.01 ms. By flushing of R 407 C, the spectrum becomes broadened in shape and the luminescence intensity is reduced by factor 500 with respects to the non-flushing film. This factor is estimated tentatively by taking into accounts of bleaching effects and the partial recovery after 24 hrs. The reference film II did not show such a drastic luminescence quenching

1809

1

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i

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t5

i

tc

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i t.o

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400

5oo

1..

o.o

60o

Wavelength / n m

Figure 1" Luminescence spectra of dye-sensitized polymer films before (weak solid line) and after (strong solid line) flushing of HFCs. Infrared spectra of dye molecules in polymer films before and after flushing of R 407 C are shown in Fig. 2. The disappearance of two peaks at 1,200 and 1,500 (cm -l) indicates changes of chemical structures due to the N-H bending and C=N stretching modes. Luminescence quenching in this dye-sensitized film seems to be specific to the dye used. In order to confirm the experimental results, the electronic structure of the sensitized films should be examined by TEM, SEM and XRD spectroscopy. To summarise, we have investigated luminescence, TRS and decay times of polymer films doped with dye under flush gas R 407 C. Luminescence quenching and its recovery were found in the dye-sensitized films. To improve the quality of the films and to discriminate chemical components, further experiments are being undertaken in combination with FTIR spectroscopy. After the disclosure of our patents pending, more concrete data will be published in the near future [4]. ACKNOWLEDGEMENTS We express our sincere gratitude to Prof. Kazutoshi Tanabe of the Chiba Institute of Technology for his valuable discussion and also to Mr. Masao Miyoshi and Dr. Munetaka Iwamura for their cordial support and encouragement.

1810

o

t

J 4OO0

Figure 2:

Infrared absorption spectra of dye doped in polymer films before (upper hal0 and after (lower hal0 flushing of R 407 C gases at room temperature.

REFERENCES 1 N.A.(2001) In: "Feasibility study of the development of the recycle system of HFC Gases", Japanese Institution of Cooling and Air Conditioning Industries (Eds). Tokyo. 2 3 4

Sousa, S. R., Bialowski, S. E. (2001). Anal. Chim. Acta 433, 181. Duerr, .J.T. (2000). Appliance 57, 92.. Morita, M. and Iwamura, M. to be published

RENEWABLE ENERGY

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1813

CSIRO's ADVANCED POWER GENERATION TECHNOLOGY USING SOLAR THERMAL - FOSSIL ENERGY HYBRID SYSTEMS

R. Benito, G.J. Duffy, K.T. Do, R. McNaughton, J. H. Edwards N Dave, M. Chensee and C.Walters CSIRO Energy Technology, Lucas Heights, N.S.W. Australia

ABSTRACT CSIRO has completed the construction and commissioning of a demonstration facility integrating solar thermal energy and fossil fuels for advanced power generation and other applications with substantially reduced greenhouse gas emissions. Solar energy via a 107 m 2 twin-axis tracking paraboloidal solar concentrating dish is used to reform 36 kW (LHV) of natural gas with steam to generate a mixture of CO2 and H2 in tubular reformer housed inside a 200x200mm cavity receiver. The facility includes further gas processing steps such as low-temperature-water-gas shift reaction to convert CO, recovery of CO2 in physical and chemical absorption processes and methanation to finally reduce CO in the product H2 to the ppm levels for use in a PEM fuel cell. All components of the facility - from solar concentrating dish to methanator - performed better than expected achieving 136% of design natural gas feed. In this paper, experiences gained in the operation of the facility and results of solar steam reforming of natural gas in a MUlti Straight Tube Reformer (MUSTR) and in a Single COiled Reformer Tube (SCORE) at 850°C and 0.5 to 2.4Mpa with downstream processing of reformer gas producing PEM fuel cell H2 gas are presented.

INTRODUCTION CSIRO has recently completed a major project to demonstrate a solar thermal-fossil energy hybrid concept for generating solar-enriched fuels and electricity with potential for high thermal efficiencies and for greatly reduced CO2 emissions. The concept features: (1) Reforming of CHa-containing gases, using concentrated solar energy, to generate a mixture of CO and H2 suitable for use as a fuel, metallurgical reductant or a chemical feed stock (2) Further conversion of this gas to H2 and CO2 followed by recovery of CO2 in a concentrated form, as required for any subsequent CO2 disposal or utilisation scheme and (3) Further purification of gas to produce H2 for use in advanced electricity generation systems such as fuel cells and turbines. The 3 year $7.5 million project was conducted jointly by CSIRO Energy Technology (CSIRO-ET) and CSIRO Manufacturing Science and Technology (CSIRO-MST). It involved the construction and operation of a facility to demonstrate the key steps in the technology so that its commercial prospects can be more accurately assessed. It was supported by ongoing laboratory-scale experiments at CSIRO-ET on aspects of process chemistry and reactor design and at CSIRO-MST on technical issues relating to power generation and fuel cell selection and operation. This paper describes the completed demonstration facility and results obtained so far are also presented.

DESCRIPTION OF THE DEMONSTRATION FACILITY Details of the demonstration facility (see Figure 1) have been published elsewhere by Edwards et al [1 ]. The demonstration facility is located adjacent to CSIRO-ET's laboratory complex at the Australian Nuclear

1814 Science and Technology Organisation site at Lucas Heights, south of Sydney. A local manufacturer, Solar Systems Pty Ltd supplied the twin-axis tracking paraboloidal solar thermal concentrating dish with 107 m 2 aperture area, 48 mirrors of which are covered with louvers for output control. The catalytic reformer was designed to process a natural gas feed rate equivalent to about 36kW thermal (LHV basis) at reforming temperatures and pressures up to 850°C and 2MPa. Two reformer designs were tested: a MUlti Straight Tube Reformer (MUSTR) consisting of six straight tubes connected in parallel and a Single COiled Reformer Tube (SCORE). Cavity receivers (200mm x 200mm cavity) with a second reflector (see Figure 1) were also designed for each of these reformers by CSIRO and Solar Systems Pty Ltd. Two water gas shift reactors were installed for operation at high and low temperatures but were both initially filled with low temperature catalysts. Laboratory scale tests indicated that a single low temperature unit would be sufficient to reduce CO levels in the product gas to those attained in the traditional two stage processing. Catalysts for each of these reactions were obtained from a commercial catalyst manufacturer. Physical and chemical absorption processes were used for treating the product H2/CO2 to recover concentrated streams of H2 and CO2. This was followed by a catalytic methanation reactor to further reduce CO in the H2 to the ppm levels necessary for using this gas in a polymer electrolyte membrane fuel cell (PEMFC).

. . . .

.

.

.

.

Figure 1: CSIRO Solar Thermal Fossil Energy Hybrid Demonstration Facility RESULTS

Initially, progress with the project was seriously hampered by the fact that several key components failed to work satisfactorily at the start. However, in the course of commissioning and operating the facility, several improvements have been suggested and implemented which had successfully addressed these problems, usually in collaboration with Solar Systems Pty Ltd and other component suppliers. Up until May 2001, most of the solar reforming tests had been short and terminated mainly due to insufficient solar energy input reaching the reformer and unstable dish tracking control. The first batch of dish mirrors started to delaminate within a year of installation with significant portion of solar energy falling outside the second reflector. The first design of second reflector failed to maintain high reflectivity as the protective coating progressively delaminated from its silver under surface. The replacement second reflector with a glass mirror glued to a water-cooled copper plate mirror has performed much better and has been in use since then. However, MUSTR still failed to achieve design feed (see columns 1 to 3, Table 1) even though lower operating pressures were used in order to achieve higher methane conversion rates at lower temperatures. A total of about 80 operating hours were accumulated in MUSTR before flow to one of the six reformer tubes was blocked by agglomerated catalyst. Catalyst agglomeration could have been caused by contact with

1815 water that accidentally flooded the catalyst bed during an emergency stop-start operation. The inlet bed of each reformer tube, which was filled with the same catalyst as that of the rest of the bed instead of an inert material in order to maximize reaction length, was also especially prone to direct contact with water depending on the temperature of this section. SCORE was therefore designed to avoid this condition and to also reduce the complexity in gas/water feeding six tubes as well as in manifolding outlet ends in MUSTR. In SCORE, water enters the reformer product gas outlet via a central annular tube and is therefore indirectly preheated and converted to steam by the hot reformer product gas prior to contact with the catalyst bed. SCORE was installed in September 2001 and since then had accumulated a total of over 40 operating hours. With much improved dish tracking algorithm but still using old dish mirrors, maximum feed rates achieved were still only about 70% of design (see column 5, Table 1). Significantly higher feed rates and improved performance were achieved when the new mirrors were installed in June 2002. With louvers still partially closed (effectively using less than 32 mirrors), feed rates of more than 136% of design were achieved in July (peak winter month in Australia) at solar energy flux levels of about 850W/m 2 (see columns 6 to 7, Table 1). TABLE 1 SUMMARY OF TEST RESULTSWITHM]JLTI STRAIGHTTUBE REFORMER(MUSTR) AND SINGLECOILEDREFORMERTUBE (SCORE) SCORE SCORE SCORE MUSTR MUSTR MUSTR SCORE Old Mirrors Old Mirrors Old Mirrors Old Mirrors Old Mirrors New Mirrors New Mirrors Old Second Old Second New Second New Second New Second New Second New Second Reflector Reflector Reflector Reflector Reflector Reflector Reflector 1. Operating conditions: Feed natural gas,kWLHV Reformer temperature,°C H20 to CH4 molar ratk; Reformer pressure,kPa Solar Irradiation, W/m; 2. Solar energy after transmission Iosses,kW 3. Heat absorbed in reformer tube/s, kW 4. Heat Iosses,kW:

1

2

3

4

9.0 788 3.3 2,061 827

9.0 770 3.3 988 833

16.8 783 2.3 582 872

19.1 813 3.6 902 885

25.4 767 3.6 1,310 936

37.4 854 3.6 2,446 854

48.0 804 3.6 2,190 855

27.1

27.3

28.6

29.0

30.7

21.0

23.5

4.4

4.6

7.4

7.7

9.1

13.5

16.2

10.7

10.7

8.6

8.7

9.0

6.5

6.3

5. Heat recovery, kW

0.0

0.0

0.0

3.0

3.6

6.2

7.2

6. Methane conversion,%

62.1

74.8

74.1

80.0

59.7

59.5

49.9

7. Receiver efficiency,%

16.1

16.8

26.0

26.7

29.7

64.1

68.9

8. Reformer gas chemical energy increase, %LHV

15.8

18.5

18.7

19.3

14.7

14.8

12.7

9. Solar-To-Chemical Energy Conversion to reformer gas,%

5.2

6.1

10.9

12.7

12.2

26.5

25.9

4.2

4.2

8.0

9.1

11.7

17.2

21.6

46.3

47.4

47.5

47.7

45.9

45.9

45.1

5.7

5.8

11.3

13.2

17.1

25.3

31.9

63.1

64.7

67.6

69.1

67.3

67.6

66.6

10. Solar Engine Power,kW 11. Overall Solar Engine Power Conversion,% 12. Solar Fuel Cell Power,kW 13. Overall Solar Fuel Cell Power Conversion,%

Start-up times were short in SCORE. Within 6 minutes of the receiver being exposed to direct solar radiation, water and natural gas could be introduced to bring the reformer to operating temperatures. Maximum wall temperatures were maintained to within 1000°C at solar concentration ratios close to 900. SCORE (and MUSTR) responds quickly to varying water/gas feed rates as a means of controlling operating wall temperatures. The louvers were used when the new mirrors were installed to control wall temperatures

1816 to a maximum of about 970°C. With heat recovery, SCORE achieved receiver efficiencies (defined as the ratio of heat absorbed by the reformer to available solar energy) of about 70%, a significant increase from about 26% achieved in MUSTR. As also can be seen in Table 1, SCORE achieved also higher solar-tochemical energy conversions (defined as the ratio of increase in chemical energy to available solar energy) than MUSTR. Further improvements in the receiver could still be achieved by reducing fairly significant receiver wall heat losses through much better thermal insulation. In SCORE, heat recovery was limited to cooling the reformer product gas to 200°C as required in the low temperature water gas shift reaction. If the application is simply the production of reformer gas as fuel, reformer product gas could be cooled to lower temperatures resulting in higher energy efficiencies. In general, higher methane conversions close to those at thermodynamic equilibrium were achieved but only at lower natural gas feed rates in SCORE. Lower methane conversion rates at high feed rates could be due to low catalyst bed densities in some sections of the tight annular space of the reformer tube. Further tests (e.g. lower steam to methane molar ratios to achieve lower gas velocities) are therefore needed to determine optimal operating conditions. The demonstration facility was first successfully operated in an integrated mode in April 2002 producing PEMFC quality H2. Solar energy reaching the receiver was insufficient during this time as the old dish mirrors were still being used such that only 70% of design natural gas feed rate could be steam reformed. The low temperature water-gas-shift reaction was found adequate in reducing CO levels in the reformer gas to less than 0.2vo1%. Although, the reactor was preheated to about 170°C prior to use, the heat energy in the reformer gas and the heat produced during reaction were sufficient to maintain operating temperatures of around 215°C. Only the CO2 chemical absorption unit was used during the integrated operation. Product gas leaving this unit had a CO2 concentration below detection limit. After passing the methanator, CO in the final product gas was reduced to undetectable levels (<2ppm). Earlier tests with the CO2 physical absorption unit successfully reduced CO2 in feed gas from about 20vo1% to 10vol%. Linking the physical and chemical absorption units in series could reduce the heating load of the reboiler in the chemical absorption unit thus reducing the overall energy consumption for CO2 removal. Unfortunately, delivery of a PEMFC unit for this project did not eventuate. Electric power generated from using the reformer gas in a gas engine or H2 in a fuel cell were therefore estimated for each test (see Table 1). At design feed rates, the solar thermal plant with reformer gas used directly in a gas engine (enginegenerator efficiency of 40%) could produce about 17kW electricity, an increase of at least 15% relative to direct use of natural gas, with 40% less CO2 released to the atmosphere. H2, after further processing of the reformer gas, could be used in a PEMFC (efficiency of 60%) to produce about 25kW electricity, an increase in overall efficiency of over 15% relative to H2 from conventional steam reformers (86 % efficiency). With improvements suggested earlier for the receiver and reformer designs, higher overall solar power conversion efficiencies could be achieved, over 49%, for example, when design natural gas feed which is steam reformed at 1 MPa and 850°C is used in a gas engine or 69% when product H2 is used in a PEMFC.

CONCLUSIONS

CSIRO has successfully demonstrated proof of proposed concept in converting natural gas to syngas and PEMFC quality gas with all components of the demonstration facility performing better than expected. Integrated mode of operation was conducted producing PEMFC quality H2. With much improved dish mirrors and tracking algorithm and an energy efficient reformer, solar steam reforming at 136% design feed was achieved. This indicates strong potential for further improvements resulting in commercial application of the proposed Solar Thermal Fossil Energy Hybrid System.

REFERENCES

Edwards J, Duffy G, Benito R, Do T, Dave N, McNaughton R, Badwal S, Jiang S and Giddey S (2000). CSIRO's solar thermal-fossil energy hybrid technology for advanced power generation, Proceedings of the Fifth International Conference on Greenhouse Control Technologies, Cairns, Australia.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1817

SOLAR TECHNOLOGY IN UGANDA FOR REDUCING CO2 EMISSIONS Wilbrod Birabwa Managing Director, Solar Promotion, P.O.Box 8061, Kampala, Uganda Email: [email protected]

ABSTRACT Before the introduction of solar technology in Uganda, most people used to burn petroleum products in order to get light. To everybody on earth, light is a prerequisite after sunset. However, it is common and clear knowledge that the burning of petroleum products produces greenhouse gases such as CO 2. More than 90% of the population of about 22 million in Uganda formerly burned petroleum products to provide light, either by using kerosene lamps or generators, since at the moment, it is calculated that only 5% have access to grid power. However, solar technology has controlled the burning of petroleum products. Each solar lamp installed replaces two to three kerosene lamps as far as light intensity is concerned. Several solar projects have been handled in Uganda to control greenhouse gases. Examples are the Uganda Photovoltaic Pilot Project for Rural Electrification (UPPPRE) where 2000 solar systems were targeted, the Church of Uganda solar project where 360 solar systems were installed, plus several others. All the above projects were handled mainly to displace carbon emissions and to protect the environment. No figures have so far been provided to confirm the level of reduction of emissions effected by the use of solar technology. However, as much as the government and stakeholders are trying to displace carbon emissions, awareness and affordability are still big problems for potential end-users.

INTRODUCTION All the solar systems installed under the Uganda Photovoltaic Pilot Project for Rural Electrification, the Church of Uganda Solar Project and others have contributed significantly towards the displacement of greenhouse gases. However, greenhouse gas reduction from these solar systems has never actually been computed. Solar systems use solar energy to generate electricity for individual rural homes and communal places such as schools, health centers, etc. that are not connected to the grid. Since they directly displace greenhouse gas emissions while contributing to sustainable Rural Development, they could be an excellent fit for the Clean Development Mechanism. The amount of CO2 abated per solar system is quite small, but the rate o f CO 2 displacement per KWh from all those solar systems is very high.

1818

Figure 1: Kerosene Lamp

The above picture shows a kerosene lamp used by most ordinary people in developing countries, especially Uganda. Kerosene is poured inside, a piece of cloth is then put inside to transport kerosene from the bottom of the lamp to the top; aider that, the lamp can be lit. The kind of light produced has soot that pollutes the environment and even makes house roofs black in colour. This type of kerosene lamp is used widely in night markets in Uganda.

Figure 2: Solar Lantern

1819 From kerosene lamps to solar technology - above is a picture of a solar lantem. After realizing the danger of burning kerosene, some middle class people have resolted to buying solar lamps.

Figure3 : Solar Array

The above picture shows an array (modules or panels). This is the major component of a solar system and it (array/module) is what makes any system a solar system. The panels tum sunlight into electricity whenever they are exposed to the sun.

1820 Figure 4: Illustration of a direct current (12v) solar installation

ROOF

PANEL

i

LOAD

MS

iI

C/C !"1"! t i t

MS

Main Switch

C/C Charge Controller B/B Battery Bank LOAD stands for all appliances hooked on the system

BIOMASS

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1823

FOSSIL FUEL CONSUMPTION AND BIOMASS ENERGY SOURCE IN SRI LANKA

G. K. Winston de Silva and Tissa Ranasinghe Saviya Development Foundation

In the developing countries, energy requirements of nearly 90% out of a population of 15 billion, are fulfilled with fossil fuel or coal. The basic task of nearly 50% of the timber supplied around the world is to facilitate cooking and heating purposes. Biomass energy sources have become prominent in the energy field in Sri Lanka. Energy, supplied by fossil fuel, has been recorded as 66% in 1992, in Sri Lanka. Bio-energy is mostly utilized at domestic level. In 1992, 81% of the Bio-gas energy was consumed for various household requirements. The principal source of Bio-energy production in Sri Lanka comprises timber and this constitutes 67% of Bio-gas energy output. 79% of the 19.1 million population in Sri Lanka are living in rural areas. Above 90% of the rural population depend on firewood as their source of energy, especially for cooking. Many obtain their firewood cost free. Even in the present century, Bio-energy is much used in the operation of bakeries. Plenty of timber is used annually to heat the ovens, and it is revealed that it is 8% of the total bio-gas usage in Sri Lanka. Fossil fuel energy is widely accepted as a CO2 emitting source. To combat global warming, every country is concerned with the mitigation of Carbon Dioxide. Scientists, researchers, and environmentalists are working full time to reduce CO2 emissions or to find a significant solution for reducing the impact of CO2 on GHGs. Efforts are being made to minimize energy consumption, to popularize renewable energy and to upgrade energy efficiency levels. Sri Lanka, being an agricultural country, has a relatively high yield of paddy husk. Bio-mass energy derived from paddy residues will simply exploit an already available source of renewable energy. Paddy husk will undoubtedly serve as an economy-generating opportunity for mill owner, who are concerned with the disposal of the husk. The husk could be turned into hard blocks or bricks, for easy transport and comfortable handling by the housewife. The industry may provide plenty of employment, save the environment, and combat degradation and desertification. Furthermore, it may assist in the minimizing of the emission of CO2, thus helping to control global warming.

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1825

PROCESSING OF NON PURIFIED ETHANOL FROM A GLUCOSE FERMENTATION PROCESS FOR SOLID OXIDE FUEL CELL APPLICATION Raphael Idem, Hussam Ibrahim, Paitoon Tontiwachwuthikul and Malcolm Wilson Faculty of Engineering, University of Regina, 3737 Wascana Parkway, Regina, SK Canada $4S 0A2

ABSTRACT In order to use ethanol as a fuel in a fuel cell, it must be processed into a form useable directly or indirectly by the fuel cell. We have conducted studies aimed at the catalytic processing of non-purified ethanol (i.e. filtered but not distilled product of a glucose fermentation process) to produce a direct fuel stream for a solid oxide fuel cell (SOFC) for stationary electric power generation. These studies involve catalyst design for reforming of ethanol as well as determining the optimum operating conditions (i.e. temperature, ethanol space velocity, water content and oxygen ratio) for maximum hydrogen selectivity and minimum energy requirement for the reforming reaction. This work also involved a thorough characterization of the catalysts. Initial results indicate that, if ethanol obtained from a fermentation process is used to produce H2 by steam reforming, there are advantages in not purifying or removing the water present in the ethanol. Firstly, the water present increases the H2 selectivity of the process, and secondly, the cost for ethanol purification is eliminated. Furthermore, with Ni/A1203 as the reforming catalyst, the overall process has better efficiency since the other organic components of non-purified ethanol are also steam reformed to produce additional H2 and CO, both of which are used as direct fuels for the solid oxide fuel cell.

INTRODUCTION

Energy is the mainstay of any nation's economy. Presently, energy production is based primarily on fossil fuels for most countries. For Canada, this makes fossil fuels important not only because they are reliable energy sources, but also because of the existing fossil fuel based energy infrastructure, basic cost of producing energy, reliability, etc. However, these fuels have high carbon intensity. They also contain metals as well as heteroatoms such as nitrogen (N), oxygen (O) and sulfur (S). In western Canada (particularly Alberta and Saskatchewan), due to the energy intensive nature of the economy, significant volumes of greenhouse, acid and toxic gases such as carbon dioxide (CO2), sulfur dioxide (SO2), oxides of nitrogen (NOx), methane (CH4)and other pollutants are being emitted from industrial facilities such as coalfired electrical generating stations, refineries, fertilizer plants, etc. For greenhouse gases (GHGs), especially C02, their increasing concentrations in the Earth's atmosphere is enhancing the natural greenhouse effect. This it is feared will lead to drastic changes in the earth's climate over the next few decades, and will present the most challenging environmental problem mankind has ever faced. For CO2, since most of the emissions are fossil fuel related, a key measure for mitigation still remains

1826 the capture of CO2 from the off-gases at point sources for use or sequestration. CO2 capture technologies should prove environmentally sustainable in the near-and medium terms. However, in the medium- and longer-terms, we must develop energy production strategies that incorporate emissions minimization or elimination as part of the overall process. Such strategies include alternative and renewable energies. Research on renewable (biomass) energy and alternative (e.g. fuel cell) energy is part of the strategies being investigated at the University of Regina. Biomass is a renewable resource. Also, its application for the production and use of energy is considered to be CO2 neutral. Furthermore, since it does not contain heteroatoms and metals, its use as source of energy does not result in emissions of NOx, SOx, particulates and other toxics. Furthermore, biomass fuel consists mostly of oxygenated hydrocarbons, which leads to complete combustion during its application to produce power. As such, little or no CO is produced. Since there is a drastic reduction in GHGs and toxic gases, and a complete elimination of acid gases, bio-fuels can be considered as an environmentally s ustainable source o f energy. F ocus h as been 0 n e thanol since i t i s 0 ne 0 f t he c leanest and potentially most abundant biomass sources for production of energy. On the other hand, fuel cells have been shown to generate electrical power more efficiently than conventional processes since they circumvent the thermodynamic efficiency limitation inherent in standard fuel burning engines. But by far the largest environmental benefits would be realized from fuel cells if bio-fuels such as ethanol could be used as the direct of indirect fuel. Under this approach, CO2 and other emissions would be completely eliminated. In order to use ethanol as a fuel in a fuel cell, particularly the solid oxide fuel cell (SOFC), it must be processed into a form useable directly or indirectly by the fuel cell. One of the direct methods is to produce H2 and perhaps CO by either the reforming process or the partial oxidation process. In either case, water is needed as a co-feed to the process. This would imply that there was no need to reduce the water and organic contents of the ethanol produced from a fermentation process if ethanol was the feed for the H2 and CO production process. In this work, we studied the catalytic processing of non-purified ethanol (i.e. filtered but not distilled product of a glucose fermentation process) to produce a direct fuel stream for solid oxide fuel cell application.

E X P E R I M E N T A L PROCEDURE

Catalysts Two types of catalysts were used in this study a copper- and a nickel-based catalyst.

Preparation The copper based catalyst was prepared from a dried coprecipitated Cu-A1 catalyst precursor containing 27.8 wt% copper. The preparation of the precursor is described in detail elsewhere [ 1]. The dried Cu-A1 catalyst precursor w as p alletized i n a hydraulic p ress under a compacting pressure o f 6 9 M Pa, c rushed a nd t hen sieved into particle sizes ranging from -8 to +10 mesh. Mn was then incorporated into the precursor by impregnation techniques using aqueous solutions of manganous nitrate [Mn(NO3)2, 50 wt% aqueous solution, obtained from Fisher Scientific Co. Fair Lawn, NJ] for incorporating Mn. An impregnation time of 24 h together with the average catalyst particle size of 2 mm were used to ensure a non-uniform distribution of the promoter salt throughout the Cu-A1 catalyst particles. The excess liquid was decanted after which the impregnated catalyst was dried overnight at 110°C in air and then calcined at 700°C. Details of the preparation procedure of this catalyst are given elsewhere [2, 3]. The nickel-based catalyst was Ni/A1203. This catalyst was prepared by adding a pre-determined amount of nickel nitrate solution to about 20 g of palletized 3,-A1203 support. This was kept for 24 h after which the excess liquid was decanted, the catalyst dried at 110°C for 24 h and then calcined at 500°C for 6 h. Ni/ A1203 catalyst was allowed to cool at room temperature, put in an air right container and stored in a desiccator.

1827

Characterization The following characterization techniques were used for calcined catalysts:

(a) Scanning Electron Microscopy (SEM-EDX). SEM studies were conducted to determine the average particle size in the two catalysts. It was also performed in order to determine the elemental distribution in the catalyst particles. These measurements were made using a JEOL JSM-5600 scanning electron microscope attached to Phoenix Pro Genesis EDS system. (b) Powder X-ray Diffraction (XRD) measurements. Powder XRD measurements w ere performed t o identify the component phases as well as to determine the degree of crystallinity of the calcined as well as activated catalysts. The XRD measurements were performed with a D8 DISCOVER diffractometer system with GADDS from Bruker.

(c) Temperature Programmed Reduction - Deferential Scanning Calorimetry (TPR-DSC). Temperature programmed reduction o f t he catalysts w as performed a t atmospheric pressure i n a T G-DSC 1 11 thermoanalyzer manufactured by SETARAM in order to verify the reduction temperature for catalyst activation.

(d) FT-IR Measurements. The FT-IR technique was employed to further identify the compounds present in the catalysts. The Infrared spectra were recorded using a Perkin-Elmer, Spectrum One, FT-IR spectrometer in the absorbance mode with a spectral resolution of 4 cm -l.

Ethanol Reforming

Feed The feed material for this work was obtained from an ethanol production process that uses the grain fermentation technology. This feed material was the liquid remaining after filtration of the final fermentation product mixture. This liquid did not undergo any further purification. This study was performed using feeds of different water contents. The different water content in the feed was achieved by adding pre-determined amounts of water to the original feed material.

Equipment The performance of the promoted and nonpromoted coprecipitated catalysts in the ethanol-steam reforming reaction was studied in a stainless steel (SS-316) microreactor model BTRS - Jr~ having a capacity of 5 mL for the heated section of the catalyst bed.

Process Operating Conditions All runs were conducted at atmospheric pressure over a temperature range of 2 0 0 ° C - 350°C. A typical test run was performed as follows: The catalyst was loaded into the reactor and activated either by reduction in a H2-N2 mixture (3% H2) at 300°C at a flow rate of 100 mL/min for 2 h followed by treatment at 250°C with a vaporized 1:1 molar mixture of ethanol and water or simply a mild reduction at 250°C with a vaporized 1:1 molar mixture of ethanol and water. Non-purified ethanol of different water contents was used for the actual test runs. For each run, the feed was pumped at an ethanol space velocity (WHSV) of 20 h -1 to the vaporizer maintained at about 250°C. The vaporized feed mixture from the vaporizer entered the reactor in a stream of nitrogen gas (99.995% purity and obtained from PRAXAIR). The ethanol-steam-reforming reaction is an endothermic reaction. Therefore, it was necessary to stabilize the reactor temperature before actual reaction data were taken. Stabilization followed the procedure outlined by Idem and Bakhshi [4]. The product mixture during the actual test run was condensed with chilled water in a gas/liquid separator to separate the gaseous and liquid products for separate analysis.

Analysis of Products The gaseous product was analyzed on line with a gas chromatograph (Model HP 6890) using A Poropak Q column in series with a Poropak R column, a thermal conductivity detector (TCD), and a mixture of 1-I2 in He as carrier gas. The liquid product was analyzed by manual injection into the same set of columns using the same gas chromatograph and analysis conditions as in the gas product.

1828 SUMMARY OF RESULTS Initial results indicate that, if ethanol obtained from a fermentation process is used to produce H2 by steam reforming, there are advantages in not purifying or removing the water present in the ethanol. Firstly, the water present increases the H2 selectivity of the process, and secondly, the cost for ethanol purification is eliminated. Furthermore, with Ni/A1203 as the reforming catalyst, the overall process has better efficiency since the other organic components of non-purified ethanol are also steam reformed to produce additional H2 and CO, both of which are used as direct fuels for the solid oxide fuel cell. REFERENCES 1. 2. 3. 4.

Idem, Idem, Idem, Idem,

R. O. and Bakhshi, N. N. (1994) Ind. Eng. Chem. Res. 33, 2047. R.O. (1995). PhD Thesis, University of Saskatchewan, Canada. R. O. and Bakhshi, N. N. (1996) Can. 3". Chem. Eng. 74, 288. R. O. and Bakhshi, N. N. (1994) Ind. Eng. Chem. Res. 33, 2056.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1829

AN EXPERIMENTAL STUDY ON BIOMASS COAL BRIQUETTING PROCESS

Yongliang MA, Kangfu XU, Jiming HAO Department of Environmental Science & Engineering, Tsinghua University, Beijing, 100084, China, E-mail: [email protected]

ABSTRACT The Biomass Coal briquette is an effective practical method to control air pollution caused by coal combustion, as well as to reduce GHG emissions through substitution of fossil fuel with biomass. The objective of this research is to establish a new briquetting technology to simplify the briquetting process and reduce energy consumption, by utilizing the linkage function of biomass fiber. Effects of coal type, briquetting pressure, biomass shape and content, and the water content in raw material on briqutting performance were examined initially at an industrial pilot scale. Results show that briquetting pressure to fix the linkage of biomass fiber is no more than 120 MPa, and a higher pressure causes a negative effect. The reasonable lower limit ofbiomass content is about 15%. Biomass drying in the air for a certain period (water content is generally less than 12%) is suitable for briquetting using the new mechanism. With a coal water content of 6-9% (depending on coal type), increasing the biomass proportion and decreasing briquetting pressure to a certain degree could significantly offset the negative effect of water content on high-pressure briquetting. Mechanical performance improves with higher biomass proportion and lower water content in the raw material. Because of the advantages of the new briquetting method, the process line can be simplified dramatically. The power consumption is about 15kWh per ton briquette. Total processing cost is about RMB20 (equivalent to US$2.5) per ton briquette, including capital investment and operation cost, less than 1/3-1/5 of that in conventional ones.

INTRODUCTION

As raw coal combustion in large amounts is one of the main reasons causing coal smoke-type air pollution, it is very important to implement varied clean coal combustion technologies for air pollution control in China. Considering cost, environmental effect and economic benefit comprehensively, the coal briquette is one of the practical technologies suitable for the situation in China. But, because of the high processing cost, difficult ignition, unsteady combustion, and negative effects on boiler production capacity, the potential advantages of coal briquettes have not been capitalised on fully at present. As a large agricultural country, China is abundant in biomass resources, with an annual yield of 6000 million tons of agricultural residue. The biomass coal briquette is a new and cleaner method to utilize coal and biomass resource. Taking full advantages of coal and biomass respectively, the biomass coal briquette has unique potential features of retaining a high fuel thermal value, reducing SO2 emission and CO2 due to substitution of fossil fuel and use of sulfur retention reagent. Moreover, there is no need for binding materials due to the linkage function ofbiomass fiber; this could reduce the processing cost enormously. The

1830 key point in biomass coal briquetting technology is how to use biomass fiber as a binder. The conventional biomass coal briquetting technologies make use of the softening ~and self-linkage characteristics of biomass at low temperature, requiring very low water, content both in the coal and biomass. This mechanism usually leads to an overly high briquetting pressure which has a negative effect on the briquette. The objective of this study is to establish a new briquetting technology, based on analyses of the disadvantages and limitations in conventional high-pressure briquetting processes, then to carry out some experiments on briquetting and combustion.

T E C H N I C A L C H A R A C T E R I S T I C S OF C O N V E N T I O N A L B R I Q U E T T E R The present high-pressure biomass coal briquetter is usually made using conventional rolling briquetting technology, using two semi-spherical moulds to produce briquettes under high pressure. Due to the special characteristics of biomass, a screw feeder with automatic control system is applied before the two rollers to pre-compress the raw materials to a certain density. This rolling mechanism has a potentially negative effect on briquetting. When the friction force is not enough to keep the materials moving downwards along with the rollers as the pressure gradient increases, a small part of the materials will inevitably go upward (relative to rollers' movement), resulting in high power consumption in briquetting and wearing of the rollers. Especially when the pressure increases continuously after the materials between the rollers reaches quasi-uncompressable status, it will cause a gliding movement that will cut the linkage of the biomass fiber between the two semi-spheres. One of the characteristics of the present briquetter is to take the lignin-like bond produced from b iomass, o ver its softening point via friction h eating, t o bond the two s emi-spheres together. Another characteristic is to adjust the screw speed automatically, rather than to make the feeding rate steady, providing pulse feeding to make the rollers move to-and-fro repeatedly in a horizon direction within a high-pressure air chamber, then to obtain a higher briquetting pressure and thus reduce the cutting force. For the former characteristic, strict control of the water content is needed. For the later one, the automatic control system needed to make the feeder and roller run in a consistent manner is very complicated, resulting a high manufacturing cost.

Size/mm

TABLE 1 SIZE DISTRIBUTION OF THE RAW MATERIALS, % 3.0.-.2.0 2.0~.1.0 1.0--0.3 <0.3

Linyi coal 9.5 13.0 40.6 37.0 Datong coal 20.7 25.0 37.6 16.7 Rice straw 3.3 9.6 51.5 35.6 Cornstalk 0.9 4.2 36.6 58.3 *Most of the rice straw is 5-8 mm fiber, and cornstalk is much shorter at 2-5mm. The experiments with two kinds of bituminous coal, Datong coal and Linyi coal, and two kinds of biomass, rice straw and corn straw, were carried out in the conventional briquetter at different coal/biomass ratios and water contents. The size distribution of raw materials is shown in Table 1. The results show that, with Linyi coal, an unbroken briquette with good mechanical performance was obtained under certain conditions. But, the briquette with Datong coal is very easy to break into two pieces; each half retains high pressure resistant strength. It is indicated that the conventional briquetter is not suitable for some kinds of coal and that strict control ofbriquetting conditions is required in terms of pressure, water content, coal category, etc.

NEW BRIQUETTING PROCESS AND EXPERIMENTS

1. Description of new Briquetting technology Based on the observation and analysis of the phenomena and mechanism of the conventional briquetting process, a new method was put forward to overcome the shortcomings presented in the existing system. It applies two different curves, intersected in rollers, to form a closed chamber as the rollers rotate. The mix of

1831 coal and biomass in the chamber is pressed into briquettes under high pressure. The process can be described as follows: a) pre-compress the materials to reduce the bulk to a half or so as the rollers rotate via friction force and gravity. The bulk of the materials between two rollers is reduced rapidly under relatively low pressure. Materials rise up during this stage because the vertical friction is not enough to resist the pressure gradient. It does not matter in terms of cutting the biomass fiber under such a low pressure, b) The materials enter the occlusive zone. The vertical friction is greater than the pressure gradient, and no rising occurs in this stage (briquetting pressure is less than 50MPa). c) The briquetting pressure is increased rapidly as the two different curves intersect each other to form a quasi-closed chamber. Turning up occurs only at the outside edge of the briquette; there is little effect on the break-up of briquette. This stage is similar to the briquetting process with the piston and die type press. 2. Experiments under new Technology Experiments with various types of coal and biomass at different conditions were conducted aider the system was improved with the new method. The preliminary results are tabulated in Table 2. All coal and biomass was dried in the open air. The water contents of Datong coal, Linyi coal and Jingxi blind coal are 6%, 0.7% and 4.7% respectively. The water contents of rice straw and cornstalk are 9.5% and 19.1% respectively. TABLE 2 EXPERIMENTAL RESULTS AFTER IMPROVEMENT

Coal type

Biomass Type Proportion %

Linyi bituninous coal

Jingxi blind coal

Pressure-resistant strength, N

17

171

171

458

30

142 171

142 171

1330 1717

50

142

142

1885

102

127

2472

30

142

142

1191

Comstalk

17 17 25 25 30

102 142 122 142 142

127 142 127 142 142

1133 1076 1208 1169 1992

Rice straw

30 50

142 142

142 142

1443 2908

30 30

142 122

142 127

1051 989

Cornstalk Datong bituminous coal

Pressure/MPa Pre-set Actual

Rice straw

Rice straw

2.1 Effects of pressure and fiber shape on briquetting It was reported that, in the low-pressure briquetting process with traditional binder, the mechanical strength of the briquette depends mainly on the types of binder, rather than pressure, once the pressure is > 25MPa. In traditional high pressure biomass coal briquetting technology, the best mechanical strength performance is obtained at about 200MPa. It can be deduced that there should be a eigenvalue for briquetting pressure to fix the linkage function of biomass fiber under the new mechanism. A lot of experimental results in this study showed that the suitable briquetting pressure is less than 120MPa for various biomass proportions. When pressure is higher than the eigenvalue, the briquette's mechanical strength decreases as the pressure increases. This is different from the test results with piston and die type briquetting, in which briquette strength continues to increase as the pressure increases. This may be because the relative gliding movement between the briquette and rollers increases as the pressure increases, making the mechanical performance worse.

1832 In the improved rolling briquetting process, the length ofbiomass fiber plays an unimportant role. Unlike the results in die type briquetting, the briquette with the shorter fiber of cornstalk has a better mechanical performance than that with the longer fiber of rice straw. It is reveals that it is more important to control the fiber thickness, rather than length, in the biomass breaking process, especially for rigid straw.

2.2 Effect of water content in coal on briquetting As it is not necessary to make use ofbiomass softening caused by frictional heating with the new briquetting method, it is supposed that the water content in the raw coal could be increased. But, increasing the water content has a clear negative effect on high-pressure briquetting, as shown in Table 3. This could be because the lubricating effect of the water increases the gliding movement of the raw materials between the rollers, making it impossible for the actual briquetting pressure to reach the preset value. The power consumption of the briquetter decreases as the water content in the coal increases. The water absorption of the biomass fiber could offset the negative effect and increase the working pressure. Increasing the biomass proportion and decreasing the briquetting pressure could increase the upper limit of water content in the raw materials. For example, adding 6% of extra water to Datong coal (water content is measured at 10.2%), mixed with 20% cornstalk containing 9.3% water, the pressure resistant strength of briquette could reach to 767N with a briquetting pressure of 120MPa.

TABLE 3 EFFECT OF WATER ADDITION ON BRIQUETTING PERFORMANCE Water added, % 0 2 4 6 Pressure resistant strength, N 770 667 474 197 *Linyi bituninous coal (water content of 1.2%): rice straw (water content of 11.4%) =85:15. *Coal is mixed with water first, then mixed with rice straw. Briquettingpressure is preset at 140MPa.

2.3 Coal types and suitable biomass proportion Theoretically, it is possible to totally utilize the linkage function of biomass fiber to produce briquette under high pressure in the new method, thus, the pressure resistant strength of the briquette increases as the biomass content increases, enabling all types of coals to be briquetted successfully. Taking into account all issues such as biomass usage, briquette strength, water content, etc., the lower limit of suitable b iomass content is determined as 15%.

CONCLUSIONS The new type of roller has excellent ability for increasing briquetting pressure, and to double the limit of water content in coal for briquetting. There is no need for a screw feeder when the biomass content is less than 50%. Pure biomass could be briquetted with a screw feeder. The new method can greatly improve technical and economical performance of the biomass briquetting process. All types of coals, including bituminous coal and blind coal, can be briquetted with biomass. The combustion experiments carried on in five boilers of different type and capacity, show that boilers could work as normal, obtaining a sulfur retention of 50-60%, with a proper sulfur-retention reagent. Because of the advantages of the new briquetting method, the process line can be simplified dramatically. The installation and operation cost could be much less than that of the traditional ones. The power consumption is about 15kWh per ton briquette, 1/3-1/5 of that in conventional system. The total processing cost per ton briquette is about RMB20 (equivalent to US$2.5), including capital investment and operation cost. Assuming the biomass proportion is 20% and thermal value is two-thirds of coal, the abatement cost of CO2 emission is estimated approximately at US$20 with the new biomass coal briquetting technology.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1833

NEW FUEL BCDF (BIO-CARBONIZED-DENSIFIED-FUEL)" THE EFFECT OF SEMI-CARBONIZATION T. Honjol, M. Fuchihata 2, T. Ida2 and H. Sano 3 INational Institute of Advanced Industrial Science and Technology, 1-8-31 Midorigaoka, Ikeda, Osaka 563-8577, Japan 2Kinki University, 3-4-1 Kowakae, Higashi-Osaka, Osaka 577-8502, Japan 3Laboratory of Global Energy System, 5-8-2-106 Makioti, Minou, Osaka 562-0004, Japan

ABSTRACT

Woody biomass is a potential energy resource for reducing greenhouse gas emissions. Japan has much forest - two-third of the land area is covered with forest. But, only a small amount of woody biomass is utilized for energy production. Therefore, it is necessary to reduce the labor and costs of gathering and transportating the materials in order to utilize it for energy production in Japan. The object of our study is to improve the calorific density of woody biomass pellets, and reduce the transportation cost per unit energy. We adopted the semi-carbonizing method to achieve it [1, 2]. After the biomass is completely dried, it is dehydrated further by decomposition of cellulose, hemi-cellulose and lignin, during carbonization. During dehydration, this process also occurs with the accompanying organic volatiles, and the energy yield of the carbonized wood is reduced. Therefore, semi-carbonizing conditions, at which maximum energy yield can be achieved, should exist. This study examined the optimum semi-carbonizing condition for pelletizing. INTRODUCTION In Japan, the amount of forest growth is big, estimated at 500Mdry-t/y [3, 5]. Nowadays, felling, collecting and transportation are labor-intensive, hence, very expensive. Consequently, it is difficult for woody biomass to compete with fossil fuels in terms of price in Japan. Therefore, we must provide solutions to issues of gathering and transport for the TABLE 1 effective utilization of woody biomass. CHARACTORS OF SEMI-CARBONIZED BM & CHARCOAL The goal of our work is to improve the energy density and the energy yield of woody biomass pellets and reduce their Calorific Calorific Energy transport costs. Increasing the energy yield density density % MJ/k~; GJ/m3 density of bio-fuel is the most important requisite in order to improve its 4-11 0.4-1 100 Green brush wood transportability. We adopted the 100 7-17 2-5 Dried wood semi-carbonizing method to achieve this. 100 17-19 10-11 Bio-pellet Woody biomass could be further about95 17-19 11-13 Ogalight* 1 dehydrated by the decomposition of . . . .

cellulose and hemi-cellulose, and combination of chemically dehydrated water in the temperature range from 200

Semi-carbonized BM Charcoal

25-35

(15-21)

50-90

33-34

(20-21)

18-40

* 1: Artificial firewood (commercial item in Japan)

t834 to 300 °C. In the present study, we examined the conditions of semi-carbonizing and pelletizing for maximum energy density and energy yield.

SEMI-CARBONIZATION The characteristics of semi-carbonized biomass and charcoal are shown in Tablel. The semi-carbonized biomass fell between the bio-pellet and classical charcoal. Fig.1 shows a schematic of the relationship.

30

,2,

•~ O

/6~

HdT~~,og/~/'/~"

c~o.,

",', " "

-

20

"o f_1 "el I=3

"d o

I0

Bmd~ood bm~lk d w ~ he~t

b~dkd w~hm~h~ I

I

I

I

10 Calorific densityt v GJlm3

1

20

Figure 1: Calorific density diagram for woody biomass Electric furnace (detachable)

,'

I

I...

(----4---,~

.

I

I

t

]

I

,

i

i '

',

i

i

! ~

'

Compression with ] m oil hydraulic machine

.

.

i

.

.

.

.

i

',

~sp,,i

, :

: I

i

F--[

......

~,---~ ....

"-r'--'r-

/1

m.:,

:

':

~]

,

:

,,

'

I

',

for tube

. -. t t .t .. . .. . . ..

,

--._ ~I . . . . ' ',

...... ~

;I

\i

___L~ se

Figure 2: E x p e r i m e n t a l a p p a r a t u s Dried woody biomass consists of cellulose, hemi-cellulose and lignin. The cal. density/w, increases during the process from the green wood to the absolutely dried state, since free water, which originates in green wood, is gradually evaporated, then the weight decreases significantly with no calorific loss.

1835 Concurrently, its volume slightly diminishes. Therefore, the calorific density per unit volume (cal. density/v) slightly increases. Cellulose and hemi-cellulose dehydrate under conditions from 200 to 250 °C due to thermal decomposition. Carbonization starts from this point, then the color of wood gradually turns black. We define semi-carbonization as these processes. The generation of wood-tar is a feature of the semi-carbonization process. The mechanisms of wood-tar generation are considered as the thermal decomposition of lignin and that of cellulose. The wood-tar is sublimated at over 400 °C. It is advantageous for the wood-tar to remain in the char for pelletizing, as it acts as antiseptic, lubricant and binder. Although the cal. density/w for charcoal matter is high, the energy yield of their production is relatively low, about 20% for mass fraction, and no more than 40% for calorific fraction [6]. Furthermore, it cannot be well pelletized without additional binder. Therefore, the high calorific and energy yielding pellets can be produced if the volatile components are retained, including the wood-tar. This is the concept of the semi-carbonization we proposet. The energy density of semi-charcoal could be higher than that of charcoal, as the semi-charcoal includes more hydrogen and other organic substances, etc. EXPERIMENTAL In this study, we used four types of biomass, sawdust, leaves and branches of a type of Japanese cypress and cellulose. Initially, thermo-gravimetric analyses (TG/DTA) for some types ofbiomass were carried out. Aiming at t he avoidance of t he energy loss, w e determined t hat t he semi-charcoal was rich i n o rganic volatiles. Therefore, we adopted hot-pelletizing, the simultaneous processing of heating and pelletizing. Figure 2 shows the experimental apparatus. About 1g of a sample was placed between the molds in the reactor tube and a mechanical pressure applied, P= 0-250kgf/cm 2. They were then heated in an electric furnace at the rate of 20 °C/min. to the final temperature residence time, where they were kept for 15 -30min. T was selected as 150-340 °C. Samples were used after drying at 110 °C for 4 hours. In the case of cellulose, experimental data are shown in Table2. Photogr.laphs of the surface of cellulose BCDF by optical metallograph are shown in Fig. 3. The semi-carbonized pellets were at about 200-330°C in the case of cellulose. With sawdust, white was 200-300°C, red was 200-270°C, leaves were 200-250°C, and branches were 200-290°C. Cellulose has a wider range for pelletization compared with these biomass materials. In the case of woody industry, wood is usually pressed at 170-200°C by steam treatment [4]. The pellets Were obtained under 86-400 kgf/cm 2 pressure. The lower pressure tended to facilitate pelletization until high temperatures were reached. TABLE 2 EXPERIMENTAL O F S E M I - C A R B O N I Z E D B I O - P E L L E T S

Run no.

Sample

5o

Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose Cellulose

46 47 46 37 39 20 21 ,,~22 24 22

Pressure Temp. kgf/cm2 °C 86 270 86 300 86 340 130 320 130 330 130 340 250 280 250 290 250 305 250 310 250 320

Hold time rain. 15 15 15 15 15 3 15 15 5 15 5

Weight Pellet Yield of loss density pellet *1 % g/cm3 (%) 6.6 1.Ol lO0 8.8 0.94 99.9 59.7 0.95 1O0 30.5 1.06 99.9 47.8 1.07 100 48.2 0.94 97 6.7 1.19 100 6.9 1.13 100 10.3 1.17 100 41.6 1.00 87.6 56.6 0.99 75.3

1836

1. Cellulose 130kgf/cm 2 320 °C.

2. Cellulose 130kgf/cm 2 330 °C.

scale • 50~tm

Figure 3: Photographs of the surface of the semi-carbonized pellets by optical metallograph. RESULTS & CONCLUSIONS Semi-carbonized biomass can be pelletized by compression, in order to improve its calorific density/volume by eliminating the void space, and also to improve the calorific density per unit weight by eliminating the water in chemical molecules. This BCDF (Bio-carbonized densified fuel) can be made from biomass such as branches, brushwood, sawdust, etc. The characteristics of BCDF are shown in Tab.3. The important features ofbiomass fuel are: (1) Water content is closely connected with calorific density/weight. Free water can be easily removed by drying. Conversely, dehydrated water, chemically combined in organic molecules, should be removed by thermal decomposition alone. (2) Void space is closely connected with calorific density/volume. The void space can be decreased by pelletizing, but this is very difficult for water-rich biomass, such as raw brush wood. Charcoal is also difficult to pelletize, because of its lack of stickiness. The semi-carbonized biomass is ideally suited for pelletizing and obtaining a high calorific density. TABLE 3 COMPARISON OF CHARACTRISTICS OF BIO-FUEL

Bulk density (g/cm3) commercial

Maximum* 1

Water contents (%) Free Decomposed. water water *2 40-50 55

Green brushwood

0.1

0.9-0.95

Dry brushwood

0.3

0.8-1.0

15-30

55

Bio pellet

0.5-0.7

1.0-1.1

5-15

55

BCDF

0.4-0.8

0.8-1.1

0-10

10-30

Charcoal

0.6-0.8

0.6-1.1

0-10

2

* 1" without void *2" water derived from organics after thermal decomposition REFERENCES 1) Honjo,T., Ida,T., Fuchihata,M., Sano,H. : Proceedings of the 21th Annual Meeting of Japan Soc. of Energy and Resources, pp.429-434 (2001). 2) Honjo,T., Sano,H., Ida,T., Fuchihata,M. : Proceedings of the 18th Conference on Energy, Economy and Environment, pp.257-262 (2002). 3) Report of RITE,"Development of prevention of global warming by carbonization of woods", RITE(Research Institute of Innovative Technology for Earth), p.80(2001). 4) Inoue,M:, Mokuzai-kougyou (Japan), vol.56, No.5, pp.245-249(2001). 5) Yokoyama,N.: J. of Japan Energy Institute, vol.81, No.4, pp.236-248(2002). 6) Kishimoto,S.: "Carbon", Soushin-sya, pp.208-210(1998).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1837

EVALUATION OF TECHNOLOGY OF GENERATING ELECTRICITY WITH WOODY BIOMASS-ESTIMATE OF REDUCTION IN CO2 EMISSION

T. Ogi I and Y. Dote 2 1. National Institute of Advanced Science and Technology, Onogawa 16-1, Tsukuba, Ibaraki 305-8569 Japan, 2. Miyazaki University Gakuen Kibanadai Nishi 1-1, Miyazaki, 889-2191 Japan

ABSTRACT We evaluated processes for converting woody biomass-to-energy and estimated the gross reduction in CO2 emissions (Rc) made possible by the use of these processes compared with coal or diesel fuel burning. We assessed 4 processes: combustion for steam turbine power generation, gasification for gas turbine power generation, pyrolysis for diesel engine-driven power generation, and ethanol fermentation for diesel-enginedriven power generation. R• values were 385 kg-C/t-biomass, 499 kg-C/t-biomass, 345 kg-C/t-biomass, and 198 kg-C/t-biomass, respectively. We also estimated the net reduction in COx emissions (RN), by considering 5 CO2 release processes: (a) biomass production, from field preparation to harvest, (b) collection ofbiomass, (c)biomass transportation to power generating plant, (d)pretreatment of biomass for power generation, and (e)conversion of biomass to fuel (only in the cases of pyrolysis and fermentation). Two transport scenarios were considered: the use of biomass generated in Japan and the use of biomass imported from abroad. The process that reduced CO2 emission most effectively in both scenarios was gasification for power generation. INTRODUCTION Biomass, which is renewable and fixes atmospheric CO2, has attracted attention as an environmentally compatible energy resource that is effective in mitigating global warming. Its extensive use has been advocated by IPCC reports and at COP3. The trend toward using biomass energy is especially strong in Western countries. Until recently, the term "biomass" was not found among new energy resources in Japan. However, deliberations held in June 2001 by the Advisory Committee for Natural Resources and Energy, biomass was added in January 2002 to the New Energy Source Law by a cabinet order amendment, and targets were set [ 1]. Although there is an increasing trend toward biomass energy use, very few large-scale commercial operations use biomass energy. If it is to be used extensively in the future, we will need to perform research that quantitatively evaluates potential biomass supplies and systems for introducing biomass energy. We estimated the gross reductions in the emissions of CO2 (Rc) that would occur if coal were to be replaced with woody biomass and if 4 types of biomass-to-electricity conversion processes were introduced in Japan. We also estimated the net CO2 reduction (RN), for each conversion process by taking into consideration both released and absorbed carbon in the total chain of 5 processes: biomass production (Re), biomass collection (Rcn), biomass transport (RTB), pretreatment (Rex) and energy conversion (RcoNv).

1838

RESEARCH

METHOD

Biomass power generation system We chose 4 biomass-to-electricity conversion processes: combustion for steam turbine power generation, gasification for gas turbine power generation, pyrolysis for diesel engine-driven power generation, and ethanol fermentation for diesel engine-driven power generation, as these processes are now either in limited but practical use or will be available in the near future. In the cases of combustion and gasification, we assumed that woody biomass would be substituted for coal. In the cases of pyrolysis we assumed that woody biomass would be first pyrolyzed to produce heavy-oil like liquid fuel (referred to as "bio-oir'), and in the case of ethanol fermentation we assumed that it would be saccharified and fermented to produce ethanol. Both the bio-oil and ethanol would then be substituted for diesel fuel in power generation. We chose 2 types of pyrolysis (or ethanol fermentation) systems: (a) transported bio-oil (or ethanol), (b) transported woody biomass as feedstock. Because in (a), the power plant and pyrolysis (or fermentation) plant would be in different locations, we took into account the CO2 emissions (RcoNv) that would arise because an extemal energy source would be used for pyrolysis (or fermentation). In (b), the power plant was assumed to adjoin the pyrolysis (or fermentation) plant, which would use energy (electricity) supplied by the power plant, and therefore RcoNv was not taken into account. We assumed that to drive the generators, turbines were used with combustion and gasification and diesel engines were used with bio-oil and ethanol. We also considered 2 transport distances: 30 km (when using biomass collected from a local area in Japan: domestic biomass) and 20,000 km (when using biomass imported from abroad: imported biomass).

Calculation of C02 reduction The net amount of CO2 reduction, RN (kg-C(carbon)/t-B(biomass))was calculated by the following formula: RN = RG - - (Rr + Rca + RTB + RpT + RCONV), where: Rt; • gross amount of CO2 emission avoided by replacing coal with biomass, when employing biomass-to energy conversion process. Further, RG = 0 o X ( r/a / r/c) RE = 0 c × Yo×

× HB (combustion and gasification)

(Oo × r/o--EpL) / r/c

(pyrolysis)

RG = 0 c X Y F × (QE× r/E--EET) /r/c (ethanolfermentation) 0 c " amount of carbon released per GJ coal (27.99 kg-C / GJ) r/c " electricity production efficiency of coal-fired power plant ( - ) 0.37 r/B " electricity production efficiency ofbiomass power plant (--) r/n was calculated as follows: r/n = ot t3Aa CA " electrical capacity (MW) • or,/~ • values obtained from a regression curve by plotting data (capacity-efficiency) from a review of the information in our previous work.J2] 770 " electricity productioon efficiency of diesel engine power plant using bio-oil (-) 77E " electricity production efficiency of diesel engine power plant using ethanol (-) Oo(GJ/t-0)" low h e a t i n g value (LHV) of b i o - o i l " Qz(GJ/t-E)'heatingvalueofethanol Y0 ( t - 0 / t - B ) , YE ( t - E / t - B ) • yield ofbio-oil or ethanol from biomass HB " heating value ofbiomass (20 GJ / t-B) Re • amount of carbon released from biomass production from field preparation to harvest (kg-C/t-B) Rcn " amount of carbon released from biomass collection (kg-C/t-B) RTR " amount of carbon released from transport ofbiomass or produced fuel (bio-oil or ethanol)(kg-C/t-B) R r r • amount of carbon released from pretreatment (kg-C/t-B)

1839 RCONV : amount of carbon released from production ofbio-oil or ethanol (kg-C/t-B) RcoNv = 0 E× EEr X YE

(ethanol fermentation) ; Rc0~= 0 EX EpL× Yo

(pyrolysis)

0 E(kg-C/GJ) ; amount of carbon released when obtaining GJ electricity (93.3 kg-C/GJ) EpL(GJ/t-0), EEr (GJ/t-E):external energy needed to produce 1 t bio-oil or ethanol. When biomass was transported, a value "0" was used, because we assumed that the electricity used for pyrolysis (fermentation) was supplied by the adjacent power plant. RcoNv was taken into account when bio-oil (ethanol) was transported. The parameters were obtained from the literature. [3] For RP, RCB, RPT, we used values obtained in previous research.[2]

R E S U L T S AND D I S C U S S I O N

Parameter study results Table 1 shows the parameters used as standard conditions for calculation. The values in parentheses express the range of parameters obtained by reviewing the literature. For Rp and RpT, average values were used.

TABLE 1 PARAMETERS USED FOR ESTIMATION RP (kg-C/t-B) :32.04 (15.11~42.09)

Rex (kg-c/t-B) :6.89 (3.96 ''~10.88)

RCB(kg-C/t-B) : 0.30(combustion), 0.26 (gasification) ,0.30 (pyrolysis) ,0.39(ethanol fermentation) CA(MW) : 25 (0.3~676) (combustionand gasificationpower generation) , 5 (dieselpower plant) cr 0.179 (combustion), 0.264 (gasification), B 0.126 (combustion), 0.086 (gasification) o 0.37,

77~0.40,

EpL0.595(GJ/t-oil),

O0 15.8 (GJ/t-oil), QE 29.7(GJ/t-ethanol),

Y0 0.737,

YE 0.22,

EET 10.6 (GJ/t-ethanol)

Electricity production efficiency (and consequently RN) increased monotonically with increasing CA. However, we assumed a CA value of 25 MW in combustion and gasification power generation, o wing to economical limitations reported in literature.[4] In diesel power generation, we assumed a CA of 5 MW. Carbon contribution of each process and estimated amount of net carbon reduction

By using the parameters in Table 1, we estimated the amounts of carbon reduced and released from each process. The results are shown in Table 2.

1840 TABLE 2 ESTIMATED AMOUNTS OF CARBON REDUCED AND RELEASED FROM EACH PROCESS (unit • kg-C/t-B) Conversion

Transported

Distance

process

substance

(km)

RG

i, RP

RPT

RCB

RTB I

biomass

Gasification

biomass

30 30

345

Pyrolysis

bio-oil

30

198

332

459 32 32 ' 6.9 i 0.30.

!

42

290

42

417

0.30 :° 1.2 ,: 39.3 ',

80

266

62

135

184

147

i

184

275

",, 6 . 9 ' ,, 0.30 " 73 i 39.3 i " 6 . 9 : 0 . 3 9 ' 72.6 ', 21.8 '

151

194

134

64

'

30

biomass

20,000

biomass

20,000

Pyrolysis

bio-oil

20,000

Fermentation

ethanol

20,000

Gasification

, :

: 2.4

:

°

32 ' 6 . 9 ' 0.39 ', 332 459

Combustion

, ',

-

-

, ',

:

:6.9', ,

ethanol

'2.4',

1

:

1

32 32 ' 6 . 9 : 0 . 2 6 ,

Fermentation

RN

',

Rconv Combustion

RT

i

32

345

,, ,, 32 ' 6.9 " 0.30

198

32 ' 6 . 9 '

0.26

° °

, ,,

,

,,

1.2

, :

'

145

,

' 21.8

:

, :

, :

'

-

,

',145',

," '0

-

In the scenario of short distance (30 km) transportation (using domestic biomass), o f the 5 CO2 releasing processes, Ib, (production of biomass) released the most carbon, (with the exception of RcoNv in pyrolysis), reaching about 80% of the total emission (RT). In pyrolysis, the conversion process consumed much energy and RcoNv was the biggest value. The contribution of Rca plus RTB, about 5% of RT, was relatively small. Although the amounts of carbon released from the total of production to conversion processes (RP + 1L,'T + RcB + RTB + RCONV) ranged from 10% to 45% of R6 depending on the process, the l ~ (= RG- RT) value was positive in all cases, which showed that power generation systems that replace coal with biomass contribute to CO2 reduction. In the scenario of long- distance (20,000 km) transportation (using imported biomass), the contribution of RTB was as high as 48% to 78% of RT, especially when feedstock biomass was transported. In the case o f ethanol fermentation, when the transport distance was 30 km, RN was nearly the same at 135 to -140 kg-C/t-B whether biomass or ethanol was transported. On the other hand, at 20,000 km, 1 ~ became negative when biomass was transported (not shown in Table 2). Figures 1 and 2 shows compare RN values among the 4 processes for transport distances of 30 km and 20,000 km, respectively. No matter what the transport distance, the RN value was highest when gasification was adopted. The gasification o f woody biomass forpower generation by gas turbines was the most effective process at reducing carbon. 500

300

400

250

,,.5.'

3oo ~ ",

200

-I

200

150

I00 100 5O

0

-

EF

-

PY

-

-

-

Figurel" Comparison o f l ~

0

GGG

CSG

(30 km)

EF

Figure

PY

2:

C~G

GGG

Comparison of RN (20,000 km)

1841 EF: ethanol fermentation- diesel engine generation, PY : pyrolysis -diesel engine generation CSG: combustion steam turbine generation, GGG : gasification gas turbine generation CONCLUSIONS We evaluated 4 processes for converting woody biomass-to-electricity and estimated the gross reduction in (202 emission ( R , ) and the net reduction in CO2 emission (RN) made possible by the use of these processes compared with coal and diesel fuel combustion. Two transport scenarios were considered. In the scenario of short distance transportation, although the amounts of carbon released (RT) ranged from 10% to 45% of RG depending on the process, the RN (=RG-RT) value was positive in all cases, which showed that power generation systems contribute to CO2 reduction. In the scenario of long distance transportation, the contribution of transportation (RTB) was as high as 48% to 78% of Ra". The process that reduced CO2 emission most effectively in both scenarios was gasification for power generation. ACKNOWLEDGEMENTS This work was funded by the Global Environment Research Program (Ministry of the Environment). The authors wish to thank Dr.Shin-ya Yokoyma (Director, AIST Chugoku Center) and Dr. Amano (Director, FFPRI) for their valuable information and suggestions. REFERENCES 1. The New Energy Source Law, amendment at January 25, 2002. 2. Dote, Y., and Ogi, T., (2001) Progress in Thermochemical Biomass Conversion, ed. by Bridgwater, A. V., Blackwell Science, 1,965 3. All literatures (23 documents) quoted in this work are listed in the above-mentioned reference [2] 4. Toft, A.J., and Bridgwater, A.V., (1997) Developments in Thermochemical Biomass Conversion, BLACKIE ACADEMIC & PROFESSIONAL, 1556

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1843

CARBON SINK AND STORAGE CAPACITY OF FOREST ECOSYSTEMS IN OZE, CENTRAL JAPAN Atsushi Hiranol, Makoto Tsuchida l, Michio Ishibashil, and Kazuhiko Ogino 2 Tokyo Electric Power Company 2 The University of Shiga Prefecture

ABSTRACT Tokyo Electric Power Company (TEPCO) owns some 180 km 2 of land, almost all of which is covered with forests, in Oze, Gunma Prefecture. In this study, the carbon sink and carbon storage of forest ecosystems including vegetation and soil were evaluated by using two methods. The results showed that the ecosystems stored about 300 tC/ha and the vegetation functioned as a carbon sink of 2 to 4 tC/ha/year. The amount of carbon sink varied according to the type of forest; the sink effect of vegetation of a planted larch forest was twice that of a natural beech forest and a natural fir forest.

INTRODUCTION Forests are considered to play an important role in suppressing global warming by acting as a sink of carbon. COP3, which was held in 1997 in Kyoto, recognized that carbon sinks of forests provide a means of absorbing carbon emissions. Methods for transparent and verifiable evaluation of the carbon sink effect of forests need to be developed, but such evaluation is difficult, especially for a whole ecosystem including vegetation and soil. Various studies have been carried out for this purpose, such as CO2 flux measurement, measurement of standing biomass increment, and model simulations. Measurements of carbon storage in forest ecosystems are also important to clarify the significance of reservations or rehabilitation of forests, because forest ecosystems are estimated to contain several hundred tons of carbon per hectare. TEPCO owns 180 km 2 of mostly forested land in the Oze area of Gunma Prefecture, and has maintained the forests for more than 30 years. In this study, the carbon sink and carbon storage effects of forests were evaluated by a combination of two methods: one was CO2 flux measurement, and the other was a combination of measurements for standing biomass, carbon input and output at the surface of the soil, and carbon storage in the soil.

MATERIALS AND M E T H O D S Location and site description Three types of forest were evaluated: a cool-temperature deciduous broad-leaved forest of beech, a sub alpine evergreen coniferous forest of fir, and a cool-temperature deciduous coniferous forest of larch. The beech forest and the fir forest were natural forests and only the larch forest was planted about 40 years ago. A representative plot was constructed in each type of forest. The area and altitude of each plot were 100 m x 60 m at 1,300 m, 100 m x 70 m at 1,900 m, 30 m x 30 m + 80 m x 20 m at 1,300 m, respectively.

At the beech forest, the annual mean air temperature was 5.9°C, and the monthly mean temperature reached around 20°C in summer and around-10°C in winter. All of the plots were covered with snow from December to May, and the maximum snow depth was about 3 m. Species diversity of each plot was as follows. In the beech forest, the dominant tree was beech (Fagus crenata), but other broad-leaved trees such

1844 as maple (Acerjaponicum Thunberg) existed. In the fir forest, the dominant tree was a fir (Abies Mariesii), but broad-leaved trees such as birch (Betula ermanii) existed. In the larch forest, only larch (Larix leptolepis) existed. The forest floors of all plots were covered with bamboo grass (Sasa kurilensis).

Measurements of standing biomass In each plot, the standing biomass of high trees, sub trees, and undergrowth were evaluated. The undergrowth included shrubs and bamboo grass. Standing biomass of each tree was determined as the sum of the dry weight of the stem (Ws), the roots (WR), the branches (WB), and the leaves (WL). Each dry weight was calculated by_ using an allometric relation to D 2 or D2H described as follows. Ws = a(DI3H2H) b, W R " - c(Do.32) d, WB = e(DB2)f, WL = g(D132)h where, H: stem height; D0.3: stem diameter at height of 0.3m; Dm~: stem diameter at height of 1.3 m; DB: stem diameter at the base of the lowest branch; and a, b, c, d, e, f, g, and h: coefficients The coefficients a, b, c, and d were determined by actual measurements for some sample trees. The coefficients e, f, g, and h were determined from the results of previous researches. To determine the standing biomass of bamboo grass, five subplots for each plot were constructed. In each subplot, the stem length (L), the stem diameter at ground level (Do), the number of leaves per each stem (N), and the mean leaf weight (w) were measured for the all of the stems existed in the subplot. The dry mass of each part was calculated as follows. Dry weight of the stem = (D02L)/3, Dry weight of the roots = dry weight of the stem/1.5 Dry weight of the leaves = N x w The standing biomass of each bamboo grass was determined as the sum of the dry weight of each part. The total standing biomass of bamboo grass in each subplot was calculated as a sum of those. Then, the biomass in each plot was calculated as the product of the biomass in the subplot and the ratio of the subplot area to the plot area. This standing biomass was converted into carbon stock using the carbon content of each part measured in this study.

Measurements of carbon flow In this study, main carbon flows within the ecosystem such as the flow from the atmosphere to the vegetation, the flow from the vegetation to the soil, and the flow from the soil to the atmosphere were evaluated (solid lines in Fig. 1). The net annual carbon flow from the atmosphere to the vegetation was assumed to increase the carbon in the vegetation in one year. This carbon increment was calculated from the annual biomass increment and the carbon content of each part. The annual carbon flow from the vegetation to the soil was calculated from annual litter. To measure the litter, three types of litter trap were devised in each plot. One was a 0.8 m~ net for trapping leaves and small branches. Twenty nets were set in each plot. One was a 5 m x 5 m sectioned ground for trapping large branches. Five sections were set in each plot. These two types of trap were used for the non-snow seasons. Another was a 2 m x 5 m ground sheet spread out in early winter in order to collect all of the litter during the snow season. Five sheets were set in each plot and the litter was collected in early spring. The total litter was converted to the carbon flow by using the carbon contents measured in this study. The annual flow from the soil to the atmosphere was evaluated as the annual CO2 effiux from the soil surface calculated by using the relationship between the effiux and the soil temperature. The CO2 effiux was measured at six points in each plot, four or five times per year. A closed chamber system (LI-COR, 6400), which measured an increase of CO2 concentration in a chamber covering the soil surface, was used. The soil temperature was also continually measured at a depth of 3 cm from the soil surface. The CO2 efflux was expressed as a function of the soil temperature to calculate the annual CO2 effiux from the continuous record of the soil temperature.

Measurement of carbon in the soil In each plot, six soil pits were dug and the soil profiles were studied. The soil horizons were observed according to its color and structure at each pit. Then, the carbon storage in each horizon was determined from the thickness, specific gravity, and the carbon content of the layer after removing roots and gravels. These carbon amounts were summed up to determine the total carbon in the soil at each pit. The total soil

1845 carbon of each plot was given as the average.

Direct measurements of net C02 flux between the atmosphere and the forest ecosystem To evaluate net CO2 flux between the atmosphere and the forest ecosystem directly, a tower equipped with measurement devices was built on the beech forest plot. The CO2 flux was measured by the eddy covariance method, which employed a three-dimensional ultrasonic anemometer (Kaijo, DA-600-3T) and a closed-path type infrared CO2 analyzer (LI-COR, 6262). The velocity and direction of wind and CO2 concentration was continuously measured at about 10 m above the crown. These continuous measurements were divided into data sets of 10 minutes each, and the instantaneous CO2 flux (mol/m2/sec) was calculated by integrating the variance of CO2 concentration from its mean value of 10 minutes (mol/mol) and the air volume which flowed across the boundary between the forest and the atmosphere (mol/m2/sec). The boundary was rotated to set the mean vertical wind speed to zero. A phase translation to correct the time lag of CO2 concentration measurement was also done. Annual CO2 flux was calculated by integrating the instantaneous values. RESULTS

Carbon stock and carbon sink of the vegetation The standing biomass of each part of the vegetation was determined twice for the undergrowth and three times for the high trees and the sub trees. The results are shown in Table 1 as the carbon stock. Those increments were also translated into the carbon sink and are shown in Table 2. The carbon stock and the carbon sink of the vegetation of the larch forest were about twice or three times greater than those of the beech forest and the fir forest, and this was probably due to the difference between the artificial plantation and the natural forests. Bamboo grass accounted for 5 to 30% of the total carbon stock of the vegetation, and these values were not negligible. Net carbon input and output at the surface of the soil The carbon input at the surface of the soil calculated from the annual litter is shown in Table 3. On the other hand, carbon output, i.e. annual carbon efflux from the soil to the atmosphere, at the beech forest plot, at the fir forest plot, and at the larch forest plot were calculated as 8.6, 6.4 - 6.9, and 8.6 - 8.8 tC/haJyear, respectively. In this calculation, the soil CO2 efflux and the temperature of the soil were found to be correlated, as was expected. Those carbon effluxes included the carbon effiuxes by decomposition of organic carbon in the soil and the carbon effluxes by roots respiration. To discuss the carbon balance in the soil, those two effluxes must be distinguished. This subject will be addressed in a future study. Carbon stock in the soil The carbon stock in the soil of the beech forest plot, the fir forest plot, and the larch forest plot were calculated as 192, 215, and 190 tC/ha, respectively. These values were not so different among the plots. The total carbon stock for the forest ecosystem was over 300 tC/ha in each plot. C02 flux between the atmosphere and the forest ecosystem Seasonal changes in the CO2 flux, in which a reasonably vigorous carbon uptake of the ecosystem in the growing season of the vegetation occurred, were observed through the measurements over two years. Net ecosystem production, which was calculated as the integration over time of the instantaneous CO2 flux, was about 1 tC/ha/year at the beech forest plot. ACKNOWLEDGEMENTS We would like to thank Prof. Naoki Kachi of Tokyo Metropolitan University, Prof. Takayoshi Koike of Hokkaido University, Prof. Hiroshi Koizumi of Gifu University, Prof. Akira Komiyama of Gifu University, Prof. Masakazu Suzuki of the University of Tokyo, and Prof. Ikuo Ninomiya of Ehime University for their advice during this study. REFERENCES 1. Komiyama, A., Kato, S., and Ninomiya, I. (2002) J.Jpn.Fpr.Soc.84, 130. 2. Saigusa N. (1997) Jpn. J. of Ecol.47, 321 3. Bekku, Y., Koizumi, H., Oikawa, T., and Iwaki, H. (1997) Applied Soil Ecol. 5,247

1846

[

~

]

The atmosphere (d)

I

a) High and sub

.................!e!....I ...............................................

,°]

trees

(c) Soil

V I

Underground water

]

Figure 1: Carbon stock and carbon flow of a forest ecosystem

TABLE 1 CARBON STOCK OF THE VEGETATION (tC/ha), (a) and (b) in FIGURE 1 Undergrowth

High and sub trees Trees (D1.3>=4cm) 1999

2000

2001

Beech forest

Shrubs (D1.3<4cm)

Bamboo grass

83.7

Fir forest

74.8

Larch forest

139.8

Beech forest

85.2

2.6

9.4

Fir forest

76.6

0.3

25.9

Larch forest

143.8

0.8

4.7

Beech forest

86.5

3.0

9.6

Fir forest

78.3

0.4

28.1

Larch forest

147.4

0.9

4.9

TABLE 2 NET CARBON SINK OF THE VEGATATION (tC/ha/year), (d) and (e) in Figure 1 Undergrowth

High and sub trees Trees (DI.3>=4cm)

Shrubs (D1.3<4cm)

Beech forest

1.3 - 1.5

0.4

Bamboo grass 0.2

Fir forest

1.7 - 1.8

0.1

2.2

Larch forest

3.6 - 4.0

0.1

0.2

TABLE 3 CARBON FLOW FROM THE VEGETATION TO THE SOIL (tC/ha/year), (f) and (g) in Figure 1 High and sub trees

Undergrowth

Trees (D1.3>=4cm)

Shrubs (D1.3<4cm)

Bamboo grass

Beech forest

3.2 - 3.8

Fir forest

2.6 -3.8

0.8 - 1.2 1.8 -2.7

Larch forest

4.2 - 6.7

0.7 - 1.2

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1847

STUDY OF D U R A B L E CATALYST FOR M E T H A N E R E F O R M I N G USING CO2 Takumi Tanaka, Zhaoyin Hou, Osamu Yokota, Tatsuaki Yashima Chemical Reserch Group, Research Institute of Innovative Technology for the Earth, Kizugawadai 9-2, Kizu-cho, Soraku-gun, Kyoto, 619-0292, JAPAN

ABSTRACT To study the durable catalyst for methane reforming using CO2, two approaches were investigated. First, Ni substituted hexaaluminates were employed and proved to have the high coking resistant ability. The reduction at high temperature formed small Ni particles on the surface, which were observed by SEM photograph. Next, addition of Ca to the supported Ni catalyst was examined. It was found that Ca enhanced the interaction between Ni and support and influenced differently to the catalyst property depend on the support.

INTRODUCTION

The importance of methane reforming using carbon dioxide (eql) has been increasing because of its low H2/CO ratio in the product gas and utilization of the greenhouse gases. The steam reforming process (eq2) is the most popular for syngas production, which provides high H2/CO ratio[ 1]. 1) CH4+CO2----~2CO+ 2H2 AH°298=247kJ/gmol H2/CO= 1 2) CH4+H20---~CO+3H2 AH°298=206kJ/gmol H2/CO=3 From a viewpoint of liquid fuel production from natural gas, syngas having low H2/CO ratio such as 1 - 2 is preferred, this is potentially achieved with a control of the CO2/H20 ratio in the reaction gas. However, since decreasing steam causes coke formation on the catalyst, generally, an excess amount of steam is employed, such as S/C>3. Development of the catalyst to suppress the coke formation is essential to decrease the amount of steam required and achieve the optimum H2/CO ratio. Also, it is contributing towards enhancing the efficiency of the process by reducing the amount of input gas. For the depression of carbon formation on the catalyst, addition of alkali to the support [2] or highly dispersed Ni [3] has been reported as being effective. In particular, an alkali support has been reported to enhance the adsorption of carbon dioxide, resulting in conversion of carbon to CO. Based on these studies, we have been researching durable catalysts for methane reforming using CO2 with two applications: a) Ni-substituted hexaaluminate catalyst b)Addition of Ca RESULTS

Ni-substituted hexaaluminate catalyst Hexaaluminates are the compounds which have a /3-alumina, or magnetplumbite, or related layered structure [4]. It is possible to substitute part of the AI by a transition metal such as Mn or Ni. Since this structure can retain a high surface area (>10m2/g) at high temperature, Mn-substituted hexaaluminate has been reported to be useful for high-temperature catalytic combustion [5]. However, there are only a few concerning the application of hexaaluminates for methane reforming [6,7]. We prepared Ni-substituted

1848 barium hexaaluminate (BaNiAlllOl9) and examined the effect of reduction condition, reforming activity, and coke formation in the methane reforming with H20 and CO2.

Catalyst Preparation Ni-substituted hexaaluminate catalyst was prepared via two processes. The powder mixture process is a simple method and suitable for obtaining good strength. The Alkoxide process is the method used to obtain large surface area

Powder mixture process (PM) The powder mixture of A1203, BaCO3, NiO is ground and compressed into a pellet form, then calcined at 1500°C for 1Oh; this is ground into particles with a diameter of 300-850 # m.

Alkoxide process (ALK) Ba metal and Al(OC3H7)3 were stirred in 2-propanol until dissolution was complete. The solution was refluxed at 80°C for 3h under N2. An aqueous solution of Ni(NO3)2 was introducing dropwise into the alcoholic solution. The resulting gel was dried at 110°C, then calcined at 1300°C for 5h. For comparison, 5wt%Ni/o~ A1203 was prepared. An aqueous solution of Ni(NO3)2 was dropped into o~A1203 with a particle size of 300-850 ~z m, dried at 110°C, then calcined at 700°C for 6h.

Reduction of Catalyst When the Ni-substituted hexaaluminate(BaNiAlllO19) was reduced at 700°C, no reforming activity was observed. TGA measured in 50% Hz/N2 flow showed that BaNiAlllOl9 was reduced over 850°C while Ni/AI203 was reduced around 400°C.(Figure 1)

.............................................. BaNiAhxOt9(PM)

\

o~

~ 5 %

-2

NilA1203

-3 0

200

Figure 1:

400 600 Temperature(°C)

800

1000 ]

TGA results in 50%H2/N2 flow

SEM photograph of BaNiAlllOl9(PM) before and after reduction at 900°C for lh were shown in Figure 2.

Figure 2:

SEM of the BaNiAlllOl9 before (A) and after(B) reduction

After reduction, a number of particles were formed on the surface of the catalyst, which were confirmed by EDX measurement to be Ni metal. The size of particles seems to be uniformly 20-30/~ m, which is not so small as a supported catalyst.

1849 The surface area of the catalysts were measured by N2 adsorption at 77K (Table 1). As expected, BaNiAllIO19 prepared by the alkoxide process has a large surface area. Also, H2 adsorption at 298K was measured after reduction. Depending on the difference of the surface area, BaNiAIIIOI9(ALK) showed a larger amount of adsorption than BaNiAlllOl9(PM). Ni/AI203 has more than the double the amount of Ni on the surface than that on the hexaaluminate catalyst. TABLE1 SURFACE AREA AND H2 ADSORPTION OF CATALYST Catalyst

Surface area(m2/g)

5%Ni/AIzO3 BaNiAll lO 19(PM) BaNiAll lO 19(ALK)

H2 adsorption(ml/g)

2.5 1.9 14.3

0.38 "l 0.12 *2 0.18 '2

•l After reduction at 700°C for 1h..2 After reduction at 900°(2 for 1h.

Activity Test Methane reforming reaction with H20 and CO2 was carried out at 700°C under atmospheric pressure, CH4/H20/CO2=3/2/1, SV=72,000ml/g-cat h, process time=15h. Before the reaction, catalysts were reduced for lh at 700°C(Ni/AI203) or 900°C(BaNiAlllOl9). The results are shown in Table2. TABLE 2 RESULTS OF THE ACTIVITY TEST Catalyst . 5%Ni/AI203

CH4 cony.(%)"~ 24.4 BaNiAI iiO 19(PM) 19.6 BaNiAllIOI9(ALK) 24.2 "Average conversion for 15h.

Coke(wt%) 11.7 0 0

Inlet pressure was increasing

All the catalysts maintained constant methane conversion, but in the case of Ni/A1203, the inlet pressure increased steadily because of coke formation in the catalyst bed. TGA analysis of the catalysts after reaction revealed l l.7wt% carbon for Ni/AI203, while no coke was found on the hexaaluminates. An SEM photograph of the catalyst surface confirmed the difference (Figure3). For Ni/AI203, coke covered the active site completely and formed a number of whiskers, while the surface of BaNiAlllO19 remained clear.

Figure3: SEM of the catalyst after reaction 5%Ni/A1203(A) and BaNiAIllOI9(PM)(B) Methane conversion of BaNiAII1OI9(ALK) was about 5% higher than BaNiAlllO19(PM), as expected by the difference of the surface area. Comparing the reforming activity per Ni based on the data in Table 2, hexaaluminates was much higher than Ni/A1203. Conversely, coke formation rates were opposite. Such a difference in catalytic property was thought to be due to the interaction between the Ni and the support or the uniformity of Ni size in BaNiAlllOl9.

Addition of Ca Alkaline metal and alkaline earth metals have been recommended for decreasing coke formation [8,9]. Here,

1850 the influence of the support was studied when various amounts of Ca was added. Experiments

Promoted Ni/SiO2 and Ni/c~ A1203 were prepared by direct impregnation of SiO2 powder and o~-A1203 particles (60-80 mesh) with the solution of Ni(NO3)2 and nitrate of promoter. The catalyst was tested in a quartz reactor with a CH4:CO2=1:1 feed gas without dilution at 800°C under atmospheric pressure, SV=60,000ml/g-cat h, process time=4h. Results and discussions

Alkaline metals (K, Cs) showed excellent coke resistance ability with a sacrificed loss of reforming activity. Small amount o f K (K/Ni<0.01, mol ratio) decreased the coke formatlon rate from 166.7 mg/g-cat-h to zero, while the reforming activity decreased from 73.2% to 25.7% (conversion of CO2). No coke could be detected on the reacted catalyst, even when very limited amounts of Cs (Cs/Ni<0.0025, mol ratio) was added to the catalyst. Reforming activity of Cs promoted Ni/SiO2 decreased with the amount of Cs. Alkaline earth metals (Mg,, Ca, Sr, Ba) showed different coke resistance ability in this research. Sr and Ba had little influence on the reforming activity of Ni/SiO2 and poor coke resistance abilities. Mg decreased the coke formation rate of Ni/SiO2, while the reforming activity decreased slightly with the amount of Mg. The addition of Ca decreased coke formation rate and reforming activity of Ni/SiO2 (Fig. 4). Ca increased the reforming activity of Ni/cz-Al203 (Fig. 5), where the coke formation increased rapidly from Ca/Ni=0.1, reaching a peak at 0.2. o I O0;

200

200

~o I O0 CO2

E 80

~" -,-; 150 ~ o

o

E

~

,

~

~0

~

m

100 o,

-r

~.

-7

o t--

~.

60

(D 40

E

O

c o

I1}

50 -~

20

o

o

•~_

m

c o

~ >

0

0.05

0.I

0.15

0.2

m

100

0 o!

?

80

,I

E

O

t-

0

CH4

150

(O 4 0 -

> 0

-/~

0

ro

(')

¢80

50

20-

-~ 0

0

~----

o

(3

o -,,,.' 0.0 0.01

0.1

1

Ca/Ni mol ratio

Ca/Ni mol ratio Fig.4: Reactivity of Ca promoted Ni/SiO2

Fig.5: Reactivity of Ca promoted Ni/ct-A1203

TPR, XRD and XPS characterization of Ca promoted Ni/SiO2 showed that small amounts of Ca enhanced the interaction between Ni and supports, causing the formation of a stable Ni phase on the surface of supports, which suppressed coke formation. ACKNOWLEDGEMENTS This research was supported by New Energy and Industrial Technology Development Organization(NEDO, Japan). REFERENCES 1. J.R. Rostrup-Nielsen,in J.R. Andersonamd M. Boudart, Catalysis Science and Technology,Vol.5, Springer. New York, 1984. 2. Z.L. Zhang, X.E. Verykios,Catal. Today, 21,589(1994). 3. C.H. Bartholomew, Cal. Rev.-Sci. Eng., 24, 67(1982). 4. N. Iyi, S. Takekawa, S. Kimura, J. SolidState Chem. 83, 8(1989). 5. M. Machida, K. Eguchi, H. Arai, J. Catal., 120, 377-386(1989). 6. M. Machida, T. Teshima, K. Eguchi, H. Arai, Chem. Lett., 231(1991). 7. Z. Xu, M. Zhen, Y. Bi, K. Zhen, Appl. Catal., 198, 267(2000). 8. M.C.J. Bradford et al, Catal. Rev., 41, 1(1999). 9. • Q. Lu, et al, CHEMTECH, January, 37(1999).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1851

MITIGATION POTENTIAL FOR CARBON SEQUESTRATION THROUGH FORESTRY ACTIVITIES IN RUSSIA D. G. Zamolodchikov 1, G. N. Korovin 1 and A. I. Utkin 2 ~Forest Ecology and Production Center of Russian Academy of Sciences, 117810, Profsouznaya ul., 84/32, Moscow, Russia 2Insitute of Forest Science of Russian Academy of Sciences, 143030, Uspenskoe, Odintsovsky r-n, Moscow region, Russia

ABSTRACT

The goals of the present work are to provide an assessment of the carbon budget of the Russian forests and to estimate possible carbon sequestration through forestry and land use activities. The carbon pool in living vegetation of the Russian Forest Fund has varied during the last 35 years between 33 and 35 Gt C, depending on the year. The soil carbon pool is significantly larger than the vegetation pool and varies from 178 to 184 Gt C. The annual accumulation of carbon in growing forests has increased, since 1966, from 185 to 252 Mt C per year. The amount of carbon in wood removed and logging residue decreased from 160 Mt C per year in 1966, to 70 Mt C per year in 1998. The area suitable for reforestation constitutes 45 million ha; an additional 11.0 million ha are designated for afforestation for soil protection purposes. The maximum total annual amount of sequestration due to reforestation and afforestation is 81 Mt C per year. The accumulated carbon pool in the woody biomass of newly established forest stands potentially amounts to 4.1 Gt C.

INTRODUCTION

Forests occupy enormous areas in Russia and play an important role in the global carbon cycle. Nevertheless, the problem of carbon assessment in the forest lands has not been fully solved. The few available scientific estimates are rather contradictory, especially in respect to carbon fluxes and balances [1, 2, 4, 5]. There has been no purposeful carbon inventory prepared for Russia in the past as well as the present. Special official programs to estimate the carbon budget of the country also are absent. As a result, the potential use of Russian forest lands to mitigate global change remains insignificant. The existing data on a Russian forest land inventory allows us to produce an initial approximation of the carbon cycle of forest ecosystems. The goals of the present work are to provide an assessment of the carbon budget of the Russian forests and to estimate possible carbon sequestration through forestry and land use activities.

MATHERIALS AND METHODS

The main sources of information for the present research were the Federal Forest Accounts (surveys of forest inventory data carried out every five years), the annual statistical report on forestry, and experimental information on forest ecosystem biomass, productivity and soils. The forest inventory system in Russia has a 70-year history and is relatively well developed. The Russian forest inventory information consists of

1852 several different types of data, however, that are produced by different methods. These methods include ground observation (63% of the total area of the Forest Fund), remotely sensed information (32%) and visual observation from the air (5%). Another important characteristic is that the Federal Forest Account, being a survey of inventory information held by local forest management agencies, includes information from local forest inventories carried out at different points in time. The pool of tree biomass carbon was estimated from the growing stock of stemwood, using conversion factors [ 1, 2]. The biomass of bushes, grasses, mosses, and lichens was estimated through their total area and an average carbon density per hectare. Organic carbon in the soil was assessed through the amount of humus in the one-meter top layer for different soil types and forest types. The amount of carbon sequestration in forest vegetation was estimated based on the carbon pool change in stands of different age classes. Carbon fluxes from tree harvesting were assessed using conversions factors for the relationship between biomass and wood volume. Fire emissions were determined from the type of the burned land and the amount of forest material burned in canopy fires, ground fires, and soil fires.

CARBON POOL AND FLUXES OF RUSSIAN FORESTS The Federal Forest Account contains data on the area and growing stock of forest land with and without forest cover, as well as for non-forest lands. The area of the land categories of the Forest Fund has been relatively stable from 1966 through to 1998 (Figure 1, top panel) with 25 million ha (2%) increment between 1973 and 1978. The latest account [3] gives the total area of the Forest Fund as 1179 million ha, of which 774 million ha are covered with forest, 108 million ha are not covered with forest, and 296 million ha constitute non-forest land. The forested area has increased somewhat since 1966 while the area without forest cover has decreased. Coniferous stands dominate, covering about 70% of the total forest area. Mature and overmature forests dominate, but decreased their share from 63% to 47%. The area of young forest almost doubled since 1966, while the area of middle-aged forest increased by half. Forest land not covered by forest consists of sparse forest, burned areas and dead forest, cutovers without regrowth, and wastes and glades. The total area has decreased from 137 to 102 million ha since 1966. Sparse forest and burned areas dominate this category, making up 69 and 25 million ha, respectively. The total area of non-forest land is 297 million ha, out of which bogs make up 128 million ha. 1200 1150

C-------------O C

C

0

0~

38

ll00

~

36

1050

--

--o--- a r e a

1000

carbon

pool

950

34

=

32

~

9OO

300

1966

1973

1978

1983

1988

1993

1998

~ . _ . . . - - - o

-r,_ 250 rj ~., 200

.....---o-----

.._.---o---'---

150 = 100

~

50

--O--

carbon

deposition

--

carbon

losses

,

0 1966

due

,

1973

felling ,

1978

,

1983

,

1988

|

1993

,

1998

Figure 1: Dynamics of area and carbon pool in biomass (top panel), annual carbon deposition in woody biomass and carbon losses associated with felling (bottom panel) in Russian Forest Fund since 1996

1853 The results indicate that the tree vegetation carbon pool is stable, both in size and in distribution among different forest types as classified by dominant species. The carbon pool varies between 33 and 35 Gt C (Figure 1, top panel), depending of the year of account. The soil carbon pool is significantly larger than the vegetation pool and varies from 178 to 184 Gt C. The structure of the soil carbon pool is similar to the structure of different soil types by area. The contribution of non-forest soils is comparatively large, however, as bogs are included in this category. An important characteristic of carbon flux is annual carbon deposition in living woody biomass. This value is equivalent to an annual increment of the carbon pool in woody biomass, in the absence of harvesting, forest fires and other destructive influences. The annual deposition of carbon in Russian forests grew from 185 to 252 million tons per year (Figure 1, bottom panel). This increase is associated mainly with changes in forest age structure, but mainly with the increase in the area of young and middle-aged stands. Logging and forest fires have significant influence on the size and changes in the Russian forest carbon pool. The harvested volume fell between 1990 and 1998 from 330 to 125 million m 3. The amount of carbon in removed wood and logging residue during the period from 1966 to the beginning of the 1990's was around 150-160 million t C (Figure 1, bottom panel). Around 86-94 million t C were removed from the forest, while 62 to 69 million t C are estimated to have remained in the forest as logging residue. By 1998, these numbers had decreased to 40 and 30 million t C, respectively. Only part of the Forest Fund is protected from forest fires. During the period 1990-1999 between 15 and 36 thousand forest fires were registered annually within this part, covering between 0.5 and 5.3 million ha of land. The magnitude of direct carbon emissions from forest fires varies between 4 and 50 million t C per year with average level 15 million t C per year. Most of these emissions were caused by ground fires. The burned area within the unprotected part of the Forest Fund is similar to that of the protected part. It is therefore reasonable to estimate that the total emission from forest fires is approximately twice as large (near 30 million t C per year). The forest fires lead not only to direct CO2 emissions to atmosphere but also to postfire tree mortality. The carbon flux, associated with above mortality, is approximately three times more than direct emissions [2]. It is possible estimate the postfire tree mortality flux as 90 million t C per year and total fire influence as 120 million t C per year. The above estimations create the basis for preliminary budgeting of the carbon pool in living woody biomass. By the late 1990s, annual carbon deposition was about 250 million t C per year; the fire influence (including postfire mortality) constitutesl20 million t C per year and harvesting led to carbon losses of 70 million t C per year. Balancing of these fluxes leads to the conclusion that the biomass of Russian forests increases at the level of 60 million t C per year. The above value corresponds well with the dynamics of the carbon pool during the years 1993-1999, when the pool increased annually at the rate of 50 million t C per year.

M I T I G A T I O N POTENTIAL Reforestation means the establishment of new stands on forest land without changing its management goal (i.e. its land use classification). The carbon sequestration potential of reforestation depends on the area and productivity of the stands created as well as the method by which they were established. Several types of forest land are considered suitable for reforestation: cutovers, burned areas within the zone protected from forest fires, forests that are sparse due to human intervention, wastelands and glades. The latest Federal Forest Account [3] estimates the area of these at 45 million ha. On 30 percent of this, reforestation is only possible by means of artificial regeneration. The remaining 70 percent are considered suitable for aided natural regeneration. An additional 11.0 million ha are designated for afforestation for protection purposes, according to the Federal program for increasing soil productivity. These stands can only be established by artificial means. When calculating the carbon potential of reforestation and afforestation, the productivity of the stands established by promotion of natural regeneration was assumed to equal that of natural stands. The productivity of artificial forests was assumed to equal that of already established artificial stands. The period of establishing these new forests was assumed to be 25 years, with equal areas being treated each year. The accumulated pool of carbon in these stands was assessed over a period of 80 years.

1854 The annual carbon sequestration due to reforestation and afforestation grows continuously as an effect of an even growth in area and an exponential growth in tree biomass (Figure 2). Established stands reach their highest rate of carbon sequestration at the age of 50-60 years. The maximum total annual amount of carbon deposition due to reforestation and afforestation is 81.4 million t C per year, of which, afforestation (planting of protection forests) accounts for 31.1 million t C per year. This means that the carbon deposition capacity of Russia's forests can potentially be increased by more than a quarter. The accumulated carbon pool in woody biomass of newly established forest stands potentially reaches 4.1 Gt C towards the end of the 80year period, not counting soil and debris carbon (Figure 2). This is more than 10 percent of the current pool of carbon in woody biomass in Russia. 100 r..)

.~, 80

4 %

r..)

60 2 n

~

20

accumulated carbon

0

,

|

|

|

20

40

60

80

1

oo= <

100

Year

Figure 2: Trends of annual carbon deposition and accumulated carbon pool as a potential result of

reforestation and protective afforestation in the Russian Federation To realize the potential described, the reforestation activity must implement 1.3 million ha per year by aiding natural regeneration and 0.9 million ha per year by planting. Actual levels (1999) are 0.71 and 0.25 million ha per year correspondingly. Note, that ten years ago, the level of reforestation activity was much higher: 1.26 million ha per year for promoting and 0.56 million ha per year for planting. Increasing of reforestation activity and afforestation is connected with availability of funding, including international projects in the field of mitigation of global change. Russia has some examples of successful international projects on carbon crediting of forestry (Saratov and Altai regions).

ACKNOWLEDGEMENTS The research was supported by project "Developing of intemational cooperation in carbon assessment" (World Resource Institute, Washington, USA). Help of L. Laestadius (WRI, USA) in discussing and preparing of results is greatly appreciated.

REFERENCES

1. Isaev, A., Korovin, G., Zamolodchikov, D., Utkin, A. and Pryaznikov, A. (1995) Carbon stock and deposition in the phytomass of the Russian Forests. Water, Air and Soil Pollution 82, 247-256. 2. Isaev, A.S., Korovin, G.N., Sukhikh, V.I., Titov, S.P., Utkin, A.I., Golub, A.A., Zamolodchikov, D.G. and Pryazhnikov, A.A. (1995) Environmental aspects of carbon dioxide absorption through reforestation and afforestation in Russia. Environmental Policy Center, Moscow (In Russian). 3. Forest Fund of Russia (account by 1 January 1999). Reference book. Lesresurs, Moscow (In Russian). 4. Nilsson, S., Shvidenko, A., Stolbovoi, V., Gluck, M., Jonas, M. and Obersteiner, M. (2000) Full carbon account for Russia. Interim report IR-O0-021. IIASA, Laxenburg. 5. Myneni, R.B., Dong, J., Tucker, C.J., Kaufmann, R.K., Kauppi, P.E., Liski, J., Zhou, L., Alexeyev, V. and Hughes, M.K. (2001) A large carbon sink in the woody biomass of Northern forests. Proceedings of the National Academy of Sciences of the United States of America 98, 14784-14789.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1855

F O R E S T A L BIOMASS : POSSIBLE E X T E N S I O N OF THE R E S O U R C E OF W O O D F R O M THINNING IN F O R E S T S H.San01, T.Honjou 2, T.ida3 and M.Futihata 3 Lab.Office of Global Energy System, Osaka, Japan 2 National Institute of AIST, Osaka,

Japan

3 Kinki University, Osaka, Japan

ABSTRACT Woody waste from thinning of forests is one of the most potentially useful forestry energy resources for the future. Other forestry wastes are sometimes considerable, however, increasing the level of these resources are difficult practically because of the limitations of the timber industry in Japan. The area of afforested land that could possibly be thinned in Japan is 10M ha (M--million); this could be accompanied, with some difficulty, by additional thinning for a total forest area of 25M ha. The ultimate potential resources of thinned wood in Japan are estimated at 25Mt-dry biomass/year. INTRODUCTION

Woody biomass forms a promising energy resource in Japan. There are many types of woody wastes available from the forestry industry: 1) Wood from thinning of the forest (mainly branches and leaves) 2) Logging residue in the forest at cut-over areas or at forest roadsides. 3) Timber factory waste wood outside the forest. 4) Wooden building wastes, mainly in urban areas. Historically, in Japan, brushwood (Types 1 and 2) was widely available for firewood, gathered by hand. Conversely, today, only a small percentage pf Type 3 waste (factory waste wood) is available for as a fuel source; this is used mainly for wood drying purposes at the timber factory.

1856 This report investigates each forestry wood waste resource quantitatively. The author discusses which waste wood resource will be the most feasible for future enlargement. [Forest

plants]

1) thinned wood

---

• factory--

2) logging residue

............ within forest area ............

> [Timber]------~[Building 3) factory waste ............

etc.]

4) construction waste

out of forest area .............

Figure 1: Location of Forest Wastes. ORIGIN OF FORESTRY WASTE Japan has one of the highest forest area rates (66%) in the world. This area is about 25.2M ha (M =million, ha = hectare). However, Japanese production of firewood or charcoal decreased so dramatically between 1975 ~

1985 (8Mm3/y---~0.6Mm3/y) that the level of production has now become negligibly small.

Therefore, where do forestry wastes go? In Fig.l, about half the amount of forest wood when processed in the factory becomes timber, the rest becoming wastes. Much thinned wood and logging residues are abandoned inside the forest because of the economic difficulty of transporting them from the location, apart from logging residues at forestry roadsides (in Fig.2). Factory wastes are more convenient to recover, but are already used for reclamation of plywood.

Forestry

(Undeveloped forest)

Industrial

(Forestry)

(Factory)

(Consumer)

~

ning, felling / ~ ~=-:~carrying out Electric (Steep Mt.) v ~1/, / [ I ~t= t-~ ~ generation Remote forest • • Farm forest arding Inclined forest . plains . forelt . .~ t=~ t=~ t=~ [fact°~~mber][~---~ [Ultimate R.] ~~-......~~~ ----,-[Probable R.] ........... [Felled R.]

[~Vastes]

~rdding

[recovered R.] I

Figure 2: Forest waste resource stream Mt." mountain, R." resource

]

1857 HOW TO EXPAND THE FORESTAL RESOURCE?

Logging residue Part of the logging residue located at forest roadsides is already recovered in the form of wood chips; these are easy to transport by truck, this allowing for their improved mass transportation. Wood chips can be used not only as fuel, but also as a raw material for plywood and veneer, or an ingredient of pulp, after a removal of some materials such as bark and leaves. In Japan, there are so many steep mountain forest [1] that the extent of future roadside logging residue is essentially limited. Moreover, the amount of logging residue is fundamentally restricted by the inland log production. That is, the Japanese wood industry consumed ll0Mm3/y of woods (in 1997), but 78% of this was imported from foreign countries. Only 25Mm 3 of wood production originated from Japanese forests. The logging residue is closely connected with the amount of felling in Japanese forests, so that the yield of logging residue is 14Mm 3/y of wood, considering the rate of logging residue = 31-50%, average 40% for accumulated biomass[2] as shown in Fig.3. 100%

60%

Biomass in forest -* (felling) T-* Ilogl -* (sawing) ~ [Timberl [logging residue] 40%

Figure 3:

The limit of production amount of logging residue.

It corresponds to 3 M toe/y (toe--ton-oil equivalent) that is equal to 1% of Japanese energy consumption. This would be the limit of logging residue resources in Japan. Thinned wood

Conversely, thinned wood is expected to form a more abundant resource in Japanese forests as forest-thinning can take place without restricting log production. In spite of this theoretical superiority, the actual state of thinning operations is relatively small. For some years, much of the forest could not be sufficiently thinned, mainly because of a lack of mountain workers, and partly because most of the forest areas exists on very steep slopes and/or are too far from roads to allow economical transport. The total forest area in Japan is 25M ha, including afforested forest 10M ha[3]. However, the area of annual thinning area was only 0.2M haJy (< 1 % of total forest). The thinning wood generated is estimated as 2 3Mm3/y.

It corresponds to 1Mtoe/y, equal to 0.3% of Japanese energy consumption. To our great regret,

even this small amount of thinned wood could not be fully recovered (40-60% as remainder).

1858 As to the need for thinning - in general, 5 years after planting is the first opportunity for thinning the trees in the forests, if we consider the condition of growing trees. At least, it is desirable that all afforested land is thinned every 5 years (the thinning area will become 2M ha/y). This will provide 10 M toe/y of thinned wood. The ultimate potential resources of thinned wood is connected with the total forested area, 25.2Mha, that corresponds to 25 M toe/y (it equals to 8 % of Japanese energy consumption). However, there are many problems to recover all of the thinned wood, from deep and steeply inclined forests in Japan. The main theme in this work must be how to improve the transportability of the branches and leaves that take up large volumes (commercial wood: 0.5t-dry/m 3 ; firewood = branches & leaves : <0.2t-dry/m3). Innovative resource o f thinned wood

All growing branches cannot remain until felling time; at least half of them are rotted away. In Japanese forests, the quantity of branches available (+49.2Mt-dry/y) is clearly larger than that of tree trunks (+35.5Mt-dry/y)[4]. Conversely, the average accumulated volume is 925Mt-dry for branches and 1,842Mt for trunks. The loss of the branches is enormous. For the purpose of recovering this loss, we are now proposing a new thinning method termed "frequent thinning" (successive thinning) in order to obtain the branches before they become rotten. The ideal yield of biomass will reach 3 times for the branches, followed by the total biomass yield of 1.5 times. REFERENCES [1] Sano,H.,et al.(2001) Procs.of the 20th Annual Meeting of Japan Society of Energy and Resources, p.441, 17-3., Japan. [2]

Yamaji,K.,et al.(2001) in: Bioenergy, p.105, (Eds)Miosin Japan.

[3]

Matumoto,M.(2001) WS Rep.ofCO2 sink in land area,p.71,ISSN/341-4356.

[4]

Yosioka,T.,et al.(2001)The 10th Conference of Japan Energy Asoc.5-9, p.377.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1859

ECONOMIC ANALYSIS OF CARBON SEQUESTRATION IN C H E R R Y B A R K OAK IN THE UNITED STATES Ching-Hsun Huang and Gary D. Kronrad Arthur Temple College of Forestry, Stephen F. Austin State University Nacogdoches, Texas, USA

ABSTRACT The increase of carbon dioxide in the atmosphere and the possible greenhouse effect on global climate has become one of today's major environmental issues. Carbon can be captured in forests and remain sequestered in long-lived wood products. This study investigated the potential and profitability of afforestation of cherrybark oak (Quercus pagoda) on marginal agricultural lands in the lower Mississippi River Valley for the purpose of capturing carbon dioxide and mitigating the greenhouse effect. Cherrybark oak, with its fast growth, clear bole, and superior wood quality, is the highest value oak in the southern United States. In addition to the positive externality of capturing and storing carbon dioxide, the conversion of idle or marginal agricultural land to forestland will increase landowners' income, improve the environment and increase biodiversity, and enhance local and regional economies. However, landowners will afforest their lands only if the forest investment is profitable. To determine the profitability of afforesting these lands, the Forest Vegetation Simulator, an individual-tree, distance-independent growth and yield model, was used to simulate stand growth data, including diameter, height and volume from stand establishment to final harvest. Variables employed included site indices from 80 to 120 feet, thinning intensities of 20, 25, 30 or 35 percent of basal area removal, rotations up to 80 years in length, and a choice of 0, 1 or 2 thinnings. Cash flow analyses were conducted on the results of each possible thinning and harvesting regime using real alternative rates of return ranging from 2.5 to 15%.

INTRODUCTION

The recognition of the role of the world's forests in the global carbon cycle brought forests and forestry into the arena of international climate change policy when the Kyoto Protocol was signed by more than 150 countries in 1997 [6]. Global concern about increasing carbon dioxide (CO2) concentrations in the atmosphere and the possible consequences of future climate changes have generated interest in offsetting emissions by storing additional carbon in forests or other terrestrial carbon sinks [5]. To manage forests in ways that would result in storage of more carbon, there are two major courses of action: 1) increase forest area by

1860 converting land currently in other uses (e.g., agriculture) into forest land and 2) increase the productivity of existing forest lands by managing the land so a~ to increase the amount of carbon sequestered. Other forestry opportunities include reducing forest burning and deforestation, increasing biomass production and utilization, planting trees in urban environments and increasing use of wood in durable products. Forest ecosystems in the United States hold approximately 57.8 billion tons (52.5 billion metric tons) of carbon above and below ground which accounts for about 4 percent of all the carbon stored in the world's forests [1]. Increases in biomass and organic matter on forestland added an average of 0.3 petagrams per year of stored carbon to forest ecosystems from 1952 to 1992, enough to offset 25% of U.S. emissions of CO2 for the period [6]. Since the United States is highly industrialized and is the largest emitter of COz, it has become crucial to d~velop options to reduce atmospheric CO2 which are both cost effective and supportive of sustainable development. Studies have suggested that carbon-sequestering forest activities may be one of the least expensive approaches to mitigate the build-up of atmospheric carbon [7]. Bottomland hardwood forests in the southern United States are important for the production of forest products, including sawlogs for lumber and veneer and pulp for high grade paper products, as well as for wildlife habitat, recreation and aesthetics. Cherrybark oak, the highest value species, can be grown economically on marginal agricultural land in the lower Mississippi River Valley due to its rapid growth rate, good form and expanding market conditions. Landowners will convert their marginal agricultural lands to forestlands and store more carbon if the forest investment is profitable. Therefore, the objectives of this study were to determine the profitability of managing cherrybark oak stands and estimate the total amount of carbon stored in the forests and their products.

METHODS

Dynamic computer programs were developed to determine the optimal number, timing and intensity of thinning(s), and the optimal rotation age, conduct cash flow analyses and calculate net present worth (NPW) and soil expectation values (SEV). The Forest Vegetation Simulator [8], a forest stand simulator, was used to predict stand growth data on diameter, height and volume from establishment to final harvest for cherrybark oak. Site indices (measure of soil productivity) of 80, 90, 100, 110 and 120 feet (base age 50) were used in the analyses. These site indices encompass the range of the most commonly observed, commercially acceptable soil qualities for cherrybark oak. The number of thinnings during the rotation (cutting cycle) could be zero, one or two. The first thinning could not be conducted until a cherrybark oak stand was at least 15 years of age. The minimum years between thinnings, or between a thinning and the final harvest, could not be less than 5 years. Four thinning intensities were employed: 20, 25, 30 or 35% of basal area removal. The same thinning intensities were used at all thinnings for a specific optimal solution regardless of the number of thinnings or age of thinning. Six alternative rates of return (ARR), which span the range of before-tax earning rates available for most landowners, were chosen for the economic analyses. They were 2.5, 5.0, 7.5, 10.0, 12.5 and 15.0% in real terms, meaning that inflation has been removed. The annual real rate of price increase for cherrybark oak sawtimber and pulpwood were assumed to be 2.0% and 4.75%, respectively. Labor costs were assumed to increase at a real rate of 1.12% per year [3]. The price of sawtimber was assumed to be $474 per thousand Doyle board feet. Pulpwood was priced at $12 per cord. It was assumed that reasonable, usual and proper

1861 forest management activities would be conducted. Generally, management costs are incurred for establishing, maintaining and harvesting the stand of trees. The aggregated cost of seedlings, planting and site preparation (herbicide application) was $581.24 per hectare. The cost of subsoiling was assumed to be $24.71 per hectare. The cost of initial management plan was $12.36, and it needed to be updated every ten years at the cost of $24.71 per hectare. Locating boundaries would cost $24.71, and the fee of maintaining boundaries at 10-year intervals would be $4.94 per hectare. Forest carbon storage was estimated using the methodology developed by Hoover et al. [4]. Merchantable volume (cubic feet) was measured up to a 10.2 cm top diameter to predict the current carbon storage in standing timber and wood products. Estimates of organic soil carbon and carbon on the forest floor and disposition patterns of harvested wood were derived from the study conducted by Birdsey [2].

RESULTS AND DISCUSSION A total of 1,626,306 operable thinning and harvesting combinations and cash flow analyses, including soil expectation values, were calculated. Results indicate that a landowner who has a low real ARR of 2.5% will generate maximum net revenues of $17,231.25, $19,463.30, $21,625.06, $23,632.75, and 25.603.74 per hectare on site indices 80, 90, 100, 110 and 120 land, respectively (Table 1). Landowners with a high real ARR of 15% will earn maximum net revenues of-$622.31, -$610.13, -$596.51, $-579.36 and -$560.51 per hectare on site indices 80, 90, 100, 110 and 120 land, respectively. On site index i 20 land, the total amount of carbon sequestered ranges from 273 tonnes per hectare during a rotation of 42 years to 478 tonnes per hectare during a rotation of 80 years (Table 2). The amount of carbon captured on site index 80 land ranges from 211 tonnes per hectare during a rotation of 50 years to 333 tonnes per hectare during a rotation of 80 years. The differences in the values of revenues and quantity of carbon sequestered are due to the specific site index-ARR-optimal financial rotation relationship required to maximize landowners' long-term financial returns. The incentive of establishing and managing cherrybark oak on marginal agricultural lands for the purpose of capturing carbon dioxide arises as the approach of establishing a voluntary market for trading emissions of greenhouse gases draws public attention. Development of a flexible, market-based mechanism for limiting CO2 emissions through a voluntary cap and trade program may enable carbon-emitting companies to get credit for voluntary reductions and to buy and sell credits in order to find the most cost effective way of achieving reduction. To some extent, a market for carbon credits already exists in the United States. Thus, further study will investigate the possible market effects on forest profitability, management activities, carbon storage and economic costs within a range of possible prices for carbon stored.

1862 TABLE 1 SOILEXPECTATIONVALUEPER HECTAREUSINGTHE FINANCIALLYOPTIMALMANAGEMENT SCHEDULESFOR CHERRYBARKOAK, BY SOILPRODUCTIVITYAND REALALTERNATIVERATESOF RETURN. Real Alternative Rates of Return 2.5% 5.0% 7.5% 10.0% 12.5% 15.0% Site Index 80 17,231.25 2,242.24 72.92 -430.01 -575.04 -622.31 90 19,463.30 2,723.80 232.55 -363.05 -547.02 -610.13 100 21,625.06 3,198.52 407.21 -292.30 -518.77 -596.51 110 23,632.75 3,699.30 597.75 -214.71 -482.80 -579.36 120 25,603.74 4,250.35 792.10 -125.65 -442.91 -560.51

TABLE 2 TOTALTONNESOF CARBONSTOREDPER HECTAREUSINGTHE FINANCIALLYOPTIMAL MANAGEMENTSCHEDULESFOR CHERRYBARKOAK, BY SOILPRODUCTIVITYAND REAL ALTERNATIVERATESOF RETURN.

Site Index 80 90 100 110 120

2.5%

Real Alternative Rates of Return 5.0% 7 1 5 % 10.0% 12.5%

333 356 398 437 478

275 307 333 358 377

256 312 310 345 376

239 255 301 321 337

226 230 246 293 307

15.0% 211 223 239 252 273

REFERENCES

Atjay, L.L., Ketner, P., and Duvigneaud, P. (1979). In: The Global Carbon Cycle, SCOPE Report No. 13, pp. 129-181, Bolin, B., Degens, E.T., Kempe, S. and Ketner, P. (Eds.). John Wiley and Sons, New York. Birdsey, R.A. (1996). Carbon Storage for Major Forest Types and Regions in the Conterminous United States. Forest and Global Change VoL2. Washington, DC: American Forests. Council of Economic Advisor. (2001). Economic Report of the President. U.S.

Government Printing Office, Washington, DC. Hoover, C.M., Birdsey, R.A., Heath, L.S. and Stout, S.L. (2000) J. of For. 98(9), 13. Intergovemmental Panel on Climate Change. (1991). Climate Change--the IPCC Responses Strategies. Island Press, Washington, DC. Murray, B.C., Prisley, S.P., Birdsey, R.A. and Sampson, R.N. (2000). J. of For. 98(9), 6. Sedjo, R.A., Sohngen, B. and Jagger, P. (2001). In: Climate Change Economic and Policy, pp. 134-142, Toman, M.A. (Ed). Resources for the Future, Washington, DC. Teck, R., Moeur, M, and Eav, B. (1996).3'. of For. 94(12), 7.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1863

INTERNATIONAL N E T W O R K FOR BIOFIXATION OF CO2 AND GREENHOUSE GAS ABATEMENT WITH MICROALGAE P. Pedroni l, J. Davison 2, H. Beckert3, P. Bergman 3 and J. Benemann4 ~EniTecnologie S.p.A., San Donato Milanese, Milan, Italy 2IEA Greenhouse Gas R&D Programme, Cheltenham, Great Britain 3National Energy Technology Laboratory, U.S. Department of Energy, Morgantown and Pittsburgh, USA 4Consultant, 3434 Tice Creek Dr. N ° 1, Walnut Creek, California, 94595, USA

ABSTRACT

The utilization of concentrated C02 sources, such as power plant flue gases, by microalgae mass cultures to produce renewable fuels and fossil fuel-sparing products provides both near- and longer-term opportunities to mitigate greenhouse gas (GHG) emissions. Microalgae mass cultures, mostly using raceway-type open ponds, are currently used commercially to produce several thousand tons of food- and feed-grade algal biomass annually. Presently, costs are over an order of magnitude higher than acceptable for renewable fuels production and GHG mitigation. However, engineering cost analyses project sufficiently low costs if large (>100 hectare) open pond cultivation systems were deployed and higher algal biomass productivities (>100 tons/hectare/year) could be achieved. Achieving high productivities and low costs will require relatively longterm applied R&D into algal photosynthesis, large-scale cultivation, harvesting technologies and biomass processing to produce both fuels and higher value co-products. Microalgae mass cultures are currently also used in wastewater treatment and these environmental applications provide nearer-term opportunities for microalgae GHG abatement and renewable fuels production. INTRODUCTION

Microalgae cultures have been investigated as a source of renewable fuels for several decades, starting with the pioneering research and process development work of Oswald and Golueke [1 ] at the University of California Berkeley. Their concept was to grow algae in municipal wastewaters to produce dissolved O2, required for bacterial oxidation of wastes, then harvest the algal biomass and convert it to methane fuel by the process of anaerobic digestion. The methane was to be used to generate electricity and the CO2 produced by the power plant, along with the nutrients recovered from the anaerobic digestion reactors, was to be used to grow additional algal biomass, expanding the potential scale of this process beyond the needs of wastewater treatment to several hundred hectares. The initial feasibility analysis appeared favorable. The energy crisis of the 1970's gave renewed impetus to R&D of this concept [2], with emphasis on the harvesting of the algal biomass from wastewater ponds through spontaneous flocculation and settling [3]. During the 1980's the emphasis in this R&D field shifted from methane production and waste treatment to biodiesel production and dedicated large-scale processes, where fuels were the only outputs. This "Aquatic Species Program" (ASP), was sponsored by the U.S. Department of Energy through the National Renewable Energy Laboratory, with the participation of many university groups and private companies [4]. Significant advances were made by the ASP, culminating in the operation of a 0.2 hectare pilot plant in Roswell, New Mexico, which demonstrated the ability to grow selected algal strains in large, potentially low cost, open ponds. However, the engineering analyses of such processes required very high biomass productivities, that is

1864 solar conversion efficiencies, among many other favorable engineering and process assumptions, for economic feasibility [5]. During the 1990's extensive research on microalgae for utilization of power plant flue gas CO2 for GHG abatement was carried out, mainly in Japan, sponsored by RITE (Research for Innovative Technologies of the Earth) and emphasizing the use of closed photobioreactors of various designs, with co-production of higher value products [6]. These R&D efforts were, however, discontinued by the end of the decade, in part because of the unfavorable economic projections for such approaches. Research along similar lines continues presently in the U.S., with the support of the Department of Energy. In the mean-time a microalgae production industry has developed, starting in Japan during the 1960's for the production of Chlorella and then in Mexico, Thailand, U.S. and other countries for the production of Spirulina, both algae being used for human food supplements and some animal feed applications. During the 1980's, commercial production systems for Dunaliella salina, used as a source of beta-carotene, were developed in the U.S. and Australia. Recent commercial developments in microalgae biotechnology have achieved the cultivation of several novel algal species, in particular Haematococcus pluvialis, a source of the carotenoid astaxanthin, used in salmon aquaculture and also in food supplements. Many small-scale cultivation facilities produce microalgae for live aquaculture feeds. At present, about five thousand tons of microalgae biomass are produced annually at facilities around the world, mainly for the human food supplements market. Production costs are generally much higher than agricultural products, limiting current applications to specialty food and feed products. Production costs for Spirulina, the largest volume microalgae product at present, with some 2000 tons produced world-wide, are about U.S. $ 5,000 per ton. A recent commercial success has been in the heterotrophic fermentation of microalgae, in the dark using sugars, for the production of polyunsaturated fatty acids, in particular DHA (docosahexaenoic acid), starting to be used in infant formulas and also animal feeds. However, microalgae are fundamentally photosynthetic organisms and their potential lies in the conversion of solar energy for useful purposes. Indeed, microalgae ponds are extensively used for wastewater treatment, although these are generally rather small systems (<10 hectares) and the algal biomass is seldom harvested or beneficially used. THE INTERNATIONAL NETWORK FOR MICROALGAE BIOFIXATION Despite several decades of R&D, applications of microalgae in fuels production and GHG abatement are yet to be realized in practice. One microalgae plant in Hawaii is using flue gas from a small power plant to supply the CO2 required in microalgae production [7], demonstrating the practical feasibility of utilizing flue gas in microalgae cultures. A wastewater treatment plant in Sunnyvale, California, harvests microalgae biomass and converts it to methane fuel. However, few such applications can be pointed to and GHG mitigation with microalgae remains to be developed to a practical level. To advance both the near- and long-term development and applications of microalgae for biofixation of CO2 and GHG mitigation, the U.S. Department of Energy and EniTecnologie, the R&D arm of the Italian oil company ENI, with the assistance of the IEA Greenhouse Gas R&D Programme, have organized the "International Network for Biofixation of CO2 and Greenhouse Gas Abatement with Microalgae". The Network, which became operative June 1, 2002, presently includes as members Arizona Public Services (a U.S. electric utility), Rio Tinto (an international mining company), ENEL Produzione Ricerca (the R&D arm of the Italian electric utility), EPRI (a U.S. R&D organization serving electric utilities) and the Gas Technology Institute (carrying out R&D in support of the gas industry). These companies and organizations, with an interest in promoting R&D and practical applications in this field, have joined together to more effectively use limited resources in a coordinated and cooperative R&D effort. The objective of the Network is to demonstrate the technical and economic feasibility of such technologies and initiate some practical demonstrations within this decade. The main task for the current year is to develop a R&D Roadmap detailing the most plausible processes and identifying specific research needs for accomplishing the technological objective. THE MICROALGAE BIOFIXATION R&D ROADMAP A Roadmap provides a structured R&D planning process by identifying the scientific and technological developments needed to achieve a specific strategic goal. The key tool is to characterize those processes that

1865 could be practically developed within a given time-frame and from these derive the specific R&D needs that have to be addressed to achieve the objective. Most importantly, the roadmapping effort involves consensus building among technical experts of the most plausible processes and the critical R&D needs that can meet the goal. The objective of the Network is to demonstrate the technical and economic feasibility of microalgae technologies in CO2 biofixation and GHG abatement within five years and to achieve some initial practical applications of such processes within ten years. This time-flame constrains the possible processes and approaches which can be projected without the need to invoke major R&D breakthroughs. The first event that laid the foundations for the development of the Network and represented the beginning of the roadmapping effort was a Workshop on microalgae technologies for CO2 biofixation and GHG mitigation held in January 2001, in Monterotondo, Italy, with some three dozen participants representing a broad diversity of disciplines and organizations interested in this area of research [8]. Technical presentations and discussions covered the range of processes and R&D approaches in this field, from wastewater treatment to commercial algae production, from closed photobioreactors to large-scale open ponds, from algal genetics and physiology to conceptual processes for large-scale microalgae systems for energy production. A strong consensus developed that further R&D in microalgae applications for energy production and GHG mitigation was worthwhile, though the specific approaches to this end were not fully developed. A central issue of discussion was the feasibility of dedicated, stand-alone microalgae systems that would utilize flue gases CO2 and produce renewable fuels as their sole outputs. This approach requires the achievement of very high productivities, near the theoretical maximum, as well as very large-scale cultivation systems, favorable locations and many other favorable assumptions to allow projection of economically viable processes [4]. The general consensus developed during these discussions was that although such approaches may be feasible in the long-term they cannot be considered for practical application in the near future. The preferred alternative is to develop microalgae biofixation systems as part of multipurpose processes, which provide additional services, such as wastewater treatment or higher value co-products, in addition to their GHG mitigation functions. Another major topic of discussion was the cultivation system to be used in such processes, in particular the applicability of closed photobioreactors. These were considered to be useful in the production of required algal inoculum, but only large open pond cultures could be of low enough cost to be applicable in microalgae GHG mitigation. The two major R&D issues identified were the need to develop techniques allowing the mass culture of selected microalgae species in large open ponds and the achievement of high productivities, of above 100 tons/hectare/year, even in multipurpose systems. A meeting during which these issues were further discussed for the Roadmap development was held in Almeria, Spain, in May 2002, in conjunction with the Congress of Algal Biotechnology. The potential of microalgae in municipal wastewater treatment, their use in recovering nutrients from wastewaters generally, in particular agricultural drainage waters, the application of nitrogen-fixing microalgae for fertilizer production, and the co-production of microalgae fuels and higher value products, were addressed during this meeting [9]. Again, the consensus was that in the near- to mid-term GHG mitigation could be achieved by microalgae systems through the development of multipurpose processes, which not only fix CO2 into renewable fuels but also avoid fossil energy inputs presently required by conventional processes, such as the production of synthetic fertilizers. Four general microalgae biofixation/GHG abatement processes were developed that encompass these potential near- to mid-term approaches in this field: 1. Municipal wastewater treatment using CO2 for CH4 production and with reduced energy consumption. 2. Recovery of nutrients from agricultural and other wastes with production ofbiofuels and fertilizers. 3. Use of nitrogen fixing microalgae and nutrient recycling for agricultural applications. 4. Co-production ofbiofuels and large volume/higher value products (biopolymers, animal feeds, etc.) There is a considerable overlap among these conceptual processes. All require essentially similar production systems, i.e., open paddle wheel-mixed raceway ponds, all are based on using CO2 from power plants or similar concentrated sources, all would produce renewable fuels and thus reduce GHG emissions, all would have additional GHG abatement functions, such as reduced fossil energy consumption compared to traditional processes, all are plausibly economically feasible, and all would be of sufficient scale, both as individual processes and in aggregate, in order to achieve significant GHG mitigation.

1866 R&D ISSUES IN M I C R O A L G E BIOFIXATON These processes also have to address essentially similar basic and applied research issues, summarized below: Algal Strains. Mass culture of defined microalgal strains has been demonstrated in only a few cases (Spirulina, Dunaliella), with most algae, even Chlorella, mass cultured with difficulty. How to select and maintain algal strains that are competitive in outdoor pond cultures is a central R&D issue in this field. Genetics and Molecular Biology. After selection of strains that can be mass cultured in open ponds, these will need to be further improved. Application of modem biotechnology tools is only in its infancy here. Physiology. In outdoor pond cultures algae are exposed to highly variable and often extreme environments. How algal strains respond to these stresses requires a fundamental understanding of their physiology. Culture stability. Algal cultures often succumb to invasions by competing algae, predation by zooplankton grazers, and crashes of unknown causes. Improving culture stability is a R&D challenge. Inoculum production. When microalgae cultures fail they can be rapidly replaced. That requires the development of large-scale production of inoculum cultures, using, in part, closed photobioreactors. Productivity. Maximizing productivity, that is solar conversion efficiencies, is the most important R&D objective in this field. Recent work on reducing algal pigments suggests approaches towards this goal. Harvesting. Concentration of dilute suspensions of microscopic algae has been a major challenge in this field. Settling by spontaneous bioflocculation is a low-cost processes, but still requires considerable R&D. Biomass conversion. Biofuels production is the main goal in GHG abatement and microalgae can be sources of CH4, H2, biodiesel, ethanol and hydrocarbons. These conversion processes all require R&D. Co-Products and Co-Processes. Biofuels production is not enough to economically justify microalgae processes. Waste treatment and large volume co-products must be integrated with biofuels production. Engineering Designs. Although large-scale open ponds can be of low cost, these, and the supporting systems (e.g. CO2 injection) have yet to be demonstrated at the scale envisioned in the feasibility analysis. Resources and GHG Mitigation Impact. Ultimately, the applicability of microalgae technologies for GHG mitigation will be decided not only by economics but also by their potential impacts: how many megatons of CO2 abatement could microalgae processes provide, both regionally and globally. This will require an inventory of resources, from water to land, from wastes to CO2, for the applicable processes. CONCLUSIONS R&D challenges in microalgae biofixation of CO2 and GHG abatement require multidisciplinary skills and a critical mass to allow a broad coverage among the many R&D topics, as well as a diversity of approaches and projects which cannot be encompassed by any single organization. The Network provides the structure and the mechanism by which the required expertise are integrated, the critical mass reached and the research projects coordinated to help focus R&D efforts on most promising approaches towards the practical application. The Network has only now started operations and the process of formulating the Roadmap represents a key step for guiding future R&D activities by integrating in its broad vision the research projects carried out, either individually or in cooperation, by the Network participants. REFERENCES 1. Oswald,W.J., and Golueke, C.G. (1960) Adv. Appl. Microbiol. 11,223 - 242. 2. Benemann,J.R., Weissman, J.C., Koopman, B.L., Oswald, W.I.(1977) Nature 268, 19-23. 3. Benemann,J.R., Koopman, B.L., Weissman, J.C., Eisenberg, D.M. and Goebel P. (1980). Algae Biomass: Production and Use, pp. 457-496, G. Shelef and C.J. Soeder (editors) Elsevier, Amsterdam 4. Sheehan,J., Dunahay, T., Benemann, J., and Roessler, P. (1998). A Look Back at the U.S. Department of Energy's Aquatic Species Program - Biodiesel from Algae. National Renewable Energy Laboratory, Golden, CO, 80401 NERL/TP-580-24190. 5. BenemannJ.R. and Oswald W.J. (1996). Systems and Economic Analysis of Microalgae Ponds for Conversion of C02 to Biomass, pp.260. Final Report, Pittsburgh Energy Technology Center. 6. Usui, N., and Ikenouchi, M. (1996) Energy Conserv. Mgmt. 38, $487 - $492. 7. Jensen;G., and Reichl; E.H. (1977). Integrated microalgae production and electricity cogeneration, U.S. Patent, 5,659,977. 8. IEA GHG R&D Programme, (2001). Workshop on Formation of an International Network on Biofixation of C02 and GHG Abatement with Microalgae. Report PH4/1, March 2001. 9. Benemann,J.R., Network Manager (2002). Minutes of the Technical Meeting of the International Network on Biofixation of C02 and GHG Abatement with Microalgae. Almeria, Spain, May 2002.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1867

COz EMISSON REDUCTION AND COz FIXATION ON THE GROUND BY USING SUPERCRITICAL CARBON DIOXIDE AS AN ALTERNATIVE TO ORGANIC SOLVENTS

Masaaki Yoshida l, Masayuki Ohsaki l, and Naohisa Yanagihara 2 IFaculty of Engineering, Utsunomiya University, Utsunomiya, Japan, 321-8585 2 Faculty of Science and Engineering, Teikyo University, Utsunomiya, Japan, 320-8551

ABSTRACT

In organic synthesis, carbon-carbon bond formation reactions are the most important reactions and that are conducted in organic solvents, which are incinerated and discharged as carbon dioxide in the air after the use. We have developed carbon dioxide fixation reactions as carbon-carbon bond formation reactions to produce carboxylic acids and esters in supercritical carbon dioxide, in place of traditional organic solvents. These reactions in supercritical carbon dioxide are more effective than that of the reaction in organic solvents. So, these technologies could replace the traditional reactions in organic solvents and could contribute to carbon dioxide emission reduction

INTRODUCTION

In the chemical industry, the majority of chemical products are organic compounds. Since organic compounds are rarely soluble in water, most organic compounds are produced in organic solvents in many organic chemical industries. After use, solvents are incinerated and discharged as carbon dioxide into the air. Therefore, the use of supercritical carbon dioxide in place of traditional organic solvents could reduce carbon dioxide emissions. Recently, dimethylformamide was produced from carbon dioxide and dimethylamine by the use of supercritical carbon dioxide as the solvent and reactant [1]. Since carbon dioxide has low critical conditions (Tc=31 °C, Pc=7.4 MPa), not much energy is required to produce supercritical carbon dioxide. We also reported urethane synthesis using supercritical carbon dioxide as the solvent and the reactant [2]. Those reactions are superior for reaction efficiency to those of the reactions in organic solvents. However, both dimethylformamide and urethane synthesis in supercritical carbon dioxide were carbon-nitrogen bond forming reactions.

1868 In organic synthesis, the carbon-carbon bond formation is the most important reaction. Therefore, carbon dioxide fixation reaction as a carbon-carbon bond formation is very significant for carbon dioxide utilization. The present paper deals with carbon dioxide fixation with the carbon-carbon bond, by using supercritical carbon dioxide as an alternative to organic solvents and as a direct raw material. CARBOXYLATION IN SUPERCRITICAL CARBON DIOXIDE Haruki reported the carboxylation of active methylene compounds with carbon dioxide to form carboxylic acid in the presence of 1,8-diazabicyclo[5,4,0]undec-7-ene(DBU) in aprotic high polar solvents such as DMSO [3]. We have found that active methylene compounds (fluorene, acetophenone, cyclohexanone, and fl-tetralone) were effectively carboxylated with supercritical carbon dioxide in the presence of DBU to give the corresponding carboxylic acids (Table 1). TABLE 1 CARBOXYLATIONS OF ACTIVE METHYLENE COMPOUNDS IN SCCO2A Entry

Substrate

1@ 2

Product

~ O

3

~

4

~~"~

80

79

O

40

86

~ O H

80

67

40

86

40

94

40

74

O

0

0

~

0

Temp. / °C Yield / %b

O

0

H

0

0

CN 6

~ C N

~~oOH

a Reaction was conducted at 8.0 MPa for 1 h in a 100ml stainless autoclave containing substrate (5 mmol) and DBU (7.5 mmol). b Isolated yield. The reaction efficiency in supercritical carbon dioxide was much higher than that attained in DMSO or DMF. The reported carboxylation of fluorene in DMSO was conducted with 13 equivalents of DBU at room

1869 temperature for 18 h to give the corresponding acid in a yield of 30% [3].

DBU

In comparison with this,

~

in scCO2 DBU 1.2 eq. 80 °C, lh inDMSO DBU13eq. rt, 18h

(1) 75% 30%

the reaction in supercritical carbon dioxide at 80°C for lh, the requirement of DBU reduced to 1.2 equivalents and the yield of fluorene-9-carboxylic acid increased to 75% (Eqn. 1). Cyclohexanone, acetophenone, and o~-tetralone were reacted at relatively low temperature because of the tendency of the corresponding [3-keto acids to decompose upon heating. Nevertheless, good yields are obtained when the temperature of the reaction is kept near 40°C. Supercritical carbon dioxide is an advantage for this carboxylation as products can be separated easily from carbon dioxide without decarboxylation, by only releasing the valve. Aprotic high polar solvents are disadvantage for separation with the product (Eqn. 2). O

O

O (2)

in scCO 2 DBU 1.5 eq. 40 °C, lh in DMSO DBU 2 eq. rt, 3 h

86% 41%

Carboxylation mediated by a strong base, such as DBU, is necessary in an equal amount of the base as the base forms salt with the produced carboxylic acid. There are only a few reports of catalytic carbon dioxide fixation reaction as carbon-carbon bond formation using transition metal catalysts [4,5]. We also found that the carboxylation of active methylene compounds was catalyzed by using potassium carbonate and onium salts instead of DBU. The carboxylic acids produced by the carboxylation were successively esterificated by alkyl halide. This alkoxycarbonylation reaction proceeded in one reactor from the three components (Scheme 1).

COOBu] BuCI~ ~

u

yield 96% Scheme 1. Alkoxycarbonylation of fluorene (5 mmol) with BuC1 (15 mmol), Bu4NBr (20 mol%), K2CO3 (20 mmol), and DMF(2 eq.) in scCO2 (8 MPa) 100 °C, 2 h.

1870 This catalytic alkoxycarbonylation is a first example of carbon dioxide fixation by carbon-carbon bond without using transition metal catalysts. This reaction does not proceed in organic solvents, but can proceed only in supercritical carbon dioxide. Here, DMF was used for the solvation effect in the reaction with the minimum amount of 2 equivalent molar, as supercritical carbon dioxide is non-polar as alipathic hydrocarbon solvents. The alkoxycarbonylation of ot-tetralone gave two products which were butylated tautomers of the first formed keto ester (Eqn. 3) O

Bu4NBr (20 mol%)

B~Bu

O u

(3)

DMF(2.0 eq.) scCO 2, 8.0 MPa, 100 °C, 2 h 65%

35%

In conclusion, we have developed two effective carbon dioxide fixation reactions as carbon-carbon bond formation in supercritical carbon dioxide without using traditional organic solvents. Therefore, those technologies could contribute significantly towards carbon dioxide emission reduction. In addition, a factory must stock carbon dioxide in a tank if supercritical carbon dioxide was to be used in many facilities. Large quantities of carbon dioxide, in comparison with organic solvents, will be fixed in the ground. So, carbon dioxide reduction will be greater than estimated from the present use of organic solvents in many factories. REFERENCES

1.

2. 3. 4. 5.

Jessop, E G.; Ikariya, T.; Noyori, R. (1994) Nature 368, 231; Jessop, E G.; Hisao. Y.; Ikariya, T.; Noyori, R. (1996) J. Am. Chem. Soc. 118, 344; Jessop, P. Ct; Ikariya, T.; Noyori, R. (1999) Chem. Rev. 99, 475. Yoshida, M; Hara. N.; Okuyama, S. (2000) Chem. Commun. 151. Haruki, E.; Arakawa, M.; Matsumura, N.; Otsuji, Y.; Imoto, E. (1974) Chem. Lett. 427. Tsuda,. T.; Ueda, K; Saegusa, T. (1974) J. Chem. Sot., Chem. Commun., 380. Fukue, Y.; Oi, S.; Inoue, Y. (1994)J. Chem. Sot., Chem. Commun., 2091.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1871

UTILIZATION OF CARBON DIOXIDE FOR NEUTRALIZATION OF ALKALINE WASTEWATER S. K. Choi, K. S. Ko, H. D. Chun, and J.G. Kim Water Protection Research Team, Research Institute of Industrial Science and Technology San 32, Hyoja-Dong, Nam-Gu, Pohang 790-330, Korea

ABSTRACT Strong mineral acids such as sulfuric and hydrochloric acid have been used to neutralize alkaline wastewater from various processes. However, mineral acids have some drawbacks such as difficulties in process control, handling, maintenance of equipments, and chemical cost. In this study, exhaust gas containing carbon dioxide has been used to neutralize alkaline wastewater instead of these mineral acids. Since 1999, two exhaust gas utilization facilities were installed at the final wastewater treatment plant for the iron and steel making area in Pohang Works and at the calcination plant in Kwangyang Works of the POSCO. From the test runs over 6 months of these processes, total alkaline wastewater of 16,000 tons per day could be neutralized and chemical costs of $200,000 per year saved. In addition, this technology can reduce carbon dioxide emission by 15,000 tons per year. The experiences and the results of these two cases of exhaust gas utilization technology are discussed in this study.

INTRODUCTION

In the iron and steel making industries, alkaline wastewater is produced from various processes such as dust scrubbing process of calcination plant, raw material yard, slag quenching process, coke making process, and degreasing process. These alkaline wastewaters must be treated to satisfy discharge limit of pH. Therefore, much of them are neutralized by sulfuric acid due to its low cost. However sulfuric acid has some drawbacks of difficulties in process control, handling, maintenance of equipments, and chemical cost. Most of all, accurate pH control using sulfuric acid is often very difficult to achieve. Initially the pH remains fairly constant during acid dosing, however, there is a sudden change and the pH drops drastically even after addition of only a small amount of acid. Carbon dioxide can solve these problems in the mineral acid use process for the following reasons, a) Natural safety net: due to a natural buffering action, CO2 cannot reduce the effluent pH below 5, even if overdosing occurs, b) Improved process control: pH drop with CO2 occurs more gradually than with mineral acids, making accurate control inherently easier, c) Environmentally friendly operation: commercial CO2 is a recycled product and does not produce residual anions such as sulfate and chloride, d) Low cost: commercial CO2 is typically about the same price of sulfuric acid and half that of hydrochloric acid. The capital cost of a CO2 system is also considerably lower than that of an equivalent mineral acid system, and easier and cheaper to modify [1 ]. Furthermore, most of industries emit exhaust gas containing high concentrations of carbon dioxide. In the Iron and Steel Making industry, the blast furnace hot air making and calcination processes produce huge amounts of exhaust gas containing approximately 20% carbon dioxide. These exhaust gases may be a good carbon dioxide source.

1872

In POSCO, the final wastewater treatment plant (FWTP) for the iron and steel making area has a treatment capacity of 40,000 tons of wastewater per day with neutralization, coagulation and filtration processes. The pH of influent wastewater ranges from 8.5 to 12, consuming 2 - 4 tons of sulfuric acid in the neutralization process per day. In the calcination plant, dust scrubbing water of 780 ton per hour is circulated continuously. The pH of this water is higher than that of the FWTP due to the calcium carbonate and calcium oxide particles. Ca hardness and SS are also concentrated by circulating use. Therefore, scale deposit on piping system and injection nozzle is a major problem of this process. The neutralization of blow-down water is operated separately in another wastewater treatment plant using sulfuric acid. The feasibility test of exhaust gas technology in the laboratory and pilot plant was investigated previously [2]. The objective of this research is application of an exhaust gas utilization technology to the final wastewater treatment plant in Pohang Works and calcination plant in Kwangyang Works. We discussed the experiences and the results of these two cases of the exhaust gas utilization technology in this study.

MATERIALS AND METHODS

Analysis Concentration of the CO2 in exhaust gas was measured by CO2 analyzer (Shimadzu, CO/COz analyzer) and pH of the wastewater was measured by on-line pH sensor. All other components were measured by standard method for water and wastewater [3].

Plant applications For the plant scale test, the exhaust gas blowing system was installed in target processes of the FWTP and calcination plant. Figure 1 shows the flow diagram of the exhaust gas blowing system installed in the FWTP. Exhaust gas of 900 m3/hr from the hot air making process was injected into the neutralization tank of the FWTP. The gas flow rate operates automatically to control the pH in the tank at the desired set point. When the pH rises above the set point, the pH probe in the tank sends a signal back to the gas control system. A control valve opens and a preset flow of exhaust gas is distributed via a submerged sparging nozzle. The CO2 is injected and mixed into the contents of the tank, reducing the pH automatically. Figure 2 shows another system installed in the calcination plant. The exhaust gas was introduced from the #2 shaft kiln stack into the overflow pond, in which the scrubbing water was reserved for circulating and blowdown, with turbo fan and specially designed sparging nozzle. Thickener exists in the circulating system (not shown in Figure) prior to the overflow pond. Therefore, most of the sludge was settled in the thickener. The pH control system is quite similar to the FWTP explained previously. Stack

Hot Air for

BF

Air

T aMM

Comb~fin~ Air chamber

M i x e d ~ Exhaust Gas COG (7%) [ ............... BFG (93%) I Stack BFHotAirMaking Process

100% Replace -.~

ShaftKiln

Bgr

mJ ~li

Contexd

40'000t°n/day/ i 2T-o1~0l ~

SulfuricAcid Tank 9O0m3/hr T EqualizationTank

Figure 1: Flow diagram of the exhaust gas utilization process in the FWTP.

Blow,t~w.

Figure 2" Flow diagram of the exhaust gas utilization process in the calcination olant.

RESULTS AND DISCUSSION The parameters for the plant scale test such as capacity of the blower, diameter of main pipe and temperature

1873 compensation, etc. are calculated from the basic and detailed design. Thereafter, the exhaust gas blowing system was installed in the FWTP and calcination plant. The following results were obtained from these plant tests. Results in the F W T P

In Figure 3, the results of pH regulation by sulfuric acid (a) and exhaust gas (b) were compared. The pH of alkaline wastewater could be controlled near the set-point within +0.1 of deviation. This result shows 10 times higher accuracy than that of using sulfuric acid. The use of sulfuric acid often drops pH below 5, however, no pH drop below the designated pH was observed in the case of exhaust gas. The high pH peaks were caused by accidental inflow of strong alkaline wastewater from the slag dumping yard.

...... -~

ii

t

_l,

8

o

........ 6

i 0

0

1

2

3

4

5

.

.

il;

.

j

......................................................

5 5

.

1

, 2

3

, 4

5

6

6

Operating time (day)

Operating time (day)

(a) pH regulation by sulfuric acid

(b) pH regulation by exhaust gas

Figure 3: Comparison of pH regulation results between sulfuric acid and exhaust gas. Figure 4 shows the difference in sulfuric acid dose when the exhaust gas was used or not. A very small amount of the sulfuric acid was used after the exhaust gas blowing. 10000

9000

8ooo

--

~_G~__

7000 6000 '~

5000 4000

"~

3000 2000 I000 0 8/1

'

:

8/21

9/10

v 9/30

10/20

Date (1999)

Figure 4: Daily changes of the sulfuric acid dose when the exhaust gas used or not. Results in Calcination Plant

In the calcination plant, the high pH of the dust scrubbing water may not be a direct problem but high Cahardness and SS are caused by this high pH. Therefore, lowering the pH can reduce the Ca-hardness and SS in the scrubbing water with increasing dust removal efficiency. Figure 5 shows the Ca-hardness and SS changes when the exhaust gas was introduced into the scrubbing water. As shown in Figure 5 (a), over 90% of calcium hardness could be reduced by the exhaust gas treatment. This means that scale growth of the piping system of scrubbing water could be highly reduced. The SS was also reduced slightly as shown in Figure 5 (b). The SS reduction is presumably due to the co-precipitation with CaCO3 particles produced by CO2 blowing.

1874 The pH variation of the scrubbing water over 5 months is shown in Figure 6 (a). It was definitely known that the exhaust gas could neutralize the strong alkaline wastewater stably for a long time. In Figure 6 (b), the dust content in the exhaust flue gas was plotted against the scrubbing water pH. The Figure shows that lowering the pH of the scrubbing water could enhance dust removal efficiency. 1600 1400 " 1200 1000 -... 800

I

i

i

.Eo.oto.s

600 400 200 0

180~!

[

I

120~

|| gg

100~1

B

14°~111

I

• Exhaust Gas

i

1

I!

i ml

! :it[tti1,,, i.'.'.,, '"i.'i i i, i..i _

Date (2000)

Date (2000)

(a) Ca-hardness

(b) SS

Figure 5: Ca-hardness and SS changes when the exhaust gas was introduced. 12 II #3 RK

-o °°

10

o ~- Exhaust Gas

~ 89 ~ 7 6 5 4 10/20

E

oo / 10

/

0 12/19

•

-~-

~3o

oo~

' 11/19

o #.4 R K

40

1/18

Date (2000~2001)

(a) pH trend

2/17

3/19

a°

' 7

8

9

10

11

12

pH of the scrubbing water

(b) dust content as a function of the pH

Figure 6" The pH variation of the scrubbing water and dust content as a function of the scrubbing water pH CONCLUSIONS The exhaust gas utilization technology was successfully applied to the final wastewater treatment facility for the iron and steel making plant area in the Pohang Works and calcination plant in the Kwangyang Works of POSCO. In the Pohang Works, sulfuric acid could be completely replaced by exhaust gas and the pH of the alkaline wastewater could be controlled stably. In Kwangyang Works, the pH value of the dust scrubbing water could be significantly reduced from 11.0 to 6.5. The Ca-hardness was also reduced from average 1,000 to 100 ppm by the exhaust gas treatment. Dust content in the exhaust flue gas decreased slightly with lowering the pH of the dust scrubbing water. In conclusion, total alkaline wastewater of 16,000 tons per day could be neutralized and chemical cost of $200,000 per year could be saved by this exhaust gas technology. In addition, carbon dioxide emission can be reduced by 15,000 tons per year. REFERENCES WWT Report, (1997). C 0 2 - Safe and Effective pH Control. Choi, S.K. and Ko, K.S. (1998). RIST Technical Report, 12, 526. A P H A - A W W A - W P C F . (1995). In: Standard Methods for Examination of Water and Wastewater, 16 th ed., American Public Health Association, Washington, DC.

1875

A U T H O R INDEX VOLUME I and II Abanades, J.C. 181 Abe, H. 1383 Abe, Y. 1477 Adahl, A. 1237 Adams, E. 785 Adams, E.E. 753 Adams, M. 423 Adams, M.A. 1383 Ahmed, A.U. 1353 Akai, M. 771 Akasaka, R. 1019 Akimoto, K. 51, 913 Akiya, T. 975 Alendal, G. 785 Ali, M. 1151 Allam, R.J. 69 Allinson, G. 615,633 Allis, R.G. 423 Alvarez, D. 181 Amoreili, A. 1325 Anand, S. 17 ! 7 Andersson, K. 1051 Andr6sen, J.M. 1621, 1729 Anthony, E.J. 671 Aoki, K. 1671 Apps, J. 243 Arashi, N. 919 Aresta, M. 1497, 1599 Aroonwilas, A. 31,127, 1547, 1587 Arts, R. 347 Asami, T. 913,943 Asamoah, J. 1349 Aumont, O. 1691 Austeil, J.M. 1077 Aya, I. 739, 825 Azar, C. 1413 Azevedo, J.L.T. 1567

Bachu, S. 477, 1633 Bae, D.H. 175 Baker, J. 417 Bamboat, M. 1131 Barbini, M. 169 Barrie, J. 31, 1575 Bartos, S.C. 1263 Bass, B. 907, 1741 Bateman, K. i 617 Bates, J. 45, 1201 Beath, A.C. 1287 Beaton, A. 697 Beaubien, S. 417 Beaubien, S.E. 391 Beaubron, J.C. 391 Bech, N. 339, 397 Becken, S. 1705 Beckert, H. 1863 Bedont, P. 1325 Beecy, D. 1089, 1275 Beecy, D.J. 297 Beggs, S. 975

Benemann, J. 1863 Benemann, J.R. 1433 Benito, R. 1813 Benson, H.Y. 627 Benson, S.M. 243,261,691, 1625, 1645 Beppu, T. 1269 Bergman, P. 1863 Bergmo, P. 489 Berndes, G. 1395, 1413 Berntsson, T. 1237 Beum, H.-T. 1563 Bidstrup, T. 657 Bielinski, A. 463 Bill, A. 81 Birabwa, W. 1817 Birkestad, H. 1051 Bishop, C.D. 595 Blanford, G.J. 1459 Blok, K. 869 Bock, B.R. 1101 Boden, J.C. 69 Bolland, O. 135 B6rjesson, P. 1395, 1413 Bossie-Codreanu, D. 403 Bouchard, R. 279 Boyd, T.J. 805 Brach, M. 391 Bradshaw, B.E. 633 Bradshaw, J. 633 Brand, P.J. 213 Bredesen, R. 135 Brewer, P.G. 739, 1667 Brook, M. 333 Brosse, E. 1617 Bruant, Jr., R.G. 1609 Brune, D.E. 1433 Brune, S. 417 Budwill, K. 697 Buen, J. 1189, 1207, 1407 Burer, M. 1311 Bustin, M. 697 Byrer, C. 429, 1625 Byrer, C.W. 523, 1641 Byrman, C. 651

Caldeira, K. 1691 Callahan, G. 1007 Campbell, W.A. 1045 Capobianco, P. 1325 Cardellini, C. 391 Carlberg, J.A. 1433 Carvaiho, M.G. 1567 Casareto, B.E. 817 Cecere, E. 1497 Celia, M.A. 477 Chadwick, A. 347 Chadwick, R.A. 321 Chakma, A. 31,127, 1547, 1583 Chalaturnyk, R.J. 471 Chalma, A. 1587

Chattopadhyay, S. 523, 621, 1641 Chen, B. 771,785, 1675 Chen, C.-H. 193 Chen, W. 881 Chensee, M. 1813 Cherepy, N. 1307 Chidsey, T. 423 Chiesa, P. 141 Chikahisa, T. 1713, 1749 Cho, S.-H. 1563 Choi, J.O. 1037 Choi, M.J. 1491 Choi, S.K. 1871 Christensen, N.P. 657 Chui, E.H. 87 Chun, H.D. 1871 Clark, C. 45 Clarke, J. 863, 1427 Clemens, T. 1319 Clerici, G. 63 Clodic, D. 155 Coelho, L.M.R. 1567 Coffin, R.B. 805 Cole, D. 1625 Contarini, S. 169 Cook, E.M. 285, 511 Cooper, J.F. 1307 Croiset, E. 1735 Cross, D.A. 69 Cuelenaere, R. 227, 1163 Cuelio, J.L. 1503 Cullinane, J.T. 1603 Czernichowski-Lauriol, I. 411, 417, 1617, 1629, 1633

D'Addario, E. 63 Dahlin, D.C. 677 Dahowski, R.T. 1107, 1 i 13 Daily, W.D. 353 Daley, T.M. 371 Damen, K. 645 Damen, K.J. 639 Dave, N. 1813 Davis, J.P. 1773, 1777 Davison, J. 75, 517, 1125, 1131, 1691, 1863 de Figueiredo, M.A. 799 de Jager, D. 1201, 1251 de La Cheshnaye, F. 1787 de Mol, R.M. 1281, 1795 de Silva, G.K.W. 1823 Deguchi, G. 531 Del Piero, G. 169 DeLaquil, P. 881 Delaytermoz, A. 279 deMontigny, D. 1583 Diao, Y.-F. 193 Dibenedetto, A. 1497, 1599 Dijk, J.-W. 589 Dijkstra, J.W. 161 DiPietro, P. 1089, 1275

1876

Do, K.T. 1813 Doerler, N. 403 Dooley, J. 863, 1427 Dooley, J.J. 273, 1107, 1 | 13 Dote, Y. 1837 Doughty, C. 1645 Doughty, C.A. 1625 Douglas, M.A. 87, 1735 Douglas, P.L. 1735 Dowaki, K. 901, 1383 Druckenmiller, M.L. 1621 Duffy, G.J. 1813 Dunk, R. 1667 Duquerroix, J.P. 403 Durocher, K. 365 Durucan, S. 539

Ebinuma, T. 1679 Edmonds, J.A. 863, 1427 Edwards, J.H. 1813 Egashira, Y. 1477 Egberts, P.J.P. 651 Eiken, O. 347 Eliasson, B. 1525 Emberley, S. 365 Endo, T. 975 Ennis-King, J. 463, 507 Ennis-Knight, J. 1653 Espie, A.A. 213 Espie, T. 621 Essaki, K. 1579 Estiva, J.A.N. 1337

Faaij, A. 645 Faber, E. 417 Favrat, D. 1311 Feng Wen 193 Fer, I. 747 Findlay, D.A. 1131 Fletcher, A.J.P. 1773, 1777 Fokker, P.A. 551 Forbes, I. 1131 Fox, C. 429 Freeman, D.J. 1131 Freund, P. 45, 1511, 1571 Frykman, P. 397 Fuchihata, M. 1401, 1833 Fujii, M. 843, 1799 Fujii, Y. 889 Fujime, K. 1183 Fujioka, M. 531 Fujioka, Y. 849 Fujisawa, S. 1231, 1439 Fukuda, K. 1019 Furukawa, S. 849 Furuse, T. 901 Futihata, M. 1855

Gale, J. 207, 311, 517, 639, 1251, 1787 Gambarotta, E. 169 Gao, P. 881 Garcia, J. 463 Garten, Jr., C.T. 1465

Gasperikova, E. 377 Gelowitz, D. 31, 1547, 1575 Genchi, Y. 919 Gerdemann, S.J. 677 Geuzebroek, F.H. 121 Giammar, D.E. 1609 Gillig, D. 1459 Gilmartin, T. 69 Gnanadesikan, A. 725,855 Goff, G.S. 115 Goldberg, P. 665 Golomb, D.S. 683 Gorgas, T.J. 831 Granieri, R. 391 Gregersen, U. 321 Grierson, P.F. 1383 Griffin, T. 81 Gritto, R. 371 Grootheest, W. 589 Gunter, B. 575, 1661 Gunter, W. 1625 Gunter, W.D. 365, 563,697 Gupta, N. 523,621, 1641 Guzman, Ma.A.L.G. 1337 Gwynn, W. 423

Hirai, S. 837 Hirano, A. 1843 Hishinuma, Y. 1713, 1749 Ho, A.M. 1637 HOhne, N. 869, 1145 Holloway, G.S. 321 Holloway, S. 333 Hongo, S. 317 Honjo, T. 1401, 1833 Honjou, T. 1855 Hou, Z. 1847 Hounshell, D.A. ! 139 Hoversten, G.M. 371,377, 1625 Hovorka, S. 1625 Hovorka, S.D. 583 Howells, M.I. 895 Huang, C.-H. 1859 Huang, G.H. 907, 1741 Huang, K. 975 Hubbard, R.A. 213 Humphreys, K. 995 Hurst, P. 39 Hustad, C-W. 1077 Hutcheon, I. 365

Ha-Duong, M. 187 Haines, M. 1319 Haines, M.R. 1571 Halmann, M. 1013 H/im/il/iinen, J. 181 Han, B. 1773, 1777 Han, S.-S. 1563 Hanaoka, T. 1257 Handa, T. 963 Haneda, H. 1671 Hao, J.M. 1829 Haraya, K. 1551, 1559 Harmelink, M. 1163 Harnisch, J. 869, 1145, 1201, 1251 Harvey, S. 1237 Hatanaka, N. 1485 Hatziyannis, G. 417 Haugan, P.M. 719, 747 Haupt, G. 1063 Hawkins, D.G. 249 Hayashi, A. 51 Hayashi, M. 1695 Haydock, H. 45 He, B.-S. 193 Heck, T. 1633 Heffelfinger, B. 931 Heidug, W. ! 319 Hendricks, C. 1163, 1201 Hendricks, C.A. 651 Hepple, R. 243 Hepple, R.P. 261 Herzog, H.J. 235, 799, 1083, 1101 Hetherington, J. 709 Hildenbrand, A. 417 Hilhorst, M.A. 1281, 1795 Hill, G. 19 Hill, N. 45 Hillis, R.R. 495

Ibrahim, H. 1825 Ickes, J. 1641 Ida, T. 1401, 1833, 1855 Idem, R. 31, 1547, 1575, 1825 lhara, T. 963 Iida, T. 981 lida, Y. 1807 Iijima, M. 57, 109, 1057 Ikeda, K. 937 Ikeda, T. 1683 lkuta, Y. 1471 Inaba, A. 919 lnoue, H. 1485 lshibashi, M. 1843 lshida, H. 1683 Ishida, K. 1649 Ishikawa, M. 457 Ishimatsu, A. 1695 lshitani, H. 949, 963, 1257, 1769 Ishizaka, J. 849, 1683 Ito, T. 1649 Itou, K. 1331 Ivens, N.W. 69 Iwata, T. 969 lzaurralde, R. 1427

Jaffe, P.R. 1657 Jansen, D. 161 Jessen, K. 463 Jia, L. 671 Jiminez, J.A. 471 Jin, G.T. 175 Johannessen, P.N. 321 Johnson, J.W. 327, 1625 Johnson, W.K. 1687 Johnsson, F. 1051 Jones, D.G. 391 Joos, F. 1691

1877

Jordal, K. 135 Juniper, L. 75 Kabaseke, R. 1781 Kai, W. 981 Kamijo, T. 109 Karani, P. ! 761 Kasai, H. 1331 Kasugai, S. 981 Kathirgamanathan, P. 1377 Kato, M. 1579 Kato, T. 981,987, 1803 Kawakami, K. ! 713 Kawamura, T. 1671 Kaya, Y. 51 Kazama, S. 1551 Keith, D. 1661 Keith, D.W. 187, 229, 1371 Kenny, A.R. 1725 Keppel, J.F. 651 Kervevan, C. 339, 1617 Kheshgi, H.S. 811, 1419 Khullar, R.K. 1359 Kidena, K. 1485 Kikkawa, T. 1695 Kim, J.G. 1037, 1871 Kim, J.-N. 1563 Kim, J.S. 1491 Kim, S.H. 863, 1427 Kirby, G.A. 321 Kita, J. 1695 Kiyono, F. 843, 1799 Klara, S. 297, 1089 Knauss, K.G. 1625 Knox, P.R. 583 Ko, K.S. 1871 Kobayashi, T. 1649 Koch, M. 869 Koide, H. 317, 359, 501,703, 1649 Kojima, R. 739, 825 Kojima, T. 1477 Koljonen, T. 291 Komai, T.. 1671 Komatsu, N. 969 Komiyama, H. 817 Komiyama, R. 889 Komoto, J. 937 Korovin, G.N. 1851 Kosugi, T. 51, 1195 Kotsubo, H. 913, 1649 Kovscek, A. 1625 Kovscek, T. 463 Kraaijveld, G.J.C. 121 Kreutz, T.G. 141 Kronrad, G.D. 1859 Krooss, B.M. 417 Kuchta, M.E. 1729 Kudoh, Y. 949 Kulagin, S.Y. 1721 Kumar, S. 1031, 1717 Kurihara, M. 1791 Kurosawa, A. 875 Kuuskraa, V. 1089, 1275 Kuuskraa, V.A. 609 Kvamsdal, H.M. 135 Kwon, T.-S. 1445

Larsen, M. 657 Larson, E.D. 881 Law, D. 1625 Law, D.H.-S. 443,463, 563 Le Gailo, Y. 403,443,463 Le Nindre, Y.M. 411, 1633 Le Thiez, P. 403 Lee, A. 1007 Lee, J.-Y. 1445 Lee, K.W. 1389, 1491 Lee, S.B. 1491 Lee, W.Y. 1491 Leites, I.L. 1701 Lemon, N.M. 435 Lermit, J. 1377 Lewis, C. 243 Li, Q. 501 Li, X. 483, 501,703,913 Lichtner, P. 463 Lin, Q.G. 907, 1741 Lindeberg, E. 255, 489 Lippmann, M. 243 Lippmann, M.J. 1625 Lombardi, S. 391,417, 1629 Lozza, G. 141 Lyngfelt, A. 1051 Lysen, E. 645

Ma, Y.L. 1829 MacDonald, D. 575 Maeda, A. 1171 Maeda, H. 1451 Mahasenan, N. 285,995, 1177 Mahasenan, N.M. 511 Maier-Reimer, E. 1691 Majer, E.L. 371, 1625 Majeski, A.J. 87 Maksinen, P. 1051 Maldal, T. 601 Mallett, C.W. 1287 Malone, E.L. 1765 Mano, H. 1551, 1555, 1559 Mantzos, L. 1201 Marcenaro, B. 1325 Marion, J.L. 81 Mariz, C. 31 Mariz, C.L. 103 Markussen, P. 1077 Marland, G. 1465 Maroto-Valer, M.M. 1621, 1729 Marsh, G. 45 Massingill, M.J. 1433 Masutani, S.M. 765, 791,805, 831 Matear, R. 1691 Matsuhashi, R. 949, 963, 1231, 1257, 1769 Matsui, T. 545 Matsumiya, N. 1555, 1559 Matsumoto, T. 51 Matsuo, S. 317 Matsuoka, I. 1225 Matsuyama, H. 149 Matumiya, N. 943 May, F. 339 Mazzamurro, G. 169

McCann, T. 1661 McCarl, B.A. 1459 McFarland, J.R. 1083 McGrail, B.P. 449, 1637 McNaughton, R. 1813 Melzer, S. 429 Mercier, G. 1151 Mignone, B. 1691 Mignone, B.K. 725 Mimura, T. 1057 Minagawa, H. 1679 Ming Yang 1243 Misra, D.D. 1343 Mitamura, W. 123 i Mitchell, B. 1151 Mitsui, Y. 1269 Mitsukawa, H. 5 Miyazaki, M. 1451 Moberg, R. 219 Moline, G. 1625 Momobayashi, Y. 1231 Montgomery, M.T. 805 Moore, J. 423 Morgan, C. 423 Mori, S. 901, 1383 Mori, T. 1803 Moriguchi, Y. 1745 Morishita, A. 1769 Morita, K. 1019 Morita, M. 1807 Muehlenbachs, K. 697 Murai, S. 733 Muramatsu, E. 57 Murata, S. 1485 Musicanti, M. 63 Myer, L.R. 371,377, 1625 Myneni, C.B. 1609 Nador, A. 417 Nagao, J. 1679 Nakagawa, K. 1579 Nakaiwa, M. 975 Nakajima, Y. 1439 Nakamura, H. 1451 Nakashiki, N. 785 Nansai, K. 1745 Narita, H. 1679 Narracci, M. 1497 Nelson, R. 575 Newmark, R.L. 353, 1625 Nguyen, V. 615,633 Nihous, G.C. 765,779 Nimiago, P. 1383 Nishibori, F. 733 Nishida, T. 1791 Nishimura, S. 703 Nishio, M. 771, 791, 1675 Nitao, J.J. 327 Niwa, S. 943 Nojo, T. 1057 Nomura, M. 1485 Nordrum, S. 1007, 1025 Nsakala ya Nsakala 81

Oakey, J.E. 181 Obdam, A. 339

1878

O'Connor, W.K. 677 Oeljeklaus, G. 1063 Ogasawara, K. 843 Ogden, J.M. 627, 1069 Ogi, T. 1837 Ogino, K. 1843 Ohga, K. 531,1671 Ohmori, T. 975 Ohmura, R. 1679 Ohnishi, N. 149 Ohsaki, M. 1867 Ohsumi, T. 317, 359, 457, 483, 501,733,771,913, 1649 Ohyama, R. 1803 Okabe, K. 1555 Okamoto, I. 483 Okano, T. 1799 Oldenburg, C. 463 Oldenburg, C.M. 443,691, 1625 Ono, E. 1503 Ono, Y. 1331 Orr, J.C. 1691 Orr, Jr., F.M. 1625 Osada, T. 1299 Ota, K. 1331 Ozaki, M. 733,791

Pacala, S.W. 267 Pagnier, H.J.M. 569 Pang, J. 1773, 1777 Park, J.-H. 1563 Parodi, F. 1325 Paterson, L. 507, 1653 Pauwels, H. 411, 417 Pawar, R. 463 Pearce, J.M. 417, 1617 Pedroni, P. 1863 Peersmann, M.R.H.E. 651 Pekot, L.J. 609 Peltzer III, E.T. 739 Peltzer, E.T. 1667 Penner, L. 391 Perkins, E.H. 365 Perrone, C. 1497 Peters, C.A. 1609 Petroceili, A. 1497 Plattner, G.-K. 1691 Post, W.M. 1465 Prasad, R. 1343 Pritchard, C. 975 Pruess, K. 463, 1625, 1645 Pruschek, R. 1063 Pulvirenti, G. 63 Purnomoadi, A. 1791 Pyong Sik Pak 95

Quattrocchi, F. 391, 1629

Ramirez, A.L. 353 Ranasinghe, T. 1823 Rao, A.B. 1119 Read, P. 1377 Reeves, S. 557 Rehder, G. 1667

Reidel, S.P. 1637 Reilly, J. 1083 Reiner, D.M. 235, 799 Reynen, B. 575 Rhodes, J.S. 1371 Rhudy, R.G. 1101 Riahi, K. 1095 Richards, W.H. 1045 Rickeard, D.J. 1419 Riddiford, F.A. 595 Riding, J.B. 1629 Rigg, A.J. 633 Riocci, M. 169 Ritter, K. 1025 Roberts, C.A. 39 Rochelle, C.A. 1617, 1629 Rochelle, G.T. 115, 1603 Rosenberg, N. 1427 Rossiter, D. 1157 Rostron, B. 385 Rubin, E.S. 1095, 1119, 1139 Rutqvist, J. 463 Ryu, H.J. 175 Ryu, J.S. 1389

Saito, M. 1477 Saitoh, K. 919 Sakai, K. 1269 Sakuragi, Y. 545 Sam, N. 1383 Sanda, H. 837 Sands, R.D. 1459 Sanjuan, B. 1617 Sano, H. 1401, 1833, 1855 Saripalli, K.P. 511 Saripalli, P. 285 Sarmiento, J. 1691 Sarmiento, J.L. 725,855 Sasaki, K. 531 Sass, B. 523, 621 Sass, B.M. 1641 Sato, T. 759, 785, 1613 Satsumi, S. 703 Savage, D. 1629 Savolainen, I. 291 Sawa, T. 1225 Schaef, H.T. 1637 Schlitzer, R. 1691 Schnieder, L.H.J.M. 121 Schrattenholzer, L. 1095 Schreurs, H. 589 Schreurs, H.C.E. 303 Schroot, B.M. 417 Scott, M.J. 1177 Sekiguchi, T. 545 Sekiya, A. 1269 Serenellini, S. 63 Serra, H. 1617 Shaw, K. 333 Shenton, W.W. 1773, 1777 Shepherd Burton, C. 1263 Shevalier, M. 365 Shi, J.Q. 539 Shikasho, N. ! 019 Shimada, S. 545,969 Shiojiri, K. 1799

Shires, T. 1025 Siikavirta, H. 291 Simbeck, D.R. 25 Simmonds, M. 39 Singh, D. 1735 Singh, U.P. I001 Skinner, R.C. 213 Skoropad, D. 1575 Slater, M. 103 Slater, R.D. 725, 855 Sminchak, J. 621 Smith, I.M. 1219 Smith, L. 523 Smith, M. 595 Smith, S. 995 Smith, S.J. 863, 1177 Socolow, R.H. 141 Solomon, M. 895 Song, Y. 771, 1675 Sorai, M. 457 Spencer, L. 633 Springer, N. 1617, 1629 Stachniak, D. 219 Steefel, C. 463 Steinberg, M. 1307 Steinfeld, A. 1013 Stevens, S.H. 429, 691 Stewart, D.B. 219 Stobbe, O. 1251 Stobbs, B. 1575 Stokes, G.M. 1427 Stollwerk, P. 589 Streit, J.E. 495 StrSmberg, L. 1051 Strutt, M.H. 391 Su, S. 1287 Sudhakara Reddy, B. 957 Sugihara, H. 937 Sugimori, M. 849 Suzuki, Y. 817 Suzuoki, Y. 981

Takahashi, N. 1477 Takahata, K. 1709 Takamatsu, T. 975 Takano, S. 843 Takeuchi, K. 849 Takeuchi, N. 149 Takeya, S. 1679 Tamaki, J. 1803 Tan, Y. 87 Tanaka, H. 1057 Tanaka, K. 1311 Tanaka, T. 1847 Tang, L. 765,831 Tani, H. 1331 Tanthapanichakoon, W. 1591 Tappel, I.M. 601 Tasaki, A. 1613 Taylor, B. 595 Taylor, M.R. 1139 Terada, S. 837 Teramoto, M. 149, 1555 Tezuka, T. 1213, 1225 Thambimuthu, K. 1,709, 1151 Thambimuthu, K.V. 87

1879

Tishchenko, P.Y. 1687 Tohno, S. 1745 Tokimatsu, K. 51, 1195 Tommasi, I. 1497 Tomoda, T. 51, 913 Tontiwachwuthikul, P. 31,127, ! 547, 1583, 1587, ! 825 Topper, J.M. ! 2 ! 9, 1543 Torazza, A. 1325 Torp, T.A. 311 Tourqui, A. 595 Travis, B. 463 Tsang, C.-F. 1625 Tsang, C.F. 243,463 Tsuchida, M. 1843 Tsuji, K. 937 Tsushima, S. 837 Tsuzuki, M. 1439 Turan, H.I. 213

Uchida, T. 1679 Uemoto, H. 1579 Uno, M. 317, 913,943, 1649 Utkin, A.I. 1851

Vainio, M. 1201 Valdiserri, M.G. 63 van Bergen, F. 569, 639, 645 van den Belt, F.J.G. 569 van der Meer, B. 1625 van der Meer, L. 339, 347 van der Meer, L.G.H. 201,551, 563,569 van der Waart, A.S. 651 Van Olst, J.C. 1433 Veawab, A. 31,127, 1547, 1587, 1591, 1595 Venugopal, S. 1293 Vianio, M. 1787 Vigouroux, P. 411 Vincent, C. 333 Voltatorni, N. 391

Wada, N. 1613 Waiters, C. 1813 Waiters, R. 665 Wang, P. 62 I Wang, S. 1657 Wannamaker, E.J. 753 Ward, C. 69 Wass, K. 1157 Watanabe, T. 317 Watanabe, Y. 1683 Watson, M.N. 435 Watt, C. 39 Weirig, M.-F. ! 691 Weissman, J.C. 1433 Wen Feng 193 West, E. 103 West, T.O. 1465 Westerhoff, R.S. 569 White, M.D. 449 White, S. 463 White, S.P. 423,443 White, T. 429 Whittaker, S.G. 385 Wichert, E, 1661 Wickett, M. 1691 Wildenborg, A. 339 Wildenborg, A.F.B. 639, 651 Wilkinson, M.B. 39, 69, 1325 Williams, R.H. 141 Wilson, E.J. 229 Wilson, M. 31, 1151, 1547, 1825 Wilson, P. 633 Winthaegen, P.L.A. 569 Wise, M.A. 273 Wong, C.S. 1687 Wong, S. 575, 1661 Wu, Z. 501,881

XinYu 1243 Xin, C.M. 1213 Xu, K.F. 1829 Xu, T.F. 463 Xu, X.-C. 193 Xue, Z. 359, 703

Yagita, H. 919 Yamada, K. 817, 1311, 1477 Yamaguchi, A. 1683 Yamaji, K. 889 Yamamoto, H. 925 Yamamoto, Y. 167 ! Yamane, K. 739, 825 Yamasaki, A. 843, 1799 Yanagihara, N. 1867 Yanagisawa, Y. 843, 1799 Yang Ming 1243 Yang, J.-W. 1445 Yang, M. 1755 Yashima, T. 1847 Yeh, S. 1139 Yokota, O. 1847 Yokoyama, T. 13, 1709 Yool, A. 1691 Yoshida, H. 51 Yoshida, M. 1867 Yoshida, Y. 949, 963, 1231, ! 257, 1769 Yoshikawa, S. 1579 Yoshiyama, T. 1057 Younes, M. 155 Yu Xin 1243 Yu, X. 1755

Zamolodchikov, D.G. 1851 Zappelli, P. 169 Zevenhoven, R. 291 Zhang, Y. 1729 Zheng, X.-Y. 193 Zhou, W. 1195 Zimmermann, G. 1063 Zinszner, B. 347 Zweigel, P. 321,347 Zwingmann, N. 435

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