i
Developments and innovation in carbon dioxide (CO2) capture and storage technology
© Woodhead Publishing Limited, 2010
ii
Related titles: Advanced power plant materials, design and technology (ISBN 978-1-84569-515-6) Fossil-fuel power plants generate the majority of the world’s power, but many plants are ageing and cannot meet rising global energy demands and increasingly stringent emissions criteria. To ensure security and economy of supply, utilities are building a new generation of advanced power plant with increased output and environmental performance. This book initially reviews improved plant designs for efficiency and fuel flexibility, including combinedcycle technology and utilisation of lower-grade feedstocks. Coverage extends to advanced material and component use, and the incorporation of alternative energy conversion technology, such as hydrogen production. Environmental and emissions performance issues round off the book. Oxy-fuel combustion for power generation and carbon dioxide (CO2) capture (ISBN: 978-1-84569-671-9) Oxy-fuel combustion is a power generation and carbon dioxide (CO2) capture option for advanced power plant in which fuel is burnt in an oxygen-rich environment instead of in air. This allows for a reduction in NOx and SOx emissions as well as producing a high-purity carbon dioxide (CO2) flue gas stream. This high-purity CO2 stream allows for more efficient and economical capture, processing and sequestration. This book critically reviews the fundamental principles, processes and technology of oxy-fuel combustion, including advanced concepts for its implementation. Details of these and other Woodhead Publishing books can be obtained by: visiting our web site at www.woodheadpublishing.com contacting Customer Services (e-mail:
[email protected]; fax: +44 (0) 1223 893694; tel.: +44 (0) 1223 891358 ext. 130; address: Woodhead Publishing Limited, Abington Hall, Granta Park, Great Abington, Cambridge CB21 6AH, UK) If you would like to receive information on forthcoming titles, please send your address details to: Francis Dodds (address, tel. and fax as above; e-mail:
[email protected]). Please confirm which subject areas you are interested in.
© Woodhead Publishing Limited, 2010
iii
Woodhead Publishing Series in Energy: Number 16
Developments and innovation in carbon dioxide (CO2) capture and storage technology Volume 2: Carbon dioxide (CO2) storage and utilisation Edited by M. Mercedes Maroto-Valer
CRC Press Boca Raton Boston New York Washington, DC
Woodhead
publishing limited
Oxford Cambridge New Delhi
© Woodhead Publishing Limited, 2010
iv Published by Woodhead Publishing Limited, Abington Hall, Granta Park, Great Abington, Cambridge CB21 6AH, UK www.woodheadpublishing.com Woodhead Publishing India Private Limited, G-2, Vardaan House, 7/28 Ansari Road, Daryaganj, New Delhi – 110002, India www.woodheadpublishingindia.com Published in North America by CRC Press LLC, 6000 Broken Sound Parkway, NW, Suite 300, Boca Raton, FL 33487, USA First published 2010, Woodhead Publishing Limited and CRC Press LLC © Woodhead Publishing Limited, 2010 The authors have asserted their moral rights. This book contains information obtained from authentic and highly regarded sources. Reprinted material is quoted with permission, and sources are indicated. Reasonable efforts have been made to publish reliable data and information, but the author and the publishers cannot assume responsibility for the validity of all materials. Neither the author nor the publishers, nor anyone else associated with this publication, shall be liable for any loss, damage or liability directly or indirectly caused or alleged to be caused by this book. Neither this book nor any part may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, microfilming and recording, or by any information storage or retrieval system, without permission in writing from Woodhead Publishing Limited. The consent of Woodhead Publishing Limited does not extend to copying for general distribution, for promotion, for creating new works, or for resale. Specific permission must be obtained in writing from Woodhead Publishing Limited for such copying. Trademark notice: Product or corporate names may be trademarks or registered trademarks, and are used only for identification and explanation, without intent to infringe. British Library Cataloguing in Publication Data A catalogue record for this book is available from the British Library. Library of Congress Cataloging in Publication Data A catalog record for this book is available from the Library of Congress. Woodhead Publishing ISBN 978-1-84569-797-6 (book) Woodhead Publishing ISBN 978-1-84569-958-1 (e-book) CRC Press ISBN 978-1-4398-3101-4 CRC Press order number: N10186 The publishers’ policy is to use permanent paper from mills that operate a sustainable forestry policy, and which has been manufactured from pulp which is processed using acidfree and elemental chlorine-free practices. Furthermore, the publishers ensure that the text paper and cover board used have met acceptable environmental accreditation standards. Cover image © BCS Creative, 88–90 North Sherwood Street, Nottingham NG1 4EE, UK, www.bcscreative.co.uk Typeset by Replika Press Pvt Ltd, India Printed by TJ International Limited, Padstow, Cornwall, UK
© Woodhead Publishing Limited, 2010
v
Contents
Contributor contact details
xiii
Woodhead Publishing Series in Energy
xvii
Foreword by Lord Oxburgh
xix
1
Overview of carbon dioxide (CO2) capture and storage technology
S. Bouzalakos and M. Mercedes Maroto-Valer, University of Nottingham, UK
1.1 1.2 1.3 1.4
Introduction Greenhouse gas emissions and global climate change Carbon management and stabilisation routes Development and innovation in carbon dioxide (CO2) capture and transport technology Development and innovation in carbon dioxide (CO2) storage and utilisation technology Future trends Sources of further information and advice Acknowledgements References
1.5 1.6 1.7 1.8 1.9
1
1 2 8 11 17 19 20 22 22
Part I Geological sequestration of carbon dioxide (CO2) 2
27
Screening and selection criteria, and characterisation techniques for the geological sequestration of carbon dioxide (CO2)
S. Bachu, Alberta Innovates – Technology Futures, Canada
2.1 2.2 2.3
Introduction Screening for storage suitability and site selection Site characterisation
27 28 43
© Woodhead Publishing Limited, 2010
vi
Contents
2.4 2.5 2.6 2.7
Estimation of carbon dioxide (CO2) storage capacity Future trends Sources of further information and advice References
47 51 52 53
3
Carbon dioxide (CO2) sequestration in deep saline aquifers and formations
57
R. J. Rosenbauer and B. Thomas, US Geological Survey, USA
3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9
Introduction Saline aquifers Trapping mechanisms Modeling of carbon dioxide (CO2) sequestration Carbon dioxide (CO2) sequestration pilot sites Future trends Conclusions Acknowledgements References
4
Carbon dioxide (CO2) sequestration in oil and gas reservoirs and use for enhanced oil recovery (EOR)
B. Vega and A.R. Kovscek, Stanford University, USA
4.1 4.2 4.3
Introduction Carbon dioxide (CO2) enhanced recovery mechanisms Co-optimization of enhanced oil recovery (EOR) and carbon storage Future trends: geologic storage in tight rocks Summary and conclusions Sources of further information and advice References
116 118 122 123 124
5
Carbon dioxide (CO2) sequestration in unmineable coal seams and use for enhanced coalbed methane recovery (ECBM)
127
M. Mazzotti and Ronny Pini, ETH Zurich, Switzerland, G. Storti, Politecnico di Milano, Italy, and L. Burlini, ETH Zurich, Switzerland
5.1 5.2 5.3 5.4 5.5 5.6
Introduction Storage in unmineable coal seams Enhanced coalbed methane recovery Competitive adsorption Swelling and permeability Mass transfer and enhanced coalbed methane (ECBM) modeling
4.4 4.5 4.6 4.7
© Woodhead Publishing Limited, 2010
57 58 64 74 80 86 88 88 88 104 104 109
127 128 129 131 139 148
Contents
5.7 5.8 5.9 5.10
Field tests Future trends Sources of further information and advice References
vii
151 155 158 159
Part II Maximising and verifying carbon dioxide (CO2) storage in underground reservoirs 6
Carbon dioxide (CO2) injection design to maximise underground reservoir storage and enhanced oil recovery (EOR)
R. Qi, T.C. LaForce and M.J. Blunt, Imperial College London, UK
6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8 6.9
Carbon storage in geological formations Experiments of capillary trapping Field-scale design of storage in aquifers Storage in oilfields Discussion and conclusions Future trends Sources of further information and advice Acknowledgements References
169 172 175 179 180 181 181 182 182
7
Capillary seals for trapping carbon dioxide (CO2) in underground reservoirs
185
T.A. Meckel, The University of Texas at Austin, USA
7.1 7.2
Introduction Calculations of anticipated capillary pressures and seal capacities Monte Carlo predictions of capillary pressure within a reservoir seal Discussion Conclusions Future trends Sources of further information and advice Acknowledgements References
193 195 198 199 199 200 200
8
Measurement and monitoring technologies for verification of carbon dioxide (CO2) storage in underground reservoirs
203
R.A. Chadwick, British Geological Survey, UK
8.1
Introduction
7.3 7.4 7.5 7.6 7.7 7.8 7.9
169
185 188
203
© Woodhead Publishing Limited, 2010
viii
Contents
8.2 8.3
Background to storage site monitoring Detection and measurement of carbon dioxide (CO2) in the subsurface Detection and measurement of carbon dioxide (CO2) leakage to surface Conclusions and future trends Sources of further information and advice References
8.4 8.5 8.6 8.7 9
Mathematical modeling of the long-term safety of carbon dioxide (CO2) storage in underground reservoirs
K. Pruess, J. Birkholzer and Q. Zhou, Lawrence Berkeley National Laboratory, University of California, USA
9.1 9.2 9.3 9.4 9.5 9.6
Introduction Coupled processes: a challenge for mathematical models Ilustrative modeling applications Conclusions Acknowledgements References
204 207 225 233 235 235
240
240 243 244 259 261 261
Part III Terrestrial and ocean sequestration of carbon dioxide (CO2) and environmental impacts 10
Terrestrial sequestration of carbon dioxide (CO2)
271
R. Lal, The Ohio State University, USA
10.1 10.2 10.3 10.4
Introduction The terrestrial pool and its role in the global carbon cycle Emissions from agricultural versus other activities Basic principles of carbon sequestration in terrestrial ecosystems 10.5 Potential of terrestrial sequestration 10.6 Challenges of terrestrial sequestration 10.7 Extrapolation 10.8 Soil and terrestrial carbon as indicators of climate change 10.9 Conclusions 10.10 References
271 273 276
11
279 290 291 295 296 297 298
Ocean sequestration of carbon dioxide (CO2)
304
D. Golomb and S. Pennell, University of Massachusetts Lowell, USA
11.1 11.2
Introduction History of carbon dioxide (CO2) deep ocean storage proposals
304
© Woodhead Publishing Limited, 2010
305
Contents
Legal constraints of deep ocean storage of carbon dioxide (CO2) 11.4 Sources of anthropogenic carbon dioxide (CO2) for ocean storage 11.5 Ocean structure 11.6 Properties of carbon dioxide (CO2) 11.7 Modeling of carbon dioxide (CO2) release 11.8 Injection of carbon dioxide, water and pulverized limestone (CO2/H2O/CaCO3) emulsion 11.9 Future trends 11.10 Conclusions 11.11 Sources of further information and advice 11.12 References
ix
11.3
12
307 308 309 311 312 313 318 320 320 321 324
Environmental risks and impacts of carbon dioxide (CO2) leakage in terrestrial ecosystems
M. D. Steven, K. L. Smith and J. J. Colls, University of Nottingham, UK
12.1 12.2 12.3 12.4 12.5 12.6 12.7 12.8
Introduction Leak scenarios Impacts of terrestrial leakage Atmospheric enrichment of carbon dioxide (CO2) Leak monitoring techniques Conclusions and future trends Sources of further information and advice References
324 325 327 332 334 336 338 338
13
Environmental risks and performance assessment of carbon dioxide (CO2) leakage in marine ecosystems
344
J. Blackford, S. Widdicombe and D. Lowe, Plymouth Marine Laboratory, UK, and B. Chen, Heriot Watt University, UK
13.1 13.2
Introduction The physical and chemical behaviour of carbon dioxide (CO2) in the marine system Marine ecosystem impacts of carbon dioxide (CO2) leakage Leak monitoring options Mitigation of leaks Future trends Sources of further information and advice References
13.3 13.4 13.5 13.6 13.7 13.8
© Woodhead Publishing Limited, 2010
344 346 358 365 366 366 367 368
x
Contents
Part IV Advanced concepts for carbon dioxide (CO2) storage and utilisation 14
Industrial utilization of carbon dioxide (CO2)
377
Introduction The conditions for using carbon dioxide (CO2) The carbon dioxide (CO2) sources and its value Technological uses of carbon dioxide (CO2) Biological enhanced utilization Carbon dioxide (CO2) conversion as ‘storage’ of excess electric energy or intermittent energies 14.7 Production of chemicals 14.8 Conclusions and future trends 14.9 Sources of further information and advice 14.10 References
377 378 380 381 384
M. Aresta and A. Dibenedetto, University of Bari, Italy
14.1 14.2 14.3 14.4 14.5 14.6
391 398 404 405 405
15
Biofixation of carbon dioxide (CO2) by microorganisms
B. Wang and C.Q. Lan, University of Ottawa, Canada
15.1 15.2 15.3
Introduction Basic principles and methods Carbon dioxide (CO2) fixation microorganisms: chemoautotrophs and photoautotrophs Carbon dioxide (CO2) fixation by microalgae Advantages and limitations Future trends References
411 412
Mineralisation of carbon dioxide (CO2)
433
15.4 15.5 15.6 15.7 16
411
414 418 426 427 428
R. Zevenhoven and J. Fagerlund, Åbo Akademi University, Finland
16.1 Introduction 16.2 Basic principles and methods 16.3 Technologies and potential applications 16.4 Related issues 16.5 Future trends 16.6 Sources of further information and advice 16.7 References Appendix: Energy efficiency of mineral carbonation processes
© Woodhead Publishing Limited, 2010
433 435 438 447 451 452 453 460
Contents
17
xi
Photocatalytic reduction of carbon dioxide (CO2)
463
Jeffrey C. S. Wu, Department of Chemical Engineering, National Taiwan University, Taiwan
17.1 17.2 17.3
463 465
17.4 17.5 17.6 17.7
Introduction Fundamentals of photocatalysis Renewable energy from photocatalytic reduction of carbon dioxide (CO2) Advantages and limitations of photocatalytic processes Future trends Sources of further information and advice References
470 495 495 497 497
Index
503
© Woodhead Publishing Limited, 2010
xii
xiii
Contributor contact details
(* = main contact)
Chapter 1
Chapter 3
Dr Steve Bouzalakos and Professor M. Mercedes Maroto-Valer* Centre for Innovation in Carbon Capture and Storage (CICCS) Faculty of Engineering University of Nottingham University Park Nottingham NG7 2RD UK
Robert J. Rosenbauer* and Burt Thomas US Geological Survey 345 Middlefield Road MS-999 Menlo Park CA 94025 USA
Email: mercedes.maroto-valer@ nottingham.ac.uk
Chapter 4
Chapter 2 Stefan Bachu Alberta Innovates – Technology Futures 250 Karl Clark Road NW Edmonton Alberta T6N 1E4 Canada
Email:
[email protected]
B. Vega and A. R. Kovscek* Energy Resources Engineering Department Stanford University 367 Panama St. room 065 Stanford CA 94305-2220 USA Email:
[email protected]
Email: Stefan.Bachu@albertainnovates. ca
© Woodhead Publishing Limited, 2010
xiv
Contributor contact details
Chapter 5
Chapter 7
Professor Dr Marco Mazzotti* and Ronny Pini Institute of Process Engineering ETH Zurich Sonneggstrasse 3 CH-8092 Zurich Switzerland
T. A. Meckel* Gulf Coast Carbon Center Bureau of Economic Geology John A. and Katherine G. Jackson School of Geosciences The University of Texas at Austin University Station, Box X Austin TX 78713-8924 USA
Email:
[email protected]
Professor Dr Giuseppe Storti Dipartimento di Chimica, Materiali e Ing. Chimica ‘Giulio Natta’ Politecnico di Milano, Sede Mancinelli Via Mancinelli 7 I-20131 Milano Italy L. Burlini Geological Institute ETH Zurich Leonhardstrasse 19 CH-8092 Zurich Switzerland
Email:
[email protected]
Chapter 8 Dr R. A. Chadwick British Geological Survey Kingsley Dunham Centre Keyworth Nottinghamshire NG12 5GG UK Email:
[email protected]
Chapter 9
Chapter 6 Ran Qi, Tara C. LaForce and Martin J. Blunt* Department of Earth Science and Engineering Imperial College London London SW7 2AZ UK
Karsten Pruess*, Jens Birkholzer and Quanlin Zhou Earth Sciences Division Lawrence Berkeley National Laboratory University of California One Cyclotron Road Berkeley CA 94720 USA
Email:
[email protected] Email:
[email protected]
© Woodhead Publishing Limited, 2010
Contributor contact details
Chapter 10
Chapter 13
R. Lal Carbon Management and Sequestration Center The Ohio State University Columbus OH 42310 USA
Jeremy Blackford*, Stephen Widdicombe and David Lowe Plymouth Marine Laboratory Prospect Place Plymouth PL1 3DH UK
Email:
[email protected]
Email:
[email protected]
Chapter 11 Dr D. Golomb* and Dr S. Pennell University of Massachusetts Lowell 1 University Avenue Lowell MA 01854 USA Email:
[email protected]
Chapter 12 Michael D Steven*, Karon L Smith and Jeremy J Colls University of Nottingham University Park Nottingham NG7 2RD UK
xv
Baixin Chen School of Engineering and Physical Sciences Heriot Watt University Edinburgh Scotland EH14 4AS UK
Chapter 14 Michele Aresta* and Angela Dibenedetto CIRCC and Department of Chemistry University of Bari Campus Universitario 70126 Bari Italy Email:
[email protected]
Email: michael.steven@nottingham. ac.uk
© Woodhead Publishing Limited, 2010
xvi
Contributor contact details
Chapter 15
Chapter 17
Bei Wang and Christopher Q. Lan* Department of Chemical and Biological Engineering University of Ottawa Ottawa Ontario K1N 6N5 Canada
Professor Jeffrey C. S. Wu Department of Chemical Engineering National Taiwan University No. 1 Section 4 Roosevelt Road Taipei 10617 Taiwan (R.O.C.) Email:
[email protected]
Email:
[email protected]
Chapter 16 R. Zevenhoven* and J. Fagerlund Thermal and Flow Engineering Laboratory Åbo Akademi University Biskopsgatan 8 FI-20500 Åbo/Turku Finland Email:
[email protected]
© Woodhead Publishing Limited, 2010
xvii
Woodhead Publishing Series in Energy
1 Generating power at high efficiency: Combined cycle technology for sustainable energy production Eric Jeffs 2 Advanced separation techniques for nuclear fuel reprocessing and radioactive waste treatment Edited by Kenneth L. Nash and Gregg J. Lumetta 3 Bioalcohol production: Biochemical conversion of lignocellulosic biomass Edited by K.W. Waldron 4 Understanding and mitigating ageing in nuclear power plants: Materials and operational aspects of plant life management (PLiM) Edited by Philip G. Tipping 5 Advanced power plant materials, design and technology Edited by Dermot Roddy 6 Stand-alone and hybrid wind energy systems: Technology, energy storage and applications Edited by J.K. Kaldellis 7 Biodiesel science and technology: From soil to oil Jan C.J. Bart, Natale Palmeri and Stefano Cavallaro 8 Developments and innovation in carbon dioxide (CO2) capture and storage technology Volume 1: Carbon dioxide (CO2) capture, transport and industrial applications Edited by M. Mercedes Maroto-Valer 9 Geological repository systems for safe disposal of spent nuclear fuels and radioactive waste Edited by Joonhong Ahn and Michael J. Apted 10 Wind energy systems: Optimising design and construction for safe and reliable operation Edited by John D. Sørensen and Jens N. Sørensen © Woodhead Publishing Limited, 2010
xviii
Woodhead Publishing Series in Energy
11 Solid oxide fuel cell technology: Principles, performance and operations Kevin Huang and John Bannister Goodenough 12 Handbook of advanced radioactive waste conditioning technologies Edited by Michael I. Ojovan 13 Nuclear reactor safety systems Edited by Dan Gabriel Cacuci 14 Materials for energy efficiency and thermal comfort in buildings Edited by Matthew R. Hall 15 Handbook of biofuels production: Processes and technology Edited by Rafael Luque, Juan Campelo and James Clark 16 Developments and innovation in carbon dioxide (CO2) capture and storage technology Volume 2: Carbon dioxide (CO2) storage and utilisation Edited by M. Mercedes Maroto-Valer 17 Oxy-fuel combustion for power generation and carbon dioxide (CO2) capture Edited by Ligang Zheng
© Woodhead Publishing Limited, 2010
xix
Foreword
In an ideal world, we wouldn’t need carbon capture and storage. But in an ideal world the inhabitants would have been quicker to spot that large-scale burning of fossil fuel could interfere with their planet’s carbon cycle and have serious consequences. By building a world economy over the last 150 years that flourished on the cheap and accessible energy that was available from coal and oil, we short-circuited the natural cycle. We have transferred from the solid Earth to the atmosphere huge quantities of carbon that would not otherwise have seen the light of day for many millions of years. We now know to our cost that the carbon cycle couples into the processes that control the Earth’s climate and that we have triggered rapid climate change. True, the Earth’s climate has always changed, but most natural change has happened sufficiently slowly for plants and animals to migrate or adapt to the new conditions. What we are doing is too fast to allow this. Although fossil fuels are the main cause of the rise in greenhouse gases in the atmosphere, there are also significant contributions from deforestation and changes in land use. Life on Earth depends on the benign greenhouse effect of our atmosphere. It provides surface temperatures that we do not find on neighbouring planets and that allow water to exist as ice, liquid and vapour. By burning fossil fuels, we increase the atmospheric concentration of CO2 which, along with other greenhouse gases, increases the greenhouse effect and increases mean global temperature including in the oceans. The atmospheric consequence of warming the oceans is the same as that of turning up the gas under a pan of gently simmering water – movements become faster and more violent. In weather terms this means more extreme weather conditions – storms, floods, droughts. Continental ice masses, particularly Antarctica and Greenland, begin to melt faster and contribute to a rise in sea level beyond that expected from thermal expansion. None of this is particularly good news and, although it is denied by a few, the evidence for the human influence on observed climate change is overwhelming. The more fossil fuel we burn the greater the rise in atmospheric CO2 and the worse the perturbation of the Earth’s climate. The problem is
© Woodhead Publishing Limited, 2010
xx
Foreword
that virtually all the world energy is supplied by fossil fuels, and weaning ourselves off them will take decades until we make the transition to other energy sources. The best scientific forecasts suggest that massive reductions in emissions have to be achieved by 2050 if there is to be any hope of containing damage to the climate. This is a problem that has been created largely by the developed world which owes its prosperity to the use of cheap and abundant fossil fuel. Although estimates vary, around two thirds of the ‘excess’ atmospheric CO2 is attributable to Europe and the USA. Today, however, we have new players. Developing countries whose economies are growing fast have rising energy requirements and often the cheapest available source of energy is coal, the fuel that carries the heaviest carbon cost per unit energy produced. It is urgent therefore that we find a way of managing emissions while we make the move to a low-carbon economy. The best way of managing emissions is not to produce them in the first place. This means that improved efficiency and energy conservation are vital. However something has to be done about the ‘essential’ (for the moment) emissions that we cannot avoid. These come partly from vehicles that burn liquid fossil fuels and partly from a range of so-called fixed sources such as power stations, cement factories, oil refineries and a myriad of small local sources from office blocks to domestic houses. This is where carbon capture and storage (CCS) comes in. CCS is a group of technologies that are designed to capture and immobilise emissions from the larger fixed industrial sources. This involves separating the greenhouse gases from the other gases in the industrial exhaust streams and transporting them to a suitable site where they can be contained underground for many tens of thousands of years. This may sound relatively straightforward and indeed all the component technologies needed to achieve CCS have to a greater or lesser extent been demonstrated. The problem is that these technologies have their roots elsewhere and were developed with other ends in mind. It is only relatively recently that moves have been made to harness them together to achieve CCS. There is thus enormous scope for improvement of the systems. In reality there are three different sets of technologies required: the technology for separation of greenhouse gases from the exhaust gas stream at the point source, the pipeline or other means needed to transport the separated gas, and finally the technology for storing it. Most current concepts of storage involve pumping the gas underground into geological traps that have the demonstrated ability to retain gases for many tens of thousands of years. Of the three different activities, the first is likely to be the technically most challenging and the most expensive and currently appears likely to amount to between half and two thirds of the total cost of CCS. Overall, electricity generated in coal-fired power plant with its emissions reduced by
© Woodhead Publishing Limited, 2010
Foreword
xxi
90% or more through CCS might be expected to cost between 30 and 50 % more than at present. Although these costs would be very unwelcome in the developed world, they would not be unbearable; in the developing world, however, they would be very difficult to accept. This means that there is an overriding urgency to reduce the cost of CCS. It is to be expected that with time costs will come down as engineers and operators gain experience, but more than slow incremental improvement is needed before CCS becomes deployed worldwide on a scale that can be expected to influence climate change. It would be wrong to assume, however, that the challenges are solely technical. Because CCS is a new activity, a suitable regulatory framework has to be developed and because CCS was never contemplated when the existing wider regulatory framework was established, there will certainly be conflicts to be resolved. The framework will have to cover the legal obligations and rights of all parties and the basis for licensing of all aspects of the operations. Work has already begun on these problems in a number of countries and within the EU. From a business point of view too, there are substantial logistical challenges. All three main elements identified above involve major capital expenditure and have lead times of at least five years. For a reasonably cost-effective system they need to come on line together. Furthermore, they are the responsibility of different consenting authorities for some of which CCS may not be their highest priority. This title addresses a number of the important challenges faced by CCS. They are formidable, but the most important step is to recognize them early and to plan ways of dealing with them. No one should pretend that CCS is a complete answer to the problem of fossil fuels and climate change but, conversely, it is unthinkable that we can manage that problem without CCS. Lord Oxburgh House of Lords Westminster London SW1, UK Email:
[email protected]
© Woodhead Publishing Limited, 2010
xxii
1
Overview of carbon dioxide (CO2) capture and storage technology
S. B o u z a l a k o s and M. M e r c e d e s M a r o t o - V a l e r, University of Nottingham, UK Abstract: Carbon dioxide (CO2) capture and storage (CCS) is considered one of the most promising strategies to reduce CO2 emissions while enabling the continued use of fossil fuels and without compromising the security of electricity supply. This chapter first states the global CO2 emissions from power generation and points out that climate change is a serious and urgent issue. The chapter then discusses carbon management options and puts CCS technology into perspective. An account is then given on current plans to deploy large-scale CCS demonstration projects around the world and obstacles that need to be overcome to achieve the current commercialisation target of 2020. Innovation in research, development and deployment is increasingly becoming an important driver of both the mature and developing CCS technologies. This is clearly perceptible throughout the chapters of this book. The chapter closes by offering an outlook of the future trends and recommendations of sources of further information on CCS. Key words: carbon dioxide, CO2 capture and storage, CCS, climate change, fossil fuels, power generation.
1.1
Introduction
Fossil-fuel derived energy presently dominates most aspects of modern human activities and our current way of life, and is projected to remain the main energy source for the foreseeable future. However, the combustion of fossil fuels in stationary and mobile power sources produces large amounts of greenhouse gas (GHG) emissions, including carbon dioxide (CO2) which accounts for approximately 57 % carbon dioxide-equivalent (CO2-eq) of the GHG emissions from fossil fuel use (IPCC, 2007). CO2-equivalent emission is the amount of CO2 emission that would cause the same time-integrated radiative forcing, over a given time horizon, as an emitted amount of a long-lived GHG or a mixture of GHGs such as, for example, a mixture with methane (CH4) and nitrous oxide (N2O). The equivalent CO2 emission is calculated by multiplying a given emission of GHG by its Global Warming Potential (GWP) for the given time horizon, and for a mix of GHGs the CO2-eq is calculated by summing the equivalent CO2 emissions of each gas. It should be noted that while equivalent CO2 emissions is a standard and useful metric for comparing emissions of different GHGs, it does not imply the same climate change responses (IPCC, 2007). 1 © Woodhead Publishing Limited, 2010
2
Developments and innovation in CCS technology
A recent study by McKinsey & Company (2008) states that approximately 47 % (approximately 2 GtCO2 in 2007) of total European CO2 emissions could be addressed by the application of CO2 capture and storage (CCS) technologies. This includes predominantly large stationary sources, with coal power stations accounting for 52 %. On a global scale, various recent reports estimate that CCS could potentially abate between 1.4 GtCO2 (Stern, 2006) and 4 GtCO2 (IEA, 2007) by 2030. With the increasing energy demand witnessed and projected, already soaring atmospheric CO2 emissions will continue to rise. As CO2 emissions have been unequivocally linked to global warming and climate change (IPCC, 2007), mitigation measures are a matter of urgency. A range of technologies, collectively termed CO2 capture and storage (CCS), have been identified as a critical option in the portfolio of solutions available to combat climate change, allowing for the reduction of CO2 emissions while enabling the continued use of fossil fuels (IPCC, 2005). CCS involves three main steps: capture, transportation and storage. Overall, the technologies are fairly mature and plans are underway for their largescale demonstration in the near future. Technological barriers are often a monetary concern, particularly for capture technologies that account for roughly two-thirds of the total cost of CCS. Given the fact that CCS is a relatively new activity for both power plant operators and governments, a suitable regulatory framework has to be put in place to facilitate the wider deployment of the technology. The development and use of CO2 capture technology could take place within existing regulatory frameworks for power stations; however, the main issues for regulation of CCS concern activities offshore, especially geological storage, and transportation.
1.2
Greenhouse gas emissions and global climate change
The greenhouse effect is necessary to sustain life on earth, and in its absence the average temperature on the planet would be around –18 °C. The major GHGs in terms of total emissions in 2004 were CO2 from fossil fuel use (56.6 % CO2-eq), CO2 from deforestation, decay of biomass, etc. (17.3 % CO2-eq); methane (CH4) (14.3 % CO2-eq); and nitrous oxide (N2O) (7.9 % CO2-eq) (IPCC, 2007). Carbon dioxide is the most important anthropogenic greenhouse gas, even though it is not as harmful as CH4 which is produced from fossil fuel combustion in smaller amounts (IPCC, 2007). Climate scientists have no doubt that the earth’s climate will warm in response to further release of man-made greenhouse gases into the atmosphere by intensifying the greenhouse effect. However, there are uncertainties about the extent of warming that will occur and what the regional impacts of this will be, precisely. To date, the most credible estimation of future climate states
© Woodhead Publishing Limited, 2010
Overview of carbon dioxide (CO2) capture and storage technology
3
comes from mathematical climate models based on physical approximations. Despite uncertainties, all climate models predict substantial climate warming under greenhouse gas increases (IPCC, 2007). Taking into account the range of human activities, power stations are the largest contributor of anthropogenic CO2 emissions with levels reaching approximately 0.17 GtCO2 in the UK in 2008 (BERR, 2009). This level of CO2 emissions is further emphasised by Fig. 1.1, which shows that approximately 29 % of CO2 emissions for 2006 in EU-15 countries were attributed to power generation. According to the International Energy Outlook 2008 (EIA, 2008), the total world energy-related CO2 emissions for 2005 were estimated at 28.1 GtCO2, and are projected to increase by an average of 1.7 % per annum from 2005–2030. Concentrations of atmospheric CO2 have been increasing from approximately 280 ppmv in the pre-industrial era (Fig. 1.2a) to 389.47 ppmv, as measured in April 2009 (Fig. 1.2b). The detrimental effects of increasing CO2 levels on global climate have been well documented, and it is clear that there is a need to reduce CO2 levels (Stocker and Schmittner, 1997; Palmer and Räisänen, 2002; Karl and Trenberth, 2003; Stern, 2006). According to the latest United Nations Intergovernmental Panel on Climate Change (IPCC) report (IPCC, 2007), climate change has been proven to be unequivocally linked to human activity from observations of increases in global average air and ocean temperatures, rising global average sea levels and widespread melting of sea-ice in the Arctic (Fig. 1.3).
Petroleum refining 3 %
Cement production 2 %
Iron and steel production 2 %
Other 8 % Public electricity and heat production 29 %
Commercial/ industrial 5 %
Residential 12 %
Manufacturing industries and construction 16 %
Road transportation 23 %
1.1 EU-15 CO2 emissions by source for 2006 (total emissions = 3.46 GtCO2) (EIA, 2008).
© Woodhead Publishing Limited, 2010
4
320 315
Developments and innovation in CCS technology
310
© Woodhead Publishing Limited, 2010
CO2 concentration (ppmv)
305 300 295 290 285 280 275 270 1000 1060
1120
1180 1240
1300
1360 1420
1480 1540 Year (a)
1600 1660
1720
1780 1840
1900
1960
1.2 (a) Average annual atmospheric CO2 concentrations from Antarctic ice and firn from 1010–1960 (Etheridge et al., 1996) (b) Average annual atmospheric CO2 concentrations based on direct measurements at Mauna Loa Observatory from 1960–2009 (Dr Pieter Tans, NOAA/ESRL, www.esrl.noaa.gov/gmd/ccgg/trends).
395 389.47 ppmv (April 2009)
390 385 380
© Woodhead Publishing Limited, 2010
CO2 concentration (ppmv)
375 370 365 360 355 350 345 340 335 330 325 320 315 310 1960
1965
1970
1975
1980
1985 Year (b)
1990
1995
2000
2005
2010
Overview of carbon dioxide (CO2) capture and storage technology
400
1.2 Continued
5
Developments and innovation in CCS technology
14.5
0.0
14.0
–0.5
13.5
Difference from 1961–1990 (mm)
(°c)
0.5
Temperature (°C)
6
(a)
50 0 –50 –100 –150
(b) 40
0
36
–4
(million km2)
(million km2)
4
32
1850
1900
Year (c)
1950
2000
1.3 Observed changes in (a) global average surface temperature; (b) global average sea level; and (c) Northern Hemisphere snow cover for March–April (IPCC, 2007).
Despite the increasing atmospheric CO2 concentrations mentioned in the previous paragraph, energy-related CO2 intensities, expressed as emissions per unit of economic output (Table 1.1), have been projected to improve (i.e., decline) from 2005–2030 as world economies strive to use energy more efficiently. Carbon dioxide intensity by non-OECD countries is projected to decline by an average of 2.6 % per year, from 529 metric tonnes per million dollars of GDP in 2005 to 274 metric tonnes per million dollars of GDP in 2030. For all OECD countries, average CO2 intensity in 2030 is projected to be 296 metric tonnes per million dollars of GDP. The average for the
© Woodhead Publishing Limited, 2010
Overview of carbon dioxide (CO2) capture and storage technology
7
Table 1.1 Carbon dioxide intensity by region and country, 1980–2030, in metric tonnes per million 2000 US dollars of gross domestic product (GDP) (EIA, 2008) Region History Projections
Average annual percent change
1980 1990 2005 2010 2015 2020 2025 2030 1990– 2005
2005– 2030
OECD United States Canada Mexico Europe Japan South Korea Australia/ New Zealand Non-OECD Europe/Eurasia Russia Other Asia China India Other Middle East Africa Central and South America Brazil Other Total world
732 916 867 394 674 482 942 694
565 701 679 441 508 353 729 679
461 544 607 381 383 358 670 633
411 483 563 337 343 316 580 558
379 439 521 312 318 297 521 500
347 399 486 288 290 284 464 449
319 366 453 266 264 273 424 404
296 339 422 247 241 262 396 365
–1.3 –1.7 –0.7 –1.0 –1.9 0.1 –0.6 –0.5
–1.8 –1.9 –1.4 –1.7 –1.8 –1.2 –2.1 –2.2
694 1019 900 1215 755 1959 295 400 450 398 317
711 1166 1060 1339 624 1242 333 352 854 448 310
529 804 836 762 498 693 287 360 903 421 305
440 615 649 573 411 552 221 313 827 362 290
388 531 554 504 363 478 189 299 747 327 262
344 469 494 440 322 421 165 270 679 292 234
306 410 432 385 289 373 148 246 605 255 209
274 368 392 342 261 334 135 224 539 220 187
–2.0 –2.4 –1.6 –3.7 –1.5 –3.8 –1.0 0.1 0.4 –0.4 –0.1
–2.6 –3.1 –3.0 –3.2 –2.5 –2.9 –3.0 –1.9 –2.0 –2.6 –1.9
212 403
211 219 224 398 379 342
208 303
192 267
175 234
162 205
0.2 –0.3
–1.2 –2.4
716
624 494 427
384
345
311
282
–1.6
–2.2
entire world is projected to fall from 494 metric tonnes per million dollars of GDP in 2005 to 282 metric tonnes in 2030 (EIA, 2008). The United Nations Framework Convention on Climate Change (UNFCCC) in 1994, through which the Kyoto Protocol entered into full force in 2005, commits nations to achieving a: ‘stabilisation of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.’ For instance, the Stern review comments that the worst impacts of climate change could be substantially reduced if greenhouse gas concentrations were to be stabilised between 450 and 550 ppm CO2-eq (Stern, 2006). In November 2008, the UK Climate Change Act became law in the UK, setting up a target of 80 % reduction over 1990 CO2 levels by 2050; making the UK the first country to set such a long-range and significant carbon reduction target into law (DECC, 2009). Further global commitments were discussed at the 15th Conference of the Parties (COP15) under the auspices of the United Nations Framework Convention on Climate
© Woodhead Publishing Limited, 2010
8
Developments and innovation in CCS technology
Change (UNFCCC), in Copenhagen, in December 2009, with the intention to create a legally binding, international treaty to replace the Kyoto Protocol that expires in 2012. Negotiations in the run-up to COP15 showed disagreement on how to tackle climate change and the expectations for a legally binding agreement were lowered (Climatico, 2010). An accord was reached that, although it has significant elements, is not legally binding. The key elements of the accord include the objective to keep the maximum temperature rise to below 2 °C, commitment to list developed countries emission reduction targets and mitigation actions for developing countries, and finance to kick start action in the developing world to fight climate change (http://unfccc. int/meetings/cop_15/items/5257.php). The success of COP15 will depend on the challenge to develop the Copenhagen Accord into a legally binding treaty in 2010 (COP16 in Mexico).
1.3
Carbon management and stabilisation routes
The management of increasing CO2 emissions typically revolves around three broad (but closely related) strategies as possible solutions, namely: (i) switching to a low-carbon economy, i.e., relying on renewable and/ or alternative sources of energy; (ii) increasing the efficiency and energy conservation of our current fossil-fuel energy generation; and (iii) applying CCS technologies to reduce CO2 emissions in order to bridge the gap presented by working to change from our current fossil-fuel dependency to a fully sustainable, low-carbon future. These strategies are discussed in more detail below. Fossil fuels (mainly coal) account for approximately 86 % of the overall world energy use (IEA, 2007; Orr, Jr, 2009), and are foreseen to remain the dominant energy source for the largest part of the 21st century (McKinsey & Company, 2008). Although there is significant concern about the increasing amount of CO2 that will be emitted (Bachu, 2008b; IPCC, 2007, 2005), alternative or renewable energy sources still have fundamental hurdles to overcome. For instance, there are many security and environmental issues still associated with nuclear energy generation, while on the other hand wind, solar, water, wave and geothermal power cannot currently provide sufficient amounts of base-load electricity generation to displace fossil-fuel power. Many of these technologies also rely on the availability of resources, which depends on the geographical location and attributes of a country (Martinot et al., 2007). Furthermore, the use of biomass leaves open the question of the correct technology to be implemented if heavy energy demand is to be met. Hydrogen is likely to be an important energy-carrier in the future (Edwards et al., 2008), but it requires reliable and high-capacity production that is independent of the decarbonisation of fossil fuels, as well as improved storage technologies, to achieve this role in a sustainable future.
© Woodhead Publishing Limited, 2010
Overview of carbon dioxide (CO2) capture and storage technology
9
For the time being, the reduction of CO2 emissions can be achieved by implementing efficient energy strategies. Innovative technologies for power generation, such as Integrated Gasification Combined Cycle (IGCC), may increase the efficiency of conversion of the fuel’s chemical energy from 28–32 % of the recent past to 52 %. Supercritical and ultra-supercritical coalfired power plant technology may also offer a major option for high-efficiency and low-emission power generation, with efficiency projected in the region of 50 % and approximately 30 % projected CO2 emissions reduction. Fuel flexibility can also contribute to the reduction of emissions. For instance, moving from coal to oil to liquefied natural gas (LNG), the amount of CO2 emitted per kWh goes down from 1 to 0.75 to 0.5 kg, respectively. However, even with increased efficiency and reduction in emissions, the rapid expansion of the worldwide demand for energy will ultimately produce a net increase in CO2 emissions. A net reduction in emissions would require a rigorous carbon management strategy to be applied worldwide. CO2 capture and storage (CCS) is a technically feasible strategy to reduce anthropogenic CO2 emissions from large point sources, and particularly fossil fuel-fired power plants, by up to 90 % (IPCC, 2005). One of the key features of this technology is that it allows for the continued use of fossil fuels, including coal which is relatively cheap and abundant, while simultaneously reducing CO2 emissions to the atmosphere (IRGC, 2008). Overall, CCS consists of three main steps: separating and capturing CO2 from other exhaust gases; compressing the CO2 to supercritical conditions in order to transport it to its storage location; and final isolation from the atmosphere by a variety of methods as illustrated in Fig. 1.4. The carbon mitigation potential of the different strategies mentioned above requires a fixed timeframe. For instance, Pacala and Socolow (2004) propose that a 50-year perspective could be long enough to allow changes in infrastructure and consumption patterns but short enough to be heavily influenced by decisions made today. Assuming the world continues on its current predicted path, i.e., business as usual (BAU), it is predicted that CO2 emissions will roughly double by 2054. Stabilising GHG concentrations in the region of 500 ± 50 ppm has been proposed as the target level to prevent the most damaging climate change. Avoiding the doubling of CO2 levels in the business as usual case, in order to reduce substantially the likelihood of the most dramatic consequences of climate change, would require a monumental effort. Committing to a CO2 emissions trajectory approximating a flat path requires an amount of CO2 emissions reduction in 2054 roughly equal to all CO2 emissions today (Fig. 1.5). To assess the potential of the various carbon mitigation strategies, Pacala and Socolow (2004) introduced the concept of stabilisation wedges (Fig. 1.5). The difference between currently predicted path and flat path from present to 2054 gives a triangle of emissions to be avoided, a total of nearly 200
© Woodhead Publishing Limited, 2010
10
Biomass
Cement/steel/ refineries, etc.
Gas Natural gas + CO2 capture
Oil
Mineral carbonation
Coal
CO2
Petrochemical plants + CO2 capture Future H2 use
Electricity generation
Industrial uses
Ocean storage (ship or pipeline)
1.4 Schematic diagram of possible CCS systems showing the sources for which CCS might be relevant, transport of CO 2 and storage options (IPCC, 2005).
Developments and innovation in CCS technology
© Woodhead Publishing Limited, 2010
Gas to domestic supply
Overview of carbon dioxide (CO2) capture and storage technology
Billions of tonnes of carbon emitted per year
14
11
7 wedges
C
re ur
nt
ly
pr
ed
ic
d te
pa
are needed to build the stabilisation triangle
th
Stabilisation triangle 1 wedge 1 ‘wedge’
7
Flat path 2004
Year
avoids 1 billion tonnes of carbon emissions per 2054 year by 2054
1.5 Stabilisation wedges concept for reducing carbon emissions by 2054 (Socolow et al., 2004).
GtC. The stabilisation triangle can be further divided into seven wedges of equal area each representing a reduction of 1 GtC/year by 2054. This is based on technologies that have the potential to contribute a full wedge to carbon mitigation. CCS technology prevents about 90 % of fossil carbon from reaching the atmosphere, so a wedge would be provided by the installation of CCS at 800 GW of base-load coal plants by 2054 or 1600 GW of baseload natural gas plants.
1.4
Development and innovation in carbon dioxide (CO2) capture and transport technology
Although many of the component technologies for CCS are fairly mature, there are no, as yet, fully integrated commercial applications (Fig. 1.6). There are, however, a number of pilot-scale CCS projects around the world demonstrating confidence in the technology (Table 1.2). The UK government launched a competition in 2007 to build one of the first commercial-scale CCS projects by 2014 (BERR, 2008; APGTF, 2009). As can be seen in Table 1.2, other world governments and energy corporations are focusing on similar incentives to facilitate widespread deployment of CCS technologies in the near future. A programme of 10–12 demonstrations has also been called for in the EU to be operational by 2015, in line with the target of commercialisation of CCS by 2020 (APGTF, 2009). China, which is overtaking the USA in CO2 emissions (approximately 6.0 GtCO2 in comparison to the 5.9 GtCO2 by the USA in 2006) from consumption and flaring of fossil fuels (EIA, 2008), is making significant
© Woodhead Publishing Limited, 2010
Concept
12
Stage of development Lab testing
Commercial refinements needed
© Woodhead Publishing Limited, 2010
First projects are coming online now
Commercial
Component technologies are mature; integrated platform to be proven
Several projects are operational (e.g., Weyburn (Canada)). EU has limited EOR potential
Post-combustion Membranes Chemical looping
Oxyfuel
CO2– EGR
Pre-combustion
Saline aquifers
Sleipner (Norway) field has been operational for around 10 years
Depleted oil and gas fields
Have been used for seasonal gas storage for decades
CO2–EOR Transport Transport offshore onshore
USA has existing CO2 pipeline network of more than 5000 km Capture Transport Storage
1.6 Stage of CCS component technologies (EGR = enhanced gas recovery) (McKinsey & Company, 2008).
Developments and innovation in CCS technology
Potential future breakthrough technologies
Demonstration
© Woodhead Publishing Limited, 2010
Project name
Location
Leader
Feedstock
Size (MW)
Capture process
CO2 fate
Start-up
Total Lacq Schwarze Pumpe AEP Alstom Mountaineer Callide-A Oxy Fuel GreenGen Williston Kimberlina NZEC AEP Alstom Northeastern Sargas Husnes Scottish & Southern Energy Ferrybridge Naturkraft Kårstø Fort Nelson ZeroGen Antelope Valley WA Parish UAE Project Appalachian Power Wallula Energy Resource Centre RWE npower Tilbury Tenaska HECA UK CCS Project Statoil Mongstad RWE Zero CO2 Boundary Dam Monash Energy
France Germany USA Australia China USA USA China USA Norway UK
Total Vattenfall AEP CS Energy GreenGen PCOR CES UK & China AEP Sargas SSE
Oil Coal Coal Coal Coal Coal Coal Coal Coal Coal Coal
35 30/300/1000 30 30 250/800 450 50 TBD 200 400 500
Oxy Oxy Post Oxy Pre Post Oxy TBD Post Post Post
Seq Seq/EOR Seq Seq Seq EOR Seq Seq EOR EOR Seq
2008 2008 2008 2009 2009 2009–15 2010 2010 2011 2011 2011–12
Norway Canada Australia USA USA UAE USA USA
Naturkraft PCOR ZeroGen Basin Electric NRG Energy Masdar AEP Wallula Energy
Gas Gas Coal Coal Coal Gas Coal Coal
420 Gas process 100 120 125 420 629 600–700
Post Pre Pre Post Post Pre Pre Pre
TBD Brine res Seq EOR EOR EOR TBD Seq
2011–12 2011 2012 2012 2012 2012 2012 2013
UK USA USA UK Norway Germany Canada Australia
RWE Tenaska HEI TBD Statoil RWE SaskPower Monash
Coal Coal Petcoke Coal Gas Coal Coal Coal
1600 600 390 300–400 630 CHP 450 100 60 k bpd
Post Post Post Post Post Pre Oxy Pre
Seq EOR EOR Seq Seq Seq EOR Seq
2013 2014 2014 2014 2014 2015 2015 2016
13
Notes: Seq = sequestration; EOR = enhanced oil recovery; TBD = to be decided; Brine res = brine reservoir; Gas process = gas processing; Pre = pre-combustion; Post = post-combustion; Oxy = oxyfuel combustion.
Overview of carbon dioxide (CO2) capture and storage technology
Table 1.2 Global CO2 capture and storage projects (MIT, 2008)
14
Developments and innovation in CCS technology
progress in CCS projects. GreenGen is a partnership between the Chinese government, Chinese energy companies and Peabody energy. It is planned to deploy incrementally to a 400 MW IGCC power plant with CCS by 2020. Near Zero Emission Coal (NZEC) is another CCS project between China and the European Union, and has the goal of deploying a coal-fuelled power plant with CCS by 2020. The Australian government in April 2009 formally launched the Global Carbon Capture and Storage Institute (GCCSI), a new initiative aimed at accelerating the worldwide commercial deployment of CCS technologies. The G8 countries have committed to the development of 20 large-scale CCS projects to be operational by 2020, with the GCCSI playing a vital role in developing the partnerships to make these projects a reality. The Department of Energy (DOE) in the USA has formed a nationwide network of Regional Carbon Sequestration Partnerships (RCSP) to help determine the best approaches for capturing and storing GHG. The RCSP initiative is currently in the development phase (2008–2017) to conduct large-volume carbon storage tests.
1.4.1 Carbon dioxide (CO2) capture and storage economics, regulation and planning A major difficulty in deploying CCS technology is the reluctance of corporations to invest given the absence of financial cost associated with greenhouse gas emissions, uncertainty over the future regulations governing coal-burning power plants and CO2 storage, and the need for additional research, development and demonstration (Gibbins and Chalmers, 2008). The absence of governmental regulations and policy frameworks creates additional uncertainty for companies considering investment in CCS (Bachu, 2008b). Volume 1, Chapter 3, deConinck, provides a regulatory analysis and outlook for CCS technologies. Commercial-scale CCS deployment will require a regime to manage risks as well as supporting policies to facilitate technology investment (IRGC, 2008). Public perception and support are also vital for actual implementation of CCS technologies. The main concerns society has over CCS are related to safety issues and the extent to which CCS provides a solution to climate change (Gough and Shackley, 2005; van Alphen et al., 2007). Estimating the cost of CCS technologies involves a high degree of uncertainty over how these costs may develop over time and in terms of potential variations in the technical requirements, scale and application of projects. McKinsey & Company (2008) have recently released a report in which CCS costs are predicted, based on a case-study approach. According to the main findings of the report, early commercial CCS projects, potentially around 2020, are estimated to cost 735–50 per tonne CO2 abated (Fig. 1.7). By far, CO2 capture is the most expensive component and may account for
© Woodhead Publishing Limited, 2010
Overview of carbon dioxide (CO2) capture and storage technology
15
Assumption
1 Capture
2 Transport
25–32
4–6
∑ CO2 capture rate of 90–92 % ∑ CCS efficiency penalty of 7–12 % points ∑ Same utilisation as non-CCS plant (86 %) ∑ CO2 compression at capture site ∑ Transport through onshore/offshore pipeline network of 200/300 km in supercritical state with no intermediate booster station ∑ Use of carbon steel (assumed sufficiently dry CO2) ∑ Injection depth of 1500 m in supercritical state 4–12 ∑ Use of carbon steel (assumed sufficiently dry CO2) ∑ Vertical well for onshore/directional for offshore
3 Storage
35–50*
Total *Ranges are rounded to 5 on totals.
1.7 Total cost of early commercial projects – reference case (7/tonne CO2 abated; ranges include on- and offshore) (McKinsey & Company, 2008).
up to two-thirds of the total cost of a CCS project (725–32 per tonne CO2 abated). Further information on economic analyses of CCS technologies is provided in Vol. 1, Chapter 2, Ogden, and further information on planning and economic modelling for CO2 capture and reduction is provided in Vol. 1, Chapter 4, Elkamel, Mirzaesmaeeli, Croiset and Douglas.
1.4.2 Carbon dioxide (CO2) capture processes and technologies in power plants There are three main technologies for carbon capture from fossil fuel power plants: ∑ after combustion (post-combustion); ∑ decarbonisation of the fuel before combustion (pre-combustion); and, ∑ burning the fuel in pure oxygen (oxyfuel combustion). Post- and pre-combustion processes include chemical and physical capture of CO2 by absorption (Vol. 1, Chapter 5, Desideri) and adsorption (Vol. 1, Chapter 6, Davidson), as well as CO2 separation by membranes (Vol. 1, Chapter 7, Basile, Gallucci, Morrone and Iulianelli) and gasification of fuels syngas/hydrogen for combustion and CO2 for capture (Vol. 1, Chapter 8, Higman). Under oxyfuel combustion conditions, fuel is burnt in pure oxygen rather than air, resulting in more complete combustion and producing a flue gas constituting approximately 90 % CO2 for easier separation (oxyfuel
© Woodhead Publishing Limited, 2010
16
Developments and innovation in CCS technology
combustion) (Vol. 1, Chapter 9, Mathieu). Advanced oxygen separation and generation systems (Vol. 1, Chapter 10, Kluiters, van den Brink and Haije), and chemical looping combustion systems (Vol. 1, Chapter 11, Anthony) are also being developed as promising alternatives to the more common post- and pre-combustion capture processes.
1.4.3 Carbon dioxide (CO2) compression, transport and injection processes and technologies Transport of pressurised supercritical CO2 from the point of capture to storage sites through an extensive pipeline network is considered to be the most cost-effective and reliable method for onshore CCS (Svensson et al., 2004). Although there may be a risk associated with potential leakage through infrastructure failure or third-party intrusion, there is a lot of experience from the petroleum industry in the USA and Canada in the transport of natural gas, hydrocarbon liquids and CO2 for enhanced oil recovery (EOR) that could be applicable to CO2 transport for CCS. Nevertheless, long-distance CO2 pipeline networks, both onshore and offshore, have technical challenges (e.g., safety and reliability) that need to be faced in order to minimise risks to the environment and human health. Further innovation is focused on pipeline materials, infrastructure and modelling studies to minimise the risk of failure and to yield a better understanding of the consequences and behaviour of a pipeline failure (Mazzoldi et al., 2008). Theses issues and further details on the various compression, transport and injection technologies applicable to CCS systems are respectively discussed in Vol. 1, Chapter 12, Aspelund; Chapter 13, Downie, Race and Seevam; and, Chapter 14, Solomon and Flach.
1.4.4 Industrial applications of carbon dioxide (CO2) capture and storage technologies Wider implementation of CCS is being encouraged in other industries responsible for significant contribution to global CO2 emissions, e.g., the cement and concrete industry (Vol. 1, Chapter 15, Ghoshal and Zeman), and the iron and steel industry (Vol. 1, Chapter 16, Birat). It is estimated that the cement industry is responsible for approximately 5 % of global CO2 emissions (IPCC, 2005). The reduction of CO2 emissions from cement production is currently being addressed by looking into post-combustion and oxygen combustion capture, and using the CO2 for accelerated curing of concrete products and cement-based waste stabilisation/solidification. The iron and steel industry is also responsible for another 6–7 % of global CO2 emissions (IPCC, 2005). Strategies to control CO2 emissions have focused on energy conservation measures. However, further development and incorporation of CCS systems need to be adopted to further reduce CO2 © Woodhead Publishing Limited, 2010
Overview of carbon dioxide (CO2) capture and storage technology
17
emissions. This involves post- and pre-combustion capture processes in the core of the blast furnace, with the potential of retrofitting existing steel mills from the 2020s onwards. New technologies may also be developed with CCS, and possibly without relying on CCS, through the use of hydrogen, electricity or biomass.
1.5
Development and innovation in carbon dioxide (CO2) storage and utilisation technology
1.5.1 Geological sequestration of carbon dioxide (CO2) Various options are possible for final storage of CO2. At present, injection into underground geological formations is the most promising and developed method (Holloway, 2005; IPCC, 2005; Bachu, 2008a,b), although these formations naturally need to be characterised and screened to ensure longterm sequestration (Vol. 2, Chapter 2, Bachu). There are three main types of proposed underground storage site: deep saline aquifers (Vol. 2, Chapter 3, Rosenbauer and Thomas); depleted oil/gas reservoirs and enhanced oil recovery (EOR) (Vol. 2, Chapter 4, Kovscek and Vega); and deep unmineable coal seams (Vol. 2, Chapter 5, Mazzotti, Pini, Storti and Burlini). Geological storage combines a number of engineering processes to ensure safe and long-term isolation of CO2 from the atmosphere. Deep saline aquifers are likely to be the most promising of other geological options, but there is still uncertainty regarding their capacity and geological/geochemical properties. To address the issue, innovative research is being focused to better understand the geochemical reactions between CO2, impurity gases, formation brine, host rocks and cap rocks. Depleted oil and gas reservoirs are frequently said to be the likely first category of geological formation to inject CO2 owing largely to the added benefit of EOR. It is estimated that 80 % of oil reservoirs worldwide might be suitable for CO2 injection for EOR. Enhanced Coal Bed Methane (ECBM) recovery is a technique under investigation for storing CO2 in unmineable coal seams with the added benefit of methane production.
1.5.2 Maximising and verifying carbon dioxide (CO2) storage in underground reservoirs Petrographical studies and the established body of knowledge concerning CO2 storage/migration mechanisms in geological media from the oil industry, combine to improve our understanding of the CO2 injection design approaches that can be adopted to maximise CO2 storage and/or EOR in underground reservoirs (Vol. 2, Chapter 6, Blunt, Qi and LaForce). Similarly, improved methods of sealing underground reservoirs for CO2 trapping have been
© Woodhead Publishing Limited, 2010
18
Developments and innovation in CCS technology
informed by our understanding of gas leakage mechanisms from geological media (Vol. 2, Chapter 7, Meckel). Improved measurement, monitoring and verification (MMV) (Vol. 2, Chapter 8, Chadwick) and modelling (Vol. 2, Chapter 9, Pruess, Birkholzer and Zhou) techniques are being developed to verify storage and to prove long-term storage security. The environmental impact and safety of CO2 storage is constantly being developed to quantify risk, and better understand and minimise potential leakage of CO2 into freshwater aquifers or back into the atmosphere.
1.5.3 Terrestrial and ocean sequestration of carbon dioxide (CO2) and environmental impacts Another option for CO2 storage is terrestrial sequestration which, along with CO2 emissions reduction, has such ancillary benefits as increased agronomic productivity through CO2 use by plants (Vol. 2, Chapter 10, Lal). While CO2 sequestration has been noted to present benefits to terrestrial ecosystems, up to a point, there remain risks of CO2 leakage from underground reservoirs, and increased levels of CO2 present greater impacts and risks, including the potential for phytotoxicity whereby affected plant species will no longer grow (Vol. 2, Chapter 12, Steven, Smith and Colls). Injection into the deep ocean has also been proposed (Vol. 2, Chapter 11, Golomb and Pennell) but is associated with many more risks to marine ecosystems (including risks of CO2 leakage from subsea reservoirs) that have not yet been adequately researched (Vol. 2, Chapter 13, Blackford, Widdicombe, Lowe and Chen).
1.5.4 Advanced concepts for carbon dioxide (CO2) storage and utilisation Alternative, less conventional, routes for CO2 storage and utilisation are receiving increased attention, including CO2 utilisation by industry, mineralisation/mineral carbonation, biofixation of CO2 by microorganisms and photocatalytic reduction of CO2. The majority of these technologies are still in the research phase, apart from mineralisation/mineral carbonation which is almost ready for pilot-scale demonstration within the next few years. The technological barriers that usually render the process financially non-viable are where further innovation and breakthroughs are needed if these technologies are to have any chance of being integrated into the CCS agenda in the near future. Industrial fixation in inorganic carbonates (mineral carbonation) could have an increasingly important role in future CCS operations, particularly if waste materials are put to use (Vol. 2, Chapter 16, Zevenhoven and
© Woodhead Publishing Limited, 2010
Overview of carbon dioxide (CO2) capture and storage technology
19
Fagerlund). Some industrial processes might also utilise and store small amounts of captured CO2 in manufactured products (Vol. 2, Chapter 14, Aresta and Dibenedetto). In biofixation of CO2, microorganisms use CO2 for cell growth, which can be achieved both in natural habitats as well as in controlled systems such as microalgal farming, while the potential for CO2 conversion to biofuels by microorganisms is also undergoing further research (Vol. 2, Chapter 15, Wang and Lan). The future development of photocatalytic reduction processes for CO2 presents the potential for a similar benefit through the conversion of CO2 to hydrocarbons using artificial light or sunlight, in a process similar to photosynthesis (Vol. 2, Chapter 17, Wu).
1.6
Future trends
As previously mentioned in this chapter, it is highly likely that coal and other fossil fuels will dominate worldwide power generation for the foreseeable future. In order to maintain current standards of living with the ever increasing demand for energy, CCS must play a vital role in reducing CO2 emissions to the atmosphere to mitigate the potential for further global warming and climate change until a low-carbon economy can be fully implemented. At present, however, CCS cannot justify itself on an economic basis alone owing to the high energy penalty and associated costs of installation, and it may remain unprofitable until policy issues are decided and technologies further developed. More research, development and deployment is clearly necessary to make CCS more realistic (in terms of economic costs) to occur on a large scale. Industries are increasingly focusing their attention on CCS technologies, with a large number of pilot-scale projects currently operational and many more being planned to begin within the next five years. International collaboration is now considered a key element in delivering CCS commercialisation targets. It is anticipated that CCS will be demonstrated on a large scale by around 2012, and by the 2020s there will be some tens of CCS plants and some hundreds by the 2030s around the world. Although in comparison to the total number of fossil-fuel fired power stations, these figures are quite low, these developments can be regarded as significant progress towards implementing effective global warming mitigation measures. Legal and regulatory frameworks are underway and are planned to be enforced from about 2010–2012; these will help to justify more robust investment decisions and to minimise barriers for deployment in the near future. For example, the European Commission has recently proposed a Directive on CCS (EC, 2008) to enable environmentally-safe capture and geological storage of CO2 in the EU as part of a major legislative package of measures to achieve the EU’s emissions targets, mitigate the potential effects of climate change and promote renewable energy up to 2020 and beyond.
© Woodhead Publishing Limited, 2010
20
Developments and innovation in CCS technology
Although this Directive provides a regulatory framework specifically for geological storage, additionally, CO2 capture is regulated under Commission Directive 96/61/EC concerning integrated pollution prevention and control (IPPC) and Commission Directive 85/337/EEC on the effects of certain public and private projects on the environment. The market for CCS is huge, and by about 2020 CCS should have the potential to develop into a significant and competitive option to simultaneously reduce CO2 emissions and promote economic development, energy security and air quality in many countries for decades to come. Compared to a business-as-usual case, CCS could reduce energy-related CO2 emissions by up to a half by 2050. This largely relies on the commercial value of carbon exceeding the cost of CCS technologies and eventually on other incentives for implementation. CCS could also present increased revenue opportunities in the future, particularly where CO2 can be sold to nearby oil field operators for EOR. Other future industrial applications are likely to develop, and business opportunities may include managing CCS applications for hydrogen production, fuel cell applications, emission trading and CO2 storage (WEC, 2007).
1.7
Sources of further information and advice
There is now a plethora of sources for information on CCS. This includes a range of reports, articles published in academic journals, international symposia, research organisations/institutions, professional bodies, popular science books, and the World Wide Web. The ones mentioned below are by no means exhaustive, but merely indicative of the variety available to anyone interested in this field. Each chapter of the book provides additional sources of information. Probably one of the most well-known publications on CCS is the Special Report by the IPCC in 2005. This was the first major reporting of a consortium of leading professionals in the form of an intergovernmental scientific body presenting the urgency to act upon the global warming phenomenon and the role of CCS. This was followed by another renowned publication, The Stern Review (Stern, 2006), on the economics of climate change. Two recent books presenting a holistic account of CCS technologies are available by Wilson and Gerard (2007) and Shackley and Gough (2006). An earlier account on the science and technology of CO2 mitigation is available by Halmann and Steinberg (1999). Marini (2007), Baines and Worden (2004) and Wanty and Seal II (2004) provide extensive information on geological sequestration of CO2. A series of reports are available from many leading professional and research organisations/institutions and government bodies/departments. Some recent examples are mentioned below and other reports have been previously
© Woodhead Publishing Limited, 2010
Overview of carbon dioxide (CO2) capture and storage technology
21
referenced in this chapter. The World Resources Institute (WRI) has released a publication providing guidelines for CO2 capture, transportation and storage (WRI, 2008). McKinsey & Company (2008) address the economics of CCS and predict the cost of CCS technologies in their early days of commercialisation. The International Energy Agency Greenhouse Gas Programme (IEA GHG) holds a large collection of technical reports on CCS and it is advisable to check their website for further information (www.ieagreen.org.uk). The Energy Information Administration (EIA) produces annual international energy outlook reports (EIA, 2008) providing vital information on global energy trends and predictions to 2030. Finally, the UK Advanced Power Generation Technology Forum (APGTF) produced an excellent document in April 2009 providing guidance and advice on research, development and deployment needs of carbon abatement technologies (CATs) for fossil fuels (APGTF, 2009). Academic peer-reviewed articles on CCS are becoming increasingly popular in many journal publications. Elsevier launched a journal in 2008 (International Journal on Greenhouse Gas Control) specifically targeting papers on CCS and related topics, and it has been well received by the scientific community. The Carbon Capture Journal is another recent magazine that aims to inform on developments in CCS and related government policy. Other journals popular amongst researchers include: Energy Conversion & Management (Elsevier); Fuel Processing Technology (Elsevier); Fuel (Elsevier); Energy Policy (Elsevier); Environmental Science & Technology (American Chemical Society); Energy & Fuels (American Chemical Society); Energy & Environmental Science (Royal Society of Chemistry) and Proceedings of ICE – Energy (Institution of Civil Engineers). Several symposia are available to exchange ideas and present the state of the art on research and developments in CCS. The bi-annual International Greenhouse Gas Technologies conference (GHGT) is probably the main venue attracting thousands of delegates. Other well-known venues include the Annual Conference on Carbon Capture and Sequestration (USA); the Platts Annual European Carbon Capture and Storage Conference; and the International Conference on Carbon Dioxide Utilisation (ICCDU). The above mentioned events are dedicated to CCS; however, there are many more conferences in related fields that cover themes on CCS. The main organisations/institutions and centres involved with CCS research and development include the: Centre for Innovation in Carbon Capture and Storage (CICCS) (UK); Scottish Centre for Carbon Storage (UK); UK Energy Research Centre (UKERC); British Geological Survey (BGS); Energy Technologies Institute (ETI) (UK); Princeton University Carbon Mitigation Initiative (USA); Columbia University Earth Engineering Centre (USA); Stanford University Global Climate & Energy Project (USA); US Geological Survey (USGS); Lawrence Berkeley National Laboratory (USA); Los Alamos
© Woodhead Publishing Limited, 2010
22
Developments and innovation in CCS technology
National Laboratory (USA); National Energy Technologies Laboratory (USA); Global CCS Institute (Australia); CO2 Cooperative Research Centre (CO2CRC) (Australia); Australian Commonwealth Scientific and Research Organisation (CSIRO); CO2NET; Carbon Sequestration Leadership Forum (CSLF); Research Institute of Innovative Technology for the Earth (RITE) (Japan); Bureau de Recherches Géologiques et Minières (BRGM) (France); SINTEF (Norway); Canadian Geological Survey; and Bellona (Norway/ Russia).
1.8
Acknowledgements
The financial support of the Centre for Innovation in Carbon Capture and Storage (CICCS, EP/F012098/1) is gratefully acknowledged by the authors.
1.9
References
APGTF (2009) Cleaner Fossil Power Generation in the 21st Century: A Technology Strategy for Carbon Capture and Storage. UK Advanced Power Generation Technology Forum (APGTF), April. Bachu S (2008a) CO2 storage in geological media: Role, means, status and barriers to deployment. Progress in Energy and Combustion Science, 34: 254–273. Bachu S (2008b) Legal and regulatory challenges in the implementation of CO2 geological storage: an Alberta and Canadian perspective. International Journal of Greenhouse Gas Control, 2: 259–273. Baines SJ and Worden RH (2004) Geological Storage of Carbon Dioxide. Special Publication 233, Geological Society, London, UK. BERR (2008) Towards Carbon Capture and Storage: A Consultation Document. Department for Business, Enterprise & Regulatory Reform (BERR), London, UK. BERR (2009) Energy Trends. Department of Energy and Climate Change, London, UK. Climatico (2010) Copenhagen De-briefing, An analysis of COP15 for long-term cooperation, available at: http://www.climaticoanalysis.org/post/copenhagen-de-briefing-an-analysisof-cop15-for-long-term-cooperation/ (accessed January 2010). DECC (2009) Climate Change Act 2008: Impact Assessment. Department of Energy and Climate Change (DECC), London, UK. Edwards PP, Kuznetsov VL, David WIF and Brandon NP (2008) Hydrogen and fuel cells: towards a sustainable energy future. Energy Policy, 36(12): 4356–4362. EC (2008) COM (2008) 18 final, Proposal for a Directive of the European Parliament and of the Council on the geological storage of carbon dioxide and amending Council Directives 85/337/EEC, 96/61/EC, Directives 2000/60/EC, 2001/80/EC, 2004/35/EC, 2006/12/EC and Regulation (EC) No 1013/2006. Brussels, 23.1.2008. EIA (2008) International Energy Outlook 2008. Energy Information Administration (EIA), US Department of Energy (DOE), DOE/EIA-0404(2008), Washington, DC. Etheridge DM, Steele LP, Langenfields RL, Francey RJ, Barnola J-M and Morgan VI (1996) Natural and anthropogenic changes in atmospheric CO2 over the last 1000
© Woodhead Publishing Limited, 2010
Overview of carbon dioxide (CO2) capture and storage technology
23
years from air in Antarctic ice and firn. Journal of Geophysical Research, 101(D2): 4115–4128. Gibbins J and Chalmers H (2008) Carbon capture and storage. Energy Policy, 36: 4317–4322. Gough C and Shackley S (2005) An Integrated Assessment of Carbon Dioxide Capture and Storage in the UK. Technical Report 47, Tyndall Centre for Climate Change Research, Manchester, UK. Halmann MM and Steinberg M (1999) Greenhouse Gas Carbon Dioxide Mitigation: Science and Technology. CRC Press, Boca Raton, FL. Holloway S (2005) Underground sequestration of carbon dioxide – a viable greenhouse gas mitigation option. Energy, 30: 2318–2333. IEA (2007) World Energy Outlook 2007. International Energy Agency, OECD/IEA, Paris, France. IPCC (2005) IPCC Special Report on Carbon Dioxide Capture and Storage, Working Group III of the Intergovernmental Panel on Climate Change, Metz B, Davidson O, de Coninck HC, Loos M and Meyer L A (eds), Cambridge University Press, Cambridge, UK. IPCC (2007) Climate Change 2007: Mitigation, Contribution of Working Group III to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change, Metz B, Davidson O R, Bosch P R, Dave R, Meyer L A (eds), Cambridge University Press, Cambridge, UK. IRGC (2008) Policy Brief: Regulation of Carbon Capture and Storage. International Risk Governance Council (IRGC), Geneva, Switzerland. Karl TR and Trenberth KE (2003) Modern global climate change. Science, 302: 1719–1723. Marini L (2007) Geological Sequestration of Carbon Dioxide: Thermodynamics, Kinetics and Reaction Path Modelling. Elsevier, Amsterdam, the Netherlands. Martinot E, Dienst C, Weiliang L and Qimin C (2007) Renewable energy futures: Targets, scenarios and pathways. Annual Review of Environment and Resources, 32: 205–239. Mazzoldi A, Hill T and Colls JJ (2008) CO2 transportation for carbon capture and storage: Sublimation of carbon dioxide from a dry ice bank. International Journal of Greenhouse Gas Control, 2: 210–218. McKinsey & Company (2008) Carbon Capture and Storage: Assessing the Economics. McKinsey & Company, available at: http://www.mckinsey.com/clientservice/ccsi/pdf/ CCS_Assessing_the_Economics.pdf (accessed December, 2009). MIT (2008) Carbon capture and storage projects. Massachusetts Institute of Technology, Cambridge, MA, available at: http://sequestration.mit.edu/tools/projects/index.html (accessed December 2009). Orr Jr, FM (2009) CO2 capture and storage: are we ready? Energy & Environmental Science, 2: 449–458. Pacala S and Socolow R (2004) Stabilisation wedges: Solving the climate problem for the next 50 years with current technology. Science, 305: 968–972. Palmer TN and Räisänen J (2002) Quantifying the risk of extreme seasonal precipitation events in a changing climate. Nature, 415(6871): 512–514. Shackley S and Gough C (2006) Carbon Capture and its Storage: An Integrated Assessment. Ashgate Publishing, Aldershot, UK. Socolow R, Hotinski R, Greenblatt JB and Pacala S (2004) Solving the climate problem: technologies available to curb CO2 emissions. Environment, 46(10): 8–19.
© Woodhead Publishing Limited, 2010
24
Developments and innovation in CCS technology
Stern N (2006) The economics of climate change: The Stern review. Cambridge University Press, Cambridge, UK. Stocker TF and Schmittner A (1997) Influence of CO2 emission rates on the stability of the thermohaline circulation. Nature, 388(6645): 862–865. Svensson R, Odenberger M, Johnsson F and Strömberg L (2004) Transportation systems for CO2 – application to carbon capture and storage. Energy Conservation and Management, 45: 2343–2353. van Alphen K, van Voorst tot Voorst Q, Hekkert M and Smits REHM (2007) Societal acceptance of carbon capture and storage technologies. Energy Policy, 35: 4368– 4380. Wanty RB and Seal II RR (2004) Water–Rock Interaction: Proceedings of the Eleventh International Symposium on Water–Rock Interaction, WRI-11, Taylor & Francis, London, UK. WEC (2007) Carbon Capture and Storage: A WEC “Interim Balance”. World Energy Council (WEC) Clean Fossil Fuels Systems Committee. Wilson EJ and Gerard D (2007) Carbon Capture and Sequestration: Integrating Technology, Monitoring and Regulation. Wiley-Blackwell, Oxford, UK. WRI (2008) CCS Guidelines: Guidelines for Carbon Dioxide Capture, Transportation and Storage. World Resource Institute (WRI), Washington, DC.
© Woodhead Publishing Limited, 2010
2
Screening and selection criteria, and characterisation techniques for the geological sequestration of carbon dioxide (CO2) S. B a c h u, Alberta Innovates – Technology Futures, Canada Abstract: Potential sites for the geological sequestration of CO2 must be subject to a systematic screening process. The chapter covers fundamental site selection criteria (capacity and injectivity; safety and reliability; compatibility with other energy, mineral and water resources; regulatory and other societal requirements), site characterisation (geology; hydrogeological, pressure and geothermal regimes; land features; location, climate and access) as well as future planning (predicting the fate and effects of the injected CO2; site design, permitting, operating, monitoring and eventual abandonment). Estimates of storage capacity are critical to the site selection and characterisation process, and these are based on volumetric evaluations. Key words: CO2 storage, site selection, site characterisation, storage capacity, coal beds, hydrocarbon reservoirs, deep saline aquifers.
2.1
Introduction
Three storage media have been identified that have the potential to sequester carbon dioxide (CO2) in the short-to-medium term: uneconomic coal beds, oil and gas reservoirs and deep saline aquifers (IEA, 2004; Benson et al., 2005). Of these, CO2 storage in uneconomic coal beds has been identified as: (i) being an immature technology and (ii) having the smallest storage potential (Benson et al., 2005). Oil reservoirs possess, at depletion, smaller storage capacity than gas reservoirs or deep saline aquifers; however, they present the advantage that, if suitable for CO2 enhanced oil recovery (CO2–EOR), their storage capacity will increase and the cost of storage will decrease by producing additional oil. Gas reservoirs have significant CO2 storage capacity because of their very large recovery factor (between 80 and 90 %) and large size. However, it is believed that deep saline aquifers possess the largest CO2 storage capacity, besides having the advantage that they are present also in regions where there are no oil and gas reservoirs or where oil and gas reservoirs are still in production and are not yet available for CO2 storage. Along the various elements of the CO2 capture and storage (CCS) chain, site selection and characterisation is of critical importance because any 27 © Woodhead Publishing Limited, 2010
28
Developments and innovation in CCS technology
storage site must demonstrate that it can store the intended amount of CO2 at the rate that it is supplied to the site without posing any unacceptable risks. As identified in the IPCC Special Report on CCS (Benson et al., 2005), for sites that are properly selected, designed and operated, the expectation is that there will be no leakage or that, if there is leakage, it will be below an acceptable level from both the point of view of atmospheric greenhouse gas emissions and from a health, safety and environmental (HSE) point of view. Regulatory agencies, which will permit CO2 storage in geological media, and the public, which has to accept and support CCS as a climate-change mitigation strategy, need to be convinced that proposed CO2 storage sites meet these requirements, and this can be achieved only through a proper and transparent process of site selection and characterisation. Site screening is the process by which the potential for CO2 storage in a selected region, defined either by geology (e.g., sedimentary basin), jurisdiction (e.g., country, province or state) or any other criterion, is evaluated by assessing and comparing possible candidate storage sites. The aim is to identify the sites that meet CO2 storage requirements. Ranking of these sites according to various criteria allows identification of the best sites with respect to that set of criteria, enabling investment decisions into further site characterisation. Sites for CO 2 storage vary around the globe in their quality and characteristics, and there will be instances where sites of poorer quality will be used for storage because no other sites are available or because other sites are too far away and/or much more costly to develop and operate. However, use of poorer-quality storage sites means that additional measures may have to be taken, particularly with regard to ensuring their safety, in order to obtain regulatory approval. For this reason, it is important to be able to judge the quality of a storage site based on an established and accepted set of criteria. This chapter will present criteria by which prospective sites should be assessed in terms of their suitability for CO2 storage and ranked for site selection, together with methodology for estimating their storage capacity.
2.2
Screening for storage suitability and site selection
2.2.1 Selection of sites for carbon dioxide (CO2) storage Currently there is very little practical experience worldwide with the selection and characterisation of sites for the injection/disposal of buoyant fluids. Fifteen criteria for assessing and ranking sedimentary basins in terms of their suitability for CO2 storage were successively introduced by Bachu in a series of papers (Bachu and Gunter, 1999; Bachu, 2000, 2001, 2002, 2003), criteria that can be broadly divided into the following categories: 1. basin characteristics (e.g., size and depth);
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
29
2. tectonic and geological; 3. hydrogeological and geothermal; 4. basin resources and industry maturity, i.e., the presence or absence of various media suitable for CO2 storage (oil and gas reservoirs, coal beds, salt domes and/or beds) and the degree of exploration and production associated with hydrocarbon resources; 5. CO 2 sources, accessibility and infrastructure, including climatic conditions; 6. economic, political and societal factors. In addition to these basin-scale criteria, Bachu (2003) introduced local-scale selection criteria such as: caprock integrity including well penetrations, in situ conditions, fate of the injected CO2, long-term site integrity and safety and local public acceptance. Building on previous work by Bachu (2003) and the Carbon Sequestration Leadership Forum (Bachu et al., 2007; CSLF, 2007), Kaldi and Gibson-Poole (2008) produced a similar system for screening of sedimentary basins for CO2 storage at the country scale, adding two more selection criteria: ‘Reservoir-seal pairs’ which refers to secondary geological barriers to upward CO2 flow, and ‘Coal rank’, which refers to the type and quality of coal for CO2 storage in coal seams. The IPCC Special Report on CO2 Capture and Storage (Benson et al., 2005) has reviewed the status of knowledge up to and including 2005 publications on this subject. Ideally, sites should be located in a stable geological environment thus avoiding potential compromising of the site in the future, but it is recognised that the fundamental storage criteria may be met also by sites in a less stable tectonic environment. Matching of CO2 sources with potential sinks is an important criterion for site selection, since potential sinks that are too far from CO2 sources will be stranded and will not be utilised due to the high cost of transportation. In 2008, the European Union produced a Best Practice Manual for Storage of CO2 in Saline Aquifers (Chadwick et al., 2008), building on the European experience gained between 1998 and 2006 through the SACS, SACS2 and CO2STORE projects in Europe. The authors compiled a table of positive (favourable) and cautionary (less favourable) qualitative indicators regarding reservoir and caprock properties to be used in the assessment of prospective CO2 storage sites. In the case of the five sites examined in the SACS and CO2STORE projects, various screening/selection criteria were used, such as size (capacity), injectivity, depth, structural enclosure, aquifer thickness, porosity, caprock quality, distance from the CO2 source, potential conflict with other industries (mainly hydrocarbon production) and land use, right of access and population density (for onshore sites). Societal risks associated with CO2 storage were also examined and used as a screening tool, including HSE risks, economic risks and risks related to public perception and trust.
© Woodhead Publishing Limited, 2010
30
Developments and innovation in CCS technology
Oldenburg (2008) presented a screening and ranking framework based on the potential for and effects of leakage from a CO2 storage site by evaluating three main characteristics: (i) the potential for primary containment of the CO2 within the target unit; (ii) the potential for secondary containment between the target unit and the shallow subsurface in case CO2 containment in the primary storage unit fails; and (iii) the potential for attenuation of the leaked CO2 in the shallow subsurface and at surface, in case CO2 leaks past secondary containment. Ramírez et al. (2009) presented a system for screening storage options in the Netherlands that was developed based on the opinion of a large group of international experts. Preliminary results show that aquifers have an average risk (mainly because of lack of detailed information and because seal capacity is not proven), and that storage in aquifers entails a higher cost than hydrocarbon reservoirs because of lack of infrastructure. Wilkinson et al. (2009) introduced three key priorities for storage site selection, design, construction and operations: (i) Safety, Health and Environment (SHE), which involves protection of personnel and the environment; (ii) Efficiency, which is defined by storing the greatest amount of CO2 in the minimum amount of pore space at the lowest unit cost; and (iii) Reliability, which is an operational concept and refers to maximising uptime and minimising downtime of the storage operation when CO2 storage will have to cease. In a series of two papers, Kopp et al. (2009a,b) have examined through dimensional analysis and numerical simulations the effect of parameters such as depth, temperature, absolute and relative permeability and capillary pressure on storage capacity in aquifers. Relative permeability exerts a great influence on storage capacity through both irreducible CO2 and brine saturations, and the shape of the relative permeability curves. Furthermore, storage capacity and injectivity are not completely independent of each other because both depend on permeability and mobility. Basically, higher storage capacity is achieved for lower injectivity. This counter-intuitive result is due to the fact that, in a homogeneous environment, poorer sweep efficiency is attained for higher permeability/injectivity, hence less pore space will be reached and less residual gas trapping and less dissolution will occur. The work to date suggests that screening for site selection is a two-stage process, by which the first assessment is performed at the basin and/or regional scale, and the more detailed selection is performed at the local and/ or site-specific scale. Basin and regional scale screening The criteria developed by Bachu (2003) with improvements by IPCC (Benson et al., 2005) and Kaldi and Gibson-Poole (2008) form the basis of site screening at these scales. Table 2.1 presents a set of eliminatory criteria, i.e.,
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
31
Table 2.1 Eliminatory suitability criteria for assessing sedimentary basins for CO 2 geological storage
Criterion
Not suitable
Suitable
1 Depth Less than 1000 m
Greater than 1000 m, with storage units deeper than 800 m
2 Reservoir-seal pairs Poor and stratigraphic sequences
Intermediate and excellent At least one major extensive, regional-scale competent seal
3 Pressure regime
Over-pressured
Hydrostatic or sub-hydrostatic
4 Seismicity (basin tectonic setting)
High and very high (subduction zones; syn-rift and strike- slip basins)
Very low to moderate (foreland, passive margin and cratonic basins)
5 Faulting and fracturing Extensive intensity
Limited to moderate
6 Surface areal extent
Less than 2500 km2
Greater than 2500 km2
7 Hydrogeology
Shallow, short flow systems, or compaction flow
Intermediate and regionalscale flow systems; topography and erosional flow
8 ‘Legal’ accessibility
Forbidden
Possible
a sedimentary basin or region that does not pass these criteria should not be considered for CO2 storage. The first three criteria (depth, seal and pressure regime) are critical criteria, in the sense that a basin or part thereof that does not satisfy all of these suitability criteria should automatically be deemed as being not suitable for CO2 storage because of the high risk of compromising the safety and security of storage. The next four criteria (seismicity, faulting and fracturing, size and hydrogeology) are essential criteria in the sense that there may be special cases, which have to be thoroughly documented and justified, where, if one of these criteria is not being met but all the others are, such a basin may still be considered for CO2 storage. Examples would be small intramontane basin with a single large CO2 source (e.g., a pulp mill) and with no other options for storage, such as in the Canadian Rocky Mountains, or sedimentary basins in California (an active tectonic zone) where hydrocarbon reservoirs are present. However, if more than one of the essential suitability criteria is not being met, then that basin or region should not be considered for CO2 storage. Finally, the last criterion (Legal Accessibility) is also a critical criterion (i.e., it is eliminatory by itself) but, unlike the others, it is not a physical characteristic of the basin but rather a designation resulting from a legislative or regulatory act that may change in the future. Examples are certain offshore North American basins where drilling and exploration are not permitted at this time.
© Woodhead Publishing Limited, 2010
32
Developments and innovation in CCS technology
Other suitability criteria for CO2 storage, listed in Table 2.2, fall in the desirable category. The first four criteria (1–4) refer to general CO2 storage characteristics of the basin. Storage sites within fold belts are less desirable because of faulting. However, there may be cases where storage sites may be found in the fold belts of mountain ranges, similarly to the very large gas reservoirs found in the thrust and fold belt of the Canadian Rocky Mountain foothills. Diagenetic processes usually lead to loss of porosity (hence of storage space) and permeability (hence of injectivity). Warm basins have lower storage efficacy and the stored CO2 is subject to stronger buoyancy forces because of lower CO2 density. Salt beds have the advantage that they form strong barriers to upward CO2 flow, and both salt domes and beds may offer the opportunity of CO2 storage in salt caverns. The next five criteria (5–9) refer to the potential for storage in specific media. Hydrocarbon potential and industry maturity refer to the potential for CO2 storage in oil and gas reservoirs, while the presence or absence of coal seams, their rank and their economic value refer to the potential for CO2 storage in coal beds. The next four criteria (10–13) are proxies for the economics of CO2 storage. Costs are higher deep offshore, in harsh climate conditions (e.g., in the Arctic), in places that are difficult to access (again, Table 2.2 Desirable characteristics of sedimentary basins or parts thereof suitable for CO2 storage
Criterion
Undesirable
1 Within fold belts Yes 2 Significant Present diagenesis 3 Geothermal Warm basin (gradients regime > 40 °C/km and/or high surface temperature) 4 Evaporites (salt) Absent 5 Hydrocarbon Absent or small potential 6 Industry maturity Immature 7 Coal seams Absent, very shallow or very deep (< 400 m or > 800 m depth) 8 Coal rank Lignite or anthracite 9 Coal value Economic 10 On/off shore Deep offshore 11 Climate Harsh 12 Accessibility Inaccessible or difficult 13 Infrastructure Absent or rudimentary 14 CO2 sources within Absent economic distance
Desirable No Absent Cold and moderate basins (gradients < 40 °C/km and low surface temperature) Domes and beds Medium to giant Mature At intermediate depth (400–800 m) Sub-bituminous and/or bituminous Uneconomic Shallow offshore and/or onshore Moderate Good Developed Present
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
33
Arctic, or intramontane basins, etc.) where infrastructure is lacking and has to be built or the terrain is difficult (e.g., in or across mountain ranges). The last criterion is also a proxy for economics, but the economic distance may change with developments in pipeline technology and construction, in shipping technology or with the construction of new CO2 sources. None of these criteria is eliminatory by itself, and it could be that a basin or region thereof may have several unfavourable characteristics and still be considered for CO2 storage. On the other hand, if too many criteria are unfavourable, then serious consideration should be given as to whether to proceed with CO2 geological storage in that basin or part thereof. Generally, Table 2.2 can be used to asses if a sedimentary basin has poor or good potential for CO2 storage before proceeding with storage capacity estimations and site selection. A basin or part thereof that meets most of the desirable criteria has good potential, while the reverse is true for basins or regions with poor CO2 storage potential. Local and site scale screening A storage site must pass the criteria for identification of sedimentary basins suitable for CO2 storage (Table 2.1), should posses desirable (or favourable) characteristics (Table 2.2) and must meet additional screening criteria that are specific and can be applied only at these scales. Local-scale site selection criteria can be grouped into the following broad categories: 1. capacity and injectivity, which is similar to capacity and deliverability in natural gas storage; 2. confinement, including avoidance or minimisation of risks to other resources, equity and life, as well as return of CO2 to the atmosphere; 3. legal and regulatory restrictions, including access; 4. economic, including costs, infrastructure, financing, etc., 5. societal attitudes. Although in the past capacity and injectivity were considered as separate criteria for site selection, more recent work indicates that they are not completely independent of each other, at least not during the active period of injection. Because of the link between them, they are considered hence as a single criterion. There is a significant difference between the first and the second criteria listed above. These criteria should be simultaneously met. However, if capacity and/or injectivity are less than those initially desired or estimated, operational adjustments can be made (e.g., storing less CO2 or injecting at a lower rate, with the balance of CO2 being diverted to another site, or just storing a smaller volume than that emitted). On the other hand, lack of confinement would automatically exclude a site from consideration. Also, the first criterion applies to the active period of CO2 injection, which
© Woodhead Publishing Limited, 2010
34
Developments and innovation in CCS technology
is in the order of decades, while the second one applies to a much longer period, up to three orders of magnitude longer than the injection period. Failure to properly assess site capacity and/or injectivity can and will be identified during the operational (injection) period, and, in the case that any of them is lacking, measures can immediately be taken, such as increasing well injectivity, drilling additional injection wells or moving to another site if there is insufficient capacity. Meeting the second criterion must be demonstrated prior to injection, based on site knowledge and predictions of the fate and effects of the injected CO2. Lack of confinement, with corresponding CO2 migration and/or leakage,1 may occur much later (years to centuries) after cessation of injection, in which case different remedial measures have to be taken that no longer affect the selection and operation of the site. Many other detailed site selection criteria derive from these two. Some of the screening criteria are outright eliminatory, such as unacceptable risk of leakage, or strong public opposition or lack of access. Some may be applicable at a particular moment in time, but may change in the future, e.g., economics of operation, or regulatory requirements or availability in the case of a hydrocarbon reservoir that is still producing. Very few of the site selection criteria listed below are eliminatory by themselves but, if a prospective storage site has too many unfavourable characteristics, then serious consideration should be given to rejecting it. The following are eliminatory criteria, i.e., sites falling in any of the following categories should generally be eliminated from further consideration. In discussing these criteria, one should be aware of the three-dimensionality of the problem, the storage unit being located at a certain depth in the subsurface but requiring land access at surface. These eliminatory criteria can be grouped into three broad categories: (i) lack of legal and/or physical access; (ii) potentially affecting other resources whose production and/ or utilisation has primacy over CO2 storage; and (iii) lacking security and safety. 1. Legally inaccessible. This is the case of potential sites located in protected or reserved areas, such as national parks, protected natural reserves, military areas and regions where drilling and exploration are prohibited (e.g., offshore in certain US and Canadian waters). 2. Legally unreachable. This is the case of sites for which right of access cannot be obtained for various reasons (mostly land access). In some 1
For clarification, migration in this context is defined as the lateral movement of a plume of injected CO2 within the same geological unit, e.g., aquifer, but out of the storage site as legally defined through the tenure and permitting process, while leakage is defined as cross-formational flow of CO2 out of the storage unit into overlying strata and possibly to shallow groundwater, soil and/or the atmosphere.
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
3.
4.
5. 6.
7.
8.
9.
35
jurisdictions, there are regulatory bodies that may decide and grant right of access for the greater public good. Legally unavailable. This would be the case of a prospective site, such as a hydrocarbon reservoir, in which there are third party equity interests that make the site unavailable for CO2 storage. Future legislation may deal with this situation through unitisation, like in the case of flooded oil reservoirs. Or it could be the case of a subsurface property owner, like in the case of freeholders in Canada, or land owners in the USA, who refuse access to/use of the subsurface storage site itself. Physically unavailable. This would be the case of a hydrocarbon reservoir still in production, and possibly of an aquifer used for mineral or geothermal energy production, unavailable for CO2 storage within the time period of interest. Located within high-density population areas. Sites located in areas of high population density should not be considered because of very likely public opposition. Potentially affecting other natural, energy and mineral resources and equity. Sites where CO2 storage may affect directly or indirectly other resources and/or equity should not be considered for CO2 storage. There will be cases when the interested parties may reach compensatory agreements, but generally such sites should be considered only as a last resort. Within the depth of protected groundwater. Sites at depths encompassed by the designation of protected groundwater should not be considered for CO2 storage, regardless of actual physical depth that may in some cases be greater than the recommended 800 m. Protected groundwater is defined as groundwater with salinity less than a certain threshold, which varies between 4000 and 10 000 ppm depending on jurisdiction. With increasing needs for water and increasing reliance on groundwater, probably groundwater with salinity less than 10 000 ppm should be protected for human, agricultural and industrial use. Located at shallow depth. Generally a depth of minimum 800 m has been considered as necessary for CO2 storage to maximize storage efficacy (amount of CO2 stored per unit of pore volume). Although this is not a ‘hard’ threshold, in the sense that some sites could be at a shallower depth, particularly depleted hydrocarbon reservoirs, the congruence of this and other criteria such as groundwater protection, and the general acceptance of this threshold depth, makes this an eliminatory criterion. Lacking at least one major, extensive, competent barrier to upward CO2 migration. This relates to the requirement of security and safety of storage, i.e., containment within the primary storage unit. A highly fractured region, with fractures reaching to the surface, will also fall into this category.
© Woodhead Publishing Limited, 2010
36
Developments and innovation in CCS technology
10. Located in an area of very high seismicity. This also relates to the security and safety of storage. 11. Located in overpressured strata. The risks of leakage and/or well blowout are higher in overpressured strata (approaching lithostatic) than in normally-pressured and sub-hydrostatic aquifers and/or reservoirs. 12. Lacking monitoring potential. Since it is assumed that regulatory requirements for site permitting, operation and abandonment will include monitoring of the fate and effects of the injected CO2, sites where monitoring is not possible or very poor most likely will not be approved, and hence should be avoided. This would be the case where an aquifer or reservoir is too thin or with low porosity such that the CO2 plume is not discernible on seismic, nor are wells available for monitoring. The last criterion does not fall specifically in any of the three broad categories mentioned initially; however, it may and likely will lead to the rejection of a proposed site. While the previous criteria were of an eliminatory nature (i.e., a site either passes all these criteria or is rejected), the following criteria are selection criteria in the sense that these are favourable characteristics that would make a site preferable to another, all other considerations being equal. Failure to meet a particular criterion will not eliminate a site, it will only reduce its ‘desirability’ or suitability. 1. Sufficient capacity and injectivity. It is desirable to have sufficient capacity for storing emissions at the supply rate for the entire period of time but, depending on economics and the expansion of the pipeline network for CO2 collection and distribution, smaller-capacity sites may be considered. It is very important to assess not just the ‘static’ storage capacity according to accepted methodology and guidelines and based on ultimately-available pore volume (e.g., see Bachu et al., 2007), but also the ‘dynamic’ storage capacity, i.e., the storage capacity that can be achieved during the active lifetime of the project by injecting CO2 at rates and pressures that meet safety and regulatory requirements (Birkholzer and Zhou, 2009; Mathias et al., 2009). This refers to maintaining maximum bottomhole injection pressure at injection wells and aquifer or reservoir pressure below any, or a combination, of: ∑ a fraction of the rock fracturing threshold (usually established by regulation, e.g., 90 % in Alberta and 75 % in British Columbia, Canada); ∑ fracture and/or fault opening pressure (for pre-existing fractures and faults); ∑ caprock fracturing pressure; ∑ caprock displacement pressure (the pressure at which the injected
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
37
CO2 intrudes into the caprock, related to capillary pressure and interfacial tension of the CO2/brine system at in situ conditions); ∑ initial reservoir pressure (in the case of storage in hydrocarbon reservoirs). It is important to note that the caprock displacement pressure may in some cases limit the injection pressure more significantly than the other geomechanical criteria like fault reactivation and fracturing threshold. This is because the interfacial tension (IFT) of water/CO2 systems is about half of water/CH4 systems (water/gas) (Li et al., 2006); thus capillary breakthrough may occur in systems that held natural gas for geological periods of time (e.g., in some cases of depleted gas reservoirs that are pressurised with CO2 back to the initial reservoir pressure). Furthermore, if the injected stream of CO2 contains impurities such as H2S, the capillary breakthrough pressure will be even lower because the IFT of H2S/water systems is lower than that of CO2/water systems by a factor of 2–3, and the IFT of systems containing CO2–H2S mixtures and water is proportional to the CO2 (or H2S) mole fraction in the injection stream (Shah et al., 2008). The dynamic storage capacity is most likely significantly less than the static storage capacity, and can be evaluated only through numerical modelling (simulation) of injection, including various injection strategies such as (i) increasing the number of injection wells, (ii) using directional and horizontal wells and (iii) pumping aquifer water while injecting CO2. Unacceptable pressure increases identified through modelling studies could render a potential site unable to store the intended volume (van der Meer and Egberts, 2008; Ghaderi et al., 2009), leading to its rejection or to changes in overall storage strategies (e.g., use of several sites instead of just one). Relative permeability affects the pressure buildup in an aquifer, hence the pressure-induced risk during the active phase of CO2 injection (Oruganti and Bryant, 2009). 2. Sufficient thickness. Thick aquifers or reservoirs are preferable to thin ones, not just because of assumed higher storage capacity but also because they allow various injection strategies (e.g., injection at the bottom and letting the plume of CO2 rise), can be assumed to lead to areally smaller plumes of CO2, increase CO2 dissolution through larger area of contact between CO2 and aquifer water, increase CO2 residual-gas trapping through exposing more pore volume to CO2, and increase the potential for monitoring of plume evolution using geophysical methods. A minimum thickness of 20 m is recommended. 3. Low temperature (as defined by low geothermal gradients and/or low surface temperatures). This increases storage efficacy by ensuring higher CO2 density, hence higher storage capacity for the same pore volume. It also increases storage security by decreasing the buoyancy force acting on CO2. © Woodhead Publishing Limited, 2010
38
Developments and innovation in CCS technology
4. Favourable hydrodynamic regime. Aquifers with long-range, regional-scale flow systems are preferable to those with intermediate or short systems because the former will allow a much longer travel time during which the injected CO2 will dissolve and/or be immobilised by residual-gas trapping. 5. Low number (density) of wells penetrating the storage area of influence. The presence of wells increases the potential for, and hence the risk of, leakage. The presence of wells constitutes a conundrum for the following reasons. A larger number of wells results in a better characterised storage unit, a greater degree of confidence in the assessment, and a better potential for monitoring through fluid sampling and/or seismic measurement. On the other hand, the potential for leakage increases with increasing number of wells. It is very important to have a clear understanding of what constitutes the area of influence. Injecting CO2 in a reservoir or aquifer has two effects: introduction of an immiscible buoyant fluid that will spread and migrate for a certain distance until immobilisation, and increasing reservoir or aquifer pressure which will propagate significantly faster and beyond the distance of the CO2 plume itself (Birkholzer and Zhou, 2009). This pressure wave may affect other resources and may induce brine leakage in wells and/or fractures that otherwise will not be reached by CO2. In this respect, the presence of wells and their potential for leakage should be considered for the area of influence as defined by pressure increase and not by CO2 reach. 6. Presence of a multilayered overlying system of aquifers/reservoirs and aquitards/caprock. This increases the safety and security of storage (secondary containment in case of leakage), and is particularly important in the case of sites with a significant number of well penetrations (e.g., see Nordbotten et al., 2005, 2008). 7. Potential for attenuation of leaked CO2 near and at surface (in shallow groundwater, soil and atmospheric). Sites with characteristics more favourable for CO2 attenuation and dispersion near and at surface as a result of topographic, climatic and/or vegetation conditions should be preferred to sites where CO2 will have a tendency to stagnate and accumulate. 8. Site accessibility and infrastructure. This affects the cost/economics of transportation to the storage site. This criterion includes any combination of location (onshore/offshore), distance from source, terrain and climate difficulty, right of access (e.g., pipeline corridors) and avoidance of populated or reserved areas that have to be bypassed. 9 Storage economics. This includes the cost of site facilities, wells and compression, and affects the cost/economics of the entire CO2 capture and storage operation.
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
39
Porosity, permeability and depth have been suggested in the past to be site selection criteria, but they should not explicitly be. Porosity and permeability are indirectly included in the criterion of capacity and injectivity. Depth is indirectly included in the criteria of groundwater protection and storage economics. Water salinity was also suggested by some to be a selection criterion, but it is implicitly taken into account by the criterion of groundwater and mineral resource protection. It could be seen that the first three site selection criteria refer to the efficacy of storage (capacity and injectivity), the next four criteria refer to the safety and security of storage, and the last two refer, in aggregate, to the cost and economics of storage. With regard to the latter category, conditions may change as infrastructure and technology develop, and as regulations and economic conditions change.
2.2.2 Carbon dioxide (CO2) storage in depleted hydrocarbon reservoirs and in enhanced oil or gas recovery Carbon dioxide can be stored in hydrocarbon reservoirs after abandonment (at depletion), or can be stored while hydrocarbons are still being produced, during enhanced recovery operations. The latter option provides the advantage that some of the CCS costs will be offset or, most likely, an economic profit will be realised, as a result of incremental oil production. Although 800 m is considered as the minimum depth for CO2 storage because of the high density of supercritical CO2, shallower hydrocarbon reservoirs should not be rejected a priori if they meet the requirements of capacity, confinement, risk minimisation and societal acceptance (injectivity has been demonstrated by producing the oil and/or gas). An important additional screening/selection criterion for oil and gas reservoirs is time of availability (i.e., time of depletion and abandonment2). Since these reservoirs are producing, they may not be available for CO2 storage within the desired time frame, thus being eliminated from consideration. The existence or absence of strong aquifer support is also an important factor in the selection of oil or gas reservoirs for CO2 storage because, in the case of strong support, aquifer water will invade the reservoir as oil and/or gas is being produced, thus reducing the reservoir storage capacity and also increasing its pressure (Bachu and Shaw, 2003). Similarly, oil reservoirs that have been water flooded (secondary recovery) and solvent or gas flooded (tertiary recovery) should not be considered for CO2 storage because the pore space is filled with 2
It should be noted here that reservoir depletion and abandonment are relative terms, dictated as much by geology and engineering as by economic conditions.
© Woodhead Publishing Limited, 2010
40
Developments and innovation in CCS technology
water and/or gas/solvent, and the pressure is most likely close to the initial reservoir pressure. Finally, reservoir size, expressed either by an estimate of CO2 storage capacity or by recoverable oil (or gas) in place (ROIP), which is given by the product of recovery factor (Rf) and original oil in place (OOIP), should be used as a screening criterion because it is uneconomic to develop the necessary transportation and storage infrastructure for reservoirs that do not have the required capacity. Carbon dioxide retention in oil or gas reservoirs during enhanced recovery represents a special case of CO2 storage. In these cases, sites must meet an additional set of criteria very specific to the respective process of enhanced oil or gas recovery. Use of CO2 in enhanced gas recovery has not been practised to date, and it is questionable because gas reservoirs have a high recovery factor (greater than 80 %) and because, at the low reservoir pressures attained at this stage of production, CO2 will expand quickly in the reservoir and will be produced together with the remaining gas (e.g., Pooladi-Darvish et al., 2008), hence necessitating additional separating facilities and recirculating the produced CO2. Thus, CO2 will most likely be stored in gas reservoirs after abandonment (depletion). The situation is different for oil reservoirs, which most often have much lower recovery factors (less than 30 %) and for which the value of the incremental oil produced justifies the additional costs of enhanced recovery (including CO2 separation). Holtz (2009) indicates that real-time CO2 trapping within oil reservoirs occurs as a mobile phase, residual phase and dissolved in the oil phase. Long-term trapping is achieved by dissolution of CO2 in the water phase and through mineral precipitation. Furthermore, Holtz (2009) identifies five successful gas displacement recovery processes where CO2 may be used: 1. miscible displacement; 2. immiscible displacement; 3. pressure maintenance, particularly for gas condensate reservoirs or oil reservoirs with a gas cap; 4. gas assisted gravity drainage, which usually results in the lowest water and oil saturations and highest saturation for stored CO2; 5. mixed gas EOR (e.g., mixtures of CO 2 , N 2 , solvents and light hydrocarbons). Not all oil reservoirs are suitable for CO2–EOR; thus, additional criteria must be applied for the identification and selection of oil reservoirs for CO2 flooding, notwithstanding the economics of such operations. This is because most CO2–EOR operations are based on the miscibility between oil and CO2, and their phase behaviour. Based on the experience with CO2–EOR in the USA, a series of authors have identified several criteria, reviewed in Shaw and Bachu (2002), for the identification of oil reservoirs technically suitable for CO2–EOR. Based on the previous analyses and on the characteristics of
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
41
more than 100 existing CO2–EOR operations in North America at the end of 2007 (Moritis, 2008), the criteria presented in Table 2.3 could be used for identifying oil reservoirs suitable for miscible CO2–EOR (the immiscible operations are too few to draw meaningful conclusions). These criteria refer only to miscible CO2–EOR, and not to the other gas displacement processes identified by Holtz (2009). In addition, reservoir pressure at the beginning of the CO2–EOR operation should be above the minimum miscibility pressure (MMP), i.e., the pressure at which CO2 and oil become miscible. The MMP depends on oil gravity and a few other characteristics, and is usually determined in the laboratory on a case-by-case basis, but it is always above CO2 critical pressure. In the absence of specific laboratory data, particularly when screening a large number of oil reservoirs, an empirical relationship can be applied to estimate MMP on the basis of the molecular weight of the C5+ components in reservoir oil and reservoir temperature (Núñez-López et al., 2008). The condition that reservoir pressure should be greater than the MMP for miscibility, while at the same time it should be less than the fracturing pressure Pf, implicitly introduces a screening criterion that MMP should be less than Pf. Bachu and Shaw (2005) have used an additional criterion for selecting oil reservoirs for CO2–EOR and CO2 storage, namely that of storage capacity greater than 1 Mt CO2 (which is a proxy for economics). Núñez-López et al. (2008) have developed similar methodology, based on the same principles, for screening of oil reservoirs suitable for CO2–EOR and estimating their incremental oil recovery and corresponding CO2 storage capacity, and have applied it to oil reservoirs along the US Gulf Coast, except that they start from reservoir size as the first screening criterion and consider only reservoirs with a cumulative production greater than 1 million standard barrels (MMstb). This approach eliminates from the beginning small reservoirs while avoiding using estimates of CO2 storage capacity, which are uncertain, as a screening criterion. While these additional criteria are suitable for Gulf Coast reservoirs Table 2.3 Suggested characteristics of oil reservoirs suitable for miscible CO2–EOR (metric values are given in brackets) Reservoir parameter
Miscible CO2–EOR
Size (ROIP in MMstb; or MtCO2) Depth (ft/m) Temperature (°F/°C) Pressure Porosity (%) Permeability (mD) Oil gravity (API) Oil viscosity (cP/mPa·s) Remaining oil fraction in the reservoir
≥ 1 (whichever condition is met first) > 2000 (> 610) 82–250 (28–121) > MMP and < Pf ≥3 ≥5 27–45 <6 ≥ 0.30
© Woodhead Publishing Limited, 2010
42
Developments and innovation in CCS technology
in the USA that have been in production for a long time, they are not suitable for other producing regions in the world because they would eliminate from consideration reservoirs that are in an initial stage of production or that are not yet at the stage of immediate CO2–EOR application but that would be amenable to CO2–EOR at some time in the future. Instead of cumulative oil production, a more suitable criterion indicative of reservoir size would be the ROIP. Thus, either the ROIP or a rough estimate of CO2 storage capacity should be used as a screening criterion for oil reservoirs suitable for CO2–EOR.
2.2.3 Carbon dioxide (CO2) storage in uneconomic coal beds Due to the different nature of the storage medium and of the trapping mechanism, CO2 storage in coal beds poses different specific screening and selection requirements than storage in deep saline aquifers or hydrocarbon reservoirs. The basic requirements of capacity, injectivity, confinement, risk minimisation and societal acceptance still apply, but the application of these criteria is different. Because coal represents an energy resource with a present and potentially future economic value, either for mining or for in situ gasification, only uneconomic coal beds should be considered for CO2 storage. Unfortunately, currently there are no clear and accepted definitions of uneconomic coal beds, and these will likely change in time with changing economic conditions, and also will vary from jurisdiction to jurisdiction and from place to place. Coal economic value can be determined based on geological characteristics such as thickness, depth of burial and number of seams and will use present day standards of technology and economic profitability (Bachu et al., 2007; USDOE, 2008). Therefore, mineable deposits will include shallow coals that can be mined in open-pit operations and deeper thick coal beds that can be mined underground. Thin coals at intermediate depths most likely won’t be economic and can be safely considered as uneconomic. As an example, coals in the Illinois Basin in the USA are not considered for possible CO2 storage if they are shallow (< 500 ft, i.e., < 152 m) regardless of thickness, or deep (> 1000 ft, i.e., 305 m) and of a certain thickness (> 1.5 ft, i.e., 0.52 m) (Frailey et al., 2006). At intermediate depths (500–1000 ft, i.e.152–305 m), only coals less than 3.5 ft (1.1 m) and greater than 1.5 ft (0.52 m) in thickness were considered as potential targets for CO2 storage. Another consideration with regard to CO2 storage in coal beds is that the process of adsorption applies to CO2 in gaseous phase, i.e., at depths for which temperature is less than 31 °C and pressure is less than 7.38 MPa (738 m hydrostatic column). Storage of supercritical CO2 is less understood currently and it is not clear if no free phase CO2 will exist in the coal. Another
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
43
limiting factor in regard to CO2 storage in coal beds is the fact that shallow groundwater resources should be protected, and these extend sometimes at depths of several hundred meters, thus eliminating from consideration shallower coals. Because coal swells in the presence of CO2, with the net effect of reducing permeability by approximately one order of magnitude, coals need to have permeability of at least 1 mD and higher in order to ensure injectivity. In light of the fact that coal permeability decreases with increasing depth as a result of increasing effective stress, the requirement of adequate permeability has the net result of restricting the depth of coals that can be used for CO2 storage at no more than approximately 1000 m. Between the requirements of adequate permeability, protection of groundwater resources and protection of coal as an energy resource, not too much coal is left for CO2 storage. Finally, CO2 storage in coal beds requires an extensive infrastructure comprising a high density of injection wells with the associated CO2 distribution pipeline system, and an equally high density of producing wells and gathering pipelines for the coalbed methane that will be produced as a result of CO2 storage. Since methane is also a greenhouse gas, actually stronger than CO2, it has to be captured and used. The existence and/or costs of such an infrastructure will certainly put CO2 storage in coal beds at a disadvantage in comparison to CO2 storage in deep saline aquifers and hydrocarbon reservoirs.
2.3
Site characterisation
Site characterisation is basically the process by which data, information and knowledge are acquired and processed to provide satisfactory answers to the question: does the site meet the site selection criteria? A more detailed definition is provided by Cook (2006) as: ‘the collection, analysis and interpretation of subsurface, surface and atmospheric data (geoscientific, spatial, engineering, social, economic, environmental) and application of that knowledge to judge, with a degree of confidence, if an identified site will geologically store a specific amount of CO2 for a defined period of time and meet all required health, safety, environmental and regulatory standards’. Site characterisation both predates and follows site selection. Sites should be sufficiently characterised initially to be able to judge them on the basis of site selection criteria and, once selected, further characterisation is needed to demonstrate site performance, including monitoring. Performance predictions are based on numerical simulations of injection and of the various processes that take place in the storage unit. The performance modelling also relies on data used for site selection, but needs additional data and at increased resolution and detail. Another category of site characterisation activities consists of characterisation of risk at the storage site, and this characterisation
© Woodhead Publishing Limited, 2010
44
Developments and innovation in CCS technology
usually focuses on the overlying strata and their structure and geology, other resources, shallow groundwater, vegetation, animal life and population, marine (if offshore), and atmospheric conditions, etc. Finally, additional site characterisation should be performed for capturing the baseline conditions at the site prior to the start of CO2 injection on which basis a monitoring, measurement and verification (MMV) programme can be designed and implemented. Thus, the aims of site characterisation are: 1. refine storage capacity estimates, therefore confirming capacity requirements; 2. predict the extent of the plume of injected CO2 and the effects of CO2 in free phase or dissolved in aquifer water in reservoir and seal rocks; 3. ascertain that, as far as it can be discerned prior to injection, the site will perform effectively and safely; 4. establish the baseline conditions for the design and implementation of a monitoring programme; 5. assess the risk associated with the storage operation and remediation strategies in case of site non-performance; 6. complete the material necessary for application and permitting of the site. To achieve the aims of site characterisation, the following are recommended: ∑ ∑ ∑ ∑ ∑ ∑ ∑ ∑
geological characterisation; characterisation of reservoir rock properties; characterisation of caprock properties; predictive flow modelling; geochemical assessment; geomechanical assessment; risk assessment; design of monitoring programme.
Geological characterisation The geological characterisation is a prerequisite for predictive fluid flow and geochemical simulations, risk assessment and design of a monitoring programme. The geological characterisation of the storage reservoir and its overburden aims to describe the geometry and lithology or the sedimentary succession comprising the storage unit, the immediately confining caprock and the overburden above. Pressure and temperature distributions are essential in establishing the in situ properties of CO2 such as density and viscosity, which affect storage capacity, injectivity and sweep efficiency. Reservoir top structure, thickness and compartmentalisation by faults and/or depositional
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
45
and/or diagenetic processes (i.e., lateral extent) are the minimum information that should be produced using geophysical and well data. Properly mapping the aquifer top is critical in the case of open aquifers because it is essential in establishing plume evolution and migration pathway along the top of the aquifer. Properties of the storage unit These properties are derived from well logs, core and cuttings, and geophysical lines. The main rock properties are aquifer porosity, permeability and relative permeability for CO2/brine systems at in situ conditions (Bachu and Bennion, 2008), facies type and distribution (which control, in turn, porosity and permeability), shale fraction and geometry of shale bodies, net-to-gross thickness and mineralogy, which is critical for geochemical evaluations of the effects and fate of the injected CO2. Analysis of core should meet the needs of predictive and geochemical modelling, but most likely will include: ∑ sedimentology (optical and scanning electron microscopy); ∑ mineralogy (X-ray diffraction, particle size analysis); ∑ petrophysical properties (porosity, permeability, relative permeability); ∑ mechanical and thermal properties; ∑ acoustic and elastic properties of rocks, such as Young’s modulus and Poisson’s ratio; ∑ pore water chemistry. Caprock and overburden properties The evaluation of the caprock is key in establishing the long-term safety of the storage site. The presence of additional aquifers and sealing units is of considerable interest as it provides the possibility of early warnings in case of CO2 leakage via seismically-imaged spots, changes in groundwater chemistry or even changes in gravity values. The capillary entry pressure is critical because it is a limiting factor in regard to injection pressures and the underlying CO2 plume that it can sustain. A laboratory programme is necessary to test the capillary entry and breakthrough pressure, mineralogy and geochemical composition of the caprock. Caprock core analysis should include: ∑ ∑ ∑
sedimentology (optical and scanning electron microscopy); mineralogy (X-ray diffraction, particle size analysis, cation exchange capacity – CEC, total organic carbon – TOC); petrophysical properties (capillary entry pressure, porosity, permeability and relative permeability);
© Woodhead Publishing Limited, 2010
46
Developments and innovation in CCS technology
∑
mechanical and thermal properties (Mohr–Coulomb behaviour, drained bulk modulus, time-dependent creep, dehydration); ∑ acoustic and elastic properties, e.g., Young’s modulus and poisson’s ratio; ∑ pore water chemistry. Geochemical assessment
Once dissolved in aquifer water, CO2 forms a weak carbonic acid which may potentially attack and alter rocks, cements and well casings that come in contact with it. The assessment of geochemical impact is thus essential in assessing the safety of a CO2 storage site. The degree of reactivity between CO2, pore water and rock minerals will influence the long-term storage potential and safety of the reservoir. The geochemical assessment of a prospective storage site should include modelling of short-term geochemical reactions, based on the initial characterisation of the system and constrained by laboratory experiments used to calibrate the predictive geochemical modelling, and long-term predictive modelling to assess the geochemical impact of the injected CO2 over hundreds to thousands of years (Chadwick et al., 2008). Modelling results are crucially dependent on which reactions are taken into account and their underpinning chemical data. The output will depend also on the chosen conceptual model. Geomechanical assessment Examples of such assessment are stress regime (stress magnitude and orientation), fault and fracture characteristics, shear strength, activation of preexisting faults and fractures as a result of pressure buildup, and caprock weakening in hydrocarbon reservoirs as a result of pressure decline due to production. Predictive flow modelling This is a key element in site characterisation because it helps in refining storage capacity estimates and provides a means to evaluate the pressure buildup (e.g., Mathias et al., 2009; Birkholzer and Zhou, 2009) and likely lateral spread of CO2 during injection and in the future (plume footprint), which are essential in identifying possible leakage scenarios, design of a monitoring programme and application and permitting. Key modelling parameters include: ∑
reservoir characteristics: geometry, temperature, pressure, porosity, permeability, relative permeability and capillary pressure;
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
47
∑
caprock characteristics: thickness, permeability, capillary entry pressures; ∑ fluids: water salinity, CO2 composition (type and amount of impurities), phase behaviour.
Risk assessment This type of characterisation is important for assessing the potential risks to the environment and life posed by the CO2 storage project. In the evaluation of consequences versus environmental criteria, the latter must correspond to amounts or concentrations that are measurable, and acceptable levels and limit values must be determined. To determine site-specific criteria, it is necessary to know the baseline conditions, such as groundwater chemistry and ecosystem composition. It is important to note that authorities are responsible for setting requirements, environmental criteria and limit values, but input from industry, the public and other stakeholders is important in the development and determination of acceptable levels and limits.
2.4
Estimation of carbon dioxide (co2) storage capacity
Static and dynamic methods are used in the oil and gas industry, underground natural gas storage, groundwater and underground disposal of fluids for estimating subsurface volumes. Static methods are volumetric and compressibility-based. The dynamic methods are decline/incline curve analysis, material balance and reservoir simulations, and they can be applied only after the start of active injection; hence only static methods will be summarily described here based on the work of Bachu et al. (2007).
2.4.1 Coal beds The effective storage capacity MCO2e for a given coal bed is given by the relation:
Ê ˆ M CO2e = E ¥ rCO2s ¥ A ¥ h ¥ nC ¥ ÁVL ¥ P ˜ ¥ (1 – fa – fm ) Ë P + PL ¯
[2.1]
where rCO2s = 1.873 kg/m3 is CO2 density at standard (surface) conditions, A and h are the area and effective thickness of the coal zone, respectively, ñC is the bulk coal density (generally ñC ≈1.4 t/m3), P is pressure, PL and VL are Langmuir pressure and volume, respectively, fa and fm are the ash
© Woodhead Publishing Limited, 2010
48
Developments and innovation in CCS technology
and moisture weight fraction of the coal, respectively, and E is the storage efficiency factor. Monte Carlo simulations performed by USDOE (2007) produced a range for E between 28 and 40 % for a 15–85 % confidence range, with an average of 33 % for 50 % confidence. The coal gas saturation (in units of volume of gas per unit of coal mass) is given by GCS and is the coal gas content (dry, ash free) at saturation, assuming that the coal will be 100 % saturated with CO2. It is generally assumed to follow a pressure-dependent Langmuir isotherm of the form:
GCS = VL ¥
P P + PL
[2.2]
2.4.2 Oil and gas reservoirs Assessments for CO2 storage capacity in oil and gas reservoirs are based on reserves databases that list hydrocarbon reserves and various reservoir characteristics. Solution gas should not be considered in storage capacity calculations because it is implicitly taken into account in oil reservoirs through the shrinkage factor. Since reserves databases indicate the volume of original gas and oil in place (OGIP and OOIP) at surface conditions, the theoretical mass storage capacity for CO2 storage in a reservoir at in situ conditions, MCO2t, is given by:
MCO2t = rCO2r ¥ Rf ¥ (1 – FIG) ¥ OGIP
¥ [(Ps ¥ Zr ¥ Tr)/(Pr ¥ Zs ¥ Ts)]
[2.3]
for gas reservoirs, and by:
MCO2t = rCO2r ¥ [Rf ¥ OOIP ¥ Bf – Viw + Vpw]
[2.4]
for oil reservoirs. An alternate equation for calculating the CO2 storage capacity in oil and gas reservoirs is based on the geometry of the reservoir (areal extent and thickness) as given in reserves databases:
MCO2t = rCO2r ¥ [Rf ¥ A ¥ h ¥ f ¥ (1 – Sw) – Viw + Vpw]
[2.5]
In the above equations rCO2r is CO2 density at reservoir conditions of temperature and pressure, calculated from equations of state. OGIP and OOIP are the initial gas and oil in place, respectively, Rf is the recovery factor, FIG is the fraction of injected gas, P, T and Z denote pressure, temperature and the gas compressibility factor, respectively, Bf is the formation volume factor that brings the oil volume from standard conditions to in situ conditions, Viw and Vpw are the volumes of injected and produced water, respectively (applicable in the case of oil reservoirs), and A, h, f and Sw are reservoir area, thickness, porosity and water saturation, respectively. If gas or miscible
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
49
solvent is injected in oil reservoirs during tertiary recovery, then the mass balance of these should be added to Equations 2.4 and 2.5. The subscripts ‘r’ and ‘s’ denote reservoir and surface conditions, respectively. The volumes of injected and/or produced water, solvent or gas can be calculated from production records. In the case of reservoirs with strong aquifer support (water drive), the volumes of injected and produced water may be negligible by comparison with the amount of invading water. In the case of reservoirs underlain by aquifers, the reservoir fluid (oil and/ or gas) was originally in hydrodynamic equilibrium with the aquifer water. As hydrocarbons are produced and the pressure in the reservoir declines, a pressure differential is created that drives aquifer water up into the reservoir, invading the reservoir. If CO2 is then injected into the reservoir, the pore space invaded by water may not all be available for CO2 storage, resulting in a net reduction of reservoir capacity. The pore volume invaded by water from underlying aquifers cannot be estimated without detailed monitoring of the oil–water interface and detailed knowledge of reservoir characteristics. As CO2 is injected and pressure increases, some of the invading water may be expelled back into the aquifer; however, the hysteresis caused by relative permeability effects and irreducible saturations will prevent complete withdrawal of invaded water, leading to a permanent loss of storage space. Notwithstanding the effect of an underlying aquifer, three other factors control the effectiveness of the CO2 storage process: CO2 mobility with respect to oil and water; the density contrast between CO2 and reservoir oil and water which leads to gravity segregation; and reservoir heterogeneity. All these processes and reservoir characteristics that reduce the actual volume available for CO2 storage can be expressed by capacity coefficients (C < 1) in the form:
MCO2e = Cm ¥ Cb ¥ Ch ¥ Cw ¥ Ca ¥ MCO2t ∫ E ¥ MCO2t
[2.6]
where MCO2e is the effective reservoir capacity for CO2 storage, the subscripts ‘m’, ‘b’, ‘h’, ‘w’ and ‘a’ stand for mobility, buoyancy, heterogeneity, water saturation and aquifer strength, respectively, and E is the storage efficiency coefficient that incorporates the cumulative effects of all the others. In the cases where good production (and injection) records are available, and particularly when cumulative production is greater than the estimated original oil or gas in place, a production-based method can be used to estimate CO2 storage capacity, in which basically the product Rf ¥ OGIP or Rf ¥ OOIP in Equations 2.3 and 2.4 is replaced by the produced gas or oil, respectively. In some cases, more oil or gas has been produced than originally estimated would be recoverable, resulting in a real Rf > 1. Cumulative production data should be used whenever possible to check and update the real Rf.
© Woodhead Publishing Limited, 2010
50
Developments and innovation in CCS technology
2.4.3 Deep saline aquifers Storing CO2 in water-saturated structural and stratigraphic traps is similar to storage in depleted oil and gas reservoirs. If the geometric volume (Vtrap) of the structural or stratigraphic trap down to the spill point is known, as well as its porosity (f) and the irreducible water saturation (Swirr), then the theoretical volume available for CO2 storage (VCO2t) can be calculated with the formula:
VCO2t = Vtrap ¥ f ¥ (1 – Swirr) ∫ A ¥ h ¥ f ¥ (1 – Swirr)
[2.7]
where A and h are the trap area and average thickness, respectively. This volume is time-independent, and depends on trap characteristics alone. Relation (2.7) assumes constant porosity and irreducible water saturation, and is applicable when average or characteristic values are used. The effective storage volume (VCO2e) is given by:
VCO2e = E ¥ VCO2t
[2.8]
where E is a storage efficiency coefficient that incorporates the cumulative effects of trap heterogeneity, CO2 buoyancy and sweep efficiency. Calculating the mass of CO2 that corresponds to the effective storage volume is more difficult because CO2 density (rCO2) depends on the pressure in the trap once it is filled with CO2. This pressure is not known a priori but depends on permeability, relative permeability to formation water and CO2, dimensions and volume, and the nature of trap boundaries, and may vary with the injection strategy (injection rate, number and/or inclination of injection wells, etc.). However, this pressure has to be higher than the initial water pressure in the trap (Pi) in order to achieve CO2 injection, but it has to be lower than the maximum bottomhole injection pressure (Pmax) that regulatory agencies usually impose in order to avoid rock fracturing or breaching of the capillary seal. Thus, the mass of CO2 that would be stored in a structural or stratigraphic trap would be between these two limits (Bachu et al., 2007):
minMCO2e = rCO2(Pi, T) ¥ VCO2e ≤ MCO2e ≤ maxMCO2e
= rCO2(Pmax, T) ¥ VCO2e
[2.9]
where T is the average temperature in the trap. The mass capacity of a trap may vary in time if pressure varies because, although the volume of the trap remains constant, CO2 density varies with varying pressure. Relations 2.7 –2.9 can also be applied to the case of a plume of CO2 that is not necessarily contained in a stratigraphic or structural trap, but the area and thickness of the CO2 plume have to be known a priori through numerical simulations. USDOE (2007) proposes to use the entire volume of the aquifer according to the following relation for calculating the volumetric CO2 storage capacity:
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
MCO2e = E ¥ A ¥ h ¥ f ¥ rCO2
51
[2.10]
where rCO2 is the average CO2 density evaluated at pressure and temperature that represent storage conditions anticipated for a specific deep saline aquifer, and E is a storage efficiency factor that reflects the total pore volume filled with CO2. Application of Relation 2.10 may be difficult for aquifers of large areal extent and great variability, in which case an integral form of Relation 2.10 should be used:
M CO2e = E ¥
ÚÚfr
CO2 d Ad h
[2.11]
The effect of irreducible water saturation is not taken into account explicitly in Relation 2.10 as in Relation 2.7, but is included in the efficiency factor E through the pore-scale displacement efficiency. Monte Carlo simulations performed by members of the project team produced a range for E between 1 and 4 % of the bulk volume of a deep saline aquifer for a 15–85 % confidence range, with an average of 2.4 % for 50 % confidence (USDOE, 2007). More recent work shows that the efficiency factor E varies, depending on aquifer lithology, between 1.4 % for limestone aquifers with a 10 % confidence and 6 % for sandstone aquifers with a 90 % confidence (Gorecki et al., 2009).
2.5
Future trends
Future trends in site selection and characterisation depend on progress in the science and economics of CO2 geological storage. As CO2 capture becomes more widespread and CO2 becomes available in greater volumes and at lower costs, and as infrastructure develops, particularly pipelines, the economic criteria for site selection will probably change, with more sites meeting selection criteria. Similarly, as CO2 capture and storage gains wider public acceptance as part of a portfolio of measures for mitigating climate change, some societal screening criteria will likely change. On the other hand, as more and more projects are implemented, and as the regulatory framework for site selection, permitting, operation and abandonment evolves, the criteria for screening and the requirements for characterisation will also evolve, with the potential to become more stringent or less so, depending on the experience gained to date. With regard to CO2 storage in coal beds, as the technology matures and as uneconomic coal beds will be better defined, the requirements for screening and characterisation will also improve. Similarly for deep saline aquifers, as flow and geochemical processes become better understood, most likely the need for better characterisation will increase (e.g., the emergence of relative permeability as a key factor in both capacity estimates and CO2 plume evolution). Other media, such as organic-rich shales, basalts, ultramaphic
© Woodhead Publishing Limited, 2010
52
Developments and innovation in CCS technology
rocks such as olivine and serpentine, and hydrates, may prove in the mediumto-long term to be suitable for CO2 storage, in which case a new set of screening criteria and characterisation requirements will emerge. Finally, site characterisation will develop significantly beyond site selection, to meet regulatory requirements for permitting, and also for monitoring the fate and effects of the injected CO2. With regard to performance assessment, as the science of CO2 storage will advance and as predictive models improve, the need for characterisation at increasingly higher resolution/smaller scales will increase. Characterisation will continue past the operational stage of a CO2 storage project into the closure and post-closure phases. To conclude, screening criteria for site selection will evolve as the science of CO2 storage advances, as more field experience is gained, and as regulatory frameworks are implemented. Site characterisation will also expand to cover more aspects at increasing resolution and detail and for longer periods of time, basically covering the entire lifetime of a CO2 storage project, from inception to complete abandonment.
2.6
Sources of further information and advice
Generally papers written before 2005 presented cases of site characterisation specific to the CO2 storage projects active or in implementation phase up to that time; these have been reviewed in the IPCC Special Report on CO2 Capture and Storage (Benson et al., 2005). Many cases of and various aspects of site characterisation have been presented at the International Conferences on Greenhouse Gas Technologies, whose papers have been published in conference proceedings. Environmental Geosciences has published two special issues in 2006 (numbers 2 and 3 of volume 13) and Environmental Geology has published a special issue in June 2008 (volume 54, number 8) devoted to the subject of site characterisation. Worth mentioning are the papers describing site-specific cases of site characterisation in North America at the Frio, Mountaineer and Tea Pot Dome sites (Friedmann and Stamp, 2006; Hovorka et al., 2006; Lucier et al., 2006; Chiaramonte et al., 2008; Doughty et al., 2008; Lucier and Zoback, 2008), in Europe (Förster et al., 2006; Meyer et al., 2008) and Australia (Sayers et al., 2006; Gibson-Poole et al., 2008). Several papers of interest have been published in the International Journal of Greenhouse Gas Control. In addition, the American Association of Petroleum Geologists (AAPG) published in 2009 a special volume on site characterisation for CO2 storage (AAPG Studies #59: Carbon Dioxide Sequestration in Geological Media – State of the Art). The American Geophysical Union (AGU) also published in 2009 a special monograph: The Science of CO2 Storage, Geophysical Monograph Series GM148. Currently, every major professional organisation, such as European Association of Geophysicists and Engineers (EAGE), American
© Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
53
Geophysical Union (AGU), Society of Petroleum Engineers (SPE), American Chemical Society (ACS), American Association of Petroleum Geologists (AAPG), holds annual conferences and various other meetings where one or more sessions are devoted to CO2 storage in geological media, or even special meetings dedicated only to CO2 capture and storage, like the SPE International Conference on CO2 Capture, Storage and Utilization held in San Diego, California, November 2–4, 2009.
2.7
References
Bachu S (2000) Sequestration of carbon dioxide in geological media: criteria and approach for site selection. Energy Convers. Manage., 41(9), 953–970. Bachu S (2001) From suitability to ultimate capacity: a roadmap for assessing sedimentary basins and selecting sites for CO2 storage in geological media. In: Williams D J, Durie R A, McMullan P, Paulson C A J and Smith A Y (eds), Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies (GHGT5), Collingwood, VIC, Australia, CSIRO Publishing, 328–333. Bachu S (2002) Sequestration of CO2 in geological media in response to climate change: roadmap for site selection using the transform of the geological space into the CO2–phase space. Energy Convers. Manage., 43, 87–102. Bachu S (2003) Screening and ranking of sedimentary basins for sequestration of CO2 in geological media. Environ. Geol., 44(3), 277–289. Bachu S and Bennion DB (2008) Drainage and imbibition relative permeability relationships for supercritical CO2 and H2S/brine systems in intergranular sandstone, carbonate, shale and anhydrite formations. SPE Res. Eval. Eng., 11(3), 487–496. Bachu S and Gunter WD (1999) Storage capacity of CO2 in geological media in sedimentary basins with application to the Alberta basin. In: Riemer P, Eliasson B and Wokaun A (eds), Proceedings of the Fourth International Conference on Greenhouse Gas Control Technologies (GHGT4), Amsterdam, the Netherlands, Pergamon, 195–200. Bachu S and Shaw JC (2003) Evaluation of the CO2 sequestration capacity in Alberta’s oil and gas reservoirs at depletion and the effect of underlying aquifers. J. Can. Pet. Technol., 42(9), 51–61. Bachu S and Shaw JC (2005) CO2 storage in oil and gas reservoirs in western Canada: effect of aquifers, potential for CO2-flood enhanced oil recovery, and practical capacity. In: Rubin E S, Keith D W and Gilboy C F (eds), Proceedings of the Seventh International Conference on Greenhouse Gas Control Technologies: GHGT7, Cheltenham, UK, IEA GHG, Vol. 1, 361–369. Bachu S, Bonijoly D, Bradshaw J, Burruss R, Holloway S, Christensen NP and Mathiassen OP (2007) CO2 storage capacity estimation: Methodology and gaps. Int. J. Greenhouse Gas Control, 1(4), 430–443. Benson S and Cook P et al. (2005) Transport of CO2. In: Metz B, Davidson O, de Coninck H, Loos M and Meyer L (eds), IPCC Special Report on Carbon Dioxide Capture and Storage, Cambridge, UK, Cambridge University Press, 197–276. Birkholzer JT and Zhou Q (2009) Basin-scale hydrogeologic impacts of CO2 storage: capacity and regulatory implications. Int. J. Greenhouse Gas Control, 3(6), 745–756. Chadwick A, Arts R, Bernstone C, May F, Thibeau S and Zweigel P (2008) Best Practice for the CO2 Storage in Saline Aquifers – Observations and Guidelines from the SACS and CO2STORE Projects. Nottingham, UK, British Geological Survey.
© Woodhead Publishing Limited, 2010
54
Developments and innovation in CCS technology
Chiaramonte L, Zoback MD, Friedmann J and Stamp V (2008) Seal integrity and feasibility of CO2 sequestration in the Teapot Dome EOR pilot: geomechanical site characterisation. Environ. Geol., 54(8), 1667–1675. Cook PJ (2006) Site characterisation. In: International Symposium on Site Characterisation for CO2 Storage, 20–22 March 2006, Berkeley, CA, Lawrence Berkeley National Laboratory, 3–5. CSLF (Carbon Sequestration Leadership Forum), (2007) Estimation of CO2 storage capacity in geological media, June, available at: http://www.cslforum.org/publications/ documents/PhaseIIReportStorageCapacityMeasurementTaskForce.pdf (accessed January 2010). Doughty C, Freifeld BM and Trautz RC (2008) Site characterisation for CO2 geologic storage and vice-versa: the Frio brine pilot, Texas, USA as a case study. Environ. Geol., 54(8), 1635–1656. Förster A, Norden B, Zinck-Jørgensen K, Frykman P, Kulenkampff J, Spangenberg E, Erzinger J, Cosma C-G and Hurter S (2006) Baseline characterisation of the CO2SINK geological storage site at Ketzin, Germany. Environ. Geosci., 13(3), 145–161. Frailey SM, Rittenhouse S, Knepp R, Anderson A, Leetaru H, Korse C, Rupp R and Finley RJ (2006) Reservoir simulation and GIS modeling as tools for defining geological sequestration capacity: An optimal approach toward more specific assessments, Illinois basin, USA. In: Gale J, Rokke N, Zweigel P and Svenson H (eds), Proceedings of the Eighth International Conference on Greenhouse Gas Control Technologies: GHGT8, Oxford, UK, Elsevier, CD-ROM. Friedmann SJ and Stamp VW (2006) Teapot Dome: characterisation of a CO2-enhanced oil recovery and storage site in Eastern Wyoming. Environ. Geosci., 13(3), 181–199. Ghaderi SM, Keith DW and Leonenko Y (2009) Feasibility of injecting large volumes of CO2 into aquifers. In: Gale J, Herzog H and Braitsch J (eds), Greenhouse Gas Control Technologies 9, Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies (GHGT9), Energy Procedia, 1, 3113–3120. Gibson-Poole CM, Svendsen L, Underschultz J, Watson MN, Ennis-King J, van Ruth PJ, Nelson EJ, Daniel RF and Cinar Y (2008) Site characterisation of a basin-scale CO2 geological storage system: Gippsland Basin, southeast Australia. Environ. Geol., 54(8), 1583–1606. Gorecki CD, Sorensen JA, bremer JM, Knudsen DJ, Smith SA, Steadman EN and Harju JA (2009) Development of storage coefficients for determining the effective CO2 storage resource in deep saline formations. SPE International Conference on CO2 Capture, Storage and Utilization, San Diego, CA, 2–4 November, SPE Paper 126444. Holtz MH (2009) Geologic CO2 storage in oil fields: Considerations for successful sites. SPE International Conference on CO2 Capture, Storage and Utilization, San Diego, CA, 2–4 November, SPE Paper 126198. Hovorka SD, Benson SM, Doughty C, Freifeld BM, Sakurai S, Daley TM, Khaaraka Y, Holtz MH, Trautz RC, Seay Nance H, Myer LR and Knauss KG (2006) Measuring permanence of CO2 storage in saline formations: the Frio experiment. Environ. Geosci., 13(2), 105–122. IEA (2004) Prospects for CO2 Capture and Storage. IEA/OECD, Paris, France. Kaldi JG and Gibson-Poole CM (eds), (2008) Storage Capacity Estimation, Site Selection and Characterisation for CO2 Storage Projects. Report No: RPT08-1001, Canberra, ACT, AU, CO2CRC. Kopp A, Class H and Helmig R (2009a) Investigations on CO2 storage capacity in saline aquifers – Part 1: Dimensional analysis of flow processes and reservoir characteristics. Int. J. Greenhouse Gas Control, 3(3), 263–276. © Woodhead Publishing Limited, 2010
Geological sequestration of carbon dioxide (CO2)
55
Kopp A, Class H and Helmig R (2009b) Investigations on CO2 storage capacity in saline aquifers – Part 2: Estimation of storage capacity coefficients. Int. J. Greenhouse Gas Control, 3(3), 277–287. Li S, Dong M, Li Z and Huang S (2006) CO2 sequestration in depleted oil and gas reservoirs – caprock characterization and storage capacity. Energy Convers. Manage., 47(11–12), 1372–1382. Lucier A and Zoback M (2008) Assessing the economic feasibility of regional deep saline aquifer CO2 injection and storage: a geomechanics-based workflow applied to the Rose Run sandstone in eastern Ohio, USA. Int. J. Greenhouse Gas Control, 2(2), 248–258. Lucier A, Zoback M, Gupta N and Ramakrishnan TS (2006) Geomechanical aspects of CO2 sequestration in a deep saline reservoir in the Ohio River Valley region. Environ. Geosci., 13(2), 85–103. Mathias SA, Hardisty PE, Trudell MR and Zimmerman RW (2009) Screening and selection of sites for CO2 sequestration based on pressure buildup. Int. J. Greenhouse Gas Control, 3(5), 577–585. Meyer R, May F, Müller C, Geel K and Bernstone C (2008) Regional search, selection and geological characterisation of a large anticlinal structure, as a candidate site for CO2 storage in northern Germany. Environ. Geol., 54(8), 1607–1618. Moritis G (2008) Special report: More US EOR projects start but EOR production continues to decline. Oil & Gas J., 106(15), 41–42, 44–46. Nordbotten JM, Celia MA and Bachu S (2005) Semi-analytical solution for CO2 leakage through an abandoned well. Environ. Sci. Technol., 39(2), 602–611. Nordbotten JM, Kavetski D, Celia MA and Bachu S (2008) A model for CO2 leakage including multiple geological layers and multiple leaky wells. Environ. Sci. Technol., 43(3), 743–749. Núñez-López V, Holtz MH, Wood DJ, Ambrose WA and Hovorka SD (2008) Quicklook assessment to identify optimal CO2 EOR storage sites. Environ. Geol., 54(8), 1695–1706. Oldenburg CM (2008) Screening and ranking framework for geologic CO2 storage site selection on the basis of health, safety, and environmental risk. Environ. Geol., 54(8), 1687–1694. Oruganti YD and Bryant SL (2009) Effect of relative permeability on pressure-induced risk during CO2 injection in aquifers. SPE International Conference on CO2 Capture, Storage and Utilization, San Diego, CA, 2–4 November, SPE Paper 126932. Pooladi-Darvish M, Hong H, Theys S, Stocker R, Bachu S and Dashtgard S (2008) CO2 injection for enhanced gas recovery and geological storage of CO2 in the Long Coulee Glauconite F Pool, Alberta. SPE Annual Technical Conference and Exhibition, Denver, CO, USA, September 21–24, SPE Paper 115789. Ramírez A, Hagedoorn S, Kramers L, Wildenborg T and Hendricks C (2009) Screening storage options in the Netherlands. In: Gale J, Herzog H and Braitsch J (eds), Greenhouse Gas Control Technologies 9, Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies (GHGT9), Energy Procedia, 1, 2801–2808. Sayers J, Marsh C, Scott A, Cinar Y, Bradshaw J, Henning A, Barclay S and Daniel R (2006) Assessment of a potential storage site for carbon dioxide: A case study, southeast Queensland, Australia. Environ. Geosci., 13(2), 123–142. Shah V, Broseta D, Mouronval G and Montel F (2008) Water/acid gas interfacial tensions and their impact on acid gas geological storage. Int. J. Greenhouse Gas Control, 2(4), 595–604.
© Woodhead Publishing Limited, 2010
56
Developments and innovation in CCS technology
Shaw JC and Bachu S (2002) Screening, evaluation and ranking of oil reservoirs suitable for CO2-flood EOR and carbon dioxide sequestration. J. Can. Pet. Technol., 41(9), 51–61. USDOE (U.S. Department of Energy, Office of Fossil Energy), 2007. Carbon Sequestration Atlas of United States and Canada. USDOE (U.S. Department of Energy, Office of Fossil Energy), 2008. Carbon Sequestration Atlas of United States and Canada, 2nd edn. van der Meer LGH and Egberts PJP (2008) A general method for calculating subsurface CO2 storage capacity. Offshore Technology Conference, Houston, TX, USA, 5–8 May, OTC Paper 19309. Wilkinson J, Szafranski R, Lee K-S and Kratzing C (2009) Subsurface design considerations for carbon dioxide storage. In: Gale J, Herzog H and Braitsch J (eds), Greenhouse Gas Control Technologies 9, Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies (GHGT9), Energy Procedia, 1, 3047–3054.
© Woodhead Publishing Limited, 2010
3
Carbon dioxide (CO2) sequestration in deep saline aquifers and formations
R. J. R o s e n b a u e r and B. T h o m a s, US Geological Survey, USA Abstract: Carbon dioxide (CO2) capture and sequestration in geologic media is one among many emerging strategies to reduce atmospheric emissions of anthropogenic CO2. This chapter looks at the potential of deep saline aquifers – based on their capacity and close proximity to large point sources of CO2 – as repositories for the geologic sequestration of CO2. The petrochemical characteristics which impact on the suitability of saline aquifers for CO2 sequestration and the role of coupled geochemical transport models and numerical tools in evaluating site feasibility are also examined. The full-scale commercial CO2 sequestration project at Sleipner is described together with ongoing pilot and demonstration projects. Key words: CO2 storage, CO2 sequestration, saline aquifer, saline formation, geologic storage.
3.1
Inroduction
The carbon cycle is dominated by steady-state reactions that involve carbon dioxide (CO2). Although the climate-stabilizing exchange of carbon among its various reservoirs is geologically rapid, the anthropogenic combustion of fossil fuels has caused a continuous and rapid > 35 % increase of atmospheric CO2 over the past 150 years (Keeling and Whorf, 2005). This increase of CO2, a major greenhouse gas, is expected to affect global climate (Stocker and Schmittner, 1997; Allen et al., 2000; Cox et al., 2000; Falkowski et al., 2000; Albritton and Meira Filho, 2001; Cuffey and Vimeux, 2001; Palmer and Räisänen, 2002; IPCC, 2007). Carbon dioxide capture and storage (CCS) represents a key component of a larger portfolio of advanced energy technologies and climate policies needed to mediate the rise in atmospheric CO2 concentration. Geologic CCS systems are specifically designed to remove CO2 from various point sources and safely deposit the CO2 in secure storage sites deep underground. The disposal of CO2 into deep-saline aquifers is one of several possible geologic storage options (Gupta et al., 1999). Other geologic CO2 repositories under consideration are depleted oil field reservoirs and deep unmineable coal seams (Gale and Freund, 2001; Stevens et al., 2001; Damen et al., 2005). These approaches have a value-added economic benefit because CO2 injection into these reservoirs enhances oil recovery (EOR) and coalbed methane recovery 57 © Woodhead Publishing Limited, 2010
58
Developments and innovation in CCS technology
(ECBM), but these options may pose a higher environmental risk due to reactions of supercritical CO2 with organic matter (Kolak and Burruss, 2006) and caprock seals (Kharaka et al., 2006b). Organic-rich shale may provide an adsorption substrate for CO2 storage similar to CO2 storage in coal seams (Nuttall et al., 2005; Vermylen et al., 2008). Basalt formations (Matter et al., 2005; Goldberg et al., 2008; Rosenbauer and Bischoff, 2009) and ultramafic rocks (Goff and Lackner, 1998; Maroto-Valer et al., 2005) are also under consideration for sequestering CO2 because of their potential to convert CO2 to a solid mineral form. These latter options provide CO2 sequestration alternatives in regions without subsurface reservoirs such as the Pacific northwest in the USA, Hawaii, and island nations such as Iceland where a pilot study is currently underway to inject CO2 into basalt rocks (Alfredssom et al., 2008; Gislason et al., 2008). Successful implementation of any of these approaches requires knowledge of the fundamental science that governs the physical and chemical behavior of CO2 during and after injection into the deep subsurface.
3.2
Saline aquifers
Broadly defined, deep saline aquifers are underground, water-filled strata. They are distributed widely across much of the world (Fig. 3.1 and 3.2) and are important potential CO2 repositories because many are large, generally contiguous reservoirs that may be capable of storing large volumes of CO2 (Hitchon et al., 1999). These aquifers, beneath both continents and oceans, are often highly permeable, allowing high rates of fluid extraction and injection (Marsily, 1986, p.115). Carbonate (limestone or dolomite) or sandstone formations host saline water in pore spaces between rock grains or within fractures and void spaces. Salinity in such aquifers can vary by orders of magnitude from mg/L in relatively fresh aquifers to more than 10 g/L in evaporitic formations (Kharaka and Hanor, 2007). Within sedimentary basins, salinity tends to increase with depth. Salinity heterogeneity develops from lithologic influences, differing groundwater flow regimes, and potential meteoric recharge. While most sedimentary rocks are formed with connate pore water contents that approximate that of seawater, during sediment diagenesis fluids react with silicates, carbonates, and evaporites. In particular, calcite alteration to dolomite decreases Mg and increases Ca fluid contents and albitization of plagioclase results in a decrease of dissolved Na relative to Ca (Davisson and Criss, 1996). Also, at greater depth, high salinities correlate with low (~300 mg/L) carbonate alkalinity (Kharaka and Hanor, 2007) due to precipitation of carbonates in response to high dissolved Ca concentrations. As a result, increasing salinities are consistent with the evolution of Na–Cl connate brines to Ca–Na–Cl brines with low carbonate alkalinity and lower pH (Kharaka and Hanor, 2007).
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
59
3.1 Map depicting sedimentary basins within North America containing saline aquifers (image courtesy of the US Department of Energy, National Energy Technology Laboratory).
There are more than 800 sedimentary provinces in the world (St John et al., 1984) distributed on and along continents (Fig. 3.2) that are variously well suited for CO2 storage and sequestration (Bachu, 2003; Holtz, 2003; Bradshaw and Dance, 2005a,b). The highest potential for CO2 storage is in large, continental-sized basins, such as the Illinois, and the northern Gulf of Mexico sedimentary basins in USA. In general, active margin sedimentary basins are less favorable for CO2 storage than passive margin basins because deep-seated faults and high-density fracture zones characteristic of active margins increase the likelihood of hydraulic connection with the surface. Tectonic complexity also decreases the lateral extent of formations and limits the exploitable reservoir volume for a given injection well. Rarely exploited for economic resources, saline formations are the largest, but least defined, of the geologic storage possibilities. Considerable
© Woodhead Publishing Limited, 2010
60
Developments and innovation in CCS technology
Basins on rigid lithosphere
Perisutural basins
Episutural basins
Atlantic-type basins Foredeeps
Pannonian-type basins
Subduction-related folded belts
Chinese-type
Forearc backarc
Trenches
basins
and California-
Cratonic basins
type basins
3.2 Map depicting major sedimentary basins of the world (image based on St John et al., 1984 in Bachu 2003, AAPG©1984, reprinted by the permission of the AAPG whose permission is required for further use).
uncertainty surrounds reservoir properties, flow regimes and capacities of saline aquifers, but the storage capacity is generally considered to be very large and the reservoir properties are likely favorable (Burruss et al., 2009). The evaluation of a formation for sequestration requires a set of variables that balance the total capacity of the reservoir with the likelihood of retention, the ease of injection, and the risks to environment and human health. Relevant physical and chemical formation variables include depth (temperature and pressure), rock properties such as mineralogy and grainsize, pore properties such as such as porosity and permeability, formation properties such as the structure and thickness of the reservoir, the resident fluid composition, and reservoir confinement. These variables are needed to calculate hydrostatic potentials, to create generalized groundwater and CO2 flow maps, and to estimate a net pore volume for CO2 storage. Below, we describe how these variables relate to the suitability of individual formations for CO2 storage.
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
61
3.2.1 Saline aquifer characteristics Depth The preferred concept is to inject CO2 into a porous and permeable reservoir covered with a caprock located at sufficient depth and pressure where CO2 can be injected and stored under supercritical conditions (31.1 °C and 73.8 bar) (Fig. 3.3). Minimum and maximum estimates for surface temperatures (15–20 °C), geothermal gradients (25–35°/km), and hydrostatic pressure gradients (105–160 bar/km) (Spycher et al., 2003) yield a range of potential injection conditions from above ambient temperature and pressure (TP) up to 150 °C and 800 bar, shown in fig. 3.4 between the dashed lines. Within this projected TP range there co-exist a dense immiscible CO2-rich fluid (Fig. 3.3) and a H2O-rich liquid phase. At all reservoir conditions, CO2 fluids are buoyant relative to aqueous phases and tend to migrate toward the 100 80 60 50 40 30 20
Pressure (MPa)
Solid
Super critical phase
Liquid
10 8 6 5 4 3
Critical point
2 Gas 1.0 .8 .6 .5 .4
Triple point
.3 .2 .1 –100
–80
–60
–40 –20 0 Temperature (°C)
20
40
60
3.3 Phase diagram of CO2 showing the triple and critical points and regions where CO2 is stable as a gas, liquid, solid, or supercritical fluid. The critical point is 31.1 °C and 73.8 bar (based on Bachu 2000; by permission of Elsevier©2000).
© Woodhead Publishing Limited, 2010
62
Developments and innovation in CCS technology 300
Pressure (bar)
250
Injection conditions
200 Supercritical 150 Liquid
100 50
CP
H+L V
0
0
30
60 90 Temperature (°C)
120
150
3.4 Range of potential injection conditions from above ambient temperature and pressure (TP) up to 150 °C and 300 bar based on minimum and maximum estimates for surface temperatures (15–20 °C), geothermal gradients (25–35°/km), and hydrostatic pressure gradients (105–160 bar/km) (Spycher et al., 2003). Projections are extrapolated to earth surface conditions; actual CO2 injection would take place at conditions above the critical point. CP = critical point; H = hydrate; L = Liquid; V = Vapor.
surface. Depending on the local geothermal gradient, a minimum reservoir depth of 800 m (Hitchon, 1996) is typically necessary for CO2 to remain in its supercritical state. This depth may vary, depending on local geothermal and hydrostatic pressure gradients of the formation. Mineralogy and grain size Target saline reservoirs are typically sandy units. These units may have variable clay and silicate mineral contents and be overlain by shale seals. Quartz sand and clays are minimally reactive with CO2 whereas carbonates, in particular, as well as plagioclase feldspar and mafic minerals are more reactive (Gunter et al., 1993, 1997; Kaszuba et al., 2003; Knauss et al., 2005; Rosenbauer et al., 2005). The presence of carbonate cements in shales and sandstones will influence the reactivity with CO2 as described later in the text. In general, larger grain sizes correlate with increased hydraulic conductivity at the expense of residual trapping efficiency (Holtz and Bryant, 2005). Porosity and permeability Permeability controls the direction and rate of CO2 injection and subsequent movement. Porosity and residual saturation control the size, shape, and
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
63
dispersion of the CO2 plume (Holtz et al., 2004). Porosity in the range 5–30 % (NRG Associates, 2001; Kuuskraa, 2004; Shafeen et al., 2004; Zweigel et al., 2004; Bertier et al., 2006) and permeability in the range 20–3500 md (McRae and Holtz, 1995; Zweigel et al., 2004; Bertier et al., 2006) provide sufficient reservoir volume and injection rates for the CO2 (Bentham and Kirby, 2005). In low-permeability rocks, pressure gradients dissipate slowly and fluid pressure progressively increases near the injection well. The need to avoid compromising the overlying seal may limit the viable injection rate and may limit the accessible pore volume for a given well. Capacity The area extent of worldwide sedimentary basins, not including those offshore, is approximately 70–80 million km2 (Koide et al., 1992; Hendriks and Blok, 1995; Bruant et al., 2002; Ecofys & TNO-NITG, 2002). The vast majority of these sedimentary basins contain deep brines that are variably suitable for sequestration. Worldwide potential capacity estimates of CO2 storage in saline formations range widely from 350 to > 11 000 Gt of CO2 (Omerod, 1994; Bergman and Winter, 1995; IEA, 1995; Holloway, 1997; Beecy and Kuuskraa, 2001; Davison et al., 2001; White et al., 2003; IPCC, 2005, 2007; Bradshaw et al., 2007). The storage volume for saline aquifers is large compared with other geologic repositories (Table 3.1) and capable of storing up to ~1000 years worth of modern CO2 emissions, based on total annual emissions of 31 Gt (IPCC, 2005; Oelkers and Schott, 2005; EIA, 2006). Estimates differ based on assumptions about volumes of sedimentary basins, aquifer characteristics, CO2 storage density, and technological and economic constraints (Bruant et al., 2002). Deficiencies in the accuracy and reliability of these past estimates are due in large part to a lack of common methodology and guidelines. Recent efforts have focused on developing consistent methodologies and specific standards for storage capacity estimation in deep saline aquifers and for the identification, screening, and prioritization of suitable geological basins
Table 3.1 Estimated storage capacities for major geologic storage reservoirs, (Dooley et al., 2006) Sequestration option
Worldwide capacity (Gt CO2)
Deep saline aquifers Depleted oil reservoir Depleted natural gas reservoir Deep coal seams Deep saline basalt formations Organic shales
100s–10 000s 120 700 140 > 240 unknown
© Woodhead Publishing Limited, 2010
64
Developments and innovation in CCS technology
for CO2 storage (CSLF, 2005, 2007, 2008; Bachu et al., 2007; Bradshaw et al., 2007; USDOE, 2008; Burruss et al., 2009; Vangkilde-Pedersen et al., 2009). Classification terminology from the petroleum industry is combined with a methodology to facilitate dynamic and risk-adjusted storage estimates (Frailey et al., 2006). The resulting probabilistic ranges of storage volumes are analogous to assessments of oil and gas resources (Burruss, 2004; Brennan and Burruss, 2006; Burruss et al., 2009) and allow differentiation of CO2 resource assessments from CO2 capacity estimates (Bachu, et al., 2007; CSLF, 2005, 2007; USDOE, 2008). Carbon dioxide resource estimates include only the technical screening criteria such as the tectonic setting and geology, the basin geothermal regime, and the hydrodynamic regime of formation waters to estimate the volume of porous and permeable sedimentary rocks available and accessible for CO2 storage. Capacity estimates include economic variables related to access, infrastructure and socio-political conditions (CSLF, 2005; Bachu et al., 2007). As with oil and gas resources, knowledge of storage capacity of saline aquifers is inversely proportional to the spatial scale of the assessment. Certainty increases in a progression from country and region to basin, local, and site-specific scales (Bachu et al., 2007). Carbon dioxide storage capacity at basin and regional scales can be evaluated only in the broadest terms. Capacity estimates are more robust at local and site-specific scales (Bachu et al., 2007). Each storage site is therefore unique and requires a specific technical and operational evaluation.
3.3
Trapping mechanisms
A combination of physical and chemical processes causes CO2 to become trapped and stored in saline aquifers. These processes vary in importance from site to site, depending on the reservoir characteristics, and they are effective over varying timescales (IPCC, 2005; Bachu et al., 2007). CO2 can be physically immobilized by structural, stratigraphic, lithologic, and hydrodynamic traps and can be physically bound by pore capillary forces as an immiscible residue. Chemical processes include dissolution of CO2 fluid into the aqueous phase, geochemical acid-base reactions, and mineral dissolution and precipitation (Chadwick et al., 2003; CSLF, 2005). Initially, the main storage processes are structural or stratigraphic traps (Fig. 3.5). Deformed or fractured reservoir strata, such as folded and faulted sandstones, in combination with overlying low permeability strata, such as mudstones, physically contain CO2 (Fig. 3.5b). Low hydraulic conductivity aquitards or aquicludes may be contiguous or a series of multiple interbedded confining layers. Confining layers are crucial because, following injection, the positively buoyant CO2 will follow a pressure gradient migrating from the injection site to other potentially less desirable reservoirs including
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
65
(a)
1 km + 100s km (b)
3.5 (a) hydrodynamic stratigraphic trapping where CO2 is trapped by an overlying layer of cap rock coupled with impermeable rock within a narrowing of the formation aquifer; (b) structural trapping, where CO2 is trapped by a fold in the rock formations; (c) trapping by impermeable rock layers shifted along a sealing fault to contain the CO2 (image source: CO2CRC).
© Woodhead Publishing Limited, 2010
66
Developments and innovation in CCS technology
(c)
3.5 Continued
freshwater aquifers. If unconfined, CO2 plumes can reach surface conditions where they can volatilize and vent to the atmosphere.
3.3.1 Hydrodynamic Hydrodynamic trapping refers to a time-dependent hydrogeological process where injected CO2 is effectively trapped by the existence of very long travel times to the surface. Following injection, the CO2 fluid migrates vertically as a plume along preferentially permeable pathways until it encounters a relatively impermeable caprock. It then travels laterally, driven by buoyancy, to structurally higher levels along the caprock–reservoir boundary. This mechanism is particularly effective in laterally unconfined sedimentary basins with limited structural traps, but with large-scale flow systems and low groundwater and fluid flow rates (fig. 3.5a). In contrast to these open and laterally unconfined systems, some sedimentary basins are bounded laterally by low-permeability zones and impervious seals due to natural heterogeneity or faulting (Fig. 3.5c). In such a closed system where the lateral and vertical migration of the fluids is contained, CO 2 injection rapidly increases pore pressure in the vicinity of injection wells. This is a limiting factor affecting CO2 storage capacity because of the need
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
67
to avoid geomechanical damage of the overlying seals. Highly structurally compartmentalized reservoirs are likely therefore to be less suited to CO2 storage than large unfaulted or high permeability reservoirs (Bentham and Kirby, 2005).
3.3.2 Residual trapping Residual trapping of injected CO2 occurs by capillary forces in the pores of reservoir rocks. It is the result of brine back filling the trailing edge of a mobile plume of supercritical CO2 that has been injected into the formation and has displaced the resident fluid. As buoyant CO2 moves through the formation, aqueous fluid replaces it, but some CO2 is left behind as disconnected, or residual, droplets in the pore spaces (Benson and Cole, 2008). The magnitude of residual saturation within a rock, and hence the fraction of injected CO2 that can be stored in this form, is a function of the rocks pore network geometry (Holtz and Bryant, 2005). It is likely that changes in the aspect ratio (pore radius/pore throat radius) of the pore network due to changes in inter-granular porosity control residual-phase saturation (Holtz and Bryant, 2005). The amount of residual gas trapping is also a function of both the vertical and horizontal extensions of the CO2 plume (Han et al., 2008). The amount of residual-trapped CO2 increases when the injected CO2 plume sweeps a larger area; thus, estimates differ on the amount of CO2 that can be retained by this process. Based on 3D reservoir modeling, capillary trapping ranges from 15–25 % for typical storage formations (Holtz, 2002), but could exceed 25 %, depending upon the porosity and permeability of the formation. Experimental measurements of supercritical CO2 in a Berea sandstone suggest that the maximum residual gas saturation of supercritical CO2 is about 8–10 % (Kitamura and Xue, 2006). Studies by Hesse et al. (2008) and Ide et al. (2007) suggest that, over time, 100 % of the CO2 in a subsurface plume could be immobilized by capillary trapping.
3.3.3 Carbon dioxide (CO2) dissolution Some injected CO2 will dissolve in the saline formation waters as a result of its solubility. The rate of dissolution is initially rapid (Rosenbauer and Koksalan, 2002) but, as the reservoir becomes density stratified, the dissolution becomes diffusion and convection limited. Carbon dioxide saturated formation water is more dense than pure formation water and therefore induces density instability and convective mixing that accelerates CO2 dissolution (Lindeberg and Wessell-Berg, 1997; Xu et al., 2006). Depending on the relative contact lens area and solubility gradient between the CO2 plume and the formation water, saturation of the formation water by the supercritical plume may take several millenia (Ennis-King and Paterson, 2001). Reservoir engineering
© Woodhead Publishing Limited, 2010
68
Developments and innovation in CCS technology
entailing forced convection by the extraction of formation fluid could accelerate the rate of dissolution trapping (Leonenko and Keith, 2008). The solubility of CO2 is well known in pure water, especially along the saturation curve, and has been measured up to 350 °C and 3500 bar (e.g. Wiebe and Gaddy, 1939, 1941; Malinin, 1959; Todheide and Franck, 1963; Takenouchi and Kennedy, 1964; Drummond, 1981; Blencoe et al., 2001; Rosenbauer et al., 2001; Rosenbauer and Koksalan, 2002; Chapoy et al., 2004). The solubility of water in CO2 has been less studied but becomes increasingly important at elevated temperature (Takenouchi and Kennedy, 1964; King et al., 1992; Spycher et al., 2003). Carbon dioxide solubility in aqueous NaCl solutions has been measured over a broad range of temperatures, pressures, and ionic strengths, but these data are generally confined to conditions relevant to seawater and hydrates (Stewart and Munjal, 1970; Barton and Chou, 1993; Aya et al., 1997) or to hydrothermal solutions and metamorphic processes (Joyce and Holloway, 1993). The solubility of CO2 in both pure water and NaCl solutions has been modeled by several investigators (Duan et al., 1995, 2006; Duan and Sun, 2003; Spycher et al., 2003), but measurements of the solubility of CO2 in saline fluids typical of P–T conditions within deep aquifers are generally lacking (Rosenbauer et al., 2001; Rosenbauer and Koksalan, 2002; Portier and Rochelle, 2005). Duan et al. (2006) present a critical review of the experimental data and a model of the solubility of CO2 in mixed electrolytes. Carbon dioxide dissolution in water produces carbonic acid (equation 3.1), a fundamentally important reaction because it is generally the aqueous (HCO3–, CO3–2), not the neutral molecular form of CO2, that reacts aquifer minerals (Rosenbauer and Koksalan, 2003).
CO2 + H2O ´ H2CO3
[3.1]
The aqueous solubility of molecular CO2 is temperature-, pressure-, and ionic-strength-dependent, generally lower at elevated temperature and salinity and greater at elevated pressure (Takenouchi and Kennedy, 1964; Rosenbauer and Koksalan, 2002; Duan and Sun, 2003). For example, at 25 °C and 1 bar, the solubility of CO2 in an aquifer fluid equivalent to a 4 M NaCl solution is approximately one-third its solubility in pure water (Rosenbauer and Koksalan, 2002) (Fig. 3.6). At conditions consistent with deep down-hole disposal of 120 °C and 300 bars, the solubility of CO2 in a 4 m NaCl equivalent aquifer fluid is 0.5 m (Rosenbauer and Koksalan, 2002; Duan and Sun, 2003). Isotherms of the solubility of CO2 in NaCl exhibit two distinct patterns of solubility versus pressure. At 21° and 50 °C, the solubility of CO2 increases as a nearly linear function of pressure (Rosenbauer, unpublished data; Fig. 3.6). At and above 100 °C, the solubility of CO2 is markedly low at low pressure and increases as a 2nd to 3rd order polynomial-shaped function of pressure,
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
69
2 Pure water
1.5
21 °C
CO2 (m)
50 °C 1
100 °C
NaCl 22 wt %
150 °C 0.5
0 0
21 °C 50 °C 100 °C 150 °C
100
200
300 400 Pressure (bar)
500
600
700
3.6 Isotherms of the solubility of CO2 in pure water contrasted the solubility of CO2 in 22 wt% NaCl. Isotherms at 21 and 50 °C are nearly linear functions with pressure. Isotherms at 100 and 150 °C are a fit to a complex polynomial expression. Solubility data are from Rosenbauer and Koksalan, 2002.
due probably in part to changes in the density and dielectric constant of CO2 (Rosenbauer, unpublished data; Fig. 3.6). The dielectric constant of CO2 is relatively independent of temperature but increases with density (Keyes and Kirkwood, 1930). The CO2-solubility isotherms also become more tightly clustered at high salt concentrations (Fig. 3.6). The differences in solubility between isotherms decrease at higher NaCl concentrations implying that, at high salinities, ionic strength increasingly controls solubility relative to temperature and pressure. In the absence of any fluid–rock interaction, this dissolved CO2 results in an acidic solution due to the dissociation of carbonic acid (Equation 3.2). H2CO3 ´ H+ + HCO3–
[3.2]
Liquid water is soluble in supercritical CO2. For example, at 100 °C, 300 bar, the solubility of H2O in supercritical CO2 is ~5 % (Takenouchi and Kennedy, 1964). Brine desiccation by mass transfer of liquid water to the supercritical gas phase has been observed in experiments containing a discrete CO2 phase. This increased ionic activity of the residual aqueous phase may promote porosity-reducing precipitation reactions in aquifers near saturation with mineral phases (Kaszuba et al., 2003; Prevost et al., 2005; Rosenbauer et al., 2005).
© Woodhead Publishing Limited, 2010
70
Developments and innovation in CCS technology
3.3.4 Ionic trapping Carbon dioxide injection induces disequilibrium in the carbonate buffer system of pore fluids. The subsequent dissolution of CO2 and dissociation of carbonic acid can result in reaction with primary minerals of the host formation. Dissociation of carbonic acid into reactive hydrogen ion and bicarbonate potentially initiates a complex series of reactions with aquifer fluids and formation rocks that serves to fix CO2 in aqueous and mineral phases (Rosenbauer et al., 2005; Rosenbauer, 2006; Oelkers and Cole, 2008). A temperature-dependent dissociation constant K can be defined for Equation 3.2 (Equation 3.2a): aH+ · aHCO–3 g H+ [H + ] · g HCO–3 [HC –3 = [3.2a] aH2 CO3 g H2 CO3 2 3CO ] [H CO ] where a is activity, [X] is concentration, and g is an activity coefficient. Calculations of log K (Equation 3.2a) using the geochemical program SUPCRT92 (Johnson et al., 1992) show that a maximum of dissociation for Reaction 3.2 occurs at about 50 °C, above which log K decreases continuously with increasing temperature such that an initially weak acid becomes increasingly weaker at elevated temperature (Fig. 3.7). Thus, at low temperatures, the increased availability of H+ might be expected to cause log K =
–3 [H+]
[H2CO3] = 1.0 molal
–4
log K or log m
–5
–6 K1 –
–7
–8 0
H2CO3 = H+ + HCO3
50
100 150 Temperature (°C)
200
3.7 Log K of the dissociation of carbonic acid versus temperature and associated log m of the concentration of hydrogen ion showing a maximum in the dissociation and hydrogen concentration at ~50 °C, indicating maximum acidity at 50 °C. Data calculated from SUPCRT92 (Johnson et al., 1992).
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
71
higher rates of wall-rock hydrolysis, in spite of expected temperature-related kinetic effects. Experiments reacting rhyolite with CO2 charged waters indeed showed a much greater degree of rock alteration at 200 °C versus 350 °C (Bischoff and Rosenbauer, 1996). The types of reactions between CO2 saturated fluids and formation rocks are dependent on the mineralogy of the formation and the composition of the pore fluids (Rosenbauer et al., 2005). For example, in a limestone matrix, calcite dissolution in response to the increased acidity produced by the dissociation of carbonic acid (Equation 3.3), CaCO3 + CO2 + H2O Æ Ca+2 + 2HCO3–
[3.3]
causes one additional mole of CO2 to be stored as bicarbonate relative to the simple aqueous solubility of CO2 and is an example of the ionic trapping of CO2 (Gunter et al., 1993, 2000, 2004; Assayag et al., 2009). It is, however, important to note that only one of the two moles of bicarbonate produced by this reaction is from the injected CO2. The second mole is produced from dissolution of a mole of carbonate rock. This reaction occurred rapidly in laboratory experiments that reacted CO2 saturated brine with limestone rocks (Rosenbauer et al., 2005). Similar reactions exist for the dissolution of other Mg- and Fe-bearing carbonates. Most carbonates have a retrograde solubility and are therefore more thermodynamically stable at elevated temperature so Reaction 3.3 is favored at lower temperatures (Fig. 3.8). The permeability –8 –2
Calcite = Ca+2 + CO3
–8.5
log K
–9
–9.5
–10
–10.5
–11
0
50
100 150 Temperature (°C)
200
250
3.8 Temperature dependence of the solubility of calcite indicates retrograde solubility; calcite is more stable at elevated temperature and more likely to precipitate from solution. Data calculated from SUPCRT92 (Johnson et al., 1992).
© Woodhead Publishing Limited, 2010
72
Developments and innovation in CCS technology
of dolomite-limestone is typically lower (range ~0.01–0.1 md, Bear, 1988) than sandstones (range 20–3500 md, e.g. Bertier et al., 2006). So the effect of Reaction 3.3 is to promote mineral dissolution near the injection site, enhancing porosity and permeability and facilitating injection. A porosity change of ~15 % was noted in laboratory experiments reacting CO2 saturated brine with limestone (Rosenbauer et al., 2005).
3.3.5 Mineral trapping Under the right geologic setting, a portion of the injected CO2 may be converted to carbonate minerals. Mineral trapping is advantageous because it increases storage capacities and immobilizes CO2 for very long periods (Gunter et al., 1993, 1997; Perkins and Gunter, 1995; Oelkers and Schott, 2005), although precipitation of minerals within porespace especially near the injection site can dramatically decrease permeability and hamper further injection (e.g. Shiraki and Dunn, 2000). The extent to which mineral trapping is capable of storing CO2 is directly dependent on rock type, sedimentary structure, mineralogy, and diffusion. Dissolution of primary and precipitation of secondary minerals affect porosity and permeability and consequently the flow regime (Piri et al., 2005). The efficiency of the CO2 geological storage in sedimentary basins thus depends on many factors, among the most important being formation water composition, lithological heterogeneity, and mineralogy. Host rock composed of silicates can be dissolved by CO2-rich aqueous solution, and carbonates, other silicates, clays, and silica can be produced. For example, reactions of CO2 saturated aquifer fluids with arkosic sandstone illustrate the mineral trapping of CO2 by silicate dissolution, in particular the anorthitic component of plagioclase (Equation 3.4),
2H+ + CaAl2Si2O8(anorthite) + H2O Æ Ca+2
+ Al2Si2O5(OH)4 (kaolinite)
[3.4]
and the subsequent precipitation of calcite (Equation 3.5).
Ca+2 + HCO3– Æ CaCO3 + H+
[3.5]
The solubility product (log Ksp) of the net reaction (Equation 3.6) decreases with increasing temperature (Johnson et al., 1992),
CaAl2Si2O8(anorthite) + H2CO3 + H2O Æ CaCO3(calcite)
+ Al2Si2O5(OH)4(kaolinite)
[3.6]
resulting in competing effects of favorable thermodynamics at low temperature versus kinetic considerations that favor reaction rates at elevated temperature
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
73
(Fig. 3.9). The dissolution of Na-rich feldspar (albite) to form dawsonite (Equation 3.7) NaAlSi3O8 + H2CO3 = NaAl(CO3)(OH)2 + 3SiO2
[3.7]
is independent of the Na/H+ as it depends only on the fugacity of CO2 (fCO2). The precipitation of amorphous silica in lieu of quartz (Equation 3.7) may significantly reduce porosity and permeability of the formation due to its 28 % greater molar volume (Cipolli et al., 2004). Dawsonite formation is also thermodynamically favored from high-salinity CO2 charged aqueous solutions (Worden, 2006). Similar reactions can be derived for other illitic (Mg-bearing), or glauconitic (Fe II-bearing) sediments, (e.g. Gunter et al., 1997, 2000; Johnson et al., 2001). In contrast to reactions with carbonate minerals, every mole of bicarbonate produced by the dissolution of silicate mineral is derived from CO2. However, most of these reactions are thought to be comparatively slow because they depend on the dissolution of silicate minerals. The overall impact on the reservoir from mineral trapping by silicate reaction may not be realized for tens to hundreds of years or longer. Laboratory experiments reacting CO 2 saturated brine with arkosic sandstone (120 °C) or shale (200 °C) indeed show that silicate reaction kinetics are slow but occur on measurable timescales (Kaszuba et al., 2003; Rosenbauer et al., 2005). Other workers (Gunter et al., 1997; Sass et al., 2002; Gupta et al., 2000; Bateman et al., 2005; Giammar et al., 2005) noted only limited amount of reaction of CO2 with pure mineral 14
Anorthite + CO2 + H2O = Kaolinite + calcite
12
log K
10
8
6 4
2
0
50
100 150 Temperature (°C)
200
250
3.9 Temperature dependence of the reaction of anorthite with dissolved CO2 to produce calcite and kaolinite. This reaction is thermodynamically favored at lower temperature.
© Woodhead Publishing Limited, 2010
74
Developments and innovation in CCS technology
phases (anorthite, glauconite, or fosterite) or sandstones at 50° and 150 °C and low pressure. Dissolution rates of fosterite determined by flow-through reactor experiments agreed well with similar batch-type experiments and published literature values (Bruant et al., 20003). Recent work on the dissolution of anorthite in the presence of CO2, based on mineral surface measurements demonstrated an initial rapid transitory rate of dissolution followed by a slower steady state (Sorai et al., 2007) resulting in porosity increases of reservoir rock of about 2 %. Oelkers and Schott (2005) suggested that experimental dissolution rates of metal-bearing silicates (Carrol and Knauss, 2005; Golubev et al., 2005) and carbonates (Pokrovsky et al. (2005) can be accurately modeled (Oelkers et al. 1994; Pokrovsky et al., 1999) by simply taking account of the presence of CO2 on solution pH. Ferriciron-bearing saline formations such as redbeds have been proposed as a mineral trap for CO2 (Palandri and Kharaka, 2004, 2005). Sulfur dioxide (SO2), a common component of flue gas, can be used to reduce ferric iron in these deposits to ferrous iron resulting in the precipitation of the iron carbonate, siderite (Equation 3.8):
Fe2O3 + 2CO2(g) + SO2(g) + H2O = 2FeCO3 + H2SO4
[3.8]
This reaction was shown to proceed experimentally at 150 °C, 300 bar (Palandri et al., 2004, 2005). Other experimental results (Rosenbauer et al., 2005) and reactive transport modeling (Knauss et al., 2002, 2005) point out that the presence of SO2 in Ca-rich brines and oxidizing environments significantly alters the quantity of CO2 trapped in carbonate minerals due to the formation of anhydrite and very low pH pore fluids. Reactions involving supercritical CO2 and carbonic acid with aquifer fluids and formation rocks are thus many and varied. In general, CO2 interaction causes the dissolution of carbonate phases in limestones and the dissolution of silicates and precipitation of carbonates in plagiocalse-rich arkosic sandstones, but none of these reactions can be taken in isolation. Multiphase systems are extremely complex; compositional changes can take different pathways and different chemical reactions can occur simultaneously. Reaction path modeling helps describe solution properties and mineral solution equilibria. Experimental studies are useful for providing and constraining input to coupled geochemical and mass transport models aimed at predicting CO2 behavior and the consequences of CO2 injection in different types of subsurface systems.
3.4
Modeling of carbon dioxide (CO2) sequestration
3.4.1 History Mathematical models and numerical simulation tools play an important role in evaluating the feasibility of CO2 storage in subsurface brine reservoirs. © Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
75
The basis of geochemical modeling of aqueous electrolyte solutions is the computation of activity coefficients, and hence activities, of relevant solutes and the solvent water through maintenance of mass and charge balances and equilibrium relations. The Debye–Huckle method (Debye and Hückel, 1923a,b) of calculating activity coefficients provided a theoretical understanding and the HKF model (Helgeson et al., 1981) and the software program SUPCRT92 (Johnson et al., 1992) provided a way to calculate the thermodynamic properties of minerals, gases, and aqueous species at elevated temperature and pressure. Early conceptual and numerical models, for example: SOLMINEQ (Kharaka and Barnes, 1973), EQ3/EQ6 (Wolery, 1979, 1992), PHREEQE (Parkhurst et al., 1980) and SOLVEQ (Reed, 1982), utilized these principles to calculate the distribution of aqueous species and mineral equilibria in a variety of natural and experimental solutions. A theoretical model of concentrated electrolytes based on a virial coefficient approach was developed by Pitzer (1973, 1975), implemented by Harvie and Weare (1980) and software created by Kharaka et al. (1988) (SOLMIN 88), Plummer et al. (1988) (PHRQPITZ), and Parkhurst (1995) (PHREEQC) to describe solution properties and mineral solution equilibria at high ionic strength. Later, the Pitzer equations were extended to aqueous solutions of NaCl and CO2 at elevated temperature (Corti et al., 1990). During CO2 injection, geochemical processes are strongly affected by physical processes such as multiphase fluid flow and solute transport. Accurate geochemical simulations therefore require a computational capability that couples multiphase-flow processes with kinetically controlled geochemical processes. State of the art modeling has advanced from separate thermodynamically-derived equilibria-based numerical models for batch process simulation to fully coupled simulation programs for non-isothermal reactive geochemical transport in variable saturated geologic media. Integrated reaction path and solute transport models such as TOUGHREACT (Xu and Pruess, 1998; Xu et al., 2004b) and updated versions of EQ3/6 (Wolery and Daveler, 1992) couple complex geochemical, hydrological, and mechanical interactions following CO2 injection (Marini, 2007, p. 349). Models that include physico-chemical processes, chemical reaction, fluid flow, heat transfer, and mechanical properties vastly improve predictive abilities of reservoir simulations. These and other models have been utilized to investigate CO2 injection, storage, and sequestration processes and analyze the coupled mechanisms that lead to structural, residual, solubility, and mineral trapping. The following are representative examples of reactive transport modeling of different reservoir types.
© Woodhead Publishing Limited, 2010
76
Developments and innovation in CCS technology
3.4.2 Sedimentary basins Sandstone aquifers The Utsira Sand, Sleipner, northern North Sea. One of the first modeling exercises simulated CO2 injection into the Utsira formation at StatoilHydro’s North-Sea Sleipner facility (Johnson et al., 2001) where the subsurface is well characterized. Johnson et al. (2001) used an integrated approach combining reactive transport simulators NUFT (Nitao, 1998) and GIMRT/OS3D (Steefel and Yabusaki, 1996; Steefel, 2001, 2008), supporting geochemical software SUPCRT92 (Johnson et al., 1992; Shock, 1998), thermodynamic-kinetic databases GEMBOCHS (Johnson and Lundeen, 1994a,b), and a graphic utility Xtool (Daveler, 1998). They created numeric simulations of three distinct sequestration scenarios, differing in the extent of intra-aquifer shale units and lateral permeability. Results of this study showed the relationship of intra-aquifer permeability to solubility and mineral trapping and the importance of the overlying shale caprock to long-term storage. Gaus et al. (2005) also performed PHREEQC (Parkhurst, 1995) 1D diffusive reactive transport simulations of dissolved CO2 in the caprock of the Utsira aquifer (Sleipner project) and concluded that plagioclase feldspar in the shale alters to dawsonite, disordered dolomite, and calcite. Glauconitic sandstone of the Alberta Basin. Two contrasting reaction path models of the potential CO2 sequestration in the glauconitic sandstone aquifer of the Alberta Basin, Western Canada have been proposed (Marini, 2007, p. 396). In fluids super-saturated with CO2, Gunter et al. (1997), utilizing PATHARCH (Perkins and Gunter, 1995a) and anorthite/albite and muscovite proxies for oligoclase and illite, modeled the alteration of primary glauconite (as annite) to siderite. At a fixed under-saturated PCO2, with the same proxies, Gunter et al. (2000), again utilizing PATHARCH, modeled the almost complete consumption of CO2 in the precipitation of siderite, calcite, and dolomite, showing the high reactivity of Fe+2-bearing silicates to CO2. In contrast, Xu et al. (2000, 2004a), utilizing TOUGHREACT and the actual mineral assemblage of this formation, modeled precipitation of the CO2-bearing phases as mainly siderite and ankerite with some dawsonite and dolomite. Later, Strazisar et al. (2006) investigated the periphery of this system at the CO2 reaction front away from the injection site. These investigators point out that precipitation reactions are more likely to occur downstream of the injection site, where the mineral assemblage buffers the pH at higher levels. Utilizing PHREEQC, they found that CO2 was trapped initially in siderite from the pH-dependent dissolution of annite and coupled with kaolinite dissolution and K-feldspar precipitation. As the CO2 front migrated further, K-feldspar dissolved and calcite and dolomite precipitated. They concluded
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
77
that most of the CO2 is trapped in siderite, consistent with previous studies (Gunter et al., 1997, 2000; Xu et al., 2000, 2004a). Deep sand aquifers of the Powder River Basin of Wyoming. McPherson and Lichtner (2001), utilizing TOUGH2 (Pruess et al., 1999), carried out a numerical model that included multiphase fluid flow of sustained injection of CO2 into the deep sand aquifers of the Powder River Basin of Wyoming. Their calculated CO2 residence time and migration rates show the unintended impact of wide-scale brine displacement out of the target aquifer and potentially spreading into adjacent sealing layers. Tertiary Gulf Coast sediments: The Frio, Vicksberg and Wilcox formations. Apps (1996) first carried out batch geochemical modeling of Gulf Coast sediments as a potential repository basis for the deep injection disposal of hazardous and industrial wastes. Xu et al. (2004a,b), utilizing TOUGHREACT, constructed a reactive transport model of the Frio Formation for potential CO2 sequestration. These investigators incorporated in their model the high organic matter (kerogen) and salt content from diapirs that are characteristic of these sediments, along with a representative mineral assemblage at a CO2 injection pressure of 260 bars. Dawsonite and ankerite were the primary CO2-bearing products; calcite and siderite were modeled to initially precipitate then dissolve. Xu et al. (2005), again utilizing TOUGHREACT, focused on the diffusion of CO2 and acidity into the caprock and found carbonate precipitation extending into the shale. Knauss et al. (2005), utilizing the geochemical software CRUNCH, another computer program for simulating multicomponent multidimensional reactive transport in porous media (Steefel, 2001), investigated the effects of ancillary contaminant gases in the Frio CO2 injection stream. This work concluded that only SO2 might have an impact on reaction processes due to the resulting extremely low pH. Permian White Rims sandstone. White et al. (2005), utilizing ChemTOUGH (White, 1995), simulated CO2 injection into this reservoir rock, situated beneath the Hunter Power plant in central Utah. These investigators found that calcite and dolomite precipitated but predicted that after 1000 years about 17 % of the CO2 had leaked to the ground surface. Carbonate aquifers Tuscan Nappe limestone formation. Cantucci et al. (2008) utilized a modified version of the PRHEEQC (V2.11) software package to investigate the shortand long-term consequences of CO2 storage in an offshore Italian porous carbonate saline aquifer, the Tuscan Nappe limestone formation. Numeric
© Woodhead Publishing Limited, 2010
78
Developments and innovation in CCS technology
simulations of the fate of CO2 injected into the saline aquifer suggest that solubility trapping prevails within the first 100 years. Nisku carbonate aquifer of the Alberta Basin. Gunter et al. (2000) modeled the interaction of under-saturated CO2 charged fluid with carbonate (calcite, dolomite) rocks of the Nisku and found rapid dissolution of calcite and precipitation of dolomite. Serpentine aquifers Serpentinites of the Gruppo di Voltri (Genova, Italy). The high Mg content of serpentinites has the potential for fixing CO2 as magnesite. Cipolli et al. (2004) carried out reaction path modeling of potential CO2 sequestration in deep aquifers hosted by the serpentinized ultramafic rocks of the southern Piedmont, Italy. These investigators concluded that the capacity for CO2 sequestration is high through dissolution of serpentine and precipitation of magnesite and chalcedony but cautioned about the progressive loss of porosity, especially if amorphous silica precipitates instead of chalcedony. They also point out that reactant armoring may occur during precipitation reactions. Not often noted in the literature, this phenomenon is seen in experimental systems.
3.4.3 Model inter-comparison Pruess et al. (2001a,b, 2002, 2004; Pruess, 2005) initiated and carried out an inter-comparison study of reactive transport models on test sets of representative CO2 sequestration in potential reservoirs. Results were quantitatively similar, indicating broad agreement among the models. Allen et al. (2005) conclude that models are only as reliable as the data and reaction scheme upon which they are based and emphasize the importance of pressure corrections to thermodynamic data. Model inter-comparisons indicate that failure to adjust all equilibrium constants to account for elevated CO 2 pressures results in significant errors in both solubility and mineral formation estimates (Allen et al., 2005). Moreover, Bateman et al. (2005) concluded that model predictions tend to overestimate the degree of reaction compared with experimental results. For example, some mineral phases such as dawsonite that are predicted to form in large quantities by models are not observed in the experimental system. These authors highlight the need for appropriate thermodynamic and kinetic data to address these discrepancies. The most robust analyses of CO2 sequestration in potential reservoirs incorporate a combination of experimental, model, and field evidence that often requires large-scale pilot project support (Fig. 3.10).
© Woodhead Publishing Limited, 2010
3
3 3 1
3 1 3
© Woodhead Publishing Limited, 2010
3
3
1 2 3 3
1
2
Other
3 Unknown
79
3.10 Geologic storage and related projects in operation or proposed around the world. Most are research, development or demonstration projects. Some are commercial operations (image source: CO2CRC).
Carbon dioxide (CO2) sequestration in deep saline aquifers
3
80
3.5
Developments and innovation in CCS technology
Carbon dioxide (CO2) sequestration pilot sites
3.5.1 The Utsira Sand, Sleipner, northern North Sea The Sleipner project is the prototypical test site for CO2 sequestration into a deep saline aquifer. It is the world’s first commercial CO2 capture and storage project (Gale et al., 2001), motivated by the high tax Norway imposes on offshore oil and gas activity. Started in September 1996, it sequesters about one million metric tons of CO2 each year into the Utsira formation at StatoilHydro’s North-Sea Sleipner facility (Chadwick et al., 2004, 2006). As of 2009, about 10 Mt CO2 had been stored in Utsira at a cost of $17/t (Hermanrud et al., 2009) with a final target of 20 Mt. The injection site lies 1000 m below the seafloor and is composed largely of uncemented finegrained sand, primarily quartz (75 %) with some feldspar (13 %) (Chadwick et al., 2004) (Fig. 3.11). Porosity of the Utsira sand is ~30 %, locally up to 42 % (Chadwick et al., 2004). The caprocks are non-organic mudstones composed of 30 % quartz, 30 % mica, and 14 % kaolinite. As of 2004, the plume area extended to 2.8 km2 and the maximum distance from the injection site was 2560 m (Torp and Gale, 2004). Extensive seismic monitoring was carried out by Saline Aquifer CO2 Storage (SACS) (Fig. 3.12), and these studies indicated only limited interaction with formation rocks (Torp and Gale, 2004). Although the activities of SACS ended in 2002, part of its effort continues in the EU-co-funded project CO2STORE, a research project with 19 participants from industry and research institutes, whose aim is to prepare the ground for widespread underground storage of CO2 in aquifers. Sleipner has been and continues to be the subject of much geophysical study (i.e. Arts et al., 2008; Hermanrud et al., 2009.
3.5.2 The Snøhvit project The Snøhvit plant in the Barents Sea is another StatoilHydro commercial project in which CO2 is captured and stored. In this case, the target formation is below a gas reservoir in the Tubåsen sandstone formation (Kårstad, 2002). This case deals with StatoilHydro’s Snøhvit natural gas field and liquid natural gas (LNG) facility in northern Norway. Gas production began at Snøhvit in 2007 and CO2 storage in April 2008 (Estublier and Lackner, 2009). At full capacity, 700 000 t of CO2 is expected to be stored per year. The field consists of a fully subsea offshore development in the Barents Sea, a 160 km pipeline to shore and a liquification plant for LNG (Kårstad, 2002). The Tubåsen sandstone is 45–75 m thick with an overlying shale cap (Maldal and Tappel, 2004).
© Woodhead Publishing Limited, 2010
© Woodhead Publishing Limited, 2010
Utsira Norway Formation Utsira formation
Sleipner
800 -1000 m depth Scotland CO 2 injection
Gas production
Gas field (3000 m)
81
3.11 Schematic diagram depicting gas production at depth and re-injection of CO 2 into the Utsira sand at StatoilHydro’s NorthSea Sleipner facility. Shown also is a location map for the facility in the North Sea (image courtesy of StatoilHydro, ASA).
Carbon dioxide (CO2) sequestration in deep saline aquifers
Sleipner platform
82
8.4 Mt CO2 (2006)
Top of Utsira sand CO2
Base of Utsira sand 2 km
CO2
200 m
© Woodhead Publishing Limited, 2010
4.3 Mt CO2 (2001)
3.12 Seismic monitoring of Sleipner CO2 injection plume. Time-lapse seismic images showing changes in reflectivity due to injected CO2. Arrows indicate CO2 accumulations (modified from original image created by Ola Eiken, StatoilHydro, ASA).
Developments and innovation in CCS technology
Pre-injection (1994)
Carbon dioxide (CO2) sequestration in deep saline aquifers
83
3.5.3 The Frio formation The first US sequestration field experiment was completed in 2008 at the Frio site located within the South Liberty oil field, near Houston, Texas (Doughty et al., 2002, 2007; Hovorka et al., 2006, 2009). Injection and updip observation wells perforated the target Frio ‘C’ sandstone at ~ 1540 m, above a zone of oil production at 2900 m (Kharaka et al., 2006b). The Frio ‘C’ unit is a poorly cemented subarkosic sandstone dominantly comprising fine grained quartz with minor amounts of illite/smectite, feldspar, and calcite with a porosity of 32 % and permeability of 2–3 darcys. (Kharaka et al., 2006b). The caprock is the regional Miocene–Oligocene Anahuac Shale (Hovorka et al., 2005). Aquifer fluids are 100 ppt NaCl at a temperature of 65 °C (Kharaka et al., 2006b). A test injection of 1600 t CO2 was carried out while monitoring downhole pressure, temperature, and fluid compositions. Intensive fluid sampling and analyses by methods described in Kharaka and Hanor (2007) showed large pH decreases and increases in concentrations of HCO3–, Ca+2, Fe+2, and Mn+2, likely resulting from the rapid dissolution of carbonate and iron oxyhydroxide minerals in the Frio Formation (Kharaka et al., 2006a,b). The time to CO2 breakthrough and the spatial distribution of the CO2 plume in the subsurface, measured with cross-well tomography and wireline logs, compare well with values and patterns predicted by transport modeling using TOUGH2 (Hovorka et al., 2005) (Fig. 3.13)
3.5.4 Other carbon dioxide (CO2) sequestration projects Other international CO2 sequestration demonstration and pilot projects (Fig. 3.10) either online or planned (IPCC, 2005) include the Minami-Nagaoka in Japan, the Otway and Gorgon in Australia, and the Ketzin in Germany. The Minami-Nagaoka gas field in Nagaoka City, 200 km north of Tokyo is the first pilot CO2 injection site in Japan. The target reservoir is the early Pleistocene sandstone formation that lies 3000 m above the gas reservoir and 1100 m below the surface. About 10 000 t CO2 were injected from 2003 through 2005 (Tanase and Yoshimura, 2008). The CO2CRC Otway Project, located in southwest Victoria is Australia’s first demonstration of deep geological storage of CO2. It will inject CO2 obtained from the Buttress gas field into a nearby depleted gas field in the Waarre Formation at depth of ~1700 m. Although technically not CO2 storage in a deep saline aquifer, the Otway Project is one of the largest research and geologic sequestration demonstration projects with a planned injection of about 100 000 t CO2 by 2010 (Sharma et al., 2009). The Gorgon Project, located in northwest Australia, will extract CO2 from produced gas within the Greater Gorgon gas fields prior to liquefaction into LNG and re-inject it into the Dupuy Formation located 2000 m beneath
© Woodhead Publishing Limited, 2010
84
Developments and innovation in CCS technology (a)
Modeled CO2 plume Obs Nov 30, 2004
75 ft
Inj
sand of C Top
107
ft
Sg: 0 0.05 0.1 0.15 0.2 0.25 0.3 Injection well
(b)
0
Distance (m) 10 20
30
Observation well
Depth (ft below GL)
4950
5000
5050 Sigma
Sigma –1.0 –0.5 0 0.5 Change in velocity (km/s)
3.13 (a) CO2 plume in the sub-surface Frio after CO2 injection, measured with cross-well tomography and wireline logs; (b) CO2 plume in the subsurface Frio predicted by transport modeling using TOUGH2 (Hovorka et al., 2005) (image modified from original created by Christine Doughty and Thomas M. Daley in Hovorka et al. (2006), reprinted with kind permission of Springer Science+Business Media).
Barrow Island. The volume of reservoir CO2 to be re-injected is about 100 Mt (Flett et al., 2008). Thirteen CCS projects involving the capture and/or storage of CO2 in Australia are currently proposed or underway. The CO2
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
85
storage site near the town of Ketzin in Germany is the first onshore pilot site in Europe. The target formation is the Triassic Stuttgart silt and sandstones at a depth of 700 m. Injection started in June 2008 and will continue for two years. A maximum of 60 000 t CO2 will be injected. Extensive geophysical and geochemical monitoring is being carried out to follow the spread of the CO2 plume (Schilling et al., 2008). Also, each of the seven US Department of Energy (DOE) Regional Carbon Sequestration Partnerships has plans for CO2 capture and storage projects in deep geologic formations. These include tertiary sandstones in the San Joaquin Valley of California, the Wingate (Jurassic–Triassic-aged) sandstone in the southwest USA, the deep carbonate saline formation in the Williston Basin in North Dakota, the Mount Simon sandstone formation in central Illinois, the Tuscaloosa Massive Sandstone in Mississippi and Louisiana, and the Nugget Sandstone formation in southwest Wyoming.
3.5.5 Weyburn The IEA Weyburn CO2 Monitoring and Storage project is neither a deep saline aquifer site nor technically even a CO2 sequestration site. It is a large-scale commercial CO2–enhanced oil recovery (EOR) site that, under the management of the Petroleum Technology Research Center (PTRC), has provided a wealth of geophysical and geochemical research that is applicable to CO2 sequestration in saline aquifers. In the Weyburn EOR Project, located in Prairie Province of Saskatchewan, Canada, CO2 has been used to increase recovery of oil from the carbonate Midale Beds of the Mississippian Charles Formation, where about 3 billion m3 of supercritical CO2 have been injected since 2000 at a rate of 5000 t/day (Riding and Rochelle, 2005; Cantucci et al., 2009). Carbon dioxide is obtained from the Dakota Gasification Company, near Beulah ND and transported 320 km via pipeline to the Weyburn and Midale oil fields where it is injected with water at 800 m depth. A mixture of oil, water, and CO2 is extracted; extracted CO2 is re-injected. The database obtained at this site has provided an opportunity to monitor dynamic reservoir response and study effective trapping mechanisms, seals, hydraulic isolation, hydrogeological regime, and pathways for migration along faults and fractures (Preston et al., 2009). Seismic monitoring has provided detailed CO2 plume distribution and containment within the reservoir (Davis et al., 2003; Preston et al., 2009). Changes in the fluid chemistry and isotopic composition of the produced fluid, pre- and post-injection, provide evidence of dissolution of injected CO2, an increase of total dissolved solids, and both dissolution and precipitation of carbonate minerals (Emberley et al., 2004, 2005; Perez et al., 2006; Mayer et al., 2008). Most of the injected CO2 exists in a supercritical state but has reacted with the reservoir rock sufficiently to mask some of the strontium isotope signature caused by 40 years of water
© Woodhead Publishing Limited, 2010
86
Developments and innovation in CCS technology
flooding (Riding and Rochelle, 2009). Geochemical modeling suggests that eventually most of the CO2 will be stored by solubility and mineral trapping (via dawsonite precipitation) (Cantucci et al., 2009). Pre- and post-injection soil gas surveys have not found any evidence for leakage of the injected CO2 to surface (Riding and Rochelle, 2009).
3.6
Future trends
The geologic storage of CO2 in saline aquifers has proven technologically feasible (Michael et al., 2009). Moreover, saline aquifers contain the volume necessary to sequester a large fraction of our fossil fuel-derived carbon output (Burruss et al., 2009), but the greatest challenges to the commercial-scale exploitation of saline aquifers still lie in the future. The costs, environmental risks, legal framework, and social acceptance of CO2 sequestration in saline aquifers represent increasingly important challenges as we look toward the future.
3.6.1 Costs of saline aquifer sequestration Saline aquifers only rarely contain exploitable hydrocarbon resources. So the primary economic incentive for industry to sequester CO2 in saline aquifers is determined by the balance between the price of carbon abatement and the cost of operations including assumed risk of leakage and environmental damage. Current estimates of the costs associated with saline aquifer sequestration depend on properties of the rocks and the industrial capacity of the locations, including access to wells, costs of drilling new wells, and the cost of transport to the disposal site. Bock et al. (2003) estimate a base case scenario cost of approximately $3/t CO2, though the estimates vary by an order of magnitude depending on the assumed well density and depth. Another estimate by Hendriks et al. (2004) depicts the depth-dependence of costs associated with both onshore and offshore operations (Fig. 3.14). The difference in offshore operation costs renders offshore operations generally much more expensive, although the environmental and public risk of leakage are greatly reduced. Currently the costs of EOR, ECBM, and disposal in depleted hydrocarbon reservoirs are far lower than the cost of saline aquifer sequestration (Bock et al., 2003).
3.6.2 Environmental safety and concerns The environmental concerns for saline aquifer sequestration are shared with many other sequestration sites. Importantly, the injection into saline formations has the potential to displace brines into freshwater resources. Given the acidic character of these brines, there may also be the potential for
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
87
12
10
8 Cost (7/t)
Offshore 6 onshore 4
2
0 1000
1500
2000 Depth of injection (m)
2500
3000
3.14 Projected transport and operating costs of saline aquifer injection into onshore and offshore reservoirs from data in Hendriks et al. (2004).
liberation of heavy metals and organic constituents from formation materials (Kharaka et al., 2006b; Kolak and Burruss, 2006). As mentioned previously, high injection pressures can induce hydraulic fracturing that increases the likelihood of brine expulsion into overlying formations. Another important concern is the escape of the CO2 plume or charged aqueous fluid to the surface along faults, fractures, or through permeable strata. In addition to negating the economic benefit of sequestration, the degassing of CO2 at the surface can produce deadly concentrations in topographic depressions such as valleys and household basements.
3.6.3 Policy considerations Unlike hydrocarbon reservoirs where mineral rights are well established, there are few laws related to the ownership of porespaces and porefluids in saline aquifers (IPCC, 2005). This legal uncertainty is problematic when considering the future assumption of risk of leakage and associated environmental damage. Clearly, local and national laws are required to clarify these concerns. In the USA, there are currently proposals under consideration to establish a
© Woodhead Publishing Limited, 2010
88
Developments and innovation in CCS technology
risk-pooling entity to absorb the costs of monitoring and verification, and the risk of environmental damage (HR 2454, 2009).
3.6.4 Social acceptance While the public increasingly supports action to mitigate climate change, public awareness is still minimal on the subject of CO2 capture and sequestration (Curry et al., 2005). Perhaps the greatest concern will be convincing the public to accept the significant industrial footprint required to implement large-scale sequestration projects. Sequestration into depleted oil and gas reservoirs or coalbed formations has the advantage of an already significant industrial footprint. For saline aquifers, there is unlikely to be a precedent industrial footprint. Thus, public skepticism and the ubiquitous ‘not in my back yard’ conundrum that has plagued other waste disposal projects should not be ignored (Ibitayo, 2002). Given these concerns, it will be important to incentivise landowner cooperation (IPCC, 2005) and to educate the public about the inherent and future risks.
3.7
Conclusions
Deep saline aquifers remain a focus as potential repositories for the geologic storage of CO2 in part due to their widespread occurrence, high capacity, and proximity to point sources. Various trapping mechanisms offer the possibility of long-term storage of the injected CO2. Methods are improving for estimating their geologic and hydrologic properties, but much of our knowledge of the behavior of CO2 in the subsurface is inferred from geochemical laboratory experiments and reactive transport modeling. Demonstration, pilot, and fullscale commercial CO2 sequestration projects such as the Sleipner Project provide invaluable data to the scientific research community and to industry to further our understanding of the geochemical, hydrological, and physical processes involved with supercritical CO2, CO2-charged fluids, and host formations.
3.8
Acknowledgements
We thank Yousif Kharaka, Steve Bouzalakos and Anna Kaminska who provided thorough and thoughtful reviews of earlier versions of this manuscript.
3.9
References
Albritton D L and Meira Filho L G (2001) Climate Change 2001: The Scientific Basis; Contribution of Working Group I to the Third Assessment Report of the Intergovernmental Panel on Climate Change – Technical Summary. IPCC, Geneva, Switzerland.
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
89
Alfredssom H A, Hardarson B S, Franzson H and Gislason S R (2008) CO2 sequestration in basaltic rock at the Hellisheidi site in SW Iceland: stratigraphy and chemical composition of the rocks at the injection site, Mineralogical Magazine, 72(1), 1–5. Allen M R, Stott P A, Mitchell J F B, Schnur R and Delworth T L (2000) Quantifying the uncertainty in forecasts of anthropogenic climate change, Nature, 407, 617–620. Allen D E, Strazisar B R, Soong Y and Hedges S W (2005) Modeling carbon dioxide sequestration in saline aquifers: Significance of elevated pressures and salinities, Fuel Processing Technology, 86(14–15), 1569–1580. Apps J A (1996) An approach to modeling of the chemistry of waste fluid disposal in deep saline aquifers, in Apps, J.A., Tsang, C.F. (eds), Deep Injection Disposal of Hazardous and Industrial Waste: Scientific and Engineering Aspects. Academic Press, San Diego, Ca, 465–488. Arts R, Chadwick A, Eiken O, Thibeau S and Nooner S (2008) Ten years’ experience of monitoring CO2 injection in the Utsira Sand at Sleipner, offshore Norway, First Break, 26, 65–72. Assayag N, Matter J, Ader M, Goldberg D and Agrinier P (2009) CO2 ionic trapping at meta-sedimentary aquifer, following a CO2 injection push-pull test, in Gale J, Herzog H and Braitsch J (eds), Greenhouse Gas Control Technologies 9, Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies (GHGT9), Energy Procedia, 1, 2357–2360. Aya I, Yamane K and Nariai H (1997) Solubility of CO2 and density of CO2 hydrate at 30 Mpa, Energy, 22, 263–271. Bachu S (2000) Sequestration of CO2 in geological media: criteria and approach for site selection in response to climate change, Energy Conversion and Management, 41, 953–970. Bachu S (2003) Screening and ranking of sedimentary basins for sequestration of CO2 in geological media in response to climate change, Environmental Geology, 44, 277–289. Bachu S, Gunter W D and Perkins E H (1994) Aquifer disposal of CO2: hydrodynamic and mineral trapping, Energy Conversion and Management, 35, 269–279. Bachu S, Bonijoly D, Bradshaw J, Burruss R, Holloway S, Christensen N P and Mathiassen O M (2007) CO2 storage capacity estimation: methodology and gaps, International Journal of Greenhouse Gas Control, 1(4), 430–443. Barton P B and Chou I (1993) Calculation of the vapor-saturated liquidus for the NaCl– CO2–H2O system, Geochimica et Cosmochimica Acta, 57, 2715–2723. Bateman K, Turner G, Pearce J M, Noy D J, Birchall D and Rochelle C A (2005) Largescale column experiment: Study of CO2, porewater, rock reactions and model test case, Oil & Gas Science and Technology – Rev. IFP, 60(1), 161–175. Bear J (1988) Dynamics of Fluids in Porous Media. Courier Dover Publications, Mineola, NY. Beecy D J and Kuuskraa V A (2001) Status of U.S. geologic carbon sequestration research and technology, Environmental Geosciences, 8, 152–159. Bentham M and Kirby G (2005) CO2 storage in saline aquifers, Oil & Gas Science and Technology – Rev. IFP, 60(3), 559–567. Benson S M and Cole D R (2008) CO2 Sequestration in deep sedimentary formations, Elements, 4, 325–331. Bergman P D and Winter E M (1995) Disposal of carbon dioxide in aquifers in the U.S., Energy Conversion and Management, 36, 523–526. Bertier P, Swennen R, Laenen B, Lagrou D and Dreesen R (2006) Experimental
© Woodhead Publishing Limited, 2010
90
Developments and innovation in CCS technology
identification of CO2–water–rock interactions caused by sequestration of CO2 in Westphalian and Buntsandstein sandstones of the Campine Basin (NE-Belgium), Journal of Geochemical Exploration, 89, 10–14. Bischoff J L and Rosenbauer R J (1996) The alteration of rhyolite in CO2 charged water at 200 and 350 °C: The unreactivity of CO2 at higher temperature, Geochimica et Cosmochimica Acta, 60(1), 7–16. Blencoe J G, Naney M T and Anovitz L M (2001) The CO2-H2O system: III. A new experimental method for determining liquid-vapor equilibria at high subcritical temperatures, American Mineralogist, 86, 1100–1111. Bock B, Rhudy R, Herzog H, Klett M, Davison J, De la Torre Ugarte D and Simbeck D (2003) Economic evaluation of CO2 storage and Sink options, DOE Research Report DE-FC26-00NT40937. Bradshaw J and Dance T (2005a) Mapping geological storage prospectivity of CO2 for the world’s sedimentary basins and regional source to sink matching, in Rubin E S, Keith D W and Gilboy C F (eds), Proceedings of the Seventh International Conference on Greenhouse Gas Control Technologies: GHGT7, IEA GHG, Cheltenham, UK, 1, 583–592. Bradshaw J and Dance T (2005b) Mapping geological storage prospectivity of CO2 for the world’s sedimentary basins and regional source to sink matching, Geophysical Research Abstracts, 7, 01865. Bradshaw J, Bachu S, Bonijoly D, Burruss R, Holloway S, Christensen N P and Mathiassen O M (2007) CO2 storage capacity estimation: Issues and development of standards, International Journal of Greenhouse Gas Control, 1(1), 62–68. Brennan S T and Burruss R C (2006) Specific storage volumes: A useful tool for CO 2 storage capacity assessment, Natural Resources Research, 15(3), 165–182. Bruant Jr. R G, Celia M A, Guswa A J and Peters C A (2002) Safe storage of CO2 in deep saline aquifiers, Environmental Science and Technology, 36(11), 240A–245A. Bruant Jr. R G, Giammar D E, Myneni S C B and Peters C A (2003) Effect of pressure, temperature, and aqueous carbon dioxide concentration on mineral weathering as applied to geological storage of carbon dioxide, in Gale J and Kaya Y (eds), Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies: GHGT6, Elsevier (Pergamon), Oxford, UK, 2, 1609–1612. Burruss R C (2004) Geologic Sequestration of carbon dioxide in the next 10 to 50 Years: An energy resource perspective, in Workshop Proceedings, The 10–50 Solution: Technologies and Policies for a Low-Carbon Future, Pew Center on Global Climate Change, March 25–26, Washington, DC. Burruss R C, Brennan S T, Freeman P A, Merrill M D, Ruppert L F, Becker M F, Herkelrath W N, Kharaka Y K, Neuzil C E, Swanson S M, Cook T A, Klett T R, Nelson P H and Schenk C (2009) Development of a Probabilistic Assessment Methodology for evaluation of carbon dioxide storage, U.S. Geological Survey Open-File Report 2009–1035, available only online at: http://pubs.usgs.gov/of/2009/1035/ (accessed January 2010). Cantucci B, Procesi M, Buttinelli M, Montegrossi G, Vaselli O and Quattrocchi F (2008) Mineralogy and geochemical trapping of CO2 in an Italian carbonatic deep saline aquifer: preliminary results, Geophysical Research Abstracts, 10, EGU2008-A-00000, 2008EGU General Assembly. Cantucci B, Montegrossi G, Vaselli O, Tassi F, Quattrocchi F and Perkins E H (2009) Geochemical modeling of CO2 storage in deep reservoirs: The Weyburn Project (Canada) case study, Chemical Geology, 265, 181–197.
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
91
Carroll S A and Knauss K G (2005) Dependence of labradorite dissolution kinetics on CO2 (aq), Al(aq), and temperature, Chemical Geology, 217, 213–225. Chadwick R A, Zweigel P, Gregersen U, Kirby G A, Holloway S and Johannessen P N (2003) Geological CO2 storage sites: lessons from Sleipner, Northern North Sea, in Gale J and Kaya Y (eds), Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies: GHGT6, Elsevier (Pergamon), Oxford, UK,1, 321–326. Chadwick R A, Zweigel P, Gregersen U, Kirby G A, Johannessen P N and Holloway S (2004) Characterisation of a CO2 storage site: The Utsira Sand, Sleipner, northern North Sea, Energy, 29, 1371–1381. Chadwick A, Arts R, Eiken O, Williamson P and Williams G (2006) Geophysical monitoring of the CO2 plume at Sleipner, North Sea: an outline review, in Lombardi, S, Altunina, LK, Beaubien, SE (eds) Advances in the Geological Storage of Carbon Dioxide: International Approaches to Reduce Anthropogenic Greenhouse Gas Emissions, NATO Science Series IV: Earth and Environmental Sciences, Springer, Dordrecht, the Netherlands, 303–314. Chapoy A, Mohammadi A H, Chareton A, Tohidi B and Richon D (2004) Measurement and modeling of gas solubility and literature review of the properties for the carbon dioxide–water system, Industrial and Engineering Chemistry Research, 43, 1794– 1802. Cipolli F, Gambardella B, Marini L, Ottonello G and Vetuschi Zuccolini M (2004) Geochemistry of high-pH waters from serpentinites of the Gruppo di Voltri (Genova, Italy) and reaction path modeling of CO2 sequestration in serpentinite aquifers, Applied Geochemistry, 19, 787–802. Corti H R, de Pablo J J and Prausnitz J M (1990) Phase equilibria for aqueous systems containing salts and carbon dioxide. Application of Pitzer’s theory for electrolyte solutions, Journal of Physical Chemistry, 94, 7876–7880. Cox P M, Betts R A, Jones C D, Spall S A and Totterdell I J (2000) Acceleration of global warming due to carbon-cycle feedbacks in a coupled climate model, Nature, 408, 184–187. CSLF (Carbon Sequestration Leadership Forum) (2005) Phase I Final Report from the Task Force for Review and Identification of Standards for CO2 Storage Capacity Measurement, CSLF-T-2005-9, August, available at: http://www.cslforum.org/ publications/documents/PhaseIReportStorageCapacityMeasurementTaskForce.pdf (accessed February 2010). CSLF (Carbon Sequestration Leadership Forum) (2007) Phase II Final Report from the Task Force for Review and Identification of Standards for CO2 Storage Capacity Estimation, CSLF-T-2007-04, June 15, available at: http://www.cslforum.org/ publications/documents/PhaseIIReportStorageCapacityMeasurementTaskForce.pdf (accessed February 2010). CSLF (Carbon Sequestration Leadership Forum) (2008) A CSLF Task Force on CO2 Storage Capacity Estimation, Comparison between Methodologies Recommended for Estimation of CO 2 Storage Capacity in Geological Media by the CSLF Task Force on CO2 Storage Capacity Estimation and the USDOE Capacity and Fairways Subgroup of the Regional Carbon Sequestration Partnerships Program, CSLF-T-2008-4, available at: http://www.cslforum.org/publications/documents/ PhaseIIIReportStorageCapacityEstimationTaskForce0408.pdf (accessed February 2010). Cuffey K M and Vimeux F (2001) Covariation of carbon dioxide and temperature from the Vostok ice core after deuterium-excess correction, Nature, 412, 523–527. © Woodhead Publishing Limited, 2010
92
Developments and innovation in CCS technology
Curry T, Reiner D, Ansolabehere S and Herzog H (2005) How aware is the public of carbon capture and storage? in Rubin E S, Keith D W and Gilboy C F (eds), Proceedings of the Seventh International Conference on Greenhouse Gas Control Technologies: GHGT7, IEA GHG, Cheltenham, UK, 1, 1001–1010. Damen K, Faaij A, van Bergen F, Gale J and Lysen E (2005) Identification of early opportunities for CO2 sequestration–worldwide screening for CO2-EOR and CO2 ECBM projects, Energy, 30(10), 1931–1952. Daveler S A (1998) XTOOL 7.15 user’s manual, UCRL-MA-130654, Lawrence Livermore National Laboratory, Livermore, CA. Davis T L, Terrell M J, Benson R D, Cardona R, Kendall R R and Winarsky R (2003) Multicomponent seismic characterization and monitoring of the CO2 flood at Weyburn Field, Saskatchewan, The Leading Edge, 22(7), 696–697. Davison J, Freund P and Smith A (2001) Putting Carbon Back in the Ground, IEA Greenhouse Gas R&D Programme, Cheltenham, UK. Davisson M L and Criss R E (1996) Na–Ca–Cl relations in basinal fluids, Geochimica et Cosmochimica Acta, 60, 2743–2752. Debye P and Hückel E (1923a) The theory of electrolytes, I Lowering of freezing point and related phenomena, Physik Zeitschrift, 24, 185–206. Debye P and Hückel E (1923b) The theory of electrolytes. II The limiting law of electrical conductivity, Physik Zeitschrift, 24, 305–325. Dooley J J, Dahowski R T, Davidson C L, Wise M A, Gupta N, Kim S H and Malone E L (2006) Carbon Dioxide Capture and Geologic Storage, A technology report from the second phase of the global energy technology strategy program, Battelle, Joint Global Change Research Institute. Doughty C, Benson S and Pruess K (2002) Capacity investigation of brine-bearing sands for geologic sequestration of CO2, Paper LBNL-51333, Lawrence Berkeley National Laboratory, Berkeley, CA, available at: http://repositories.cdlib.org/lbnl/LBNL-51333 (accessed January 2010). Doughty C, Freifeld B M and Trautz R C (2007) Site characterization for CO2 geologic storage and vice versa: the Frio brine pilot, texas, USA as a case study, Environmental Geology, 54(8), 1635–1656. Drummond S E (1981) Boiling and mixing of hydrothermal fluids: chemical effects on mineral precipitation, PhD Thesis, Pennsylvania State University. Duan Z and Sun R (2003) An improved model calculating CO2 solubility in pure water and aqueous NaCl solutions form 273 to 533 K and from 0 to 2000 bar, Chemical Geology, 193, 257–271. Duan Z H, Moller N and Weare J H (1995) Equation of state for the NaCl–H2O–CO2 system: prediction of phase equilibria and volumetric properties, Geochimica et Cosmochimica Acta, 59, 2869–2882. Duan Z, Sun R, Zhu C and Chou I-Ming (2006) An improved model for the calculation of CO2 solubility in aqueous solutions containing Na+, K+, CA2+, Mg2+, Cl-, and SO42–, Marine Chemistry, 98, 131–139. Ecofys & TNO-NITG (2002) Global carbon dioxide storage potential and costs, Report no EEP-02001, Utrecht, the Netherlands. EIA (2006) International Energy Annual 2006 (June–December 2008), energy Information Administration, Washington DC, available at: www.eia.doe.gov/iea (accessed January 2010). Emberley S, Hutcheon I, Shevalier M, Durocher K, Gunter W D and Perkins E H (2004) Geochemical monitoring of fluid-rock interaction and CO2 storage at the Weyburn
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
93
CO2-injection enhanced oil recovery site, Saskatchewan, Canada, Energy, 29(9–10), 1393–1401. Emberley S, Hutcheon I, Shevalier M, Durocher K, Mayer B, Gunter W D, and Perkins E (2005) Monitoring of fluid–rock interaction and CO2 storage through produced fluid sampling at the Weyburn CO2-injection enhanced oil recovery site, Saskatchewan, Canada, Applied Geochemistry, 20, 1131–1157. Ennis-King J and Paterson L (2001) Reservoir engineering issues in the geological disposal of carbon dioxide, in Williams D J, Durie R A, McMullan P, Paulson C A J and Smith A Y (eds), Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies: GHGT5, CSIRO Publishing, Collingwood, VIC, 290–295. Estublier A and Lackner A S (2009) Long-term simulation of the Snøhvit CO2 storage, in Gale J, Herzog H and Braitsch J (eds), Greenhouse Gas Control Technologies 9, Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies (GHGT9), Energy Procedia, 1, 3221–3228. Falkowski P, Scholes R J, Boyle E, Canadell J, Canfield D, Elser J, Gruber N, Hibbard K, Högberg P, Linder S, Mackenzie F T, Moore B, III; Pedersen T, Rosenthal Y, Seitzinger S, Smetacek V and Steffen W (2000) The global carbon cycle: A test of our knowledge of earth as a system, Science, 290, 291–296. Flett M, Beacher G, Brantjes J, Burt A, Dauth C, Koelmeyer F, Lawrence R, Leigh S, McKenna J, Gurton R, Robinson IV W F and Tankersley T (2008) Gorgon Project: Subsurface Evaluation of Carbon Dioxide Disposal under Barrow Island, SPE Asia Pacific Oil and Gas Conference and Exhibition, 20–22 October, Perth, Australia, 116372-Ms. Frailey S M, Finley R J and Hickman T S (2006) CO2 sequestration: storage capacity guideline needed, Oil & Gas Journal, 104(30), 44–46, 48–49. Gale J and Freund P (2001) Coal-bed methane enhancement with CO2 sequestration worldwide potential, Environmental Geosciences, 8(3), 210–217. Gale J, Christensen N P, Cutler A and Torp T A (2001) Demonstrating the potential for geological storage of CO2: the Sleipner and GESTCO projects, Environmental Geosciences, 8(3), 160–165. Gaus I, Azaroual M and Czernichowski-Lauriol I (2005) Reactive transport modelling of the impact of CO2 injection on the clayey cap rock at Sleipner (North Sea), Chemical Geology, 217, 319–337. Giammar D E, Bruant Jr. R G and Peters C A (2005) Forsterite dissolution and magnesite precipitation at conditions relevant for deep saline aquifer storage and sequestration of carbon dioxide, Chemical Geology, 217, 257–276. Gislason S R, Broecker W, Oelkers E H, Gunnlaugsson E, Stefánsson A, Matter J and Björnsson G (2008) Mineral CO2 sequestration into basalt: the Hellisheidi, Iceland project, International Geological Congress, August 6–14, Oslo, Norway. Goff F and Lackner K S (1998) Carbon dioxide sequestering using ultramafic rocks, Environmental Geoscience, 5(3), 89–101. Goldberg D S, Takahashi T and Slagle A L (2008) Carbon dioxide sequestration in deep-sea basalt, PNAS, 105, 9920–9925. Golubev S V, Pokrovsky O S and Schott J (2005) Experimental determination of the effects of dissolved CO2 on the dissolution kinetics of Mg and Ca silicates at 25 °C, Chemical Geology, 217, 227–238. Gunter W D, Perkins E H and McCann T J (1993) Aquifer disposal of CO2-rich gases reaction design for added capacity, Energy Conversion and Management, 34, 941–948.
© Woodhead Publishing Limited, 2010
94
Developments and innovation in CCS technology
Gunter W D, Wiwchar B and Perkins E H (1997) Aquifer disposal of CO2 -rich greenhouse gases: extension of the time scale of experiment for CO2-sequestering reactions by geochemical modeling, Mineralogy and Petrology, 59, 121–140. Gunter W D, Perkins E H and Hutcheon I (2000) Aquifer disposal of acid gases: modeling of water–rock reactions for trapping of acid wastes, Applied Geochemistry, 15, 1085–1095. Gunter W D, Bachu S and Benson S (2004) The role of hydrogeological and geochemical trapping in sedimentary basins for secure geological storage of carbon dioxide, Geological Society, London, Special Publications, 233, 129–145. Gupta N, Sass B, Sminchak J, Naymik T and Bergman P (1999) Hydrodynamics of CO2 disposal in a deep saline formation in the mid-western United States, in Riemer P, Eliasson B, Wokaun A (eds), Proceedings of the Fourth International Conference on Greenhouse Gas Control Technologies: GHGT4, Elsevier Science, Oxford, UK, 157–162. Gupta N, Sass B and Ickes (2000) Experimental evaluation of chemical sequestration of carbon dioxide in deep aquifer media – phase ii, Technical Progress Report Prepared for C. Byrer, US DOE National Energy Laboratory, Morgantown, WV. Han W, Lee S, Lu C, Thorne D, Esser R and McPherson B J (2008) Analysis of heterogeneity length-scales on residual gas trapping and buoyancy-driven CO2 migration, AGu, Fall Meeting 2008, 15–19 December, San Francisco, CA, abstract #H12C-04. Harvie C E and Weare J H (1980) The prediction of mineral solubilities in natural waters: the Na–K–Mg–Ca–Cl–SO4–H2O system from zero to high concentration at 25 °C, Geochimica Cosmochimica Acta, 44, 981–997. Helgeson H C, Kirkham D H and Flowers G C (1981) Theoretical prediction of the thermodynamic behavior of aqueous electrolytes at high pressures and temperatures: IV. Calculation of activity coefficients and relative partial molar properties to 600 °C and 5 kb, American Journal of Science, 281, 1249–1516. Hendriks C A and Blok K (1995) Underground storage of carbon dioxide, Energy Conversion and Management, 36, 539–542. Hendriks C, Graus W and van Bergen F (2004) Global carbon dioxide storage potential and costs, Report Ecofys & The Netherland Institute of Applied Geoscience TNO, Ecofys Report EEP02002. Hermanrud C, Andresen T, Eiken O, Hansen H, Janbu A, Lippard J, Bolas H N, Simmenes T H, Teige G M and Ostmo S (2009), Storage of CO2 in saline aquifers–lessons learned from 10 years of injection into the Utsira Formation in the Sleipner area, in Gale J, Herzog H and Braitsch J (eds), Greenhouse Gas Control Technologies 9, Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies (GHGT9), Energy Procedia, 1, 1997–2004. Hesse M A, Orr Jr F M and Tchelepi H A (2008) Gravity currents with residual trapping, Journal of Fluid Mechanics, 611, 35–60. Hitchon B (1996) Aquifer disposal of carbon dioxide-hydrodynamic and mineral trapping–proof of concept, report of a three-year study by the Alberta Research Council, Alberta, Canada, Geoscience Publishing Ltd, Sherwood Park, AB. Hitchon B, Gunter W D, Gentzis T and Bailey R T (1999) Sedimentary basins and greenhouse gases: a serendipitous association, Energy Conversion and Management, 40, 825–843. Holloway S (1997) Safety of the underground disposal of carbon dioxide, Energy Conversion and Management, 38(Suppl.), S241–S245. Holtz M H (2002) Residual gas saturation to aquifer influx: A calculation method for
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
95
3–D computer reservoir model construction, SPE Paper 75502, SPE Gas Technologies Symposium, 30 April-2 May, Calgary, AB, Canada. Holtz M H (2003) Pore-scale influences on saline aquifer CO2 sequestration, AAPG Annual Convention, 11–14 May, Salt Lake City, UT. Holtz M and Bryant S (2005) Effects of pore network geometry on permanent storage of sequestered CO2, AAPG’s 2005 Annual Meeting, 19–22 June, Calgary, AB, Canada. Holtz M H, Doughty C, Yeh J and Hovorka S (2004) Modeling of CO2 saline aquifer sequestration and the effects of residual phase saturation, AAPG Annual Convention, 16–21 April, Dallas, TX. Hovorka S D, Doughty C and Holtz M H (2005) Testing efficiency of storage in the subsurface: Frio Brine Pilot Experiment, in Wilson M, Morris T, Gale J and Thambimuthu K (eds), Proceedings of the Seventh International Conference on Greenhouse Gas Control Technologies: GHGT7, IEA GHG, Cheltenham, UK, 2, 1361–1366. Hovorka S D, Benson S M, Warne A G, Doughty C, Freifeld B M, Sakurai S, Daley T M, Kharaka Y K, Holtz M H, Trautz R C, Nance H S, Myer L R and Knauss K G (2006) Measuring permanence of CO2 storage in saline formations: the Frio experiment, Environmental Geosciences, 13(2), 105–121. Hovorka S D, Choi J-W, Meckel T A, Trevino R H, Zeng H, Kordi M, Wang F P and Nicot J-P (2009) Comparing carbon sequestration in an oil reservoir to sequestration in a brine formation—field study, in Gale J, Herzog H and Braitsch J (eds), Greenhouse Gas Control Technologies 9, Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies (GHGT9), Energy Procedia, 1, 2051–2056. H R 2454 (2009) American Clean Energy and Security Act (ACES), A Bill Before the US House of Representatives. Ibitayo O (2002) Public-private partnerships in the siting of hazardous waste facilities: The importance of trust, Waste Management & Research, 20, 212–222. Ide S T, Jessen K and Orr Jr F M (2007) Storage of CO2 in saline aquifers: effects of gravity, viscous, and capillary forces on amount and timing of trapping, International Journal of Greenhouse Gas Control, 1, 481–491. IEA (1995) Carbon Dioxide Disposal from Power Stations, IEA Greenhouse Gas R&D Programme, Paris, France. IPCC (2005) IPCC Special Report on Carbon Dioxide Capture and Storage, Working Group III of the Intergovernmental Panel on Climate Change, Metz B, Davidson O, de Coninck H C, Loos M and Meyer L A (eds), Cambridge, UK, Cambridge University Press. IPCC (2007) Climate Change 2007: Synthesis Report, Contribution of Working Groups I, II and III to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change, Core Writing Team, Pachauri RK and Reisinger A (eds), IPCC, Geneva, Switzerland. Johnson J W and Lundeen, S R (1994a) Jewel: A graphical-user interface for generating custom GEMBOCHS thermodynamic datafiles for use with geochemical modeling software, LLNL-YMP Milestone report MOL63, Lawrence Livermore National Laboratory, Livermore, CA. Johnson J W and Lundeen S R (1994b) GEMBOCHS thermodynamic datafiles for use with the EQ3/6 software package, LLNL-YMP Milestone report MOL72, Lawrence Livermore National Laboratory, Livermore, CA. Johnson J W, Oelkers E H and Helgeson H C (1992) SUPCRT92: A software package for calculating the standard molal thermodynamic properties of minerals, gases and
© Woodhead Publishing Limited, 2010
96
Developments and innovation in CCS technology
aqueous species from 0 to 1000 °C and 1 to 5000 bar, Computers and Geosciences, 18, 799–847. Johnson J W, Nitao J J, Steefel C I and Knauss K G (2001) Reactive transport modeling of geologic CO2 sequestration in saline aquifers: the influence of intra-aquifer shales and the relative effectiveness of structural, solubility, and mineral trapping during prograde and retrograde sequestration. First National Conference on Carbon Sequestration, 14–17 May, Washington, DC. Joyce D B and Holloway J R (1993) An experimental determination of the thermodynamic properties of H2O–CO2–NaCl fluids at high pressures and temperatures, Geochimica et Cosmochimica Acta, 57, 733–746. Kårstad O (2002) Geological storage, including costs and risks, in saline aquifers. In: Proceedings of the IPCC workshop on carbon capture and storage, 18–21 November, Regina, SK, Canada. Kaszuba J P, Janecky D R and Snow M G (2003) Carbon dioxide reaction processes in a model brine aquifer at 200 °C and 200 bars: implications for geologic sequestration of carbon, Applied Geochemistry, 18(7), 1065–80. Keeling C D and Whorf T P (2005) Atmospheric CO2 records from sites in the SIO air sampling network, in Trends: A Compendium of Data on Global Change. Carbon Dioxide Information Analysis Center, Oak Ridge National Laboratory, US Department of Energy, Oak Ridge, TN. Keyes F G and Kirkwood J G (1930) The dielectric constant of carbon dioxide as a function of temperature and density, Physical Review, 36, 754–761. Kharaka Y K and Barnes J A (1973) SOLMINEQ: solution-mineral equilibrium computations, Computer Contributions Report, U.S. Geological Survey, Reston, VA, 215–899. Kharaka Y K and Hanor J S (2007) Deep fluid in the continents: I. Sedimentary Basins, in Drever J I (ed.) Treatise on Geochemistry, Vol. 5, Surface and Ground Water, Weathering, and Soils, Elsevier Pergamon, Amsterdam, the Netherlands, 1–48. Kharaka Y K, Gunter D, Aggarwal L K, Perkins E H and DeBraal D (1988) SOLMINEQ.88: a computer program for geochemical modeling of water rock interactions, WaterResources Investigations Report Series, 88-4227, US Geological Survey, Reston, VA. Kharaka Y K, Cole D R, Thordsen J J, Kakouros E and Nance H S (2006a) Gas–water–rock interactions in sedimentary basins: CO2 sequestration in the Frio Formation, Texas, USA, Journal of Geochemical Exploration, 89, 183–186. Kharaka Y K, Cole D R, Hovorka S D, Gunter W D, Knauss K G and Freifeld B M (2006b) Gas-water-rock interactions in Frio Formation following CO2 injection: Implications for the storage of greenhouse gases in sedimentary basins, Geology, 34(7), 577–580. King M B, Mubarak A, Kim J D and Bott T R (1992) The mutual solubilities of water with supercritical and liquid carbon dioxide. Journal of Supercritical Fluids, 5, 296–302. Kitamura K and Xue Z (2006) An experimental study of residual gas saturation of carbon dioxide in water-saturated porous sandstone by using multi-channel seismic wave imaging method, AGU, Fall Meeting 2006, 11–15 December, San Francisco, CA, abstract #H51E-0531. Knauss K G, Steefel C I, Johnson J W and Boram L H (2002) Impact of CO2, contaminant gas, aqueous fluid, and reservoir rock interactions on the geologic sequestration of CO2, Geological Society of America National Meeting, 27–30 October, Denver, CO.
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
97
Knauss K G, Johnson J W and Steffel C I (2005) Evaluation of the impact of CO2, co-contaminant gas, aqueous fluid and reservoir rock interactions on the geologic sequestration of CO2, Chemical Geology, 217, 339–350. Koide H, Tazaki Y, Noguchi Y, Nakayama S, Iijima M, Ito K and Shindo Y (1992) Subterranean containment and long-term storage of carbon dioxide in unused aquifers and in depleted natural gas reservoirs, in Blok K, Turkenburg W, Hendriks C and Steinberg M (eds), Energy Conversion and Management, 33(5–8), 619–626. Kolak J J and Burruss R C (2006) Geochemical investigation of the potential for mobilizing nonmethane hydrocarbons during carbon dioxide storage in deep coal beds, Energy & Fuels, 20(2), 566–574. Kuuskraa V A (2004) Estimating CO2 storage capacity in saline aquifers, Proceedings, National Energy Technology Laboratory Third Annual Conference on Carbon Capture & Sequestration, 3–6 May, Alexandria, VA, CD-ROM. Leonenko Y and Keith D W (2008) Reservoir engineering to accelerate the dissolution of CO2 stored in aquifers, Environmental Science and Technology, 42, 2742–2747. Lindeberg E and Wessel-Berg D (1997) Vertical convection in an aquifer column under a gas cap of CO2, Energy Conversion and Management, 38 (Suppl.), S229–S234. Maldal T and Tappel I M (2004) CO2 underground storage for Snøhvit gas field development, Energy, 29(9–10), 1403–1411, 6th International Conference on Greenhouse Gas Control Technologies. Malinin S D (1959) The system water – carbon dioxide at high temperatures and pressures, Geokhimiya, 3, 292–306. Marini L (2007) Geological Sequestration of Carbon Dioxide: Thermodynamics, Kinetics, and Reaction Path Modeling, Elsevier, Amsterdam, the Netherlands. Maroto-Valer M M, Fauth D J, Kuchta M E, Zhang Y and Andrésen J M (2005) Activation of magnesium rich minerals as carbonation feedstock materials for CO2 sequestration, Fuel Processing Technology, 86(14–15), 1627–1645. Marsily G de (1986) Quantitative Hydrogeology, Academic Press, San Diego, CA. Matter J M, Goldberg D S and Takahashi T (2005) Potential of basalt aquifers for the permanent sequestration of anthropogenic carbon dioxide, AGU, Fall Meeting, 5–9 December, San Francisco, CA, abstract #B33A–1010. Mayer B, Johnson G, Nightingale M, Maurice S, Raistrick M, Taylor S, Hutcheon I and Perkins E (2008) Isotopic approaches to evaluate the fate of injected CO2 in two geological storage projects in mature oilfields in Canada, AGU, Fall Meeting 2008, 11–15 December, San Francisco, CA, abstract #H13K-04. McPherson B J O L and Lichtner P C (2001) CO2 sequestration in deep aquifers, Proceedings First National Conference on Carbon Sequestration, 14–17 May, Washington, DC. McRae L E and Holtz M H (1995) Reservoir architecture and permeability characteristics of fluvial-deltaic sandstone reservoirs, Frio Formation, Rincon Field, South Texas, AAPG Bulletin, 79, 64. Michael K, Allinson G, Golab A, Sharma S and Shulakova V (2009) CO2 storage in saline aquifers II – experience from existing storage operations, in, Gale J, Herzog H and Braitsch J (eds), Greenhouse Gas Control Technologies 9, Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies (GHGT9), Energy Procedia, 1, 1973–1980. Nitao J J (1998) Reference manual for the NUFT flow and transport code, version 2.0, UCRL-MA-130651, Lawrence Livermore National Laboratory, Livermore, CA. NRG Associates (2001) The significant oil and gas fields of the United States, NRG Associates, Inc., Colorado Springs, CO [includes data current as of May 23, 2001–
© Woodhead Publishing Limited, 2010
98
Developments and innovation in CCS technology
database available from NRG Associates, Inc., P.O. Box 1655, Colorado Springs, CO 80901]. Nuttall B C, Drahovzal J A, Eble C and Bustin R M (2005) CO2 sequestration in gas shales of Kentucky, AAPG Annual Convention, 19–22 June, Calgary, AB, Canada. Oelkers E H and Cole D R (2008) Carbon dioxide sequestration: A solution to a global problem, Elements, 4, 305–310. Oelkers E H and Schott J (2005) Geochemical aspects of CO2 sequestering, Chemical Geology, 217(3–4), 183–186. Oelkers E H, Schott J and Devidal J-L (1994) The effect of aluminum, pH, and chemical affinity on the rates of aluminosilicate dissolution reactions, Geochimica et Cosmochimica Acta, 58, 2011–2024. Omerod W (1994) Carbon dioxide disposal from power stations, IEA Greenhouse Gas R&D Programme, Cheltanham, UK. Palandri J K and Kharaka Y K (2004) Sequestration of CO2 in redbeds: Siderite precipitation from CO2 and SO2 waste gas, in Wanty R B and Seal R R, II (eds), Water–Rock Interaction, Proceedings of the Eleventh International Symposium on Water–Rock Interaction, A.A. Balkema, Rotterdam, the Netherlands 1, 567–571. Palandri J L and Kharaka Y K (2005) Ferric iron-bearing sediments as a mineral trap for CO2 sequestration: iron reduction using sulfur-bearing waste gas, Chemical Geology, 217, 351–364. Palandri J L, Rosenbauer R J and Kharaka Y K (2004) Experimental studies of CO2 sequestration in ferric iron-bearing sediments – CO2–SO2 reaction with hematite, Proceedings, National Energy Technology Laboratory Third Annual Conference on Carbon Sequestration, 3–6 May, Alexandria, VA, CD-ROM. Palandri J L, Rosenbauer R J and Kharaka Y K (2005) Ferric iron in sediments as a novel CO2 mineral trap – CO2–SO2 reaction with hematite, Applied Geochemistry, 20, 2038–2048. Palmer T N and Räisänen J (2002) Quantifying the risk of extreme seasonal precipitation events in a changing climate, Nature, 415, 512–514. Parkhurst D L (1995) User’s guide to PHREEQC–A computer program for speciation, reaction-path, advective-transport, and inverse geochemical calculations, WaterResources Investigation Report Series, 95–4227, US Geological Survey, Reston, VA. Parkhurst D L, Thorstenson D C and Plummer L N (1980) PHREEQE–A computer program for geochemical calculations, Water-Resources Investigation Report Series, 80–96, US Geological Survey, Reston, VA. (revised and reprinted August, 1990). Perez R J, Shevalier M, Hutcheon I and Mayer B (2006) A model for partitioning gases among brines and hydrocarbons in oil reservoirs: Examples from the IEA-GHG Weyburn CO2 Monitoring and Storage Project, Saskatchewan, Canada, Journal of Geochemical Exploration, 89, 326–330. Perkins E H and Gunter W D (1995a) A user’s manual for b PATHARCH.94: A reaction path-mass transfer program, ENVTR 95–11, Alberta Research Council, Edmonton, AB. Perkins E H and Gunter W D (1995b) Aquifer disposal of CO2-rich greenhouse gases: Modeling of water–rock interaction paths in a siliciclastic aquifer, in Kaharaka Y K, Chudeav, O V (eds), Water–rock Interactions, Brookfield, Rotterdam, the Netherlands, 895–898. Pitzer K S (1973) Thermodynamics of electrolytes. I Theoretical basis and general equations, Journal of Physical Chemistry, 77, 268–277. © Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
99
Pitzer K S (1975) Thermodynamics of electrolytes. V Effects of higher–order electrostatic terms, Journal of Solution Chemistry, 4, 249–265. Piri M, Prevost J H and Fuller R (2005) Carbon dioxide sequestration in saline aquifers: evaporation, precipitation and compressibility effects, Proceedings DOE/National Energy Technology Laboratory Fourth Annual Conference on Carbon Capture and Sequestration, 2–5, May, Alexandra, VA. Plummer L N, Parkhurst D L, Fleming G W and Dunkle S A (1988) A computer program incorporating Pitzer’s equations for calculation of geochemical reactions in brines, Water-Resources Investigations Report Series, 88–4153, US Geological Survey, Reston, VA. Pokrovsky O S, Schott J and Thomas F (1999) Processes at the magnesium-bearing carbonates/solution interface: I. A surface speciation model of magnesite, Geochimica et Cosmochimica Acta, 63, 863–880. Pokrovsky O S, Golubev S V and Schott J (2005) Dissolution kinetics of calcite, dolomite and magnesite at 25 °C and 0 to 50 atm pCO2, Chemical Geology, 217, 239–255. Portier S and Rochelle C (2005) Modeling CO2 solubility in pure water and NaCl-type waters from 0 to 300 °C and from 1 to 300 bar. Application to the Utsira Formation at Sleipner, Chemical Geology, 217, 187–199. Preston C, Whittaker S, Rostron B, Chalaturnyk R, White D, Hawkes C, Johnson J W, Wilkinson A and Sacuta N (2009) IEA GHG Weyburn-Midale CO2 monitoring and storage project – moving forward with the Final Phase, in Gale J, Herzog H and Braitsch J (eds), Greenhouse Gas Control Technologies 9, Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies (GHGT9), Energy Procedia, 1, 1743–1750. Prevost J H, Fuller R, Altevogt A S, Bruant R and Scherer (2005) Numerical modeling of carbon dioxide injection and transport in deep saline aquifers, in Wilson M, Morris T, Gale J and Thambimuthu K (eds), Proceedings of the Seventh International Conference on Greenhouse Gas Control Technologies: GHGT7, IEA GHG, Cheltenham, UK, Vol. 2, 2189–2193. Pruess K (2005) Numerical studies of fluid leakage from a geologic disposal reservoir for CO2 show self-limiting feedback between fluid flow and heat transfer, Geophysical Research Letters, 32, L14404. Pruess K, Oldenburg C and Muridis G (1999) TOUGH2, User’s Guide, Version 2.0, Report LBNL-43134, Lawrence Berkeley National Laboratory. Berkeley, CA. Pruess K, Tsang C F, Law D H-S and Oldenburg C M (2001a) An inter-comparison study of simulation models for geologic sequestration of CO2, Proceedings, First National Conference on Carbon Sequestration, 14–17 May, Washington, DC. Pruess K, Tsang C F, Law D and Oldenburg C (2001b) Inter-comparison of simulation models for CO2 disposal in underground storage reservoirs, Report LBNL-47353, Lawrence Berkeley National Laboratory, Berkeley, CA. Pruess K, Xu T, Apps J A and Garcia J (2001c) Numerical modeling of aquifer disposal of CO2, SPE paper 66537, SPE Exploration and Production Environmental Conference, 26–28 February, San Antonio, TX. Pruess K, Tsang C, Law D H and Oldenburg C M (2002) An inter-comparison study of simulation models for geologic sequestration of CO2, in Gale J and Kaya Y (eds), Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies: GHGT6, Elsevier (Pergamon), Oxford, UK, Vol. 1, 507–510. Pruess K, García J, Kovscek T, Oldenburg C, Rutqvist J, Steefel C and Xu T (2004) Code intercomparison builds confidence in numerical simulation models for geologic disposal of CO2, Energy, 29(9–10), 1431–1444. © Woodhead Publishing Limited, 2010
100
Developments and innovation in CCS technology
Reed M H (1982) Calculation of multicomponent chemical equilibria and reaction processes in systems involving minerals, gases, and an aqueous phase, Geochimica et Cosmochimica Acta, 46, 513–528. Riding J and Rochelle C (2005) The IEA Weyburn CO2 monitoring and storage project, final report of the European research team, British Geological Survey, Keyworth, UK. Riding J and Rochelle C (2009) Subsurface characterization and geological monitoring of the CO2 injection operation at Weyburn, Saskatchewan, Canada, Geological Society, London, Special Publications, 313, 227–256. Rosenbauer R J (2006) Experimental multi-phase CO2–H2O brine–rock interactions at elevated temperature and pressure: Implications for CO2 sequestration in deep-saline aquifers, Eos Trans. AGU, 87(36), West. Pac. Geophys. Meet. Suppl., 24–27 July, Beijing, China, Abstract V34B-01. Rosenbauer R J and Bischoff J L (2009) CO2 Sequestration by basalt: experimental studies and geochemical modeling, Goldschmidt Conference Abstracts 2009, Geochimica at Cosmochimica Acta., 54. Rosenbauer R J and Koksalan T (2002) Experimental determination of the solubility of CO2 in electrolytes: application to CO2 sequestration in deep-saline aquifers, GSA Abstracts with Programs, Annual Meeting, 27–30 October, Denver, CO, 135, Vol. 2, 304. Rosenbauer R J and Koksalan T (2003) Experimental CO2-brine-rock interactions at elevated temperature and pressure: implications for the geologic sequestration of CO2 in deep-saline aquifers, Proceedings, 226th American Chemical Society National Meeting, 7–11 September, New York, NY. Rosenbauer R J, Bischoff J L and Koksalan T (2001) An experimental approach to CO2 sequestration in saline aquifers: Application to Paradox Valley, CO, Eos Trans. AGU, 83(47), Fall Meeting, San Francisco, CA, Suppl., Abstract 2002V32B–0974. Rosenbauer R J, Koksalan T and Palandri J L (2005) Experimental investigation of CO2–brine–rock interactions at elevated temperature and pressure: implications for CO2 sequestration in deep-saline aquifers, Fuel Processing Technology, 86(12–14), 1581–1597. Sass B M, Engelhard M H, Berman P and Byrer C J (2002) Interaction of rock minerals with carbon dioxide and brine: A hydrothermal investigation, Energy & Environmental Research, 2, 23–31. Schilling F R, Borm G, Wuerdeman H, Moeller F, Kuehn M and Liebscher A (2008) Status Report on the First European on-shore CO2 Storage Site at Ketzin (Germany), Eos Trans. AGU, 89(53), Fall Meeting, San Francisco, CA, Suppl., Abstract U44A-04. Shafeen A, Croiset E, Douglas P L and Chatzis I (2004) CO2 sequestration in Ontario, Canada. Part I: storage evaluation of potential reservoirs, Energy Conversion and Management, 45, 2645–2659. Sharma S, Cook P, Berly T and Lees M (2009) The CO2CRC Otway Project: Overcoming challenges from planning to execution of Australia’s first CCS project, in Gale J, Herzog H and Braitsch J (eds), Greenhouse Gas Control Technologies 9, Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies (GHGT9), Energy Procedia, 1, 1965–1972. Shiraki R and Dunn T L (2000) Experimental study on water–interactions during CO2 flooding in the Tensleep Formation, Wyoming USA, Applied Geochemistry, 15, 265–279. Shock E L (1998) An updated and augmented version (slop07.dat) of the original
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
101
SUPCRT92 database (sprons92.dat) is available at: http://zonvark.wustl.edu/geopig/ (accessed February 2010). Sorai M, Ohsumi T, Ishikawa M and Tsukamoto K (2007) Feldspar dissolution rates measured using phase-shift interferometry: implications to CO 2 underground sequestration, Applied Geochemistry, 22, 2795–2809. Spycher N, Pruess K and Ennis-King J (2003) CO2–H2O mixtures in the geological sequestration of CO2. I. Assessment and calculation of mutual solubilities from 12 to 100 °C and up to 600 bar, Geochimica et Cosmochimica Acta, 67, 3015–3031. Steefel C I (2001) GIMRT, version 1.2: Software for modeling multicomponent, multidimensional reactive transport. User’s Guide, UCRL-MA-143182, Lawrence Livermore National Laboratory, Livermore, CA. Steefel C I (2008) CRUNCHFLOW: Software for multicomponent reactive transport: USER’S MANUAL, Lawrence Livermore National Laboratory, Livermore, CA. Steefel C I and Yabusaki S B (1996) OS3D/GIMRT, Software for multicomponentmultidimensional reactive transport: User’s Manual and Programmer’s Guide, PNL11166, Pacific Northwest National Laboratory, Richland, WA. Stevens S H, Kuuskraa V A, Gale J and Beecy D (2001) CO2 injection and sequestration in depleted oil and gas fields and deep coal seams: worldwide potential and costs, Environmental Geosciences, 8(3), 200–209. Stewart P B and Munjal P (1970) Solubility of carbon dioxide in pure water, synthetic sea water, and synthetic sea water concentrates at 5° to 25° C and 10 to 45 atm. Pressure. Journal of Chemical and Engineering Data, 15, 67–71. St John B, Bally A W and Klemme H D (1984) Sedimentary provinces of the world hydrocarbon productive and nonproductive, American Association of Petroleum Geologists, Tulsa, OK. Stocker T F and Schmittner A (1997) Influence of CO2 emission rates on the stability of the thermohaline circulation, Nature, 388, 862–865. Strazisar B R, Zhu C and Hedges S W (2006) Preliminary modeling of the long-term fate of CO2 following injection into deep geologic formations, Environmental Geosciences, 13(1), 1–15. Takenouchi S and Kennedy G C (1964) The binary system H2O–CO2 at high temperatures and pressures, American Journal of Science, 262, 1055–1074. Tanase D and Yoshimura T (2008) Nagaoka CO2 injection and monitoring project; a gateway of the intimate understanding of CO2 behavior in the deep reservoir, International Geological Congress, 6–14 August, Oslo, Norway. Todheide K and Franck E U (1963) Das Zweiphasengebiet und die kritische Kurve im System Kohlendioxid-Wasser bis zu Drucken von 3500 bar, Zeitschrift fur Physikalische Chemie, 37, 387–401. Torp T A and Gale J (2004) Demonstrating storage of CO2 in geological reservoirs: The Sleipner and SACS projects, Energy, 29(9–10), 1361–1369, 6th International Conference on Greenhouse Gas Control Technologies. United States Department of Energy, National Energy Technology Laboratory (2008), Carbon Sequestration Atlas of the United States and Canada, March. Vangkilde-Pedersen T, Lyng Anthonsen K, Smith N, Kirk K, Neele F, van der Meer B, Le Gallo Y, Bossie-Codreanud D, Wojcicki A, Le Nindre Y-M, Hendriks C, Dalhoff F and Christensen NP (2009) Assessing European capacity for geological storage of carbon dioxide – the EU GeoCapacity project, in Gale J, Herzog H and Braitsch J (eds), Greenhouse Gas Control Technologies 9, Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies (GHGT9), Energy Procedia, 1, 2663–2670. © Woodhead Publishing Limited, 2010
102
Developments and innovation in CCS technology
Vermylen J P, Hagin P N and Zoback M D (2008) Feasibility assessment of CO2 sequestration and enhanced recovery in gas shale reservoir, AGU, Fall Meeting 2008, 15–19 December, San Francisco, CA, abstract #H23D–0990. White S P (1995) Multiphase non-iosthermal transport of systems of reacting chemicals, Water Resources Research, 31(7), 1761–1772. White C M, Strazisar B R, Granite E J, Hoffman J S and Pennline H W (2003) Separation and capture of CO2 from large stationary sources and sequestration in geological formations–coalbeds and deep saline aquifer, Journal of Air and Waste Management Association, 53, 645–715. White S P, Allis R G, Moore J, Chidsey T, Morgan C, Gwynn W, Adams M, (2005) Simulation of reactive transport of injected CO2 on the Colorado Plateau, Utah, USA. Chemical Geology, 217, 387–405. Wiebe R and Gaddy V L (1939) The solubility in water of carbon dioxide at 50, 75 and 100°, at pressures to 700 atmospheres, Journal of the American Chemical Society, 61, 315–318. Wiebe R and Gaddy V L (1941) Vapor phase composition of carbon dioxide-water mixtures at various temperatures and at pressures to 700 atmospheres, Journal of the American Chemical Society, 63, 475–477. Wolery T J (1979) Calculation of chemical equilibrium between aqueous solution and minerals–The EQ3/6 software package, Report UCRL-52658, Lawrence Livermore National Laboratory, Livermore, CA. Wolery T J (1992) EQ3/6, A software package for geochemical modeling of aqueous systems: Package overview and installation guide (Version 7.0), Report UCRL-MA110662 PT 1, Lawrence Livermore National Laboratory, Livermore CA. Wolery T J and Daveler S A (1992) A computer program for reaction path modeling of aqueous geochemical solutions: Theoretical manual, user’s guide, and related documentation (version 7.0), Report UCRL-MA-110662 PT IV, Lawrence Livermore National Laboratory, Livermore, CA. Worden R H (2006) Dawsonite cement in the Triassic Lam Formation, Shabwa Basin, Yemen. A natural analogue for a potential mineral product of subsurface CO 2 storage for greenhouse gas reduction, Marine Petroleum Geology, 23, 67–77. Xu T and Pruess K (1998) Coupled modeling of non-isothermal multiphase flow, solute transport and reactive chemistry in porous and fractured media: 1. Model development and validation, Report LBNL-42050, Lawrence Berkeley National Laboratory, Berkeley, CA. Xu T, Apps J A and Pruess K (2000) Analysis of mineral trapping for CO2 disposal in deep aquifers, Report LBNL-47315, Lawrence Berkeley National Laboratory, Berkeley, CA. Xu T, Pruess K and Apps J A (2004a) Numerical simulation to study mineral trapping for CO2 disposal in deep aquifers, Applied Geochemistry, 19, 917–936. Xu T, Sonnenthal E, Spycher N and Pruess K (2004b) TOUGHREACT user’s guide: a simulation program for non-isothermal reactive geochemical transport in variable saturated geologic media, Report LBNL-55460, Lawrence Berkeley National Laboratory, Berkeley, CA. Xu T, Sonnenthal E, Spycher N and Pruess K (2005) TOUGHREACT – A simulation program for non-isothermal reactive geochemical transport in variable saturated geologic media: Applications to geothermal injectivity and CO2 geologic sequestration, Computers and Geosciences, 32(2), 145–165. Xu T, Chen S and Zhang D (2006) Convective stability analysis of the long-term storage
© Woodhead Publishing Limited, 2010
Carbon dioxide (CO2) sequestration in deep saline aquifers
103
of carbon dioxide in deep saline aquifers, Advances in Water Resources, 29(3), 397–407. Zweigel P, Arts R, Lothe A E and Lindeberg E B G (2004) Reservoir geology of the Utsira Formation at the first industrial-scale underground CO2 storage site (Sleipner area, North sea), in Baines S J and Worden R H (eds), Geological Storage of Carbon Dioxide, GSA Special Publication 233, Geological Society of America, Boulder, CO, 165–180.
© Woodhead Publishing Limited, 2010
4
Carbon dioxide (CO2) sequestration in oil and gas reservoirs and use for enhanced oil recovery (EOR)
B. V e g a and A. R. K o v s c e k, Stanford University, USA Abstract: It is frequently said that oil and gas reservoirs are likely to be the first category of geological formation where carbon dioxide (CO 2) shall be injected for greenhouse gas sequestration on a large scale, if sequestration proves feasible. Carbon dioxide is injected into comparatively few reservoirs at the present time. It is estimated, however, that 80 % of oil reservoirs worldwide might be suitable for CO2 injection to enhance oil recovery. Enhanced oil recovery operations with CO2 have been limited by the availability and cost of CO2, but not necessarily candidate reservoirs. The problem of co-optimizing oil production and CO2 storage differs dramatically from current gas injection practice because of the cost– benefit difference due to the purchase cost of CO2 for enhanced recovery projects. When low-cost CO2 becomes widely available, injection into a wider range of reservoirs is foreseen, with the objective of maximizing the amount of CO2 left in the reservoir at abandonment. In addition to discussion of the conventional oil reservoir setting, we demonstrate, using laboratory experiments, the applicability and potential of low-permeability unconventional hydrocarbon reservoirs to store significant volumes of CO 2. Key words: enhanced oil recovery, carbon dioxide sequestration, storage capacity, unconventional oil production.
4.1
Introduction
This article discusses the storage of greenhouse gases, mainly carbon dioxide (CO2), in oil and gas reservoirs. Carbon dioxide is the most often considered greenhouse gas; hence, the focus on CO2 here. Oil and gas reservoirs, by the very fact that hydrocarbons accumulated, are effective in preventing the upward migration of buoyant fluids over long periods of time. Likewise, gas injection is a widely practised method to enhance the pr
