No title

MAR. 7, 2011 | USD 10

International Petroleum News and Technology | www.ogjonline.com

CAPITAL SPENDING

OUTLOOK REFINING

REPORT

LNG

UPDATE VAST DEEPWATER POTENTIAL MULTIPHASE FLOWMETER GROWTH

Innovation Flows From Our Labs To Your Fields, And Now To Your Refineries Chemtech has joined the Champion Technologies portfolio to further optimize our chemicals, engineered programs and downstream capabilities that meet your refinery challenges. Our new, integrated offering delivers cost-effective performance, more reliability and improved throughput with an emphasis on safety. Now offering complete upstream, midstream and downstream solutions.

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www.champ-tech.com CH 3

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CONTENTS Mar. 7, 2011 Volume 109.10

78

GENERAL INTEREST Capital budgets to rise this year in North America and worldwide Marilyn Radler

26 Highlight: individual company plans and price expectations

US industry expects higher costs following Macondo Paula Dittrick

40 INGAA prepares for comprehensive pipeline safety legislation

Gadhafi threatens revenge as Libya’s output plunges Eric Watkins

LNG UPDATE

Capital budgets to rise this year in North America and worldwide

Global LNG capacities rising to meet increasing demand

Marilyn Radler

Warren R. True

26

100

Highlight: individual company plans and price expectations

Is LNG a global commodity...yet?

27

110

40

SPECIAL REPORT WATCHING GOVERNMENT NTSB’s limitations

REFINING REPORT

42

Capacity, complexity expansions characterize China’s refining industry past, present, future

Marilyn Radler, Laura Bell

30

SPECIAL REPORT

CAPITAL SPENDING OUTLOOK

Study lists Alaska Arctic OCS development’s potential benefits Nick Snow

Kang Wu

78

42

36 BOEMRE approves first deepwater drilling permit since accident

Brigham’s Bakken operation accelerating

43

Nick Snow

WATCHING THE WORLD LNG booms in Asia-Pacific

38

Sam Fletcher

38 Helix Energy outlines oil spill response system Paula Dittrick

39

EU REFINING—3 (Conclusion): Capacity upgrading to cut gasoline exports by 2030

88

37

Industry still skeptical after first drilling permit since Macondo

Simon Bonini

Nick Snow

27 Oil prices drive earnings in fourth quarter 2010

SPECIAL REPORT

Conditions improving for floating LNG production John Vautrain, Christopher Holmes

114 REGULAR FEATURES NEWSLETTER 6 LETTERS 16 CALENDAR 16 JOURNALLY SPEAKING 22 EDITORIAL 24 EQUIP./SOFTWARE/LITERATURE 118 SERVICES/SUPPLIERS 120 STATISTICS 121 MARKETPLACE 124 ADVERTISERS’ INDEX 127 EDITOR’S PERSPECTIVE/ MARKET JOURNAL 128

COVER Navajo Refinery’s Artesia, NM, 100,000-b/d plant uses KBR’s ROSE solvent deasphalting process. The refinery can process heavy, sour, and light crude oils into such light products as gasoline, diesel fuel, and jet fuel. For 2009, says owners Holly Corp., gasoline, diesel fuel, and jet fuel (excluding volumes purchased for resale) represented 58%, 32%, and 2%, respectively, of the refinery’s sales volumes. This issue’s Refining Report (p. 78) contains an update on refining in China—home to the world’s second largest concentration of refining capacity after the US. Also part of this annual report is the concluding article in a series on EU refining issues and future. Photo from KBR, Houston.

How come the weather is the only nasty thing at this gas field?

Visit us at booth A220, hall 1 at GASTECH 2011, March 21–24, Amsterdam, Netherlands

E50001-E440-F140-X-4A00

Innovative compressor trains from Siemens boost production and preserve the environment. After 50 years of operation, the Groningen gas field in the Netherlands is now, and also for the next decades, fit to secure the supply of its clients. The facilities are fully modernized. One key success factor was the long-term relationship of the operating company NAM and its contractors. Siemens has advanced the compression and variable speed drive technologies to ensure the adaptation of the gas supply to fluctuating demand, to slash maintenance requirements, and to maximize environmental performance. Highest availability and low power consumption of all units are the best basis for an eco-friendly and successful operation. Learn more: www.siemens.com/energy

Answers for energy.

EXPLORATION & DEVELOPMENT

DRILLING & PRODUCTION

PROCESSING

TRANSPORTATION

Continent below the oceans: how much and how far? The future for deepwater exploration (and geopolitics)

Forecast expects continued multiphase flowmeter growth

Global LNG capacities rising to meet increasing demand

Gioia Falcone, Bob Harrison

Capacity, complexity expansions characterize China’s refining industry past, present, future

68

Kang Wu

100

Warren R. True

78

Keith H. James

Shale gas, oil, minerals processing offer synergies in Brazil’s Amazon basins

CLOSED-LOOP CIRCULATING—4 (Conclusion): Data benefit completion design, field development

EU REFINING—3 (Conclusion): Capacity upgrading to cut gasoline exports by 2030

Fabiano Sayao Lobato

David Pavel, Brian Grayson

88

54

74

Conditions improving for floating LNG production

Nelson-Farrar monthly cost indexes

John Vautrain, Christopher Holmes

44

93

US OLEFINS— SECOND-HALF 2010: Ethylene markets return to normal Dan Lippe

94

74

Is LNG a global commodity...yet? Simon Bonini

110

114

Photo from ExxonMobil

100


     
 



    


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PennWell, Houston office 1455 West Loop South, Suite 400, Houston, TX 77027 Telephone 713.621.9720 / Fax 713.963.6285 Web site www.ogj.com Editor Chief Editor-Exploration Chief Technology Editor-LNG/Gas Processing Production Editor Pipeline Editor Senior Editor-Economics Senior Editor Senior Writer Senior Staff Writer Survey Editor/News Writer Publisher Vice-President/Group Publishing Director Vice-President/Custom Publishing

Bob Tippee, [email protected] Alan Petzet, [email protected] Warren R. True, [email protected] Guntis Moritis, [email protected] Christopher E. Smith, [email protected] Marilyn Radler, [email protected] Steven Poruban, [email protected] Sam Fletcher, [email protected] Paula Dittrick, [email protected] Leena Koottungal, [email protected] Jim Klingele, [email protected] Paul Westervelt, [email protected] Roy Markum, [email protected]

PennWell, Tulsa office

 
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1421 S. Sheridan Rd., Tulsa, OK 74112 PO Box 1260, Tulsa, OK 74101 Telephone 918.835.3161 / Fax 918.832.9290 Presentation/Equipment Editor Associate Presentation Editor Statistics Editor Illustrators Editorial Assistant Production Director Production Manager

Jim Stilwell, [email protected] Michelle Gourd, [email protected] Laura Bell, [email protected] Mike Reeder, Kay Wayne Donna Barnett, [email protected] Charlie Cole Shirley Gamboa

Washington Tel 703.533.1552 Washington Editor Nick Snow, [email protected]

Los Angeles

       

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Tel 310.595.5657 Oil Diplomacy Editor Eric Watkins, [email protected]

OGJ News Please submit press releases via e-mail to: [email protected]

Subscriber Service P.O. Box 2002, Tulsa OK 74101 Tel 1.800.633.1656 / 918.831.9423 / Fax 918.831.9482 E-mail [email protected] Audience Development Manager Tommie Grigg, [email protected]

PennWell Corporate Headquarters 1421 S. Sheridan Rd., Tulsa, OK 74112

Chairman President/Chief Executive Officer


 
           
     


       
   


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P.C. Lauinger, 1900-1988 Frank T. Lauinger Robert F. Biolchini

Member Audit Bureau of Circulations & American Business Media Copyright 2011 by PennWell Corporation (Registered in U.S. Patent & Trademark Office). All rights reserved. Oil & Gas Journal or any part thereof may not be reproduced, stored in a retrieval system, or transcribed in any form or by any means, electronic or mechanical, including photocopying and recording, without the prior written permission of the Editor. Permission, however, is granted for employees of corporations licensed under the Annual Authorization Service offered by the Copyright Clearance Center Inc. (CCC), 222 Rosewood Drive, Danvers, Mass. 01923, or by calling CCC’s Customer Relations Department at 978-750-8400 prior to copying. Requests for bulk orders should be addressed to the Editor. Oil & Gas Journal (ISSN 00301388) is published 12x per year - monthly the first Monday of each month in print and other Mondays in digital form by PennWell Corporation, 1421 S. Sheridan Rd., Tulsa, Okla., Box 1260, 74101. Periodicals postage paid at Tulsa, Okla., and at additional mailing offices. Oil & Gas Journal and OGJ are registered trademarks of PennWell Corporation. POSTMASTER: send address changes, letters about subscription service, or subscription orders to P.O. Box 3497, Northbrook, IL 60065, or telephone (800) 633-1656. Change of address notices should be sent promptly with old as well as new address and with ZIP code or postal zone. Allow 30 days for change of address. Oil & Gas Journal is available for electronic retrieval on Oil & Gas Journal Online (www.ogjonline.com) or the NEXIS® Service, Box 933, Dayton, Ohio 45401, (937) 865-6800. SUBSCRIPTION RATES in the US: 1 yr. $89; Latin America and Canada: 1 yr. $94; Russia and republics of the former USSR, 1 yr. 2,200 rubles; all other countries: 1 yr. $129, 1 yr. premium digital $59 worldwide. These rates apply only to individuals holding responsible positions in the petroleum industry. Single copies are $10 each except for 100th Anniversary issue which is $20. Publisher reserves the right to refuse non-qualified subscriptions. Oil & Gas Journal is available on the Internet at http://www.ogjonline.com. (Vol. 109, No. 10) Printed in the US. GST No. 126813153. Publications Mail Agreement Number 602914. Return Undeliverable Canadian Addresses to: P.O. Box 1632, Windsor, ON N9A 7C9. Ride-a-Long enclosed in P2 & P3


  
        
      

    
          










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OGJ Newsletter

Mar. 7, 2011

®

International News for oil and gas professionals

GENERAL INTEREST Q U IC K TA K E S EPA extends GHG reporting deadline beyond Mar. 31 The US Environmental Protection Agency extended the deadline for initial reporting of greenhouse gas emissions beyond its original Mar. 31 date following extensive conversations with affected industries and other stakeholders. EPA also is in the process of finalizing a user-friendly online electronic reporting program to ensure that requirements are understandable and practical, the agency said on Mar. 1. The National Petrochemical & Refiners Association applauded EPA’s move. “It’s a sensible step that will benefit both the American people and businesses across the nation by providing better quality information,” NPRA Pres. Charles T. Drevna said. EPA said it plans to have the final uploading tool for GHG reporting available this summer, with the data scheduled to be published later this year. The extension will let EPA further test the system plants will use to submit data and give industries a chance to test the tool, provide feedback, and have enough time to become familiar with it prior to actual reporting, it said. “Taking a little extra time to get this program right makes more sense than rushing to meet an artificial and inflexible deadline,” NPRA’s Drevna said. “Our members have been working for several years to develop an accurate greenhouse gas database for their refineries and petrochemical manufacturing facilities, and we recognize the need for a quality reporting program.” EPA said it will provide more details about the intended changes in the next few weeks, and make certain the reporting extension is in effect before the original Mar. 31 deadline. The agency also has been holding hearings with industries which will be affected first by its programs to limit GHG emissions, and was to meet with refiners on Mar. 4.

BLM issues guidance to its field managers The US Bureau of Land Management issued guidance to its field managers on Feb. 25 describing how the agency will use its land use planning process to help states, communities, Indian tribes, and other stakeholders develop the best ways to manage public land with wilderness characteristics. The guidance was issued under Secretarial Order 3310,

6

For up-to-the-minute news, visit www.ogjonline.com

which US Interior Sec. Ken Salazar issued in December. The order restores a policy that was revoked in 2003 as part of an outof-court settlement between then-Sec. Gale A. Norton, Utah’s state government, and other parties. BLM has not had comprehensive, long-term guidance on managing public land with wilderness characteristics since that time, Salazar said when he issued the order. The policy is “a common sense approach that also makes good economic sense,” BLM Director Robert V. Abbey said as he issued it. The order, which some groups consider a de facto setting aside of additional acreage for wilderness, requires BLM to consider all resources on public lands, including wilderness characteristics, in its land use planning. Land with wilderness characteristics provides outstanding recreational opportunities as well as cultural, scientific, historical, and environmental resources, supports of the policy argue.

EPA revamps boiler rules to cut costs The US Environmental Protection Agency issued revised Clean Air Act standards for boilers and certain incinerators, saying it cut estimated costs by about 50% from the rules that it proposed last year. EPA estimates its final rules lower the cost of pollution control installation and maintenance by about $1.8 billion/year less than its original proposal. The rules cover toxic emissions from some 13,800 large industrial boilers, including refineries and chemical plants. The new boiler rule, known as the maximum achievable control technology (MACT) rule, sets standards to reduce air emissions of mercury, organic air toxics, and dioxins (OGJ Online, Feb. 4, 2011). Howard Feldman, American Petroleum Institute director of science and regulatory policy, said he was reviewing the rule. “API understands that EPA has finalized work practices for most gas-fired boilers and process heaters,” Feldman said. “We continue to believe that this is the appropriate control measure for all low-emitting gas-fired units. API is committed to work with the agency during its reconsideration period.” In response to a September 2009 court order, EPA issued the proposed rules in April 2010, prompting significant public input. EPA made extensive revisions and in December 2010 requested additional time for review. The court granted EPA 30

Oil & Gas Journal

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IPE BRENT / NYMEX LIGHT SWEET CRUDE $/bbl 115.00 112.00 109.00 106.00 103.00 100.00 97.00 94.00

US INDUSTRY SCOREBOARD — 3/7 4 wk. average

Latest week 2/18

Feb. 23

Feb. 24

Feb. 25

Feb. 28

Mar. 1

Motor gasoline Distillate Jet fuel Residual Other products

YTD avg. year ago1

Change, %

8,741 3,701 1,321 602 4,730 19,095

0.1 2.7 6.9 10.1 3.6 2.3

8,743 3,731 1,418 582 4,845 19,319

8,704 3,709 1,328 552 4,655 18,948

0.4 0.6 6.8 5.4 4.1 2.0

Crude production NGL production2 Crude imports Product imports Other supply2, 3 TOTAL SUPPLY Refining, 1,000 b/d

5,595 2,065 8,574 2,654 2,026 20,914

5,466 2,022 8,600 2,860 1,777 20,725

2.4 2.2 –0.3 –7.2 14.0 0.9

5,496 2,062 8,794 2,652 2,069 21,073

5,455 2,098 8,529 2,807 1,665 20,554

0.8 –1.7 3.1 –5.5 24.3 2.5

Feb. 23

Feb. 24

Feb. 25

Crude runs to stills Input to crude stills % utilization

14,011 14,504 82.5

13,263 14,204 80.8

5.6 2.1 ––

14,177 14,603 83.0

14,283 14,593 82.6

–0.7 0.1 ––

Supply, 1,000 b/d

Feb. 28

Mar. 1

NYMEX NATURAL GAS / SPOT GAS - HENRY HUB

Latest week 2/18

Latest week

Previous week1

346,739 238,298 159,937 40,475 37,403

345,917 241,096 161,270 41,435 39,451

24.7 27.2 42.1 19.9

24.4 27.9 42.3 19.3

Stock cover (days)4 Feb. 23

Feb. 24

Feb. 25

Feb. 28

Mar. 1

Same week year ago1 Change

Change

Change, %

Stocks, 1,000 bbl Crude oil Motor gasoline Distillate Jet fuel-kerosine Residual

IPE GAS OIL / NYMEX HEATING OIL ¢/gal 302.00 299.00 296.00 293.00 290.00 287.00 284.00 281.00

YTD average1

8,746 3,802 1,412 663 4,902 19,525

TOTAL PRODUCT SUPPLIED

$/MMbtu 4.10 4.00 3.95 3.90 3.85 3.80 3.75 3.70

Change, %

Product supplied, 1,000 b/d

WTI CUSHING / BRENT SPOT $/bbl 113.00 110.00 107.00 104.00 101.00 98.00 95.00 92.00

4 wk. avg. year ago1

822 –2,798 –1,333 –960 –2,048

337,537 231,170 152,664 43,650 40,017

9,202 7,128 7,273 –3,175 –2,614

Change, %

Crude Motor gasoline Distillate Propane Futures prices5 2/25

Change, %

1.2 –2.5 –0.5 3.1

24.6 26.4 41.2 18.7

0.4 3.0 2.2 6.4

Change

Light sweet crude ($/bbl) Natural gas, $/MMbtu

96.71 3.89

85.34 3.91

2.7 3.1 4.8 –7.3 –6.5

Change

11.37 –0.02

78.30 5.23

%

18.41 –1.34

23.5 –25.6

1 Based on revised figures. 2OGJ estimates. 3Includes other liquids, refinery processing gain, and unaccounted for crude oil. 4Stocks divided by average daily product supplied for the prior 4 weeks. 5Weekly average of daily closing futures prices. Source: Energy Information Administration, Wall Street Journal

Feb. 23

Feb. 24

Feb. 25

Feb. 28

Mar. 1

BAKER HUGHES INTERNATIONAL RIG COUNT: TOTAL WORLD / TOTAL ONSHORE / TOTAL OFFSHORE

PROPANE - MT. BELVIEU / BUTANE - MT. BELVIEU ¢/gal 185.00 180.00 175.00 155.00 150.00 145.00 140.00

Feb. 23

Feb. 24

Feb. 25 Feb. 28 1

Mar. 1

NYMEX GASOLINE (RBOB)2 / NY SPOT GASOLINE3 ¢/gal 300.00 295.00 290.00 285.00 280.00 275.00 270.00 265.00 1Not

3,900 3,600 3,300 3,000 2,700 2,400 2,100 1,800 1,500 300 0

3,437 3,100

336

Jan. 10

Feb. 10

Mar. 10

Apr. 10

May 10 Jun. 10

Jul. 10

Aug. 10

Sept. 10

Oct. 10

Nov. 10

Dec. 10

Jan. 11

Note: Monthly average count

BAKER HUGHES RIG COUNT: US / CANADA 1,800

1,699

1,600

1,373

1,400 1,200 1,000 800

623

576

600 400 Feb. 23

Feb. 24

Feb. 25

Feb. 28

Mar. 1

available 2Reformulated gasoline blendstock for oxygen blending 3Nonoxygenated regular unleaded

200

12/11/09

12/25/09

12/18/09

1/8/10

1/1/10

1/22/10

1/15/10

2/5/10

1/29/10

2/19/10

2/12/10

12/10/10

2/26/10

12/24/10

12/17/10

1/7/11

12/31/10

1/21/11

1/14/11

2/4/11

1/28/11

2/18/11

2/11/11

2/25/11

Note: End of week average count

8

Oil & Gas Journal | Mar. 7, 2011

Shouldn’t you know your safety loops from the inside out?

With a smart safety instrumented system you can. DeltaV SIS. Smart. DeltaV SIS is the only logic solver to digitally diagnose and automatically proof test components of your entire safety loop. No more second guessing–the health of each element in the safety loop is continuously monitored. This valuable information is easily accessed by operators without data-mapping and multiple databases. DeltaV SIS shuts down your plant when needed for safety, but keeps you running safely when components fail–reducing spurious trips. DeltaV SIS is the first to use predictive intelligence and device diagnostics to enable safer facilities, improve availability, lower life-cycle costs, and ease regulatory compliance. For more insight, visit: www.DeltaVSIS.com

The Emerson logo is a trademark and a service mark of Emerson Electric Co. ©2010 Emerson Electric Company

days, resulting in the Feb. 23 announcement. Because the final standards significantly differ from the proposals, EPA believes further public review is required. The agency said it will reconsider the final standards under a Clean Air Act process that allows it to seek additional public review and comment to ensure full transparency.

EXPLORATION & DEVELOPMENT Q U IC K TA K E S Perla gas in place hiked to more than 16 tcf Eni SPA and Repsol-YPF SA have hiked the estimate of gas in place at supergiant Perla gas-condensate field in the Gulf of Venezuela to more than 16 tcf from the previous estimate of more than 14 tcf. The companies have finalized front-end engineering design for a 300 MMscfd early production phase targeted to start up in 2013 (OGJ Online, Nov. 15, 2010). The most recent appraisal well, Perla-4, tested at 17 MMscfd of gas and 560 b/d of condensate. The well is in 60 m of water on the Cardon IV block. Four light offshore platforms would be linked by pipeline to a central processing facility (CPF) on the Paria Peninsula. Full phase development would involve additional wells and an upgrade of the CPF to 1.2 bscfd. Eni said, “Early assessments indicate capacity for Perla gas commercialization via the domestic market due to gas request for power generation, petrochemical, and heavy oil upgrading projects. However, further options for gas export will also be analyzed, jointly with the government, in order to extract maximum commercial value from the field.” The block is licensed and operated by Cardon IV SA, a joint operating company owned 50-50 by Eni and Repsol-YPF. Petroleos de Venezuela SA owns a 35% back-in right to be exercised in the development phase, and at that time Eni and Repsol-YPF will each hold a 32.5% interest in the project, which will then be jointly operated by the three companies.

Colombia’s Rancho Hermoso oil field growing Canacol Energy Ltd., Calgary, will drill as many as seven development wells starting in late second quarter 2011 in Rancho Hermoso field in the northwestern Llanos basin in Colombia, where its latest development well tested oil from five formations including one new field pay. The RH 10 well went to a total depth of 10,305 ft and cut 110 ft of net oil pay in Ubaque, Guadalupe, Los Cuervos-Barco, Mirador, and new pay Carbonera C7 formations. Combined production rate totaled 26,286 b/d of oil. The well previously tested a combined 19,066 b/d of oil from the Ubaque and Guadalupe reservoirs. Los Cuervos-Barco, with 19 ft of net oil pay with 26% average porosity, stabilized at 6,791 b/d of 34° gravity oil with 28% water cut on an electric submersible pump from perforations at 9,410-25 ft measured depth. Mirador had 9 ft of oil pay with 25% average porosity.

10

The C7 tried to blow out when perforated at 8,962-74 ft MD. Bull heading brought the well under control in 3 days, after which the formation made 429 b/d of 34° gravity oil with 10% load water cut on an ESP. Formation damage is probable, and the zone is to be properly stimulated and tested in future wells. The C7 is present and oil-bearing in the majority of the field’s wells, and Canacol will formulate a development plan. The well is to be completed next week in the Ubaque, which tested at 8,122 b/d. RH 10 is the last of a five-well development program begun in mid-2010. The 2011 seven-well program is directed at all reservoirs except C7.

Trinidad and Tobago receives bids on offshore blocks Trinidad and Tobago received five bids on three blocks in its Deep Water Atlantic Bid Round, which closed Feb. 18. BP PLC was the sole bidder on Block 14. Three entities bid on Block 23(a): BP PLC, Niko Resources Ltd., and a consortium of BHP Billiton, Repsol-YPF SA, and Total SA. A consortium of BHP and Repsol-YPF was the only bidder for Block 23(b). The twin-island nation’s Minister of Energy and Energy Affairs Carolyn Seepersad-Bachan noted that while 11 blocks were put up for bid, it was not surprising that companies opted for the blocks that they felt were more prospective. “You will recall that we instituted a nomination process asking companies to nominate blocks for the bid round. On the basis of this we chose to offer a wide range of blocks to cover every eventuality,” the energy minister said. “In taking this approach, we offered many more blocks than we would usually do and we recognize no matter how many blocks we offer, companies always cluster around what they perceive to be among the most prospective,” she said. Seepersad-Bachan said more than two thirds of Trinidad and Tobago’s acreage has not yet been explored. Most of this acreage lies in the deep water and is frontier acreage, carrying significant risks but high rewards. She said for this reason, the country reformed its fiscal regime to allow companies the flexibility to arrange their exploration programs to reduce some of this risk. She explained, “Therefore in what is perceived to be the less-prospective blocks, companies may bid a seismic option only. And in the more prospective blocks, the number of wells in the obligatory phase may vary. We have also opted for an open biddable profit-sharing matrix, no signature bonus or carried participation.” However the minister said there were minimum benchmarks for bids and the ministry will not accept bids below this threshold. She said recent studies have gone a long way in establishing the prospectivity of the deepwater acreage. “The studies have shown that there are significant resources in the deep water, in the billion barrel region, and as with Brazil, the early adopters will benefit.”

Oil & Gas Journal | Mar. 7, 2011

GAS TREATING AND PROCESSING. SOLUTIONS. NITROGEN, HELIUM, COAL MINE METHANE, CO2 TECHNOLOGY. BEYOND ENGINEERING.

DRILLING & PRODUCTION Q U IC K TA K E S Petrobras starts well test in Campos basin Petroleo Brazileiro SA (Petrobras) commenced on Feb. 23 an extended well test on the Tracaja presalt reservoir, via well 6-MLL-70, which is in the Campos basin’s Marlin Leste field, 124 km off Rio de Janeiro. Petrobras connected Well 6-MLL-70, which made the oil discovery at a 4,442-m depth in September 2010, to the P-53 floating production, storage, and offloading vessel that also handles production from other wells in the Marlin Leste field that produce oil from non presalt reservoirs. Initial flow from Well-6-MML-70 was 23,300 b/d. In December 2010, Petrobras began a similar test at Carimbe also in the presalt cluster in the Caratinga area. Petrobras submitted the discovery assessment plan for Tracaja to the National Petroleum Agency in 2010. The plan calls for the drilling one or two wells for delineating the accumulation. In addition to Tracaja and Carimbe, Petrobras has discovered oil in other Campos basin presalt areas and will start an extended well test at Brava (Marlim concession), Aruana, and Oliva (exploration Block BM-C-36) in 2011. In the northern portion of the Campos basin, off the coast of Espirito Santo, Petrobras has been producing presalt oil from Parque das Baleias since August 2008.

Solar technology supplies steam to EOR project The world’s first commercial thermal enhanced oil recovery project that uses solar steam generators went on line Feb. 24 at Berry Petroleum Co.’s heavy oil 21Z lease in McKittrick, Calif. The project incorporates GlassPoint Solar’s single transit trough technology, specifically designed for rugged oil field environments. The solar facility uses a glasshouse enclosure to protect and seal the solar mirror from the elements, including dust, dirt, sand, and humidity. GlassPoint said the protected environment allows for the use

of ultralight, low-cost reflective materials. Other features of its system noted by GlassPoint are: • Creation of a protected environment, where high-performance, front-surface reflectors are now practical and durable for the first time. • Automated washing equipment that eliminates manual cleaning and operator intervention, further reducing costs and water use as well as worker health and safety concerns. • Elimination of multiple light transits through dirty glass, delivering higher real-world optical efficiency than today’s other solar systems. • Efficient land use, offering the highest steam production per acre of any solar technology—five times more steam per acre than solar tower systems. • Directly raising steam with standard oil field boiler feedwater, eliminating reboilers and expensive deionizing units required by older solar systems. • Delivery of steam at a constant price for the entire 30-year life of the system. GlassPoint built the solar unit in less than 6 weeks and estimates that its facililty on the 21Z lease will supply during the day about an average 1 million btu/hr of solar heat and replace 25-80% of the steam generated by gas-fired boilers on the lease. In a February presentation, Berry Petroleum noted that it acquired the 21Z lease in 2009 and that it considered the development of the lease as a next generation heavy oil project. It said these projects have higher viscosity crude and will require higher steam-oil ratios and tighter spacing than traditional Midway-Sunset developments. Berry completed a pilot on the 21Z lease in 2010 and has targeted a 50-well development program for the lease in 2011.

Alberta Blackrod SAGD pilot injection nears BlackPearl Resources Inc., Calgary, plans to inject steam in the second quarter of 2011 at a steam-assisted gravity drainage pilot at Blackrod in Alberta’s Athabasca area. BlackPearl expects pilot results in late 2011 and would apply for a 40,000 b/d commercial development in the 2012 first quarter. The project involves 9° gravity oil in 18-26 m of pay in the Lower Grand Rapids formation on 30,080 net acres (OGJ Online, Mar. 30, 2010). Since receiving regulatory approval for the pilot last October, BlackPearl has drilled a horizontal well pair and water source, water disposal, observation, and monitoring wells. The company has 100% working interest and is operator of the project.

PROCESSING Q U IC K TA K E S PBF unit completes Toledo refinery purchase

Solar house for Berry Petroleum Co.’s heavy oil 21Z lease in McKittrick, Calif. Photo from GlassPoint Solar.

12

Toledo Refining Co. LLC, a wholly owned subsidiary of PBF Holding Co. LLC, has completed its purchase of a 170,000-b/d refinery in Toledo, Ohio, from Sunoco Inc. (OGJ, Dec. 13, 2010, Newsletter). The purchase price was $400 million, half in cash and half in a 2-year note.

Oil & Gas Journal | Mar. 7, 2011

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Oman Refineries & Petrochemical Co. let a $40 million contract to CB&I, Houston, for front-end engineering and design and project management at the Sohar refinery. The project will increase capacity of the refinery to 187,000 b/sd from 116,000 b/sd by installing various clean fuels units and increasing capacity of and debottlenecking existing units, said the CB&I announcement.

two-berth pier and LNG is transferred over cryogenic arms from supply vessel to regasification vessel. At the TRBA terminal, LNG will be transferred directly between vessels using side-by-side docking, which means that the regasification vessel will dock at a single-berth, island-type pier, said the company. With direct connection to the supply vessel, LNG will be transferred over short hoses or loading arms to the regasification vessel, which will convert LNG back into a vapor. Gas will then be injected into the pipeline network through a 28-in. pipeline that is 49 km long including a 15-km subsea section. Petrobras noted that currently only two other LNG terminals in the world use this configuration: Bahia Blanca in Argentina and the UAE’s Dubai terminal.

Two Chilean refineries due technical services

KMEP enters Bakken, Eagle Ford rail partnership

SGS Industrial Services Chile, Santiago, has been assigned a 2-year contract to provide comprehensive asset integrity management and nondestructive testing services for two oil refineries in Chile. The company didn’t identify the plants. OGJ’s annual survey indicates that Chile’s state Empresa Nacional de Petroleo operates the country’s only three refineries, Anconcagua, Gregorio, and BioBio. SGS said its role will be to help the client manage the refineries’ assets and to ensure their integrity and reliability. The services include inspection of reactors, tanks, certain pipelines and distillation columns, conventional and advanced nondestructive testing (NDT), including vibration analysis for rotary equipment, and rope access services to enable access at different inspection points.

Kinder Morgan Energy Partners LP (KMEP) and Watco Cos. LLC will build and operate several rail facilities in key markets for loading and unloading crude oil, along with other commodities and products tied to the oil and gas industry. The network will include markets such as Dore and Stanley, ND; Stroud, Okla.; and Houston as well as strategic loading facilities in the Eagle Ford shale in South Texas. Each facility will handle large unit train crude volumes along with manifest commodities such as frac sand, pipe, and drilling supplies. The Dore facility will include Pioneer Oil LLC and have more than 10,000 ft of track in Phase I along with warehousing for inside storage. Watco expects the facility to enter service Sept. 1. Stroud will handle unit train volumes starting Oct. 1, providing customers direct access to Cushing, Okla. KMEP is 50% partner in a new venture building 750,000 bbl of new storage at Cushing (OGJ Online, Mar. 1, 2011). The other locations are still in design phase and will be operational first-quarter 2012. Burlington Northern Santa Fe Railway Co. will provide rail services for the project. BNSF also is serving Rangeland Energy LLC’s North Dakota oil terminal, COLT Connector, set to enter service by December (OGJ Online, Dec. 1, 2010).

The deal also included a participation payment of up to $125 million, based on profitability of the refinery, and sale of inventories. The high-conversion refinery processes mainly light, sweet crudes from the US Midcontinent and Canada.

Oman awards refinery expansion contract

TRANSPORTATION Q U IC K TA K E S Petrobras announces third LNG terminal Petroleo Brasileiro SA (Petrobras) reported it will install a third offshore LNG terminal. The Bahia regasification terminal (TRBA), with capacity to regasify 14 million cu m/day (cmd), will supply natural gas to the state of Bahia, the heaviest consumer of gas among the northeastern Brazilian states. TRBA will be installed in the Bay of All Saints and interconnect with a pipeline network at two sites: one in the Bahia network, at Candeias, and the other at kilometer 910 on the Cacimbas-Catu pipeline, a section of the Southeast-Northeast Gas Pipeline started up in March 2010. As part of Brazil’s Growth Acceleration Program, Petrobras said, work will begin in March 2012 with completion scheduled for August 2013 under an investment of nearly $425 million. Currently, Brazil has LNG terminals at Pecem (State of Ceara) with a regasification capacity of 7 million cmd, and in the Guanabara Bay (State of Rio de Janeiro) with capacity of 14 million cmd. When the TRBA terminal comes online in September 2013, Brazil’s total regasification capacity will reach 35 million cmd, overtaking the gas imports via pipeline from Bolivia (31 million cmd). At the Pecem and Guanabara Bay terminals, tankers moor at a

14

Venture to add storage capacity at Cushing Kinder Morgan Energy Partners LP is investing $25 million for a 50% interest in a tank farm at Cushing, Okla., to which a related joint venture will add storage capacity. Kinder Morgan formed the JV with Deeprock Energy Resources LLC, the construction manager and terminal operator, and Mercuria Energy Trading Inc., which will remain anchor tenant for the next 5 years with an option to extend. The JV will build three storage tanks with capacity totaling 750,000 bbl. Capacity of the tank farm now is 1 million bbl. KMEP also entered a development agreement in which it receives an option to participate in future expansions on the remaining 254 acres of Deeprock’s undeveloped land. Partly because crude in storage at Cushing is at nearly capacity levels, West Texas Intermediate crude is trading at an unusually large discount to Brent.

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LABOR ANALYTICS

LETTERS

2011-2012 EVENT CALENDAR

Joint spill planning

Denotes new listing or 228-6329 (fax), website: www.events.nace.org/ a change in previously conferences/c2011/inpublished information. As Cuba and The Bahamas develop their dex.asp. 13-17. deepwater oil and natural gas potential, the

possibility of an accidental oil spill demands proactive joint planning by both countries and the US in order to minimize or avoid such a disaster in a spirit of cooperation and not confrontation in order to protect our fragile shared marine environment. A model for such planning can be the MEXUS Plan signed by the US and Mexico in 1980 in response to the 1979 blowout of the Ixtoc I exploratory well and consequent spill in the Bay of Campeche. US Rep. Vern Buchanan of Sarasota recently introduced a bill, HR 372, which attempts to coerce foreign oil companies that explore in Cuban waters by blocking them from drilling in US territorial waters. This approach is counterproductive and affects American oil companies’ overseas ventures in countries such as Brazil, Angola, Vietnam, and Russia and as a result jeopardizes US international energy security interests. Such an action would also impact domestic national energy policy as foreign oil companies are today the operators or interest holders in about a quarter of the active of pending federal oil and gas leases in the Gulf of Mexico. A retaliatory strategy does not accomplish the objective of prudent environmental stewardship. We should be responsible and pragmatic in order to respond effectively to an oil-related marine accident by providing international oil companies operating in Cuba and The Bahamas immediate access to US oil services and equipment companies that can provide the near-instant technology and know-how that will be needed to limit and halt damage to the marine environment. The Deepwater Horizon incident experience taught the US very important hands-on lessons on how to manage such a catastrophe, lessons which would benefit us in the future by sharing them with neighbors. Obviously, the establishment of working relations between the US, Cuba, and The Bahamas in marine environmental protection would assist enormously in the contingency planning and cooperation necessary to an early and truly effective response to an oil spill. Jorge R. Pinon Visiting Research Fellow Florida International University Miami

16

MARCH 2011

Libya International Petro & Energy Fair, Tripoli, 00971 4 2988144, 00971 4 2987886 (fax), e-mail: [email protected], website: www. orangefairs.com. 7-10. API Spring Committee on Petroleum Measurement Standards Meeting, Dallas, (202) 682 8000, (202) 682-8222 (fax), website: www.api.gor. 7-10.

AIChE Spring Meeting & Global Congress on Process Safety, Chicago, (800) 242-4363, (203) 775-5177 (fax), website: www.aiche.org/conferences/springmeeting/ index.aspx. 13-17. Offshore West Africa Conference & Exhibition, Accra, Ghana, (918) 8319160, (918) 831-9161 (fax), e-mail: [email protected], website: www.offshorewestafrica.com. 15-17.

CERA Week, Houston, (713) 840-8282, (713) 599-9111 (fax), e-mail: [email protected], website: www.cera.com. 7-11.

World Heavy Oil Congress, Edmonton, Alta., (888) 799-2545, (403) 245-8649 (fax), website: www.worldheavyoilconRenewable Energy World gress.com. 15-17. Conference & Expo North America, Tampa, TUROGE Turkish International Oil & Gas (918) 831-9160, (918) Conference & Showcase, 831-9161 (fax), e-mail: Ankara, +44 (0) 20 7596 registration@pennwell. 5000, +44 (0) 20 7596 com, website: www. renewableenergyworld- 5111 (fax), e-mail: [email protected], events.com. 8-10. website: www.turoge. European Fuels Confer- com. 16-17. ence Annual Meeting, NPRA Annual Meeting, Paris, +44 (0)207 430 San Antonio, (202) 4579513, +44 (0)207 430 0480, (202) 457-0486 9513 (fax), e-mail: e.huiban@theenergyex- (fax), e-mail: info@npra. org, website: www.npra. change.co.uk, website: org. 20-22. www.wraconferences. com/2/4/articles/205. MEOS/SPE’s Middle East php. 8-11. Oil & Gas Conference & Exhibition, Manama, +44 DEA(e) Technical Oil & Gas Conference on Well (0)20 7840 2139, +44 Control, Bad Bentheim, (0)20 7840 2119 (fax), e+44 (0) 1483 598000, mail: meos@oesallworld. com, website: www. e-mail: dawn.dukes@ meos2011.com. 20-23. otmnet.com, website: www.dea-europe.com. GPA Europe at GasTech 10-11. Conference & Exhibition, NACE Corrosion Confer- Amsterdam, +44 (0) ence & Expo, Houston, 1737 855000, +44 (0) 1737 855482 (fax), e(800) 797-6223, (281) mail: [email protected],

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e-mail: www.gastech. co.uk. 21-24.

OMC Offshore Mediterranean Conference, Ravenna, +39 0544 GASTECH International 219418, e-mail: conferConference & Exhibition, [email protected], website: Amsterdam, +44 (0) www.omc.it/2011. 23-25. 1737 855000, +44 (0) 1737 855482 (fax), eMarine Technology mail: [email protected], Society Houston Section e-mail: www.gastech. Annual Marine/Offshore co.uk. 21-24. Industry Outlook Conference, Houston, (512) CIPPE China Inter301-2744, website: www. national Petroleum & mtshouston.org. 24. Petrochemical Technology and Equipment SPE Production and Exhibition, Beijing, +86 Operations Sympo10 58236588/6555. sium, Oklahoma City, +86 10 58236567 (fax), (800) 456-9393, (972) e-mail: cippe@zhenwei952-9435 (fax), e-mail: expo.com, website: www. [email protected], website: cippe.com.cn/cippeen. www.spe.org. 27-29. 22-24. IADC Drilling HSE Asia Pacific Conference & Exhibition, Singapore, (713) 292-1945, (713) 292-1946 (fax), e-mail: [email protected], website: www.iadc.org/conferences. 23-24.

NPRA International Petrochemical Conference, San Antonio, (202) 4570480, (202) 457-0486 (fax), e-mail: info@npra. org, website: www.npra. org. 27-29.

Oil & Gas Journal | Mar. 7, 2011

Howard Weil Annual Energy Conference, New Orleans, (504) 5822500, website: www. howardweil.com/energyconference.aspx. 27-30. Middle East Downstream Week Annual Meeting, Abu Dhabi, +44 (0) 1242 529 090, +44 (0) 1242 529 060 (fax), e-mail: wra@theenergyexchange. co.uk, website: www. wraconference.com. 27-30. ACS National Meeting & Exposition, Anaheim, Calif., (202) 872-4600, e-mail: [email protected], website: www.acs.org. 27-31. Purvin & Gertz International LPG Seminar, The Woodlands-Houston, (713) 331-4000, (713) 236-8490 (fax), e-mail: info@purvingertz. com, website: www. purvingertz.com. 28-31.

17

2011-2012 EVENT CALENDAR

Crawfish • Beer and soft drinks Barbecue • Hot dogs • Bratwurst Live band • Desserts Children’s games • Raffles Proceeds go to Engineering Scholarships

Sunday, May 1 / 1-5 p.m. $35/ticket ($40 at the door) University of Houston (entrance #1 – off Spur 5)

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For tickets & sponsorship Info: contact Diane Ashen, (713) 271-1983 Thank You 2010 Sponsors TITANIUM SPONSORS AKER SOLUTIONS ASHEN & ASSOCIATES EXECUTIVE SEARCH BAKER HUGHES CAMERON DRIL-QUIP GE OIL & GAS PENNWELL RADOIL

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18

website: www.pipelineconference.com. 4-5.

Eastern Canada shale Gas Symposium, Montreal, Que., (877) 927-7936, (877) 927-1563 (fax), e-mail: customerservice@canadianinstitute. com, website: www. canadianinstitute.com/ energy_resources/EasternShaleGas.htm. 29-30. Offshore Asia Conference & Exhibition, Singapore, (918) 831-9160, (918) 831-9161 (fax), e-mail: registration@pennwell. com, website: www. offshoreasiaevent.com. 29-31. IRO On & Offshore Exhibition, Gorinchem, +31 523 289866, e-mail: [email protected], website: www.evenementenhal. nl/gorinchem/beurzen. 29-31. SEG Shale Gas Forum, Chengdu, Sichuan, (918) 497-5500, (918) 497-5557 (fax), website: www.seg.org. 30-31.

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SPE/IADC Managed Pressure Drilling & Underbalanced Operations Middle East Downstream ShaleCon Conference, Conference, Denver, Week Annual Meeting, Montreal, Q.C., (800) (800) 456-9393, (972) Abu Dhabi, +44 1242 882-8684, e-mail: info@ 952-9435 (fax), e-mail: 529 090, +44 1242 iapc.com, website: www. [email protected], website: 529 060 (fax), e-mail: shalecon.com/Event. [email protected]. 5-6. aspx?id=388398. 4-7. Woodford Shale Summit, change.co.uk, website: Norman, Okla., (405) www.wraconferences. OilTech Atyrau Regional 525-3556, ext. 117, Hannover Messe Intercom/2/4/articles/105. Petroleum Technology (405) 525-3592 (fax), national Trade Show, php. 3-6. Conference, Atyrau, +44 e-mail: amy.childers@ Hannover, +49 511 89 0, (0) 20 7596 5000, +44 iogcc.state.ok.us, webGPA Annual Convention, +49 511 89 32626 (fax), (0) 20 7596 5111 (fax), site: www.woodfordsum- San Antonio, (918) 493- website: www.hannovere-mail: [email protected]. 29-30. messe.de/homepage_e. 3872, (918) 493-3875 exhibition.com, website: 4-8. (fax), e-mail: pmirkin@ www.oiltech-atyrau.com/ GIOGIE Georgian gpaglobal.org, website: home.html. 5-6. International Oil & Gas SPE/ICoTA CoiledTubwww.GPAglobal.org. 3-6. Energy and Infrastructure ing & Well Intervention Conference, Tbilisi, +44 Hannover Messe Pipeline Conference & Exhibition, Atyrau North Caspian 207 596 5135, +44 207 Technology ConferThe Woodlands, Texas, Regional Oil, Gas and 596 5106 (fax), e-mail: (800) 456-9393, (972) Infrastructure Exhibience, Hannover, +49 ilyas.idigov@ite-exhibi511 90992 22, +49 511 952-9435 (fax), e-mail: tion, Atyrau, +44 (0) 20 tions.com, website: www. 90992 69 (fax), e-mail: [email protected], website: 7596 5000, +44 (0) 20 giogie.com/2011/. 29-30. [email protected], www.spe.org. 5-6. 7596 5111 (fax), e-mail: SPE European Well Abandonment Seminar, Aberdeen, +44 1224 495051, e-mail: jane. rodger@hulse-rodger. com, website: www.speuk.org. 29.

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FLOW EQUIPMENT Reliability .

2011-2012 EVENT CALENDAR enquiry@ite-exhibition. com, website: www. atyrauoilgas.com2011/. 5-7.

APPEA. Conference and Exhibition, Perth, +61 (7) 3802 2208, +61 (7) 3802 2209, website: www.appeaconferences. AAPG Annual Convention com.au. 10-13. & Exhibition, Houston, GITA’s Geospatial (918) 560-2679, (918) 560-2684 (fax), website: Infrastructure Solutions Conference, Grapevine, www.aapg.org. 10-13.

Texas, (303) 337-0513, (303) 337-1001 (fax) website: www.gita.org/ events/futconf.asp. 10-14. SAGEEP Information Exchange for New-Surface Geophysics Forum, Charleston, (918) 497-

[email protected], website: ISA Calgary, Calgary, Alta., (403) 209-3555. www.gtui.org. 10-15. (403) 245-8649 (fax), The Project Forum, Mos- website: www.isacalgary. com. 13-14. cow, +44 (0) 20 7357 Gas Turbine Users International Annual Con- 8394, +44 (0) 20 7357 Middle East Petroleum & 8395 (fax), e-mail: enference (GTUI), Dubai, +971 4 8047883, +971 [email protected], Gas Conference (MPGC), 4 8873584 (fax), e-mail: website: www.europetro. Bahrain, 0065 6338 0064, 0065 6338 4090 com. 11-12. (fax), website: www. gulfoilandgas.com. 17-19. Process Safety Man5500, (918) 497-5557 (fax), website: www.seg. org. 10-14.

agement of Chem/ Petrochem & Refineries Conference, Houston, (312) 540-300, ext. 6625, e-mail: Michelew@marcusevansch. com, website: www. marcusevansch.com/ OGJPSM. 11-13.

DUG Developing Unconventional Gas Conference & Exhibition, Fort Worth, (713) 280-6479, (713) 583-1353 (fax), e-mail: acooper@hartenergy. com, website: www.dugconference.com. 18-20.

IPAA OGIS-New York, NewYorkCity, (202) 8574722, (202) 857-4799 (fax), website: www.ipaa. org. 11-13.

Alliance Expo & Annual Meeting, Wichita Falls, Texas, (940) 723-4131, (940) 723-4132 (fax), e-mail: texasalliance@ texasalliance.org, website: www.texasalliance. org/index.php. 26-27.

Pipe Line Contractors Association of Canada Annual Convention, Maui, (905) 847-9383, (905) 847-7824 (fax), email: [email protected], website: www.pipeline. ca/convention.html. 11-15.

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Oil & Gas Siberia, Novosibirsk, +7 383 2106290, +7 383 2209747 (fax), email: [email protected], website: www.petroleum. sibfair.ru/eng/. 27-29.

GPA Mid-continent Annual Meeting, Okla. City, API Pipeline Conference, (918) 493-3872, (918) San Antonio, (202) 682 493-3875 (fax), website: 8000, (202) 682-8222 www.gpaglobal.org/chap(fax), website: www.api. ters/midcontinent. 28. org. 12-13. AADE National Technical Conference and Exhibition, Houston, (281) 366-8204, e-mail: [email protected], website: www.aade.org. 12-14. Russia & CIS Bottom of the Barrel Technology Conference & Exhibition, Moscow, +44 (0) 20 7357 8394, +44 (0) 20 7357 8395 (fax), e-mail: enquiries@europetro. com, website: www.europetro.com. 13-14.

MAY 2011 OTC Offshore Technology Conference, Houston, (301) 694-5243, or (866) 229-2386, (972) 952-9435 (fax), e-mail: [email protected], website: www.otcnet. org.2011. 2-5. GPA Permian Basin Annual Meeting, Odessa, (918) 493-3872, (918) 493-3875 (fax), website: www.gasprocessor.com/ calendar.html. 3.

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JOURNALLY SPEAKING

Chinese budgets An energy outlook survey of chief financial officers at US exploration and production companies found that concerns about increased dependence on foreign sources of oil persist in light of US President Barack Obama’s proposals to eliminate certain tax incentives for US-based producers. Indeed, 57% of respondents of the survey, conducted last November by financial services firm BDO, expressed such concerns that the changes also would send investment dollars and jobs overseas. “One message came through loud and clear in this year’s survey: Legislative changes represent the biggest threat to growth in the oil and gas industry,” said BDO partner and natural resources industry practice leader Charles Dewhurst. The survey also found that despite an expected MARILYN RADLER increase in global oil demand, only 7% of compaSenior Editor-Economics nies in the random sample survey plan to expand to new geographic areas outside the US in 2011. Investments inside and outside the US this year will climb, though.

CNOOC spending China National Offshore Oil Corp. Ltd. (CNOOC) announced that it has planned a robust capital budget and strong production growth for 2011. CNOOC said its capital expenditures will total $8.77 billion this year. The company’s 2010 budget was set at $7.93 billion, a 30% jump from 2009 spending. Spending will support sustainable growth as well as deepwater exploration and development, including in the South China Sea, as the Beijingbased company drills 96 exploration wells during the year. Exploration capital spending will be $1.56 billion, CNOOC said, while outlays will total $5.05 billion this year for development and $2.02 billion for production. Projected net production this year is 355-365 million boe, assuming that the price of West Texas Intermediate crude oil averages $82/bbl. Last year, net production was about 328 million boe.

Chinese government ties Just how closely Chinese oil companies are controlled by the government is part of a new report by the International Energy Agency that highlights

22

inaccuracies in some commonly held views of those companies. IEA noted that before this report, titled Overseas Investments by Chinese National Oil Companies, there had been little analysis to test the presumption that these oil producers act under the instructions and in close coordination with the Chinese government. The report finds that Chinese producers operate with a high degree of independence from the government, and contrary to some beliefs, their investments have largely boosted global supplies of oil and gas, on which other importers rely. Julie Jiang and Jonathan Sinton, IEA experts on China and the report’s authors, said these are far from puppet companies operating under the government’s control, and their investments in recent years have been driven by a strong commercial interest. These Chinese companies emerged in the 1980s when the government converted ministry assets such as refineries into state-owned enterprises, aiming to stimulate competition so that the companies were subject to market discipline. The companies in the early 1990s invested in other countries and have grown into big international players. The largest one, the report says, is China National Petroleum Corp., the world’s fifth-largest oil company with 1.6 million employees. Another misperception about the management of these Chinese companies was that the government imposed a quota on the amount of equity oil they must send to China from overseas investments. The research uncovered no evidence of such quotas. In 2010, China’s oil companies invested nearly $16 billion to acquire assets, including refineries, in Latin America, and by late 2010, these companies had equity oil in 20 of the 31 countries where they operated, according to IEA. Decisions about the marketing of equity oil, where the Chinese companies have control over the disposition of their share of production, appear to be dominated by market considerations, the report said, as almost all of the equity production that Chinese firms have in the Americas has been sold locally rather than shipped to China.

Oil & Gas Journal | Mar. 7, 2011

EDITORIAL

Reporting alarm To an incendiary story the New York Times published Feb. 27 on hydraulic fracturing, there are proper and improper ways to respond. An improper way might come naturally to US oil and gas producers, who have reason to be jaded by exaggerations underlying opposition to their work. That response would be to ignore the story as yet more mongering of nonexistent problems. In fact, the Times might have identified a genuine problem. Following sad tradition of investigative journalism, however, its story didn’t run hard enough at the central question. Doing so might have produced an antidote to alarm, without which the story would have collapsed. Who, outside an industry dependent on the process for completing horizontal wells in gas-rich shales, wants to read about hydraulic fracturing unless it represents clear and present danger?

Water contamination The potential problem, enshrouded by the story in several thousand words, is possible mistreatment of contamination brought to surface by frac-water returns. The largest worry: naturally occurring radium and other radioactive substances, encountered in meaningful amounts in some but not all wells. The Times discovered that not all wastewater treatment plants in Pennsylvania remove all radioactive wastes or even test for them before dumping treated water into rivers; furthermore, downstream drinking-water plants aren’t testing intake flows for radioactivity. Contamination, therefore, might be entering drinking water in concentrations high enough to be dangerous. But is it? That no definite answer exists is reason for Pennsylvania to require radioactive testing of wastewater plant effluent and, especially, of flows into drinking-water plants. For calling attention to the need for new precaution against a possible health threat, the Times deserves credit. But dilution happens. The Times story cites several views of the extent to which Pennsylvania streams lower concentrations of waterborne radioactive wastes but leaves the strong impression of an uncontrolled threat. And it deserves scorn for the muted emphasis it gives several other alarm dampeners, such as a toughening of wastewater-disposal regulation in Pennsylvania

24

last year and the increasing use of wastewater recycling in a state unusual for the extent to which it allows discharges into waterways. John Hanger, until Jan. 18 secretary of the Pennsylvania Department of Environmental Protection, rebutted the Times article on his blog, citing the new disposal rules and sundry omissions and factual errors. “The article excludes information completely or from the main story, used misleading words to conceal important points, and consistently shaped information to advance the narrative of ‘lax regulation,’” Hanger said. One of the omissions was a favorable review by an independent group last year of Pennsylvania’s regulation of hydraulic fracturing. That program has been strained by a drilling surge in the prolific Marcellus shale. Hanger conceded that the Times identified an important question: “whether or not unhealthy levels of radium are in the drinking water as a result of gas drilling wastewater.” While tougher regulation and recycling provide reason to think not, he said, “Only testing of the drinking water for these pollutants can resolve the issue.”

Different response His response to the Times article is judicious. The same can’t be said for an opportunistic appeal for help from the US Environmental Protection Agency by Rep. Ed Markey (D-Mass.), who seeks federal regulation of hydraulic fracturing. “I do not believe that the price for energy extracted from deep beneath the earth’s surface should include a risk to the health of those who live above it,” Markey wrote to EPA Administrator Lisa Jackson, citing the Times article. “I am outraged that state and federal regulators were evidently well aware of the risks that the wastewater might pose but instead chose to adopt a ‘see no evil, hear no evil’ approach to regulation by ignoring them.” An industry pest thus distorts a warped report in pursuit of more regulation and less energy supply. The oil and gas business has unhappy familiarity with Markey’s style of extremism—and promotion of it by the New York Times.

Oil & Gas Journal | Mar. 7, 2011

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GENERAL INTEREST

Capital budgets to rise this year in North America and worldwide Marilyn Radler

will conduct any lease sales during 2011, which would be the first year without a Gulf of Mexico lease sale since 1964. In 2010, the agency’s forerunner, the Minerals ManageCapital expenditures for oil and gas projects in the US will ment Service, held one lease sale in the Gulf of Mexico. It increase 5% this year, according to OGJ’s annual spending generated $1.3 billion in bonus payments, compared with report. Upstream, midstream, downstream, and the $801 million in bonus payments from two Gulf corporate capital outlays will total $284 billion. of Mexico lease sales held in 2009. The pace of growth has slowed following last year’s A recent study by Wood Mackenzie, sponsored rebound from a drop in 2009. by the American Petroleum Institute, found that Oil and gas capital expenditures also will climb aside from the loss of oil and gas production, the in Canada this year, up 3.7% to $52.6 billion. This current suspension of permits to drill in the Gulf of compares with 37% growth in spending for such Mexico could put at risk $70 billion in investment SPECIAL projects last year. and $18 billion in government revenue between REPORT In Mexico, Petroleos Mexicanos plans a 9% in2011 and 2022 (OGJ Online, Jan. 25, 2011). crease in capital spending this year. And outside In 2009, capital spending sank as a result of the North America, oil and gas capital expenditures are drop in demand for oil and gas during the economic recession. US upstream budgets that year included $175 forecast to remain strong, also climbing from a year ago. billion for exploration and drilling, $33 billion for producUS upstream spending tion capital outlays, and $801 million in OCS bonus payCapital outlays in the US this year for all upstream projects ments for the two lease sales. will total $258.9 billion, compared with $245 billion last The number of wells drilled in the US declined in 2009 year. to about 33,830 from 56,550 in 2008, according to API. In Most of this year’s expenditures will go toward explora2010, the number of wells drilled rebounded somewhat to tion and drilling, the remainder to production. No Outer 37,892. Continental Shelf (OCS) bonus is forecast due to the suspenOGJ’s forecast of 2011 activity assumes that the number sion of activity in the Gulf of Mexico. of wells drilled in the US will grow 4% from last year. The As of presstime, OGJ does not expect that the Bureau of forecast also assumes that the average cost of drilling an oil Ocean Energy Management, Regulation, and Enforcement or gas well, after dipping in 2009, will climb for the second year in a row. Senior Editor-Economics

WHERE FUNDS WILL GO FOR US PROJECTS 2011, million $

Change 2011-2010, %

2010, million $

217,532 41,331 0 258,863

6.2 6.2 –100.0 5.7

204,806 38,913 1,300 245,019

17.0 17.0 62.3 17.2

175,070 33,263 801 209,134

9,200 300 2,900 1,408 5,348 1,100 1,000 4,000 25,256 –––––––– Total . . . . . . . . . . . . . . . . . . . . 284,119

73.6 0.0 6.2 –83.6 74.7 15.8 0.0 0.0 –2.5 –––– 4.9

5,300 300 2,730 8,563 3,062 950 1,000 4,000 25,905 –––––––– 270,924

–47.7 –14.3 40.0 –5.9 –74.3 13.1 11.1 6.7 –33.5 ––––– 9.2

10,140 350 1,950 9,104 11,907 840 900 3,750 38,941 –––––––– 248,075

Exploration-production Drilling-exploration . . . . . . . . . . . . Production . . . . . . . . . . . . . . . . . . OCS lease bonus . . . . . . . . . . . . . . Subtotal . . . . . . . . . . . . . . . . . . . . Other Refining . . . . . . . . . . . . . . . . . . . . Petrochemicals . . . . . . . . . . . . . . . Marketing . . . . . . . . . . . . . . . . . . . Crude and products pipelines . . . . Natural gas pipelines . . . . . . . . . . . Other transportation . . . . . . . . . . . Mining, other energy . . . . . . . . . . . Miscellaneous . . . . . . . . . . . . . . . . Subtotal . . . . . . . . . . . . . . . . . . . .

26

Table 1

Change 2010-2009, 2009, % million $

Other US spending Total capital expenditures for all other projects in the US this year, including refining, pipelines, and LNG, will decline by 2.5%, OGJ forecasts. Spending in some categories will increase, though. Natural gas pipeline projects will account for a large portion of capital outlays in the US this year. Plans call for construction of 1,480 miles of gas lines in 2011, according to OGJ’s Worldwide Pipeline Construction report (OGJ, Feb. 7, 2011, p. 110). Capital expenditures for the proj-

Oil & Gas Journal | Mar. 7, 2011

Highlight: individual company plans and price expectations Many companies, flush with cash after posting hefty profits on last year’s strong oil prices, are ready to boost spending in order to ramp up production. Chevron Corp. in December 2010 announced a $26 billion capital and exploratory spending program for this year. About 85% of the budget targets exploration and production projects, while 10% is for operations that manufacture, transport, and sell petroleum products, additives, and petrochemicals. Chevron allocated $17.2 billion of its budget to upstream operations outside the US and $5.4 billion to projects within the US. Major capital investments include development of natural gas resources in Western Australia and development opportunities in the deepwater US Gulf of Mexico, Western Africa, and the Gulf of Thailand. The company plans to spend $2.9 billion for downstream operations this year, including projects geared toward improving returns at refineries in Mississippi and California, Chevron said. BP PLC, which also plans to boost exploration spending this year, announced that its worldwide organic capital expenditure for 2011 will be about $20 billion. In 2010, such outlays totaled $18.2 billion. In addition to boosting exploration, BP plans to resume activity in the Gulf of Mexico this year, ramp up activity in Iraq, and increase the number of turnarounds at its refineries.

In November of last year, ConocoPhillips said it plans to sharply hike capital spending in the Southeast Texas Eagle Ford shale play in 2011. Investment was likely to be $1-1.5 billion in 2011, compared with $300 million in 2010. The 2011 amount is for drilling and completions, not to add acreage (OGJ, Nov. 29, 2010, Newsletter). Hess Corp. announced a $5.6 billion 2011 capital and exploratory budget, nearly all targeted for exploration and production. Hess has allocated $3.1 billion for production, $1.6 billion for development, and $900 million for exploration. Only $85 million has been budgeted for marketing, refining, and corporate capital expenditures. Shell announced last year that it could invest $40 billion in North America over the next 4 years to boost production by 40% from current levels. Shell’s investment focus would be on heavy oil, onshore gas, deep water, and exploration.

Independent producers Continental Resources Inc., Enid, Okla., announced in October 2010 that it had committed 91% of its $1.36 billion 2011 capital expenditures budget to drilling, workovers, and facilities to raise production. Of these drillingrelated outlays, Continental said, 92% will be invested in the Bakken shale in North Dakota and Montana and in the Woodford shale in Oklahoma. These two plays are critical to Continental’s

ects, including pump stations and compressors, will total $5.3 billion. This represents a 75% jump in capital outlays for gas pipelines from 2010. This year’s expenditures for crude and products pipelines in the US will decline 84% to $1.4 billion, as plans call for the construction of 483 miles of these lines. Gulf LNG Energy LLC, owned by El Paso Corp., Crest Group, and Sonangol USA, this year will complete construction of its LNG terminal at Pascagoula, Miss. The total cost of the project was $1.1 billion. The work included two storage

Oil & Gas Journal | Mar. 7, 2011

growth over the next 5 years, the company said. LINN Energy LLC, Houston, in December announced that its $480 million 2011 oil and gas capital program will focus on the high rate-of-return, liquids-focused drilling in the Granite Wash and Permian basin Wolfberry trend as well as on low-risk, low-cost projects. About $120 million of LINN’s 2011 capital program has been designated as maintenance capital. The company expects to drill more than 220 wells and complete more than 380 workover, recompletion, and optimization projects during 2011.

Price assumptions The Barclays Capital E&P spending survey found that the average oil price on which companies based their 2011 budgets was about $77.32/bbl for West Texas Intermediate crude. This compares with a $70.16/bbl assumption used for 2010 budgets in December 2009. At midyear 2010, companies were basing budgets on an oil price of $73.56/bbl. Budgets also reflect a natural gas price forecast of $4.27/Mcf, down 18% from the gas-price expectation a year earlier and an 8% decrease from expectations at midyear 2010. These are the lowest gas prices expected since 2004, with $4-6/Mcf as the range outside of which many producers would change budgets, Barclays said.

tanks with combined capacity of 6.6 bcf. Send-out capacity is 1.3 bcfd. Other LNG projects recently have been completed, including expansions at Sempra Energy’s terminal at Hackberry, La., and at the Southern LNG Elba Island, Ga., terminal. All other transportation, mining, petrochemical, marketing, and corporate capital spending is expected to be little changed from 2010 as companies concentrate on development elsewhere.

27

GENERAL INTEREST

US refining outlays

development in 2010 was $13 billion. In 2009, oil sands expenditures declined to $11.2 billion (Can.) from a 2008 peak of $18.1 billion (Can.), according to CAPP. Construction of oil sands development projects—including the Kearl project, jointly owned by operator Imperial Oil and ExxonMobil Canada—will account for a large portion of this year’s capital spending in Canada. The first phase of the Kearl project is targeted to start up in late 2012, with initial output of about 110,000 b/d, according to Imperial. One mine is planned for the project life of more than 40 years, taking production capacity up to 345,000 b/d, but current plans do not include any on-site bitumen upgrading facilities. The project team is evaluating its refining options, including possible integration with North American refineries owned by Imperial and ExxonMobil. The Jackpine Mine at the Athabasca Oil Sands Project was completed last year, adding capacity of 100,000 boe/d to the existing Muskeg River Mine capacity of 155,000 boe/d. But once the expansion of the Scotford upgrader is on line early this year, production there will rise toward capacity. Canadian Oil Sands Trust, the largest joint venture owner of Syncrude, announced that its capital costs will total about $930 million (Can.) in 2011, including $620 million for major projects and the remainder for regular maintenance of Canadian E&P, oil sands the business and other projects. Capital expenditures this year in Canada for conventional Suncor Energy Inc. announced a $6.7 billion (Can.) capioil and gas exploration and production will rise 3.1% to tal spending plan for 2011, with $4.18 million allocated to oil sands operations. About $2.8 billion of Suncor’s total budget will fund growth projects, priCANADIAN SPENDING PLANS Table 2 marily at the company’s oil sands op2011, Change 2010, Change 2009, million $ 2011-2010, million $ 2010-2009, million $ erations, while $3.9 billion in spend(Can.) % (Can.) % (Can.) ing is targeted to sustaining existing Exploration-production operations, including planned mainDrilling-exploration . . . . . . . . . . . . 23,700 3.0 23,000 45.3 15,825 Production . . . . . . . . . . . . . . . . . . 9,800 3.2 9,500 45.9 6,510 tenance to support reliability and furSubtotal . . . . . . . . . . . . . . . . . . . . 33,500 3.1 32,500 45.5 22,335 ther deployment of new tailings reclaOil sands* . . . . . . . . . . . . . . . . . . . . 15,000 15.4 13,000 15.8 11,227 mation technology, Suncor said. Other The majority of growth spending Refining . . . . . . . . . . . . . . . . . . . . 1,700 70.0 1,000 –33.3 1,500 Petrochemicals . . . . . . . . . . . . . . . 50 25.0 40 300.0 10 will be directed toward expansion of Marketing . . . . . . . . . . . . . . . . . . . 500 0.0 500 0.0 500 Crude and products pipelines . . . . 431 –20.9 545 –10.9 612 Suncor’s Firebag in-situ oil sands facilNatural gas pipelines . . . . . . . . . . . 434 –81.0 2,286 6,890.8 33 ities. Firebag Stage 3 is slated to begin Other transportation . . . . . . . . . . . 300 20.0 250 11.1 225 Miscellaneous . . . . . . . . . . . . . . . . 700 16.7 600 9.1 550 production late in the second quarter Subtotal . . . . . . . . . . . . . . . . . . . . 4,115 –21.2 5,221 52.2 3,429 ––––––– ––––– ––––––– ––––– ––––––– of this year, ramping up toward caTotal . . . . . . . . . . . . . . . . . . . . 52,615 3.7 50,721 37.1 36,991 pacity of 62,500 b/d of bitumen over *In situ, mining, and upgrading. about 24 years. Suncor also is directing 2011 growth spending toward the Fort Hills $33.5 billion (Can.), up as a result of a rebound in the numoil sands mining project and resuming construction of the ber of wells drilled. Voyageur upgrader, two key elements in the company’s lonOGJ forecasts the capital spending for development and ger-term growth strategy. upgrading of Canada’s oil sands this year will total $15 bilWhile Suncor’s primary growth focus remains on its large lion. The Canadian Association of Petroleum Producers oil sands resource base, 2011 growth spending of $1.1 bil(CAPP) estimates that industry capital spending for oil sands lion is planned for development outside Canada and offshore Capital spending this year at US refineries will fund some large growth projects, maintenance, and all other projects and will total $9.2 billion, climbing 74% from last year. Valero Energy announced a preliminary capital spending estimate of $2.9 billion for 2011, an increase from its prior plan of $2.6 billion as it will install new hydrocrackers at its Port Arthur, Tex., and St. Charles, La., refineries sooner than originally scheduled. Valero increased its 2011 budget given the benefits of a new tax law allowing full depreciation this year on capital projects. The company said it has accelerated spending on economic-growth projects, thereby increasing its spending in 2011 by $300 million before the cash-tax benefits that may offset the increase in spending. The 2011 capital spending estimate also incorporates several major turnarounds in the first quarter and the early part of the second quarter, including reliability investments for a revamp of its St. Charles refinery cat cracker and replacement of coke drums at its Port Arthur refinery, Valero said. Meanwhile, the 325,000 b/d expansion of Motiva’s refinery in Port Arthur, Tex., is scheduled to be completed in early 2012. With a total capacity of 600,000 b/d, this will be the largest refinery in the US.

28

Oil & Gas Journal | Mar. 7, 2011

  






 






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GENERAL INTEREST operations, and $90 million is allocated to renewable energy projects.

Other Canadian expenditures A decline in pipeline construction will outweigh a large increase in spending at refineries to result in a collective decrease in 2011 midstream, downstream, and corporate oil and gas capital expenditures in Canada. OGJ’s Worldwide Pipeline Construction report finds that plans call for 149 miles of natural gas pipelines and 236 miles of crude and products pipelines to be laid in Canada this year. Total capital spending for all these pipeline projects will be $865 million (Can.). In 2010, plans called for the construction of 627 miles of new natural gas pipelines and 409 miles of crude oil and products pipelines in Canada. These projects are estimated to have cost a combined $2.8 billion. Capital spending this year at Canadian refineries will total $1.7 billion, a 70% increase from a year ago. Petrochemical expenditures are also expected to climb to $50 million from $40 million last year, while marketing outlays are unchanged at $500 million. All other capital spending in Canada including other transportation and corporate expenditures will increase by about 20% from last year.

Spending elsewhere This year Pemex plans capital spending of $22.2 billion, up from 2010 outlays of $20.4 billion. Of the total, the company said it has allocated 85% to upstream projects, including maintenance. In its most recent E&P spending survey, released in December, Barclay’s Capital found that outside North America, upstream capital spending budgets will rise 12% this year to $363.3 billion. This is based on the investment bank’s survey of 141 companies (OGJ, Jan. 3, 2011, p. 20). Among the companies in its survey, Petrobras will spend $28 billion this year in upstream capital outlays, up from 2010 E&P spending of $24 billion, Barclay’s estimates. This

increase is driven by the company’s expansion in deepwater activity, most notably development of Tupi field. Barclay’s also estimated that Ecopetrol will boost its 2011 E&P spending by 14% to $5.14 billion and that Petroleos de Venezuela will increase its upstream capital expenditures this year by the same percentage to $4.5 billion.

Middle East, Caspian markets Research and analysis firm Infield Systems in January released its Offshore Middle East & Caspian Sea Oil & Gas Market Report to 2015, which finds that Iran and Saudi Arabia will drive offshore capital spending in the Middle East and Caspian region from 2011-15. Infield Systems expects a 33% increase in offshore capital spending in the Middle East and Caspian to $39.9 billion over the period compared to 2006-10. Much of this growth will be driven by an expected $6 billion increase in Iran to around $12 billion. Capital expenditures in Saudi Arabia will reach $5.8 billion over 2011-15, up from $4.5 billion over the previous 5-year period. Combined, Iran and Saudi Arabia will contribute 44% of total offshore capital outlays in the region between 2011 and 2015, according to the report. Capital spending in Qatar is expected to drop markedly during 2011-15 period compared to the previous 5-year period, perhaps a reflection of the moratorium until 2014 on further development of North Field, the report said. Israel also is expected to become a steady contributor to the regional offshore oil and gas scene during the forecast period, largely through new offshore gas projects in the eastern Mediterranean Sea, including some deepwater developments, Infield Systems said. Just over $2 billion is expected to be spent in Israel over the next 5 years, compared to $272 million during 2006-10. Azerbaijan, the largest oil and gas producer in the Caspian Sea, is expected to continue headlining capital expenditures in this region, the report said, and Kazakhstan, Russia, and Turkmenistan are expected to contribute $1.6-2 billion in expenditure each over the forecast period.

Oil prices drive earnings in fourth quarter 2010 Marilyn Radler Senior Editor-Economics

Laura Bell Statistics Editor

Higher oil prices in the fourth quarter of 2010 resulted in higher earnings for oil producers in the US and Canada, and full-year profits posted even sharper gains from 2009. A random sample of oil and gas producers and refiners

30

based in the US posted a collective 43% earnings increase for the fourth quarter of 2010 and a 127% spike in earnings for the 12 months as compared with a year earlier. Meanwhile, a group of producers and pipeline operators with headquarters in Canada recorded a combined increase in profits for the recent quarter and for 2010. A sample of oil and gas service and supply companies also combined for improved earnings from a year earlier. While fourth-quarter 2010 oil prices were up from a year earlier, natural gas prices were lower than during the final

Oil & Gas Journal | Mar. 7, 2011

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GENERAL INTEREST

US OIL AND GAS FIRMS’ FOURTH QUARTER 2010 REVENUES, EARNINGS ––––––––– Revenues –––––– ––––– Net income ––––– ––––––– Revenues ––––––– –––––– Net income ––––– –––––––––––––––––––– 4th quarter –––––––––––––––– –––––––––––––––––––––– Full year ––––––––––––––––––– 2010 2009 2010 2009 2010 2009 2010 2009 –––––––––––––––––––––––––––––––––––––––––––––– Million $ (US) –––––––––––––––––––––––––––––––––––––––– Anadarko Petroleum Corp. . . . . . . . . . . . Apache Corp. . . . . . . . . . . . . . . . . . . . . . Chevron Corp. . . . . . . . . . . . . . . . . . . . . . Comstock Resources Inc. . . . . . . . . . . . . ConocoPhillips . . . . . . . . . . . . . . . . . . . . Devon Energy Corp. . . . . . . . . . . . . . . . . Energen Corp. . . . . . . . . . . . . . . . . . . . . . EOG Resources Inc. . . . . . . . . . . . . . . . . EQT Corp. . . . . . . . . . . . . . . . . . . . . . . . . ExxonMobil Corp. . . . . . . . . . . . . . . . . . . Forest Oil Corp. . . . . . . . . . . . . . . . . . . . . Goodrich Petroleum Corp. . . . . . . . . . . . . Hess Corp. . . . . . . . . . . . . . . . . . . . . . . . HKN Inc. . . . . . . . . . . . . . . . . . . . . . . . . Magnum Hunter Resources Corp. . . . . . . Marathon Oil Corp. . . . . . . . . . . . . . . . . . Murphy Oil Corp.. . . . . . . . . . . . . . . . . . . Newfield Exploration Co. . . . . . . . . . . . . . Noble Energy Inc. . . . . . . . . . . . . . . . . . . Occidental Petroleum Corp.. . . . . . . . . . . Pioneer Natural Resources Co. . . . . . . . . Questar Corp. . . . . . . . . . . . . . . . . . . . . . Sunoco Inc. . . . . . . . . . . . . . . . . . . . . . . Tesoro Petroleum Corp. . . . . . . . . . . . . . . Ultra Petroleum. . . . . . . . . . . . . . . . . . . . Unit Corp. . . . . . . . . . . . . . . . . . . . . . . . . Venoco Inc.. . . . . . . . . . . . . . . . . . . . . . . Williams Cos. Inc. . . . . . . . . . . . . . . . . . .

2,691.0 3,434.0 54,027.0 72.7 53,217.0 2,135.0 374.1 1,789.2 371.2 105,186.0 214.4 36.3 8,690.0 3.3 9.7 20,217.0 6,509.2 528.0 783.0 5,063.0 486.7 362.7 10,232.0 5,513.0 237.5 252.6 72.1 2,424.0 –––––––––– Total . . . . . . . . . . . . . . . . . . . . . . . . . . . 284,931.7

2,417.0 129.0 2,555.0 689.0 48,676.0 5,320.0 91.9 (20.6) 43,695.0 2,053.0 2,445.0 562.0 362.8 80.3 1,760.9 53.7 344.0 73.1 89,841.0 9,516.0 214.4 16.2 32.2 (19.7) 8,558.0 83.0 3.1 (1.6) 2.4 (0.7) 15,990.0 706.0 5,827.2 174.1 414.0 22.0 760.0 52.0 4,382.0 1,200.0 310.1 82.1 344.0 63.7 8,692.0 118.0 4,669.0 3.0 213.3 37.9 177.3 43.7 80.5 4.4 2,326.0 228.0 –––––––––– –––––––––– 245,184.1 21,267.6

2009 quarter. The price of oil last year gained momentum along with the acceleration of economic growth. But a weak natural gas market suppressed gas prices throughout 2010. In the fourth quarter of 2010, WTI spot prices averaged $85.10/bbl, up 12% from a year earlier. The spot price of West Texas Intermediate crude averaged $79.40/bbl in 2010, up from a 2009 average of $61.65/bbl. An abundance of production and volumes in storage sent natural gas prices lower during the final 2010 quarter, such that the price of Henry Hub averaged 12.5% less at $3.799/ MMbtu. For the entire year, the average 2010 Henry Hub price was up 11% from 2009 due to price strength in the first 3 quarters of the year.

US producers Although the overall trend among the sample of US companies shows an improvement in results for both the final 2010 quarter and the year due to higher oil and gas prices, some of the producers registered losses for the periods and others showed declines in revenues and earnings from a year earlier. The large integrated companies in the group posted strong increases in results year-on-year, but some of the independent producers announced declines and losses for the recent quarter and for 2010. Among the largest earnings increases were those recorded by Chevron Corp., ConocoPhillips, and Marathon Oil Corp., while ExxonMobil Corp. posted the biggest fourth-quarter 2010 earnings at $9.5 billion, up 55% from a year earlier. Marathon’s earnings for the fourth quarter, up 99% to $706 million, and for 2010, up 76% to $2.57 billion, were

32

238.0 585.0 3,102.0 (6.8) 1,314.0 667.0 58.6 400.4 55.4 6,139.0 45.2 (189.6) 370.0 (1.5) (7.3) 355.0 318.9 113.0 8.0 938.0 54.2 150.0 56.0 (179.0) 95.4 28.5 (7.8) 222.0 ––––––––– 14,921.6

10,984.0 12,092.0 204,928.0 349.1 198,655.0 9,940.0 1,578.5 6,099.9 1,322.7 383,221.0 854.8 148.3 34,613.0 12.9 32.7 73,621.0 23,345.1 1,883.0 3,022.0 19,045.0 2,471.6 1,123.6 37,489.0 20,583.0 979.4 881.1 295.3 9,616.0 ––––––––––– 1,059,187.0

9,000.0 8,615.0 171,636.0 292.6 152,390.0 8,015.0 1,440.4 4,787.0 1,269.8 310,586.0 768.5 110.4 29,569.0 12.3 6.8 53,956.0 19,012.4 1,338.0 2,313.0 14,814.0 1,347.7 1,109.9 30,392.0 16,872.0 666.8 709.9 270.5 8,255.0 –––––––––– 849,556.0

821.0 3,032.0 19,136.0 (19.6) 11,417.0 4,550.0 290.8 160.7 227.7 31,398.0 227.5 (262.1) 2,138.0 (0.2) (13.8) 2,568.0 798.1 523.0 725.0 4,500.0 646.0 339.2 428.0 (29.0) 464.5 146.5 67.5 (922.0) ––––––––– 83,357.8

(103.0) (285.0) 10,563.0 (36.5) 4,492.0 (2,479.0) 256.3 546.6 156.9 19,658.0 (923.1) (251.0) 807.0 (3.3) (15.1) 1,463.0 837.6 (542.0) (131.0) 2,900.0 (42.3) 393.3 (200.0) (140.0) (451.1) (55.5) (47.3) 361.0 ––––––––– 36,729.5

higher on improved income in its exploration and production segment outside the US, in which income in the recent quarter increased to $479 million from $439 million a year earlier, and in the company’s refining, marketing, and transportation segment, in which fourth-quarter income recovered to $213 million from a year-earlier loss of $18 million. Marathon said its refining and wholesale marketing gross margin was 8.99¢/gal in the 2010 fourth quarter compared with 0.62¢/gal in the fourth quarter of 2009, and 7.06¢/gal for full-year 2010 compared with 6.1¢/gal for all of 2009. Primary factors contributing to the increased refining, marketing, and transportation segment income for the fourth quarter and full-year 2010 include a wider sweet/sour crude differential and increased sales volumes primarily resulting from Marathon’s Garyville refinery expansion, the company said. Anadarko Petroleum Corp. was among the nine independent producers in the sample of US companies that posted positive but lower net income as compared with fourthquarter 2009 results. Despite higher revenue on a 9% increase in sales volumes from 2009, Anadarko’s net income declined by 46% in the 2010 fourth quarter to $129 million, as the company incurred higher costs and expenses and recorded a loss on commodity derivatives vs. a gain a year earlier.

Refiners Refiners reported mostly improved results from a year earlier due to higher product prices and margins. US cash refining margins were higher on average in the

Oil & Gas Journal | Mar. 7, 2011

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GENERAL INTEREST

CANADIAN OIL AND GAS FIRMS’ FOURTH QUARTER 2010 REVENUES, EARNINGS ––––––––– Revenues –––––– ––––– Net income ––––– ––––––– Revenues ––––––– –––––– Net income ––––– –––––––––––––––––––– 4th quarter –––––––––––––––– –––––––––––––––––––––– Full year ––––––––––––––––––– 2010 2009 2010 2009 2010 2009 2010 2009 –––––––––––––––––––––––––––––––––––––––––– Million $ (Canadian) ––––––––––––––––––––––––––––––––––––––– ARC Energy Ltd. . . . . . . . . . . . . . . . . . . . Canadian Oil Sands Ltd. . . . . . . . . . . . . . Enbridge Inc. . . . . . . . . . . . . . . . . . . . . . EnCana Corp. . . . . . . . . . . . . . . . . . . . . . Husky Energy Inc. . . . . . . . . . . . . . . . . . . Imperial Oil Ltd. . . . . . . . . . . . . . . . . . . . Nexen Inc. . . . . . . . . . . . . . . . . . . . . . . . Suncor Energy Inc. . . . . . . . . . . . . . . . . . Talisman Energy Inc. . . . . . . . . . . . . . . . . TransCanada Corp. . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . .

329.3 936.0 4,143.0 1,426.7 4,731.0 6,915.2 1,555.0 9,173.0 1,874.0 2,057.0 ––––––––– 33,140.2

278.6 895.0 3,187.0 2,703.9 3,605.0 5,846.4 1,643.0 7,114.0 1,723.0 1,986.0 ––––––––– 28,981.9

(6.3) 311.0 328.0 (41.9) 305.0 796.6 220.0 1,353.0 (304.0) 283.0 –––––––– 3,244.4

2010 fourth quarter than a year earlier for US Gulf Coast, Midwest, East Coast, and West Coast refiners, according to Muse, Stancil & Co. For example, the US Gulf Coast cash margin averaged $4.12/bbl in the recent quarter, up from $1.06/bbl in the final 2009 quarter. The margin for US Midwest refiners climbed to $9.77/bbl from $3.22/bbl over the same periods. For all of 2010, average cash refining margins were up from 2009 by 63% for East Coast refiners, by 56% for Midwest refiners, and by 47% for Gulf Coast refiners, but 9% lower for West Coast refiners due to unusually high margins in January and February of 2009. Refiners’ acquisition costs for crude were higher during 2010 than a year earlier, but a strengthening in demand for products also pushed up prices that users paid for gasoline, diesel, distillate, propane, and jet fuel. Tesoro Petroleum Corp. posted $3 million in earnings for the 2010 fourth quarter on $5.5 billion in revenue. This compares with a net loss of $179 million on $4.67 million in revenue in the 2009 fourth quarter. Tesoro said for the fourth quarter of 2010, West Coast benchmark diesel margins were up nearly 100% from a year earlier, while gasoline margins gained over 40%. Increased planned and unplanned refinery downtime among California refiners and marginal improvements in clean product demand drove crack spreads higher in the quarter. Excluding business interruption insurance proceeds, the company said that it captured a gross margin of $11.15/bbl. Tesoro also said its results in the recent quarter benefitted from an improvement in clean product yields due to increased reliability and less turnaround activity. In addition, discounts for foreign heavy crude oil relative to domestic alternatives widened year-over-year. And in the Midcontinent region, increased US crude oil production as well as logistics disruptions at the end of the third quarter increased the discounts for local crude oil relative to WTI.

Canadian firms Three of the 10 companies in a sample of Canadian firms, which includes producers and transporters, posted a net loss

34

66.2 96.0 302.0 634.1 320.0 532.4 259.0 457.0 (111.0) 387.0 –––––––– 2,942.7

1,213.7 1,439.0 15,127.0 8,843.4 18,178.0 25,016.9 5,826.0 33,198.0 6,912.0 8,064.0 ––––––––– 123,818.0

978.2 1,328.0 12,466.0 11,080.7 15,074.0 21,333.9 5,062.0 17,977.0 6,061.0 8,181.0 ––––––––– 99,541.9

260.8 886.0 1,221.0 1,494.5 1,173.0 2,203.4 1,197.0 3,571.0 648.0 1,272.0 –––––––– 13,926.7

225.1 432.0 1,868.0 1,856.4 1,416.0 1,574.3 536.0 1,146.0 437.0 1,380.0 ––––––––– 10,870.8

for the final 2010 quarter, but all in the sample recorded positive net income for the year. Talisman Energy Inc. posted a net loss in the fourth quarters of both 2009 and 2010. But for all of 2010, net income was $648 million (Can.), a 48% increase from the previous year due to higher commodity prices, improved operating performance, and noncash gains on derivatives, the company said. The Calgary-based oil and gas producer reported that its cash flow last year was $3.1 billion (Can.), down 23% from 2009, due to higher cash taxes in 2010 and lower cash proceeds from financial instruments. Suncor Energy Inc. reported a surge in fourth-quarter earnings to $1.35 billion (Can.) from fourth-quarter 2009 net income of $457 million (Can.). Full-year 2010 earnings gained 85% from 2009 to reach $3.57 million (Can.). On Aug. 1, 2009, Suncor completed its merger with Petro-Canada. So results for the year ended Dec. 31, 2010, reflect results of post-merger Suncor, and the comparative figures for the year ended Dec. 31, 2009, reflect results for 5 months of the postmerger Suncor and 7 months of legacy Suncor before the merger. Suncor said the earnings increase in the recent quarter was primarily due to improved margins and increased refined product sales, higher realized prices in its oil sands segment and in its international and offshore segment, as well as increased oil sands production.

Service, supply companies A sample of 14 oil and gas service and supply companies combined in the fourth quarter of 2010 for a 45% increase in net income. But these companies’ combined 2010 earnings climbed 13% from 2009. In general, results for the group improved throughout 2010 due to increased activity in light of the continuing worldwide economic recovery. Houston-based Cameron reported that its revenues for the fourth quarter of 2010 were a record $1.81 billion, up 23.5% from the prior year, and revenues for the year were $6.1 billion, up from $5.2 billion a year earlier, also setting a record for the company.

Oil & Gas Journal | Mar. 7, 2011

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GENERAL INTEREST

SERVICE-SUPPLY COMPANIES’ FOURTH QUARTER 2010 REVENUES, EARNINGS ––––––––– Revenues –––––– ––––– Net income ––––– ––––––– Revenues ––––––– –––––– Net income ––––– –––––––––––––––––––– 4th quarter –––––––––––––––– –––––––––––––––––––––– Full year ––––––––––––––––––– 2010 2009 2010 2009 2010 2009 2010 2009 –––––––––––––––––––––––––––––––––––––––––––––– Million $ (US) –––––––––––––––––––––––––––––––––––––––– Baker Hughes Inc. . . . . . . . . . . . . . . . . . Cameron . . . . . . . . . . . . . . . . . . . . . . . . . Diamond Offshore Drilling Inc.. . . . . . . . . Halliburton Co. . . . . . . . . . . . . . . . . . . . . Hornbeck Offshore Services Inc. . . . . . . . Nabors Industries Ltd. . . . . . . . . . . . . . . . Noble Corp. . . . . . . . . . . . . . . . . . . . . . . Oceaneering International Inc.. . . . . . . . . Patterson-UTI Energy Inc. . . . . . . . . . . . . Pioneer Drilling Co. . . . . . . . . . . . . . . . . . Pride International Inc. . . . . . . . . . . . . . . RPC Inc. . . . . . . . . . . . . . . . . . . . . . . . . . Schlumberger Ltd. . . . . . . . . . . . . . . . . . Weatherford International . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . .

4,423.0 1,808.3 841.0 5,160.0 97.3 1,331.6 646.5 501.3 505.7 148.6 400.8 328.1 9,067.0 2,900.8 ––––––––– 28,160.0

2,428.0 1,464.4 890.9 3,686.0 88.3 727.2 941.9 452.3 213.6 81.2 316.7 152.4 5,744.0 2,426.1 ––––––––– 19,613.0

342.0 164.6 241.7 607.0 2.6 51.8 98.3 47.8 53.9 (6.0) 52.1 55.5 1,045.0 (50.6) ––––––– 2,705.7

Cameron Pres. and Chief Executive Officer Jack B. Moore said the increased revenues were due primarily to record deliveries of subsea equipment, where revenues exceeded 2009 levels by more than $450 million. The company also noted that total orders increased for the third quarter in a row. Moore said he expects Cameron’s capital spending to increase considerably this year due to a combination of factors, including an increased level of maintenance spending. He

84.0 97.3 276.1 244.0 9.3 (47.2) 446.4 46.1 (16.2) (8.4) (32.8) (5.2) 797.0 (27.3) ––––––– 1,863.1

14,414.0 6,134.8 3,323.0 17,973.0 420.8 4,215.5 2,817.1 1,917.0 1,462.9 487.2 1,460.1 1,096.4 27,447.0 10,211.4 ––––––––– 93,380.2

9,664.0 5,223.2 3,631.3 14,675.0 385.9 3,553.6 3,647.6 1,822.1 781.9 325.5 1,594.2 587.9 22,702.0 8,826.9 ––––––––– 77,421.1

819.0 562.9 955.5 1,842.0 36.4 94.8 773.4 200.5 116.9 (33.3) 219.1 146.7 4,266.0 39.3 –––––––– 10,039.2

421.0 475.5 1,376.2 1,155.0 50.4 (85.9) 1,678.6 188.4 (38.3) (23.2) 285.8 (22.7) 3,142.0 279.9 –––––––––– 8,882.7

also expects the company will spend about $50-75 million to expand its facilities in Brazil, including enhancements to subsea manufacturing capacity, aftermarket exposure, and research and development capability. “We will invest nearly $50 million in creating a fleet of Cameron equipment to increase our presence in the frac valve, tree, and manifold markets, further expanding our exposure in shale gas,” Moore said.

Gadhafi threatens revenge as Libya’s output plunges Eric Watkins Oil Diplomacy Editor

Uncertainty continues to prevail over Libya’s oil and gas industry, with each side in the developing civil war claiming to be in control of the country’s oil fields, pipelines, and ports. “Many of the country’s oil fields and export terminals are in parts of the country now effectively controlled by opponents of the Libyan government, although the state-run National Oil Co. (NOC) claims to retain firm control over all the country’s oil installations,” said the Centre for Global Energy Studies in recent report. But CGES said control matters little as much of the country’s oil infrastructure lies idle after foreign companies pulled out their expatriate staff and shut in large parts of the country’s oil production. “Latest estimates suggest that somewhere between 50% and 80% of Libya’s oil production has been lost temporarily, although no physical damage has been reported to oil facilities,” CGES said. Libya’s leader Moammar Gadhafi confirmed that view. “Oil production is at its lowest,” said Gadhafi, adding that “oil fields are safe and under control, but the foreign firms are afraid.” Over national television, the Libyan leader blamed armed

36

gangs roaming the country for the reduced output, saying, “These gangs made oil companies afraid, flee, and stop production.” However, Gadhafi also warned Western nations against intervening in the situation, saying it is “not at all in their interest to shake the Libyan regime.” In reprisal, he said that his country could turn to Chinese, Indian, South Korean, and Brazilian firms as business partners. Meanwhile, opponents of Gadhafi’s continued rule, who are reported to have taken control of Benghazi in the country’s eastern region, claimed that oil production and exports were continuing as normal. “There is a long cue of tankers,” said one official of the Benghazi-based Arabian Gulf Oil Co. (AGOC), which has broken ties with its parent company, NOC. “We don’t want to stop the exports, the AGOC official said. “It’s not in our interest, or the interest of the global market. We’re trying to ease the market.” He said tankers were at the eastern port in Marsa alHarigah, near the city of Tobruk, and that the company was producing just under half of its capacity of 375,000 b/d. Another AGOC executive said normal volumes of 70,000 b/d were arriving through the pipeline to the port near Tobruk, which has a storage capacity of about 4 million bbl. Despite the claims by AGOC officials, however, analysts

Oil & Gas Journal | Mar. 7, 2011

remained skeptical about the actual volumes still being produced and exported. Samuel Ciszuk, Mideast oil analyst with IHS Global Insight, stated, “It’s a very chaotic situation, and everything that’s said should be taken with a pinch of salt.”

BOEMRE approves first deepwater drilling permit since accident

In Houston, Noble Energy said it received permission to resume drilling its Santiago prospect in the deepwater Gulf of Mexico, which it described as a middle Miocene amplitude prospect in 6,500 ft of water where the independent producer is operator and holds a 23.25% working interest. The well was drilled to a 13,585 ft depth when operations were suspended on June 12, and Noble Energy said it expects to resume drilling in late March to a 19,000 ft targeted depth, with results anticipated by the end of May. David L. Stover, the company’s chief executive, said Noble Energy worked over several months with other operators and service providers to make deepwater drilling operations safer, including implementing third-party certification of well designs and blowout preventer testing.

Nick Snow Washington Editor

The US Bureau of Ocean Energy Management, Regulation, and Enforcement approved the first deepwater drilling permit on Feb. 28 since the Macondo well accident and crude oil spill. BOEMRE said Noble Energy Inc.’s application for a permit to bypass was for Well No. 2 in Mississippi Canyon Block 519 about 70 miles southeast of Venice, La. The permit represents a significant milestone for both the US Department of the Interior agency and the oil and gas industry since Interior Sec. Ken Salazar placed a moratorium on new deepwater drilling following the well blowout and explosion which took 11 lives, BOEMRE Director Michael R. Bromwich said. “This permit was issued for one simple reason: The operator successfully demonstrated that it can drill its deepwater well safely and that it is capable of containing a subsea blowout if it were to occur,” Bromwich told reporters during a teleconference. “We expect further deepwater permits to be approved in coming weeks and months based on the same process that led to the approval of this permit.”

Oil & Gas Journal | Mar. 7, 2011

Coordinated with BOEMRE “Our partnership with others in the Helix Well Containment Group has increased the deepwater Gulf subsea control and containment capabilities,” he said. “The industry has improved its ability to respond to surface spills as well. Our teams have done an outstanding job of coordinating with the BOEMRE on these matters…. Noble Energy is proud to help lead the industry back to drilling in the deepwater gulf.” Bromwich emphasized that no politics were involved in approving Noble Energy’s application, which he said had been working its way toward approval for several weeks. He noted that Helix Group has said that its system works to depths of 5,600 ft, but added that Noble Energy complemented that with additions that BOEMRE determined would effectively contain a blowout from 6,500 ft. The agency also has held several meetings with the Marine Well Containment Co., the group formed by four multinational oil companies operating in the gulf, and will approve that system if a producer demonstrates that it will work, he said. “We are taking these applications to drill as they come in.

37

WATCHING THE WORLD ERIC

WATKINS

Oil Diplomacy Editor | Blog at www.ogj.com

LNG booms in Asia-Pacific While much of the oil and gas industry’s attention was consumed by events in Libya last week, delegates at an energy summit in Indonesia heard extremely good news about natural gas and LNG. “Since 1990, global gas consumption rose by 50%, while the Asia-Pacific’s gas consumption tripled,” said Mikkal Herberg at the 2011 Pacific Energy Summit in Jakarta. “Asia also remains the center of global LNG trade: the region accounts for nearly two thirds of global LNG demand.” Herberg added, “Japan and South Korea alone account for one half of the global LNG market, and growing LNG imports to China and India ensure that the Asia-Pacific will remain the key demand center for LNG.” Still, there are problems for gas even in Asia. Perhaps foremost, according to Herberg, gas use in Asia has been constrained by the region’s wide geographic and maritime dispersion that make the “tyranny of distance” a key factor in Asia’s gas use.

Yen for Gorgon However, even that tyranny of distance may not pose such an obstacle any more. Just days after the Pacific Energy Summit, the Japan Bank for International Cooperation—aiming to support Japanese businesses procuring LNG—announced plans to lend up to $102 million to Tokyo Gas Gorgon Pty. Ltd. (TGG), a unit of Tokyo Gas Co. TGG will use the loan to partici-

38

pate in the development, in which it has a 1% stake, and will obtain 1.1 million tons of LNG through the project—about 10% of its annual supply of LNG. Additionally, Tokyo Gas will receive 150,000 tons of LNG annually as a stakeholder. Meanwhile, in what one analyst described as a sign that “robust demand for resource shipments has begun to buoy the shipbuilding industry,” Mitsubishi Heavy Industries Ltd. won a ¥20 billion order to build an LNG tanker for Nippon Yusen KK, its first such deal since yearend 2007.

Transport cost reduced Under a 15-year contract with Tokyo Electric Power Co., Nippon Yusen will import about 1 million tons/year of LNG from Papua New Guinea and other places from 2014. The new vessel will have a storage capacity of 145,400 cu m and feature an advanced steam turbine that can reduce fuel consumption by 15% compared with existing models. That news fits in with Herberg’s observation that, “The outlook for LNG supplies is booming with the development of a large number of new projects within and outside the region.” Although exports from traditional suppliers Indonesia, Malaysia, and Brunei have stabilized, Herberg noted that major new supplies have come from “Australia’s northwest offshore region as well as from future new coal seam gas LNG projects in the Queensland region.”

Right now, a very small number are pending,” Bromwich said. “I expect industry has been waiting for a signal that deepwater drilling would be allowed to resume, and this could be the signal. I have no way of knowing how long it will take to approve the next one. It involves careful analysis of each application. Given the rigorous safety requirements, the public can be confident that the approved wells will be safe.” Oil and gas industry trade associations welcomed the news. “The actual issuance of a permit for new deepwater drilling is long awaited and an important step forward in the wise development of energy off our shores,” said National Ocean Industries Association Pres. Randall B. Luthi. “With all the world-complicating factors, including rising oil prices, political turmoil in the Middle East, and the loss of jobs in the Gulf of Mexico, this decision offers hope that the United States is getting back in the energy and jobs market.” He said taking DOI at its word that approval of Noble Energy’s application is not simply a token gesture, the action “sends a calming signal to operators, producers and service companies that the long drought is just about over,” adding, “It is also a compliment to Director Bromwich and a testament to the efforts of many within industry that the containment and safety issues can be resolved when industry and BOEMRE work together.”

Industry still skeptical after first drilling permit since Macondo Sam Fletcher Senior Writer

Issuance this week of the first deepwater drilling permit since the Macondo blowout last year is “not a return to normalcy” but rather a show-and-tell exhibit for US Department of Interior

Oil & Gas Journal | Mar. 7, 2011

GENERAL INTEREST Sec. Ken Salazar to display when he testifies before the Senate Energy and Natural Resources Committee on Mar. 2. Prior to announcement of the permit, Frank Maisano, a Washington-based energy and political analyst, said, “Bookmakers are heavily favoring that Interior will issue a deepwater permit this week so Sec. Salazar won’t have to go to the Hill without a bird in hand, as a hostile Congress lies in wait.” Analysts at FBR Capital Markets & Co., Arlington, Va., said, “Now when Sec. Salazar appears before Congress this week, he will have an [approved] application for permit to drill (APD) in hand to respond to allegations that the administration has imposed a de facto moratorium. We expect media attention on the permitting issue to dissipate significantly, even if few additional permits are forthcoming. Instability in the Middle East and high oil and gasoline prices will help keep the issue in the mainstream.” Both Republicans and Democrats have cited the economy and rising oil prices to pressure the administration to issue permits for deepwater drilling in the Gulf of Mexico. However, FBR analysts predicted, “Political pressure is likely to abate somewhat.” Salazar said Feb. 25 he would not bow to political pressures from Congress or Gulf Coast governors to speed up permits for offshore drilling in the gulf. In approving the permit Feb. 28, Michael Bromwich, director of the US Bureau of Ocean Energy Management, Regulation, and Enforcement also said the move was not motivated by politics nor related to Louisiana Federal Judge Martin Feldman’s recent order to expedite five drilling permits within 30 days for Ensco PLC. Bromwich further implied the decision had nothing to do with restoring jobs along the financially troubled Gulf Coast, the rising cost of fuel to consumers, replacing quickly depleting US oil and gas reserves, or threats to foreign supply as a result of civil uprisings in the Middle East and North Africa. “This permit was issued for one simple reason: the operator successfully demonstrated that it can drill its deepwater well safely and that it is capable of containing a subsea blowout if it were to occur,” he said. “We expect further deepwater permits to be approved in coming weeks and months based on the same process that led to the approval of this permit.”

Next permit? However, analysts warn the industry and investors not to hold their breath while waiting for the next permit to drop. “We do not view this permit as a precursor to a tsunami of permits,” said Anuj Sharma, research analyst at Pritchard Capital Partners LLC in Houston. However, he said, “This action on the part of the BOEMRE could sway sentiment positively for shares of companies with meaningful gulf exposure.” FBR analysts also do not foresee “a sea change for Gulf of Mexico permitting.” They said, “In our view, this permit is more likely to mark the beginning of a long period of low permitting that is likely to underwhelm investors seeking an

Oil & Gas Journal | Mar. 7, 2011

immediate revitalization of the gulf. Resource constraints in the face of a significantly greater workload will continue to challenge BOEMRE and operators.” For example, they said, “The department has requested from Congress funding to hire as many as 40 additional permitting personnel and said that, without the money, it would be hampered in its ability to process permits. Likewise, new exploration plans (beyond the ‘grandfathered’ permits) will require enhanced environmental review, which opens the possibility for continued delays.” The “handful of permits” for wells being drilled prior to the moratorium will have “a much easier pathway than new permits that require new exploration plans, which we view as much more susceptible to policy and litigation delay,” they said. FBR analysts warned investors against “chasing a further short-term rally in [equity] stocks exposed to a recovery in US Gulf of Mexico deepwater permitting. We expect a continued rally in affected shares but caution that, as momentum wears off and incremental permits are scarce, the stocks will give back most of the current rally.” They also reported, “Our industry channel checks indicate that BOEMRE is satisfied with both Helix Well Containment Group’s containment system approved for the Noble permit and with the interim system of the ExxonMobil-led Marine Well Containment Co. However, BOEMRE’s case-by-case evaluation of spill containment resources will not produce a cookie-cutter process for APD approvals, which are site-specific and may require additional resources from operators.” Among the seven deepwater permit applications now pending are two for new wells, three for revised new wells, one for a sidetrack, and two for revised sidetracks. The permit was issued to Noble Energy Inc. to drill a bypass around the plugs it was forced under the moratorium to set in Well No. 2 in Mississippi Canyon Block 519 about 70 miles southeast of Venice, La. The well was spudded Apr. 16 in 6,500 ft of water and drilling was suspended June 12 under the drilling moratorium issued after the Macondo blowout. The moratorium was subsequently lifted in October (OGJ Online, Feb. 28, 2011).

Helix Energy outlines oil spill response system Paula Dittrick Senior Staff Writer

Helix Energy Solutions Group Inc. has assembled a Helix Fast Response System (HFRS) that some independent producers are citing as their oil spill response plan in applications for offshore drilling permits being filed with state and federal authorities.

39

GENERAL INTEREST The HFRS involves two vessels—the Helix Producer I and the Q4000—both of which were used along with many other vessels in the deepwater Macondo spill response efforts last year. The Producer is a floating production vessel while the Q4000 is a multiservice vessel. HFRS is separate from the containment system outlined by Marine Well Containment Co., a consortium primarily of oil majors led by ExxonMobil Corp. MWCC’s containment system also is available for companies operating in the Gulf of Mexico (OGJ, Feb. 21, 2011, Newsletter). BP PLC operated Macondo. An April 2010 blowout resulted in an explosion and fire on Transocean Ltd.’s Deepwater Horizon semisubmersible, killing 11 crew members and resulting in a massive oil spill. US Interior Sec. Ken Salazar and other federal officials visited Houston on Feb. 25 to meet with both Helix and MWCC for briefings on available spill response systems. Both Helix and MWCC are based in Houston. Helix signed an agreement with Clean Gulf Associates (CGA) of New Orleans, a nonprofit industry group of independents, making HFRS available for a 2-year term to CGA members in case of a well blowout in exchange for a retainer fee. During a Feb. 24 earnings conference call, Helix executives said Helix also signed separate utilization agreements with 19 CGA member companies specifying day rates to be charged if companies use HFRS. An initial HFRS is capable of capping a wellhead in 5,600 ft of water and processing up to 10,000 b/d of oil while flaring 15 MMcfd of natural gas. By Mar. 31, Helix executives expect to complete an expanded system that can operate in 8,000 ft of water and process up to 55,000 b/d of oil and flare 95 MMcfd. The Helix 4000 is capable of transferring oil to the Producer I, which would process the oil and offload it onto other vessels for transport. HFRS also involves a capping stack, Helix executives said.

US industry expects higher costs following Macondo Paula Dittrick Senior Staff Writer

US oil and gas executives are concerned that changing regulations could boost drilling costs, making some exploration projects uneconomical, Grant Thornton LLP said. More than 100 executives from independent producers and service companies listed regulations, oil and gas prices, and investment as top issues affecting their 2011 upstream outlook.

40

Survey participants identified uncertain natural gas and crude oil prices as their top concern for the third consecutive year. The 2011 outlook was Grant Thornton’s ninth annual survey of upstream US energy companies. Results indicated 68% of survey participants believe an increase in drilling costs of 20% or more due to changes in government regulations could make new exploration and development projects uneconomic. “Offshore operators and contractors continue to seek certainty in attempting to plan for the future while bracing themselves for the new regulatory requirements that will eventually be enacted,” Loretta Cross, Grant Thornton partner and director of corporate advisory and restructuring, told OGJ. US regulations are expected to change following the Apr. 20, 2010, blowout of the deepwater Macondo well in the Gulf of Mexico. The blowout caused an explosion and fire on Transocean Ltd.’s Deepwater Horizon semisubmersible, killing 11 crew members and resulting in a massive oil spill. Concerns about drilling safety “virtually paralyzed energy operations in the gulf,” Cross said. Meanwhile, recent world political events have renewed concerns about energy dependence. “With the unrest in the Middle East, it’s clear that we are going to have to define our energy policies and strategy to become less dependent on foreign oil,” Cross said.

Industry resilient Cross noted the upstream industry experienced a massive influx of capital during 2010, and she believes this will increase industry’s ability to pursue growth opportunities during 2011. When asked about their spending outlook, 71% anticipate increases in US spending during 2011 over 2010. Only 12% said they plan to increase spending outside the US. Of those surveyed, 61% expect higher employment levels at their companies in 2011. That compares with 50% in 2010 and 35% in 2009. Some 90% of respondents said they believe employment levels across the US oil and gas upstream industry will increase or hold steady during 2011. The survey was conducted via mail and the internet from November 2010 through January 2011.

INGAA prepares for comprehensive pipeline safety legislation Nick Snow Washington Editor

The Interstate Natural Gas Association of America anticipates congressional passage of a comprehensive federal pipe-

Oil & Gas Journal | Mar. 7, 2011

GENERAL INTEREST line safety bill in 2011, laying out a number of aggressive goals and delegating the details to the US Pipeline and Hazardous Materials Administration, an INGAA official said. Martin E. Edwards, INGAA’s vice-president for legislative affairs, said he expects legislation to reauthorize the 2002 federal pipeline safety law to take integrity management programs that the law imposed to the next level. “It’s fair and expected for both the industry and regulator to do this,” he told reporters at a Feb. 28 briefing at INGAA’s headquarters. US Sens. Frank R. Lautenberg (D-NJ) and John D. Rockefeller IV (D-W.Va.) have already introduced a bill that Edwards said might be marked up by the end of April and sent to the Senate floor. He said that a bill in the US House could take longer since it probably will need to come through the Transportation and Transportation and Infrastructure Committee, which is having to deal with highway matters first and probably won’t be able to get to pipeline safety until May. The issue has received more public attention than usual in the past year because of several high-profile accidents, including a Sept. 9 gas utility pipeline explosion and fire in San Bruno, Calif., which killed 8 people and destroyed 37 homes. The National Transportation Safety Board will hold a hearing in Washington on Mar. 1-3 as part of its ongoing investigation of the accident. Interstate gas pipelines have a good, but not perfect, safety record, Edwards said. “INGAA members recognize that continuous improvement is a fact of life,” he observed.

Integrity management The 2002 federal pipeline safety law addressed integrity management, which added a line of authority on pipeline segments in populated areas that is almost fully implemented now, according to Edwards. PHMSA and the industry have begun to evaluate its impacts now that it is nearly 10 years old and will discuss with federal lawmakers what to do next, he said. Some interstate pipelines actually had stiffer criteria before the 2002 law was enacted, but it allowed new technology to be applied that allowed companies to make comparisons, noted Terry Boss, INGAA’s senior vice-president, environment, safety, and operations. “There are common measurements being used between companies now because of it,” he said during the briefing. Pipeline operators also have set a very high technical bar for materials they use in their systems now and INGAA has been working with manufacturers on this, he added. Edwards said PHMSA’s pipeline safety budget would rise 14% in the US Department of Transportation’s fiscal 2012 budget request, which is consistent with previous years’ proposals. He said that neither the Obama administration’s budget request nor the Lautenberg-Rockefeller bill proposes user fees for gas utilities’ operations regulated by PHMSA. “This has been a glaring hole for 26 years,” said Edwards. “Everyone should pay a fee appropriate to its costs.”

Oil & Gas Journal | Mar. 7, 2011

41

WATCHING GOVERNMENT NICK

SNOW

Washington Editor | Blog at www.ogj.com

NTSB’s limitations The National Transportation Safety Board does not hold a hearing about every pipeline accident that it investigates. It held one Mar. 1-3 in Washington, DC, about the San Bruno, Calif., rupture and explosion that killed 8 people and destroyed 37 homes because all 5 of its board members considered it a major transportation accident. “The hearing’s purpose is to gather facts,” NTSB Chairwoman Deborah A.P. Hersman said in a Feb. 24 briefing. “We want to make sure that the record is developed, that we pursue every avenue of information, and that the public has a window into our investigation process.” That process will continue after the hearing concludes, she told reporters. “The staff will complete factual information with a technical review. Then the investigation will move inside to the safety board, which will perform its analysis of probable cause, conclusions, and recommendations,” Hersman said. “Parties won’t participate, but will be invited to submit information including about their activities following the accident and their recommendations.” She said while it takes NTSB 12-18 months to complete a major investigation, it hopes to finish this one by the accident’s 1-year anniversary. “The safety board isn’t in the business of determining liability. We are a factfinding organization and not trying to place blame,” she said. Hersman said 2010 was a bad year for US oil and gas pipeline accidents.

42

“We have seen a number which were fatal, as well as some where liquids were released. Any accident concerns us, and any fatalities and release should be of concern to the industry,” she said.

‘An opportunity’ “This is an opportunity to identify where the problems are, and what the challenges will be coming forward,” she continued. “Next week’s hearings will identify problems not just with this accident, but also industry-wide. We hope to hear about contributions from new technologies, particularly from the industry associations which are participating.” NTSB has only four investigators, and they have what Hersman considers a very heavy load examining other pipeline accidents in Illinois, Michigan, Texas, as well as California. It has not taken on investigations of other pipeline accidents, some of which have involved human fatalities, but has delegated those inquiries to state agencies and is staying in close touch with them, she said. “There’s a very good chance information they find can help us,” she added. NTSB’s examination of the San Bruno accident has “a very long way to go,” observed Terry Boss, the Interstate Natural Gas Association’s senior vice-president, environment, safety, and operations. “This is a jigsaw puzzle. We have only some of the pieces,” he said on Feb. 28.

He said that pipeline safety matters to the industry because it will need to build a lot of capacity in the next few years. “Public perceptions that pipelines aren’t safe will lead to more opposition. Pipelines need to stay in front of this,” Edwards maintained.

Study lists Alaska Arctic OCS development’s potential benefits Nick Snow Washington Editor

Development of resources in the Chukchi and Beaufort seas off Alaska’s Arctic coast would create an average 54,700 jobs/year nationwide with a $145 billion total payroll and generate $193 billion in federal, state, and local revenue over 50 years, according to a study by Northern Economics Inc., Alaska’s largest private economic consulting firm, and the University of Alaska at Anchorage’s Institute of Social and Economic Research. Commercial production of Arctic Alaska offshore oil and gas resources would generate government revenue estimated at $97 billion (in 2010 dollars) in the Beaufort Sea and $96 billion in the Chukchi Sea over 50 years, said the Feb. 18 study, which was commissioned by Shell Exploration & Production Co. Of the $193 billion of total revenue, the federal government would receive $167 billion, Alaska’s state government would get $15 billion, local governments in the state would get $4 billion, and other state governments would receive $6.5 billion, it said. It estimated about 30,100 jobs would be generated from Beaufort Sea Outer Continental Shelf development and 24,600 jobs would come from Chukchi Sea OCS development. Production could reach almost 10 billion bbl of oil and 15 tcf of nat-

Oil & Gas Journal | Mar. 7, 2011

GENERAL INTEREST ural gas, the study said. The study shows thousands of new jobs and billions of dollars in government revenue are locked up off Alaska’s Arctic coast, National Ocean Industries Association Pres. Randall L. Luthi said on Feb. 24. “In these times of economic hardship and global uncertainty, we should take full advantage of the untapped and unexplored oil and natural gas supplies off our own shores,” he maintained. “Responsible and safe development of these resources would not only provide increased domestic energy security, but also needed jobs, income, and government revenue.” David Holt, president of the Consumer Energy Alliance in Houston, said the study also showed the US could cut its imports of foreign crude, which now represent some 60% of its total supply, by about 9% over 35 years. It also noted approximately 77% of the world’s crude reserves are owned or controlled by national governments, he said. “Impediments to more American energy continue to be found above ground, not below,” Holt declared. “We know we have the resources to generate these jobs, revenue, and economic growth—as demonstrated by the billions of dollars already invested in the Alaska OCS. Yet companies are being prevented from acting on these investments by permitting delays, frivolous litigation, and other makeshift roadblocks.” “America will need all forms of energy to get our economy back on track, and that includes oil: We can either produce it here and create more American jobs or import it and create jobs elsewhere,” said Richard Ranger, a senior policy advisor at the American Petroleum Institute. “The administration and Congress need to adopt an ‘all of the above’ energy approach that leverages our offshore resources in Alaska to create an energy plan for America that boosts, rather than inhibits, our economy.”

Brigham’s Bakken operation accelerating Interpretation of microseismic data from one 18-sq-mile area appear to support the drilling of eight Bakken and Three Forks wells per 1,280-acre spacing unit in the Williston basin, said Brigham Exploration Co., Austin. The company will ramp gradually to 12 operated rigs by September 2012 after adding its eighth rig this May and is beginning to use smart pad development in its Ross and Rough Rider areas in North Dakota. Brigham hiked proved reserves 141% to 66.8 million boe, 78% oil, in 2010, by drilling 44 net wells, 39 of them in the Williston basin. An 800,000 boe downward revision involved conventional gas reserves unlikely to be drilled within 5 years.

Oil & Gas Journal | Mar. 7, 2011

Microseismic data accumulated during the Brad Olson 9-16 2H well fracture stimulation indicates that frac wings appear to extend laterally 500 ft on either side of the wellbore. The results imply an increase to 782 total net locations from 590 in the Ross-Parshall-Austin and Rough Rider project areas, Brigham said. Meanwhile, the company’s second Montana Bakken completion, Swindle 16-9 1H, produced at an early 24hr peak flow back rate of 1,065 b/d of oil equivalent. Two recent North Dakota Bakken completions averaged 3,513 boe/d. Brigham anticipates drilling 66 net Bakken and Three Forks wells in 2011 compared with 39 net wells in 2010. Drilling capital is estimated at $582.1 million or $7.9 million/well, which includes a 10% budgeted overage. Smart pad development can be implemented either by drilling multiple wells from the same location in a single spacing unit or by drilling stacked 1,280-acre spacing units, one to the north and one to the south, and drilling multiple wells in both spacing units from the same location. When fully implemented it is likely to save 10-20%/well, Brigham said. Drilling efficiencies are achieved by minimizing rig moves and the laying down of drill pipe and changing of mud systems. Completion efficiencies are achieved via the simultaneous fracture stimulation of adjacent wells. Initial results indicate that 9-11 stages a day can be performed compared with 6 stages a day at individual wells. Brigham estimates that 112 of its 188 operated 1,280acre spacing units in Rough Rider and Ross are adjacent units that provide additional drilling and completion efficiencies, 26 of which are to be drilled in 2011. The Swindle 16-9 1H, in Roosevelt County, Mont., was completed with 19 frac stages because the liner with swell packers didn’t reach total depth. About 3,200 ft of the outermost wellbore was completed with a single open hole frac stimulation. In Richland County, Mont., Brigham is stimulating the Johnson 30-19 1H with 30 stages after successfully running liner to bottom and is recompleting the Voss 21-11H, purchased from another operator that drilled and completed it in August 2007 with a single frac stimulation. Brigham plans 28 stages after running a liner with swell packers. Brigham has completed 51 consecutive long lateral, high frac stage wells in North Dakota with an average early 24-hr peak flow back rate of 2,858 boe/d. A minimum of 8 wells/month are to be brought on production starting in mid-April, when two fully dedicated frac crews will be at work.

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EXPLORATION & DEVELOPMENT

Continent below the oceans: how much and how far? The future for deepwater exploration (and geopolitics) Sandrea1 discussed possible reserves remaining to be found in the world’s deepwater areas with a most likely scenario for discovery of 50 billion bbl down to 4,000 m of water “be-

Keith H. James Consulting Geologist Covarrubias, Spain

NORTH AMERICA*

FIG. 1

Labrador Sea

Superior

le

vil

en

Gr

Bermuda s

n hia

lac

Fig. 4

a pp

A

Near-surface data [nT] –3700 –100

–50

–20

–10 –6

0

6 10

20

50

100 5300

20

50

100

Model data [nT] –100

–50

–20

–10 –5

0

5 10

*Compare with the map of North America basement (Wilko, 2008) to identify patterns associated with ancient provinces such as Superior, Grenville, Appalachians on the mainland, and note the contrast with the extended offshore region (Fig. 4). Source: After Korhonen et al., 2007

44

Oil & Gas Journal | Mar. 7, 2011

EUROPE*

FIG. 2

Fennoscandinavian Shield

Europe

TeisseyreTornquist Line

*Note the contrast in magnetic pattern between the crystalline basement of the Fennoscandinavian Shield to the northeast and fragmented Europe southwest of the Tornquist Line, a major fault system. Source: After Korhonen et al., 2007

yond which most parts of the world do not carry sediments.” US Geological Survey global reserve estimates are based upon conventional perception of the extent of continental crust below the sea—most submarine crust is oceanic and uninteresting. Reconstructions of Pangaea, the supercontinent that existed until Triassic rifting and Jurassic drift, show assemblages unrealistically on one side of the planet (http:// www.google.es/images?q=pangaea&oe=utf-8&rls=org. mozilla:en-GB:official&client=firefox-a&um=1&ie=UTF8&source=univ&ei=oxdDTbbcHNKr8AOk7dVO&sa=X&oi =image_result_group&ct=title&resnum=2&ved=0CDgQsA QwAQ&biw=1098&bih=728) and laud “tight fit” of reconstructions practically at the coastline. They leave little leeway for exploration below the deep sea. This article describes a rationale for industry to be more optimistic and explore wider and deeper. Indicating the way forward are recent major, salt-related deepwater discoveries in the Gulf of Mexico (Jack, 2004, 2,000 m water, 3-15 billion bbl of reserves) and in Brazil’s Santos basin (Lula—formerly Tupi, Carioca-Sugar Loaf, Jupiter, 2007, Libra, 2010, below 2,000+ m of water, perhaps 70 billion bbl recoverable, already surpassing Sandrea’s likely scenario). Currently estimated Carioca-Sugar Loaf reserves of 33 billion bbl rank third behind the world’s largest fields, Ghawar and Greater Burgan, discovered 60-70 years ago! The message is clear—deep water is very interesting.

Oil & Gas Journal | Mar. 7, 2011

The geology is there to be read—an example Convention sees the Caribbean Sea (depths to 5,000 m) floored by basaltic oceanic crust, thickened into an oceanic plateau. However, thorough and holistic study of Caribbean geology (crustal thickness, silicic rock chemistry, regional tectonic fabric, seismic and gravity data, stratigraphy, palaeontology) shows that it is floored by extended continental crust.2 It shares history with the Gulf of Mexico and the US eastern offshore. Seamounts interpreted in the light of the oceanic model look more like the salt diapirs of the Sigsbee Knolls in the Gulf of Mexico.2 Where there is salt, often there is oil. The area is rimmed by oil shows and bounded north and south by huge reserves of the Gulf of Mexico and northern South America.3 4 Large gas fields lie below southern waters. Those who believe the oceanic model will never find hydrocarbons here; they won’t even look.

Other areas of unsuspected continental crust? Figs. 1 and 2 show magnetic data over North America and Europe. The illustrations are derived from the Korhonen et al.,5 “Magnetic Anomaly Map of the World.” This compiles magnetic anomaly data (1% of the total magnetic field), which the

45

EXPLORATION & DEVELOPMENT

SOUTH ATLANTIC*

FIG. 3

Africa South America

Sugar Loaf-Carioca

Lula Santos basin Brazil

Falklands

*Note the large extensions of the magnetic signature of South America and Africa below the ocean. Source: After Korhonen et al., 2007

authors attribute to metamorphic and igneous rocks in the crust and upper mantle and their redox state. It is important to note that the map combines near-surface data with satellite and oceanic models and that data are extrapolated in some areas. The published map describes techniques used. The figures show distinct signatures of high magnetic contrasts over the ancient shield areas in North America and Fennoscandinavia. They contrast sharply with the rifted (Triassic) and extended areas offshore North America and Europe southwest of the Teisseyre-Tornquist Line (an interestingly parallel trend forms the southern margin of the Labrador Sea, Fig. 1). Fig. 3 shows South America-South Atlantic-Africa. Magnetic striping in the center of the area, produced by the oceanic model, is thought to record Mid-Atlantic Ridge spreading. The stripes (“C-Series of 33 magnetic chrons”) are

46

believed to have formed since the Late Cretaceous (84 Ma) recording flips in Earth’s magnetic field polarity. The Series derives from a synthetic South Atlantic magnetic anomaly model based on a single track across the South Atlantic, with added details from Pacific and Indian Ocean magnetic profiles.6 7 The submarine areas between the striped area and subaerial South America and Africa are areas where the oceanic model does not work. Data here are near-surface and-or satellite model. These areas are seen to have formed during the Cretaceous Superchron or Quiet Period when Earth’s magnetic field supposedly remained stable for some 40 million years instead of continuing its average 700,000-year polarity flip, hence the lack of magnetic stripes. However, Fig. 3 shows that the areas are startling extensions of the magnetic signatures of onshore South America and Africa into the South Atlantic.

Oil & Gas Journal | Mar. 7, 2011

Process Safety Management for Chem/Petrochem & Refineries Developing a PSM Strategy to Mitigate Risk and Comply with Evolving Industry Requirements April 11-13, 2011 Houston, TX Pre Conference Workshops: April 11 Wokshop A: Mitigating Risk Potential Through a Fail-Proof PHA Workshop B: Ensuring Process Safety Through a Pro-Active Approach to Mechanical Integrity

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EXPLORATION & DEVELOPMENT

EASTERN NORTH AMERICA*

FIG. 4

NW

SE

SW

C.O.S.T.

Shore line

NE

Neogene U Cret - Pal Mid. JJ-Early KK

5 Pre-Mezozoic basement

Salt basin 10 Km

Section Baltimore Canyon

15

Post-rift unconformity Rift basin

Carolina Trough

20 311 Miles 500 km

0

Miles

62.1

0

Km

100

Blake Plateau

V/E x10

Wedge

*Structure and stratigraphy of the offshore area (James, 2009, Fig. 6; after Benson & Doyle, 1988, and Manspeizer, 1988-inset).

What is the nature of this crust? Wedges of seawarddipping reflections typify submarine extended continental crust.8 9 They are common in the North and South Atlantic.10 Many see these as composed of volcanic/volcaniclastic rocks and, indeed, basalt has been drilled off Norway. Nevertheless, they are developed in extended continental crust, and sediments also are present. In the well-documented eastern seaboard of North America, seismic and drilling data show geology of rift basins and wedges of sediments overlain by salt, limestones, and clastic sediments (Fig. 4). In Brazil`s Santos basin, Lower Cretaceous synrift, lacustrine carbonate reservoirs of major recent discoveries are associated with tilted fault blocks 7 km below sea level. Shallow-water limestones at this depth testify that extended offshore parts of the South American continent have subsided deeply. The Korhonen et al. map5 indicates other, large areas in the world with similar magnetic signature, suggesting vast areas of unsuspected, extended, and subsided continental crust below the oceans. In accord with this, literature describes abundant data showing the presence of continental crust (crustal thickness, seismic architecture, dredged/ drilled rocks), with history often beginning with Triassic-Jurassic rifting. Many seismic illustrations of “seamounts,” premised upon “oceanic” geology, look more like salt diapirs.

East African Mozambique Channel The Mozambique Channel off East Africa presents an interesting example (Fig. 5). Larger than the North Sea in area,

48

up to 950 km wide and 4,000 m deep, it carries sections as thick as 11 km, extending back to Carboniferous-TriassicJurassic rift deposits. They include Permo-Triassic, Jurassic, and Cretaceous source rocks and Jurassic salt. Farther north off Somalia, continental crust extends at least 500 km to oceanic depths. Beyond the continental slope, seafloor topography and gravity anomalies show structures analogous to those on land.11 Salt diapirs are present in northern Kenya and Somalia.12 The large island of Madagascar lies on the eastern edge of the channel. The map shows the island to be an exposed part of in situ continental crust off East Africa. It did not migrate NE or SE from Africa during seafloor spreading as literature debates. It has always been where it is now, as correctly concluded by Kamen-Kaye.13 Ancient mammals common to Madagascar and the mainland crossed via continental connection as recently as the middle Eocene-early Miocene.14 They did not have to swim or float on vegetation mats15 across the 400-950 km wide Mozambique Channel. Madagascar has a western series of rift basins containing rocks as old as Permian in sections more than 11 km thick. In these basins the Bemolanga and Tsimiroro deposits contain 21 billion bbl of tar and 8 billion bbl of heavy oil. On the other side of the Mozambique Channel large gas fields (Pande, Temane, etc., 5.5 tcf) are present in Mozambique. This East African area is becoming an exploration hot spot, with recent large gas discoveries off Mozambique and

Oil & Gas Journal | Mar. 7, 2011

EXPLORATION & DEVELOPMENT Tanzania (Windjammer, Barquentine, etc.). Liquids also seem to be present (Ironclad).

EAST AFRICA*

FIG. 5

Somalia

Geopolitics: writing on the wall Melting ice and increased accessibility focus attention on the Arctic, where Kenya the USGS estimates a 50% chance of finding 83 billion bbl of oil. At the September 2010 meeting titled “The Arctic: Territory of Dialogue,” in Moscow, Canada, Denmark, Windjammer Norway, Russia, and the US discussed Barquentine Lagosta extensions of their continental areas Ironclad below Arctic waters. Canada and RusTubarao sia both consider the Lomonosov Ridge Bemolanga theirs, and both plan to make claims Tanzania before the UN maritime law commisTsimiroro sion by 2013. In 2007 Russia planted Pandea flag on the ridge and retrieved rock Temane samples showing its continental naMozambique ture (http://news.nationalgeographic. Mozambique Channel Madagascar com /news/2007/09/070921-arcticrussia.html). BP is joining Rosneft to explore the Russian Arctic. The Arctic debate heralds an enormous problem: international drama over how much continental crust lies below the oceans and to whom it belongs. Some examples follow: • The Institute for Research on Earth Evolution and the Japan Agency for Marine-Science and Technology consider that seismic data over *Shows occurrences of gas on the mainland and offshore and heavy oil fields on Mozambique. Source: After Korhonen et al., 2007 the Mariana arc-backarc show oceanic crust evolving into continental crust.16 The process “could be a basis for extending (Japan’s) continental shelf territory.” will need to be revisited. Rock samples indicate presence of • Symonds et al.17 studied the Kerguelen Plateau, continental rocks19 20 even in areas of magnetic striping— 4,200 miles south of India’s southern tip, to define the perceived oceanic spreading crust. The territorial debate extent of Australia’s claim to “legal” continental shelf becould eventually extend to midocean ridges. The world poyond the 200 nautical-mile Australian Exclusive Economlitical map will change drastically. ic Zone. They predict that Australia will be able to claim sovereign rights to seabed and subsoil resources over 75% The future of the plateau. The data discussed in this article not only indicate that un• The Seychelles government has submitted a prelimirecognized large areas of subsided and extended continent nary claim to continental crust beyond the 200-mile limit offer great hydrocarbon potential, they also suggest that surrounding Aldabra Island.18 the plate tectonic paradigm underpinning much geological • Argentina remains frustrated by UK exploration in the thinking of the last 45 years needs revision. Falklands/Malvinas area. They indicate that there was no South Atlantic “spreadThese activities and data discussed here suggest that ining” to record polarity reversals before the Late Cretaceous— ternational law on “natural prolongation of land territory” “Quiet Period” crust is extended continent. Fig. 6 is an approximate South America-Africa reconstruction based on Fig. 3 and assumptions that magnetic

Oil & Gas Journal | Mar. 7, 2011

49

EXPLORATION & DEVELOPMENT

SOUTH AMERICA-AFRICA*

FIG. 6

*Approximate Pangean reconstruction after removal of the central striped area of Fig. 3. Source: After Korhonen et al., 2007

striping (“oceanic”) records extreme extension (β ≥5) and submarine continent is extended to around twice its original area (β ≥2). For simplicity, the figure simply removes the entire striped central area of Fig. 3. The reconstruction indicates that the amount of “continental drift-seafloor spreading” in conventional plate tectonic reconstructions is greatly overestimated. Pangaea was much larger than presently perceived. There are important

50

implications for palaeogeography, palaeooceanography, and distributions of flora and fauna. A change of thinking might result in important new ways to see submarine geology and its potential resources.21 How much extended continental crust is present below the oceans? When and how did it evolve? Where are the sweet spots?

Oil & Gas Journal | Mar. 7, 2011

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EXPLORATION & DEVELOPMENT Fortunately, industry is not model driven.3 It is steadily stepping into deeper water and finding major reserves. Latest generation deepwater rigs are rated to 4,000 m of water. I anticipate that we shall encounter data, via seismic and the drill, that will change the way we see the world and its evolution. Perhaps also we are about to enter a new phase of hydrocarbon exploration/discovery, and peak oil is far distant.

References 1. Sandrea, R., Sandrea, I., “Deepwater crude oil output: How large will the uptick be?,” OGJ, Nov. 1, 2010, pp. 48-53. 2. James, K.H., “In-situ origin of the Caribbean: discussion of data,” in

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52

James, K.H., Lorente, M.A., and Pindell, J., eds., “Origin and evolution of the Caribbean Plate,” Geological Society of London, Special Publications, Vol. 328, 2009, pp. 75-124. 3. James, K.H., “Enterprise drives exploration,” OGJ, Mar. 24, 2008, p. 12. 4. James, K.H., “Caribbean has overlooked hydrocarbon potential on North America’s doorstep,” OGJ, May 5, 2008, pp. 46-48. 5. Korhonen, J.V., et al., “Magnetic Anomaly Map of the World,” Commission for the Geological Map of the World, Paris, 2007. 6. Cande, S.C., and Kent, D.V., “A new geomagnetic polarity time scale for the Late Cretaceous and Cenozoic,” J. Geophysical Res., Vol. 97, 1992, pp. 13,917-51. 7. Ogg, J.G., “Magnetic Polarity Time Scale of the Phanerozoic,” in Ahrens, T.J., AGU Reference Shelf 1, “Global Earth Physics, A Handbook of Physical Constants,” 1995, pp. 240-70. 8. Hinz, K., Line BFB (24-fold stack) from the Norwegian continental margin/outer Voring Plateau, in Bally, A.W., ed., “Seismic Expression of Structural Styles—A Picture and Work Atlas,” AAPG Studies in Geology 15, Vol. 2, Sec. 2, 1983, pp. 3-39. 9. Rosendahl, B.R., Meyers, J., and Groschel, J., “Nature of the transition from continental to oceanic crust and the meaning of reflection Moho,” Geology, Vol. 20, 1992, pp. 721-24. 10. Jackson, M.P., et al., “Role of subaerial volcanic rocks and mantle plumes in creation of South Atlantic margins: implications for salt tectonics and source rocks,” Marine and Petroleum Geology, Vol. 17, 2000, pp. 47798. 11. Kent, P.E, “The Somali ocean basin and the continental margin of East Africa,” in Nairn, A.E.M., and Stehli, F.G., eds., “The Indian Ocean. The Ocean Basins and Margins,” Plenum Press, New York, 1982, pp. 185-204. 12. Rabinowitz, P.D., Coffin, M.F., and Falvey, D., “Salt Diapirs Bordering the Continental Margin of Northern

Kenya and Southern Somalia,” Science, Vol. 215, No. 4533, 1982, pp. 663-65. 13. Kamen-Kaye, M., “Mozambique-Madagascar geosyncline, I: Deposition and architecture,” Journal of Petroleum Geology, Vol. 5, Issue 1, 1982, pp. 3-30. 14. McCall, R.A., “Implications of recent geological investigations of the Mozambique Channel for the mammalian colonization of Madagascar,” Proc. R. Soc. Lond. B, Vol. 264, 1997, pp. 663-65. 15. Rabinowitz, P., and Woods, S., “The Africa-Madagascar connection and mammalian migrations,” Journal of African Earth Sciences, Vol. 44, Issue 3, 2006, pp. 270-76. 16. Takahashi, N., Kodaira, S., Klemperer, S.L., Tatsumi, Y., Kaneda, Y., and Suyehiro, K., “Crustal Evolution of the Mariana intra-oceanic island arc,” Geology, Vol. 35, 2007, pp. 203-06. 17. Symonds, P.A., Ramsay, D., Bernadel, G., Coffin, M.F., and Gladczenko, T.P., “Kerguelen Plateau Law of the Sea Studies,” AGU 1997 Fall Meeting, 1997, Abs. No. T51B-06. 18. Seychelles preliminary submission Seychelles Petroleum Co. Seypec, 2009 (http://web c a c h e.go og l e u s e r c o n t e n t .c om / search?q=cache:kly8Xa7Ea1oJ:www. un.org/Depts/los/clcs_new/submissions_files/preliminary/syc2009preliminaryinfo.pdf+seychelles+petroleu m+patrick+joseph&cd=4&hl=en&ct= clnk&gl=es&client=firefox-a). 19. Pratt, D., “Plate Tectonics: a Paradigm Under Threat,” Journal of Scientific Exploration, Vol. 14, No. 3, 2000, pp. 307-52. 20. Yano, T., et al., “Ancient and continental rocks in the Atlantic Ocean: New Concepts in Global Tectonics,” No. 53, December 2009, pp. 4-37. 21. James, K.H., “Observations on new magnetic map from the Commission for the Geological Map of the World,” New Concepts in Global Tectonics Newsletter, No. 57, December 2010, pp. 14-26.

Oil & Gas Journal | Mar. 7, 2011

EXPLORATION & DEVELOPMENT

Bibliography Benson, R.N., and Doyle, R.G., “Early Mesozoic rift basins and the development of the United States middle Atlantic continental margin,” in Manspeizer, W., ed., “Triassic-Jurassic Rifting,” Part A, Elsevier, Amsterdam, 1988, pp. 99-127. Kennedy, J.L., “Impressive Arctic discoveries drive international push into unexplored areas,” World Oil, July 2010, pp. 45-54. Manspeizer, W., “Triassic-Jurassic rifting and opening of the Atlantic: an overview,” in Manspeizer, W., ed., “Triassic-Jurassic Rifting,” Part A, Elsevier, Amsterdam, 1988, pp. 41-79. Schlich, R., “The Indian Ocean: Aseismic ridges, spreading centers,

and oceanic ridges,” in Nairn, A.E.M., and Stehli, F.G., eds., “The Ocean Basins and Margins,” Vol. 6, “The Indian Ocean,” 1982, pp. 649-96. Sereno, P.C., Wilson, J.A., and Conrad, J.L., “New dinosaurs link southern landmasses in the Mid-Cretaceous,”

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Oil & Gas Journal | Mar. 7, 2011

Proceedings of the Royal Society B: Biological Sciences, Vol. 271, No. 1546, 2004, pp. 1,325-30. Wilko, S.E. (http://en.wikipedia. org/wiki/File:north_america_basement_rocks.png), 2008.

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EXPLORATION & DEVELOPMENT

Shale gas, oil, minerals processing offer synergies in Brazil’s Amazon basins Fabiano Sayao Lobato Consulting Geophysicist Kingwood, Tex.

AMAZON PALEOZOIC BASINS 80°

Caribbean Sea

FIG. 1 60°

40°

The Amazon region of Brazil is a trove of hydrocarbons and world class mineral resources, and the use of hydroAtlantic Ocean carbons to process its mineral resources could be the basis for sustainable economic development. The potential 0° for both hydrocarbons and minerals is Manaus Belem already immense even though the area Upper is minimally explored. Amazon basin Middle & Lower Horizontal drilling coupled with Amazon basins hydraulic fracturing can change the Acre basin exploration outlook for hydrocarbons B R A Z I L in the Amazon basins. Add to this the Pacific Ocean possibility of carbon dioxide injection to enhance oil recovery and a large avenue is open for utilization of vast 20° mineral resources for sustainable development of the regional and national Source: After AAPG Memoir 40 economies. The processing of minerals into usfor iron, aluminum, copper, potash, manganese, titanium, able products generates CO2 in a symbiotic sequence. The more minerals processing, the more CO2 generated which in niobium, and quartz. turn liberates more hydrocarbons for processing. This article reviews the underexplored potential of both Amazon hydrocarbon potential the hydrocarbons and minerals and points to the synergistic opportunity of simultaneous or sequential development. The main source rocks in Amazon basins are the Barreirinha An important characteristic of the Brazilian Amazon is member of the Devonian Lower Curua formation and the its size (Fig. 1). The Upper Amazon basin stretches for 625 Pitinga member of the Silurian Trombetas formation (Fig. 2). miles west-east. The Middle and Lower Amazon basins exThe Barreirinha reaches a depth of 10,820 ft (Fig. 3) and tend 1,650 miles west-east. Separating the Upper and Mida thickness of 500 ft (Fig. 4), and the Pitinga reaches a depth dle basins is the Purus arch, which roughly follows the Puof 12,140 ft (Fig. 3) and a thickness of 500 ft (Fig. 5). rus River. The city of Manaus, population 2 million, is on Fig. 6 shows total organic carbon and maturation zone the left margin of the Negro River near its junction with the distribution for the Barreirinha. At the RCM-1 well drilled the Amazon River. The Negro River is the Amazon’s largest by Shell Oil Co.’s Pecten International Co. subsidiary in tributary. 1982 about 63 miles southwest of Manaus, TOC was meaThe Amazon is called is called the Solimoes River west of sured at 15%. Manaus and Amazonas east of Manaus. Fig. 7 shows TOC and maturation zone distribution for The Amazon sedimentary basins are entirely covered by the Pitinga. In the Upper Amazon basin as well as in most tropical jungle that also extends to the north on the Guianas Lower Amazon basin, this unit is overmature. Precambrian Shield and to the south on the Brazilian PreBoth source rocks underlie 136 million acres in the Midcambrian Shield. dle and Lower Amazon basins and 74 million acres in the The hydrocarbon potential of the Amazon area is imUpper Amazon basin. mense and has components of conventional structural, Scores of exploratory wells were drilled in the Amazon stratigraphic, shale oil, and shale gas expressions. The minbasins through October 1984 (Fig. 8). The main concentraeral potential is also vast and will be detailed in this article tions of wells are in the productive Jurua and Urucu fields

54

Oil & Gas Journal | Mar. 7, 2011

EXPLORATION & DEVELOPMENT

Oil & Gas Journal | Mar. 7, 2011

Zones of diabase sills

Source rocks

Objectives

Shows

Lithology

Formation

System

Marine

Cont’l

Carboniferous

Sucunduri

1,200

Nova Olinda 6,800

Itaituba Monte Alegre

Devonian

Curua 1,000

L. Curua Erere Maecuru

Presilurian

Silurian

Pitinga Trombetas

1,870

Uatuma

2,000

Precambrian Source: After Jack D. Edwards, Shell Oil Co., 1981

AMAZON BASIN SCHEMATIC REGIONAL CROSS SECTIONS

FIG. 3

2,500 km

E

W P

P C

Carauari arch

S

S

Purus arch

D O-S

D

535 km

430 km

C D S P Permian C Carboniferous D Devonian S Silurian O Ordovician Datum: Base Cretaceous

S

2.6 km

P

Gurupa arch

Middle & Lower Amazon

Upper Amazon N

C ?

P C

Not to scale

4.5 km

4.5 km

The Nova Olinda stratigraphic well was drilled on the right margin of the Madeira River 100 miles southeast of Manaus in 1953-55. The location was chosen near the center of the Middle Amazon basin where a barge bringing the drilling rig could reach. This well produced 15,000 bbl of high-quality light oil and created the expectation of other discoveries because it was more than 1,000 miles from nearest production in Venezuela. Petrobras was created by Law 2004 of Oct. 3, 1953, and took over hydrocarbon exploration from Brazil’s National Petroleum Council, which had DeGolyer & McNaughton as consultant. The first head of exploration of Petrobras was Walter K. Link, assisted by Luis G. Morales as chief geologist. Both came from Standard Oil of New Jersey, where Link was chief geologist and Morales was chief geologist in Colombia. Petrobras was under pressure to produce results in view of the accidental oil discovery at Nova Olinda. Many wells were drilled without proper seismic/geologic support, which was out of reach due to the jungle cover. Seismic work was conducted along the rivers, but data quality was poor. Besides problems properly locating lines, reverberation from river margins masked the data, and the seismic energy reduced fish populations. Surface geologic study was limited to outcropping north and south of the basin because the center was covered by decoupled Tertiary and Cretaceous sediments. Tropical jungle covered everything, thus limiting use of aerial photography.

FIG. 2

Alter do Chao 1,500

Permian

Historical background

Max. thickness, ft

BRAZIL MIDDLE AMAZON BASINS STRATIGRAPHY

U. Cret. & Tertiary

of the Upper Amazon basin and in the area southeast of Manaus in the Middle Amazon basin. In the Upper Amazon basin the density is around one well/1.3 million acres. In the MiddleLower Amazon basins it is one well/1 million acres. Many development wells have been drilled in the two fields.

D O-S

The sections show regional unconformities and the main arches oriented in an approximate north-south direction. Source: From Petrobras: Mossman, Falkenhein, Goncalves, and Nepomoceno Filho

55

EXPLORATION & DEVELOPMENT

ISOPACH OF BARREIRINHA MEMBER OF DEVONIAN CURUA FORMATION 50°

66°

Bogota 2°

58°

Tacutu graben

VENEZ.

0°

Cayenne 50°

Paramaribo

FR. GUI.

SUR. GUY.

COL.

Atlantic Ocean

Carauari arch

2°

FIG. 4

Belem

PERU

100 50

Manaus

6°

Purus arch

50

Rio Branco

Contour interval = 50 m 0 373 Miles

Porto Velho

Km

0

10°

600

Barreirinha member limit Basement outcrop limit

BOL. Source: After Petrobras: Mossman, Falkenhein, Goncalves, and Nepomuceno Filho

ISOPACH OF PITINGA MEMBER OF SILURIAN TROMBETAS FORMATION 50°

66°

Bogota 2°

58°

VENEZ.

Tacutu graben

GUY.

COL.

FIG. 5

Cayenne 50°

Paramaribo

FR. GUI.

SUR.

Atlantic Ocean

0° 2°

Belem

PERU

100 50

Manaus 50

6°

Purus arch

Contour interval = 50 m 373 Miles

0

Rio Branco

Porto Velho

Km

0

10°

600

Pitinga member limit Basement outcrop limit

BOL. Source: After Petrobras: Mossman, Falkenhein, Goncalves, and Nepomuceno Filho

TOC AND MATURATION, BARREIRINHA MEMBER OF DEVONIAN CURUA 50°

66°

Bogota

VENEZ.

58°

Tacutu graben

COL.

2°

GUY.

Paramaribo

SUR.

FIG. 6

Cayenne 50°

FR. GUI.

Atlantic Ocean

0° 5.0 4.0 3.0 2.0

2°

PERU 2.0 1.0

2.0

6°

2.0 1.0

Manaus 0

2.0

0

Belem

Contour interval = 1.0% 373 Miles Km 600 Barreirinha member limit Basement outcrop limit

Rio Branco

Porto Velho

10°

BOL. Source: After Petrobras: Mossman, Falkenhein, Goncalves, and Nepomuceno Filho

56

1.0

Total organic carbon, % Immature Mature Overmature

Nevertheless, geological information from wells permitted recognition of a very encouraging petroleum system with world class source rocks at proper maturation (Figs. 2-7). The main problem was paucity of reservoir rocks.

Structural and deformational system A transcurrent fault may have existed during the Late Jurassic Oxfordian 160 million years ago and persisted until the Cretaceous (Fig. 9). To the figure from Prof. Scotese, the author added the possible Riedel conjugate system, which has implications to deformation of the sediments. The transcurrent fault may be the result of differential movements of the Guiana Shield, north of the Amazon basins, and the Brazilian Shield to the south. Fig. 10 illustrates the explanation of three directions of compression associated with the transcurrent fault and Riedel conjugate faults. Starting from a circle at the top of the figure, deformation of sediments creates an ellipse of which the axis AA′ corresponds to an extension of the radius of the circle and the axis BB′ corresponds to a reduction of the radius of the circle. An extension would submit the sediments to extensional faulting in a direction perpendicular to AA′ BB′. Compression in the principal axis direction BB′ would create a system of cylindrical folding with horizontal axis (lower Fig. 10). Similarly, the left lateral Riedel conjugate CC′ would create the left lateral compression, and the right lateral Riedel conjugate DD′ would create the right lateral compressional system. Fig. 11 shows the Amazon model with superposition of horizontal cylindrical folding in the principal axis and Riedel conjugate axes. The bottom of Fig. 11 is expanded as Fig. 12, where highs are surrounded by lows. The author mapped 65 four-way anticlines each 2,470 acres to 24,700 acres in the 2 million acre region southwest of Manaus. The mapping preceded the

Oil & Gas Journal | Mar. 7, 2011

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EXPLORATION & DEVELOPMENT

TOC AND MATURATION, PITINGA MEMBER OF SILURIAN TROMBETAS 50°

66°

Bogota

58°

Tacutu graben

VENEZ.

COL.

2°

Cayenne 50°

Paramaribo

FR. GUI.

SUR.

GUY.

FIG. 7

Atlantic Ocean

0° 1.0

2° 2.0

.0

<1.0

0

6°

Belem

1.0

Manaus 1

PERU

Contour interval = 1.0% 373 Miles

0

Km 600 Pitinga member limit

1.0

Total organic carbon, %

Basement outcrop limit

Rio Branco

Porto Velho

Immature

10°

Mature

BOL.

Overmature

Source: After Petrobras: Mossman, Falkenhein, Goncalves, and Nepomuceno Filho.

EXPLORATORY WELLS DRILLED IN AMAZON BASINS THROUGH 1984 50°

66°

Bogota

58°

Tacutu graben

VENEZ.

GUY.

COL.

2°

Paramaribo

SUR.

FIG. 8

Cayenne 50°

FR. GUI.

Atlantic Ocean

Gurupa arch 0°

Jurua area

2°

Purus arch Manaus

Belem

PERU <1.0

Upper Amazon basin 58 wells

6°

Acre basin

Rio Branco

Middle & Lower Amazon basins 131 wells

Porto Velho

Contour interval = 1.0% Exploratory well

10°

BOL.

Basement outcrop limit

0

Miles

373

0

Km

600

Source: After Petrobras: Mossman, Falkenhein, Goncalves, and Nepomuceno Filho

LOCATION OF TRANSCURRENT FAULTS

FIG. 9

Volcanic edifice

Possible Riedel conjugate system

Late Jurassic Oxfordian 160.6 Ma Source: Prof. C.R. Scotese, 1989

58

development of a possible explanation for the observed deformation. Considering that the prospective area of the Upper Amazon basin is 74 million acres and the area of the Middle-Lower Amazon basins is 136 million acres, the potential for exploration would involve 6,500 structures if the rate observed in the mapped area southwest of Manaus persisted throughout. It is important to emphasize that this is a speculation indicating only the order of magnitude of the potential for structures. Fig. 13 shows the structural framework of the Middle-Lower Amazon basin. Of note is the concentration of anticlinal folds in the center of the figure which are aligned with similar concentrations near Manaus, in the west Middle Amazon basin, and the Urucu-Jurua trend in the Upper Amazon basin. Of extreme importance is the mapping of Precambrian transcurrent faults both north and south of the sedimentary section that are aligned across the sediments. These faults correspond to the Riedel conjugate system suggested on Fig. 11. The right lateral component on the east end of Fig. 13 has been mapped starting in the Precambrian and was extended on the sedimentary area. The northeast/ southwest faults correspond to the left lateral Riedel conjugate. All of the preceding supports the interpretation of transcurrent faults in the Amazon basins and the possibility of a multitude of simple four-way culminations surrounded by low structural features. This system extends 1,550 miles east to west. Transcurrent faults have a predominantly vertical surface component that could be the conduit for the molten basaltic magma from the earth mantle to the sediments above. Fig. 2 indicates the existence of diabase sills in the Silurian, Devonian, and principally in the evaporite section in the Carboniferous and Permian. The age of the diabase is principally Triassic-Jurassic. The intrusion of the molten mag-

Oil & Gas Journal | Mar. 7, 2011

EXPLORATION & DEVELOPMENT

LEFT LATERAL SYSTEM

FIG. 10

FOLDING IN DIFFERENT DIRECTIONS

Strain ellipse

FIG. 11

Brazil Amazon model

Y D

A’

A

B C X’

X C’ B’

D’ Y’

Lef t la tera inc l co ipa mp res la sio xis n co mp re s sio n

Left lateral system

al

Pr

er

R

t igh

lat

n

sio

es

pr

om

c

l Riede teral Left lagate axis conju

Principal axis

Source: From Fabiano Lobato

Right lateral Riedel conjugate axis

Source: From Fabiano Lobato

BRAZIL AMAZON MODEL

FIG. 12

idealized distribution of highs surrounded by lows

ma is facilitated by assimilation of evaporites, thus creating space for penetration. There is no mention of basalt in the description of rocks in the wells, which would indicate extrusion of magma for surface cooling (which occurs at the Parana basin of southern Brazil). Only diabase is described, which would indicate slow cooling within the sediments. In any case, the magma intrusion corresponds to a thermal pulse that complements the maturation of source beds. Fig. 14 shows the thermal effect of diabase sills on maturation measured at the 1-LUC-1-AM well in the Petrobras Urucu field. Vitrinite reflectance decreases with depth as the distance to the diabase sills increases. Likewise, the thermal effect of diabase along the transcurrent fault surface (near vertical) decreases with distance.

Amazon hydrocarbon exploration myths This brings up two myths that prevailed in early hydrocarbon exploration in the Amazon basins. First, was the conclusion that no structures existed because the well information suggested persistence of bed thicknesses over large distances. Because the seismic data were so bad, the broad structures could not be detected. It was only after the seismic technology evolved that the multitude of structures could be recognized. As indicated earlier, thousands of simple four-way anticlines may be interspersed

Oil & Gas Journal | Mar. 7, 2011

with lows. The second myth was that the molten magma injected, principally in the Triassic and Jurassic, destroyed all hydrocarbons. What occurred was an increase in the degree of maturation, but hydrocarbons survived as demonstrated by accumulations in the Urucu and Jurua areas. At the Jurua area, the Monte Alegre formation equivalent (Fig. 2) produces mainly gas, despite being shallower than at the Urucu area, which produces oil, condensate, and gas. The explanation is that in the Jurua area the diabase sills are closer to the source layers (Lower Curua, Pitinga, Fig. 2) than in the Urucu area. The two ideas are myths, and this fact enhances the potential for hydrocarbons of the Amazon basins. In the Upper Amazon basin, reserves are estimated at more than 4 tcf of gas and more than 500 million bbl of oil.

59

EXPLORATION & DEVELOPMENT

STRUCTURAL FRAMEWORK, MIDDLE/LOWER AMAZON BASIN Area shown BRAZIL

FIG. 13

Gurupa arch

Layer attitude Normal fault Reverse fault Transcurrent fault Anticline Syncline Lineament Morphostructural trend Diabase dike Undifferentiated Paleozoic Mesozoic cover Seismic profile

Source: Petrobras, 1984

THERMAL EFFECT OF DIABASE SILLS ON MATURATION 1,000

Depth, m

1,500

2,000

Nova Olinda fm

Itaituba fm Dev. Rochas Geradoras 2,500

Prosperanca fm

.2

.4

.6

.8

1.0

Vitrinite reflectance, % Ro Source: From Rene Rodrigues, Petrobras Geoscience Bulletin, Jan.-Mar. 1990, pp. 85-93

Production is 40,000 b/d of oil and 160 MMcfd of gas. The gas feeds power plants at Manaus via a 410-mile pipeline inaugurated on Nov. 26, 2009.

Oil shale The outcropping Barreirinhas member of the Devonian Lower Curua is considered oil shale at the south margin of the Amazon sedimentary basin.

Concessions and production Fig. 15 shows the Amazon mineral deposits as depicted on the site of Brazil’s National Petroleum Agency (ANP).

60

More than 250 million bbl of 59° gravity, low-sulfur oil have been produced from Urucu field. Oil was discovered in the 1970s, and production started in 1982. Some produced gas ± 400 m diabase was initially reinjected to maintain reservoir energy, but much of it was ? flared. Nowadays it generates electricity at plants in Manaus and along the pipeline route. Well 1-LUC-1-AM Petrobras in early 1999 revealed a discovery that appears to be the reason behind ANP’s award of 11 million acres of concessions to Petrobras in the 4.0 Middle Amazon basin east of Manaus (Fig. 16). Outside the Petrobras blocks are 177 million acres available to other operators in the Middle/Lower Amazon basin. The company said at that time, “Petrobras specialists found a a gas-bearing formation 12 m (39.4 ft) thick, at a depth of 1,650 m (5,412 ft), 200 km (124 miles) east of the city of Manaus, the capital of the state of Amazonas. After carrying out the required tests, specialists determined that the 20 sq km (4,949 acre) area holds a production potential of 700,000 cu m/day (24.7 MMcfd) of gas with a small percent of condensate. It is estimated that the mapped area contains about 8 bcm (282 bcf) of gas in place, representing recoverable volumes of around 6 bcm (211 bcf).” High Resolution Technology (HRT) Oil & Gas, headed FIG. 14

2.0

Oil & Gas Journal | Mar. 7, 2011

APR

3

MEOW WEEK 9-14 April 2011 Kingdom of Bahrain

10 17 24

4 11 18

25

5 12 19

26

IL 2 011

1

6 13 20

27

7 14 21

28

2

8

9

15 22

29

16 23

30

EXPLORATION & DEVELOPMENT

AMAZON BASIN MINERAL DEPOSITS 66°

FIG. 15

60°

54°

4°

SURINAME

VENEZUELA

FRENCH GUIANA

GUYANA

Roraima

Amapa

Trombetas bauxite mine

50°

42°

40°

Area shown

Faro-Juruti potassium occurrence

BRAZIL

Alumina/aluminum plants

0°

Balbina dam

Arari potassium ore body 4°

48°

i on R Am a z

Belem

ve r

Manaus

Sao Luis Santarem

Tucurui dam

Fortaleza

Urucu oil-gas fields

Amazonas

Ceara

Juruti bauxite

Fazendinha/Nova Olinda potassium ore body

Maranhao

Para Piaui

8°

Porto Velho

Rondonia

Carajas Mineral Province

B

R

A

Z

Pernambuco Alagoas Sergipe

I

L

14°

Bahia Mato Grosso

Goias

0

Miles

200

0

Km

320

BOLIVIA Brasilia

by Marcio Rocha Mello, obtained a concession covering 12.1 million acres, all or parts of 21 blocks, surrounding the Urucu and Jurua areas in the Upper Amazon basin in 2009 (Fig. 16). HRT has announced a major seismic and exploratory drilling program there.

tained copper from the Sossego mine. By 2011 the Salobo mine would contribute 127,000 tons of contained copper with 130,000 oz of gold. There is no production of nickel at present, but in 2011 the Onca mine will start production of 58,000 tons of contained nickel in iron-nickel ore.

Amazon mineral potential

Bauxite and aluminum

The Amazon region has world class mineral deposits already identified and possibly many more awaiting exploration. The principal accumulations involve iron, manganese, copper, gold, nickel, aluminum, and potash, besides the volcanic chimneys. Many are potential markets for gas.

Iron, manganese, copper, gold, and nickel The Carajas Mineral Province is already considered the largest mineral province in the world (Fig. 15). More than 18 billion tons of iron ore averaging 66% of iron content have been measured. Production started in 1983 and reached 90 million tons/year in 2009. It is projected to increase to 200 million tons/year by 2015 (personal communication from Breno Augusto dos Santos, the discoverer of Carajas). Manganese ore production is 2 million tons/year. The Brazilian company Vale SA has installed copper concentrate capacity of 300,000 tons/year with 100,000 tons of con-

62

Production of high-grade bauxite started at the Trombetas mine in August 1979 (Figs. 15 and 17). The reserves were estimated at 1 billion tons of bauxite containing around 50% of alumina or 25% of aluminum. At present, Trombetas produces 16 million tons/year of bauxite. Cumulative production is 250 million tons. The 4 million tons of aluminum derived from the 16 million tons/year of bauxite corresponds to 10% of world output of new aluminum. New aluminum is specific for foil and special applications. The annual world consumption is 80% recycled aluminum and 20% new aluminum from bauxite. To produce recycled aluminum takes about 5% of the amount of energy needed to produce aluminum from bauxite. The aluminum industry has five phases. The first is the mining of bauxite, the ore used in most refineries. Refineries are industrial installations that extract alumina (Al2O3) from bauxite and constitute the aluminum industry second phase. In the third or metallurgical phase, aluminum is ob-

Oil & Gas Journal | Mar. 7, 2011

EXPLORATION & DEVELOPMENT

AMAZON OIL, GAS CONCESSIONS

FIG. 16 60°

Trombetas Manaus Urucu fields Chibata Sao Mateus

4°

Jurua 0

34 Miles

0

55 Km

6°

Petrobras HRT et al.

tained by electrolysis from alumina in smelters. The fourth phase is the production of semimanufactured goods, and the final phase is the production of finished goods. In an effort to reduce cost by eliminating bulk transportation, by-products should be disposed of at the mine site. This also results in reduction of pollution by dumping the red mud generated by processing of alumina in the natural

filtering system that produced the bauxite. This effort has defined a trend to move the first three phases from industrialized countries to countries that have high-grade bauxite deposits. Based on parameters provided by A.L. Bacon (Billiton) and Raymundo Campos Machado (Alcan, retired), computations were made for processing 1 million tons of bauxite of

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63

EXPLORATION & DEVELOPMENT

METALLOGENETIC MAP OF TROMBETAS AREA, AMAZON BASIN

Trom beta

sm ine

FIG. 17

Area shown

0

BRAZIL

the type mined at Weipa (Australia), Boke (Conakry, Guinea), and Trombetas (Brazil). It takes around 4 tons of bauxite to produce 2 tons of alumina (Al2O3) and 1 ton of aluminum. The yearly demand for gas for the processing of 1 million tons of bauxite would be 350 MMcf for bauxite drying, 4.9 bcf for alumina, 550 MMcf for aluminum, and 31.25 bcf for electrolysis, or a total of 37.05 bcf/year or 101.5 MMcfd.

Other bauxite accumulations The Alcoa-operated Juruti mine (Fig. 15) started production in 2008 of 2.8 million tons/year of bauxite. The mine will expand production to 10 million tons/year. The announced reserves of the Juruti area are 750 million tons of high-grade bauxite. The Jari project, 400 km east of Trombetas, has 1,500 million tons of bauxite. Other deposits of bauxite are indicated on Fig. 18.

0

Miles

62.1

Km

100

Potash demand Potash helps improve crop quality and a plant’s disease resistance, reduces plants’ water needs, and increases yields. There are no practical substitutes for potassium as an essential plant nutrient. Potash occurs in the Amazon area of Brazil as sylvinite, a mixture of sylvite (KCl) and halite (NaCl) (Figs. 15 and 17). The Fazendinha/Nova Olinda deposit (450 million tons of sylvinite) and Ararí deposit (550 million tons of sylvinite) measured by Petrobras mining branch, Petromisa, are recognized as potassium ore bodies. The Petrobras FA-1 well near Trombetas detected 5 m of sylvinite, but no extra drilling was made to confirm an exploitable ore body. The potassium deposits occur in the evaporite expanse that extends for 500 km by 200 km (Fig. 18). The potential for many potassium ore bodies is quite good because Fazendinha/Nova Olinda, Arari, and Faro were discovered by accident upon drilling for hydrocarbons inside the evaporites.

Bauxite processing Alumina/aluminum plants near Belem and Sao Luis are supplied with electricity by the 9,600 Mw plant at the Tucurui dam on the Tocantins River (Fig. 15). At 100 MMcfd/1 million tons/year of bauxite for processing at the mine site, the potential demand is 2.6 bcfd to process to aluminum the combined 26 million tons/year of bauxite to be produced at Trombetas and Juruti.

64

Potash processing Beneficiation of sylvinite ores is done by froth flotation since the middle 1930s. In the US and Canada, the fuel for froth flotation is natural gas. Because in the Amazon region of Brazil the shale gas source beds and the potassium ore beds occur in the same area, there is no need for construction of long pipelines.

Oil & Gas Journal | Mar. 7, 2011

EXPLORATION & DEVELOPMENT The location of plants for processing the ore can take advantage of this situation and make the operation more economical. Also, the availability of rivers navigable by ships of 75,000 tons capacity minimizes the cost for transportation of products to markets everywhere.

Importance of potash to Brazil Brazil imports 90% of the potash it consumes. Consequently, it is of interest to Brazil not only to exploit the ore bodies already discovered but to find new ones. The size and distribution of evaporites in the Amazon region as expressed by the 1 billion tons of sylvinite already measured, plus the Faro occurrence, indicate that Brazil could not only become self-sufficient in potash but could become an important exporter.

Volcanic chimneys In 1973, the National (Brazilian) Department of Mineral Production (DNPM) launched the Project RADAM-Brazil of side-looking radar to cover the Amazon region. Images were cataloged of over 200 volcanic chimneys (the exact number is 207 announced by the then-DNPM director Acyr Avila da Luz at the 1974 Brazilian Geological Society meeting at Porto Alegre). Three volcanic chimneys were drilled and sampled:

1. Seis Lagos (Six Lakes) carbonatite. Located in the Upper Rio Negro, it is considered the largest accumulation of niobium (NB2O5) and contains 1.0% to 2.1% of cerium (used on cars’ catalytic converters), barite, and manganese (Fig. 18). 2. Maicuru alkaline-ultrabasic complex (Fig. 19). Located 155 miles northeast of the Trombetas mine, where preliminary exploration indicated a potential of around 5 billion tons of titanium ore under the form of anatase (TIO2), possibly the world’s largest titanium accumulation. 3. Maraconai alkaline-ultrabasic complex, covered with titanic/magnetite crust and located near the Paru River 185 miles northeast of the Trombetas mine (Fig. 20). Three of the more than 200 volcanic chimneys drilled indicated two of the largest accumulations of niobium and titanium, respectively. One can only guess at how many large mineral deposits could be discovered in the undrilled volcanic chimneys.

Halite-caustic soda The production and processing of potash (KCl) results also in the production of large quantities of halite (NaCl). In turn, by electrolysis, halite produces caustic soda (NaOH) and chlorine. Caustic soda is used in producing alumina (AL 2O3). Plas-

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SIX LAKES CARBONATITE*

FIG. 18

tics are produced by using methane and chlorine. Thus, the separation of potash from sylvinite results in a sequence of industrial processes of importance.

Glass, cement, and ceramics

0 *Radar image of carbonatite deposit located on the Upper Negro River, where occurrences of niobium rutile were discovered. Radar image reproduced courtesy of Radam Brasil project. Image after dos Santos, 1981.

6.2

Miles Km

0

10

MAICURU ALKALINE*

FIG. 19

Of interest, the Amazon River carries large quantities of quartz under subaquatic dunes. The concentration of quartz was measured by the University of Amazonas in excess of 94% in the moving sediments. The dunes travel downriver as much as 500 m/day. The quartz already reduced to sand could be the basis for a glass industry, which in turn would require energy from hydrocarbons for processing. The bauxite at Trombetas occurs encased in clay deposits with the appropriate composition for ceramics and production of cement. Both could be economically produced because the clay would already have been mobilized for the extraction of bauxite and has low production cost.

Minerals/hydrocarbon strategy

*This is an ultrabasic complex where preliminary exploration indicated a potential of 5 billion tons of titanium ore in the form of anatase. Radar image reproduced courtesy of Radam Brasil project. Image after dos Santos, 1981.

0

Miles

6.2

0

Km

10

MARACONAI ALKALINE*

FIG. 20

0 *This is an ultrabasic complex, covered with cangue rich in titanic-magnetite, located near the Paru River. Radar image reproduced courtesy of Radam Brasil project. Image after dos Santos, 1981.

66

0

Miles

6.2

Km

10

The area encompassing the Trombetas and Juruti bauxite mines and the FA-1 well potassium occurrence is indicated for the start of possible shale gas production. At present, Trombetas and Juruti together produce close to 19 million tons/year of high grade bauxite, but this production is expected to increase to 26 million tons/year within 5 years. As in the energy requirements for the aluminum industry, it takes 100 MMcfd of gas to process to aluminum metal 1 million tons/year of bauxite. Thus, the ultimate demand for the aluminum industry is around 2.6 bcfd of gas to be supplied by shale formations. Of course, this production has to start slowly and grow as needed, but it indicates the immense potential for the development of a shale gas industry. Along the way, it is quite possible for conventional and stratigraphic hydrocarbon accumulations to be discovered and also put on production.

Oil & Gas Journal | Mar. 7, 2011

EXPLORATION & DEVELOPMENT The amount of sylvinite at the area around the FA-1 well has not been measured, but the thickness of potash at the well is 16.4 ft, which corresponds to 13 million tons/sq km if the thickness persists. Natural gas is needed to thermally process the separation of sylvite from halite as seen in the processing of potash above. The titanium ore deposit at Maicuru (Fig. 19) is 110 miles northeast of the Trombetas mine. The processing of titanium ore to metal also requires large volumes of gas. Quartz exists in large quantities in subaquatic dunes in the Amazon River near the Juruti mine, which could support a large glass industry. Also, clay deposits at Trombetas mines could activate major cement and ceramics industries. Thus, if natural gas can be produced from the source beds at the location of the above deposits, the pipelines required to supply very large industrial minerals development would be quite short. Nearly 2.5 million acres are open within 100 km from the Trombetas mine and could be licensed to start a major industrial development that could be greatly expanded. Thus, the use of hydrocarbons to process the mineral resources of Amazonia could be the basis for sustainable economic development.

2010, p. B3. Tita, Bob, “South America Beckons to U.S. Firms,” The Wall Street Journal, July 30. 2010, p. B4. Paris, Costas, and Welsch, Edward, “Interest in Potash Mounts,” The Wall Street Journal, Sept. 8, 2010, p. B1.

The author Fabiano Sayao Lobato (fabianolobato1@gmail. com) is a geophysicist retired in Kingwood, Tex., after 27 years with various divisions of Shell Oil Co. He was a staff geophysicist with Pecten International Co. in 1980-91, at various times working Sabah, China, Australia, New Zealand, Pakistan, Indonesia, Guinea Bissau, Senegal, West Africa, Cameroon, and Brazil. As chief geophysicist in Brazil, he managed seismic surveying in the Middle Amazon basin and identified and mapped prospects in the offshore Cassipore grabens, Maranhao, Ceara, and Potiguar basins. He has a doctor of science in geophysical engineering from Colorado School of Mines and civil and mining engineering degrees from the Ouro Preto School of Mines, University of Brazil.

Acknowledgment Thanks to Ana Carolina Naves Crema for the graphic presentation.

Bibliography Mossmann, R., Falkenhein, F.U.H., Goncalves, A., and Nepomuceno Filho, F., “Oil and Gas Potential of the Amazon Paleozoic Basins,” AAPG Memoir 40, 1986, pp. 207-41. Lobato, Fabiano S., “Exploration for Hydrocarbons in the Amazonas Basin,” Brasil Mineral, Special Issue 2000, pp. 3337. Caputo, Mario V., Solimoes Megashear, Intraplate Tectonics in Northwestern Brazil,” Petrobras Magazine, Vol. 7, No. 24, January/February/March 1999. dos Santos, Breno A., 1981, “Amazonia, Potencial Mineral e Perspectivas de Desenvolvimento,” T.A. Queiroz, ed., Editora da Universidade de Sao Paulo, 1981, 257 pp. da Luz, Acyr A., “Morro dos Seis Lagos,” Brasil Mineral, No. 191, Janeiro/Fevereiro 2001, p. 29. Neves, Carlos A.O., “Boletim de Geociencias da Petrobras,” Vol. 4, No. 1, 1990, p. 98. Bacon, A.L. (Billiton), and Machado, R.C. (Alcan), “Parameters for Energy Requirements for the Aluminum Industry,” personal communications. Singleton, Richard H., “Mineral Commodity Profiles,” MCP-11, US Bureau of Mines, February 1978. Briefing Brazilian Agriculture, “The Miracle of the Cerrado,” The Economist , Aug. 28, 2010, pp. 58-60. Fick, Jeff, and Jelmayer, Rogerio, ”Vale Strenghthens Its Grip With Copper Offer,” The Wall Street Journal, July 30,

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67

DRILLING & PRODUCTION

Forecast expects continued multiphase flowmeter growth Gioia Falcone

COMMERCIAL MFMS

Bob Harrison Soluzioni Idrocarburi srl Rome

A forecast based on the trends in sales and installations worldwide indicates that the upstream petroleum industry will install many multiphase flowmeters during the next 5-10 years. For this fast evolving and technically complex technology, the global market continues to grow quickly. MFMs offer many claimed capabilities but vendors still face the problems of the slow uptake of MFM technology by the oil and gas industry and the associated barriers to entry into this market.

Multiphase flowmeter market

FIG. 1

ce ur so n ive io ct arat n oa di sep tio Ra ne ela r e -li orr In X-c Trac g in pl m / sa ing n ic et tio n in di tio ok con niza e n Is e o /c ow g Fl omo turi M F h n Ve le M e ho um wn vol , % Do s on G a cti fra

Texas A&M University College Station, Tex.

Abbon Acoustic flowmeter Abbon Optimum C400 Accuflow Agar MPFM 300 Agar MPFM 400 loop Agar MPFM 50 ESMER ESMER Mobile ESMER Wet gas Expro Petrotech SmartVent MultiTrace GLCC (Tulsa) Multiphase metering loop Pietro Fiorentini Flowatch Pietro Fiorentini Flowatch High GVF Haimo MPFM Hydralift Wellcomp Jiskoot (Cameron) MIXMETER Kvaerner Duet Kvaerner Duet with Venturi McCrometer V-Cone and Wafer Cone Neftemer PhaseDynamics Kvaerner CCM QuantX Red Eye REMMS Weatherford Roxar (Emerson) MPFM 2600 Roxar (Emerson) MPFM 2600 with gamma Roxar (Emerson) MPFM WGM95 Schlumberger PhaseTester Schlumberger PhaseWatcher oil mode Schlumberger PhaseWatcher gas mode Solartron Ametek Dualstream I Solartron Ametek Dualstream I advanced Solarton Ametek Dualstream II advanced TEA Sistemi Lyra TEA Sistemi Vega

0-99.8 0-90 0-99 0-97 0-99.6 0-100 0-100 0-100 95-100 90-100 0-97 0-99 0-99.8 0-90 0-99 97-100

0-100 0-95 0-95 0-100 0-100

Multiphase flow metering, which measures the flow rate of each phase in a 0-98 flow stream,1 ranges from metering 90-100 wet-gas streams with a high gas con95-100 98-100 tent to metering heavy-oil streams. 80-100 The first commercial MFMs ap0-90 90-100 peared in the 1990s from a handful of manufacturers. The number of comCiDRA Weatherford CiDRA SONARtrac mercial MFM manufactures rises and Note: The capabilities are from the meter manufacturers. falls because of mergers and acquisitions that continue unabated, but the appearance of new vendors has maintained the total number of manufacturers at about 20. offshore, from new development projects to retrofits of deMFMs are essential for many field developments because clining fields, and from wet gas to heavy-oil streams. they allow real-time well monitoring, individual well testFig. 1 lists the currently available MFMs in the market along with their key technical characteristics claimed by ing, production allocation, and reservoir surveillance. They also provide critical information on well performance such their manufacturers. MFM history suggests that a universal as water breakthrough, gas coning, and inflow characterismetering solution does not exist. Often reported is that the service and support provided tics. by MFM vendors falls short of the mark. The meter hardware MFM applications are diverse, ranging from onshore to

68

Oil & Gas Journal | Mar. 7, 2011

Installation trends

MFM INSTALLATIONS 1,400 1,200

FIG. 2

Subsea Offshore Onshore

1,000

No. of installations

requires associated software, training, and customer assistance, yet operators often fail to discover from meter manufacturers why a given installation does not perform as expected. Operators also complain of poor technical assistance from local MFM vendors because the real expertise resides primarily in the manufacturer’s head office. Also vendors frequently offer a full-blown MFM system for applications that may require a simpler, cheaper meter.

800 600 400 200 0

1994 1995 1996 1997 1998 1999 2000 2001 2002 2004 When establishing the exact number Source: Reference 3 of MFM installations worldwide, one must distinguish between those installed and currently working, those installed but now discontinued, those MFM INSTALLATIONS LOCATION FIG. 3 ordered but not yet delivered, those Mobile 7% delivered but not yet installed, and Canada 0% those used for portable well testing. Asia-Pacific 24% Other Americas 9% MFM vendors consider market information as commercially sensitive and governmental source data vary in quality and quantity. For example, the US Bureau of Ocean Energy Management, Regulation, and Enforcement provides deUS 25% tailed listings of MFMs and wet-gas meters (WGMs) used in the Gulf of Western Europe 23% Mexico. The lists include operator, meter size, subsea or topside installation, Africa 5% meter model, type of application, apMiddle East 6% Eastern Europe (CIS) 1% Source: Reference 2 proval date, and whether the meter is still in service. The Norwegian Petroleum Direcrope, US, and Asia-Pacific accounted for 75% of the total torate (NPD), which does not log its data in as much detail, number of MFM installations, with the latter seeing a sharp claims there is a 50/50 split between subsea and topside apincrease in MFM applications and eclipsing the North Sea. plications off Norway, with subsea meters gaining popularAs to the current size of the MFM market, in 2004 Royity because of their potential for providing information close al Dutch Shell PLC claimed that there were 1 million oilto the well. NPD suggests that WGMs make up 10% of all producing wells worldwide of which 1% may have MFMs MFMs in operation off Norway. by 2010, suggesting that currently there are 10,000 MFMs installed. All Norwegian operators have some MFMs installed, with A later study claimed the perception that MFM is a mathree manufacturers dominating the local market: Framo/ ture technology is misplaced because its impact is just beSchlumberger, Roxar/Emerson, and MPM/FMC. ginning to be felt with an estimated market penetration of Notwithstanding the difficulty of gathering market data, only 0.3%.5 This would amount to 3,000 meters for 1 million Figs. 2 and 3 show an estimate of MFM installation trends producing wells worldwide. 1994-2004 and the regional distribution of those installaThe authors concur with this later estimate of market tions, respectively.2 3 In 2005, a market researcher estimated that there were size, which is roughly one third of Shell’s optimistic forecast. more than 1,600 MFM units installed, of which 10% were More recently, one estimate is that MFMs facilitate only 12% for mobile well testing and 20% were WGMs.4 Western Euof global oil and gas production, implying that there is much

Oil & Gas Journal | Mar. 7, 2011

69

DRILLING & PRODUCTION

MFM EXTRAPOLATED TREND

FIG. 4

Years since first MFM installation 0

5

10

15

20

25

7000 3

30 140

2

y = 5.48169E-03x - 2.18448E+01x + 2.17632E+04x 2

R = 9.88263E-01

6000

120

100

U.S. Average (in $/bbl.) Poly. (total MFM)

80

4000

Oil price 3000

60

2000

Oil price, $/bbl

No of MFM installations

Total MFM

5000

40

Extrapolated curve

1000

0 1993

MFMs installed 1998

2003

2008

2013

20

0 2018

BARRIERS TO ENTRY

 #   

FIG. 5

 

  


50%   

Barriers to technology development $         
 

      
            "           

  !        

  

  Source: Reference 8

room for market growth.6 The authors’ currently estimate there are 3,314 MFMs and WGMs installed, with Framo/Schlumberger and Roxar/Emerson accounting for two thirds of the global MFM market. An extrapolation for the next 5-10 years of MFM installations (Fig. 4) suggests that the number of MFM installation may double from the authors’ 2010 estimate.

New technology MFM manufacturers face several serious hurdles for getting their meters to market. It can take anywhere from a fast-

70

track of 5 years to more than 15 years to develop a basic measurement concept to a working meter, for example:7 • 1-5 years of basic research lead to development of a concept. • 2-5 years of pilot testing lead to development of a prototype. • 2-5 years of field experience, failures, and successes lead to an initial production model, which then becomes a commercial product. The slow uptake of technology in the oil and gas industry indicates that it can take another 15 years before market penetration exceeds 50%.8 Although researchers have developed many new metering ideas, it is difficult to pilot test an MFM in the field due to operator risk-aversion and conservative attitudes, especially for those without a technology-based strategy. Operators often claim poor correlation between performance and innovation as the reason for their not being more proactive in adopting new technology. This fast-follower mentality, which stems from the knowledge that suppliers eventually will have to give access to new technology, delays its implementation. The observed slow growth in patents is symptomatic of poor intellectual property (IP) protection within the oil and gas industry. Many new technology developers complain that even though they have patents, remarkably similar rival products appear quickly in the market. All of these factors create barriers to entry into development of new technology for MFMs (Fig. 5).

Patent protection Meter companies safeguard ownership of IP at all costs. For instance, Roxar reported that it successfully protected its IP by preventing FlowSys from producing, selling, or marketing MFMs for 3 years while receiving almost $2 million in damages.9 10 New technology development is a long-term investment, and as patents have a maximum validity of 20 years, any incremental developments must also be patented. Yet IP is not just about patents. Companies must also protect the knowledge developed by thorough documentation

Oil & Gas Journal | Mar. 7, 2011

DRILLING & PRODUCTION

INTELLECTUAL PROPERTY ICEBERG

TOP 20 COMPANIES BY REMAINING RESERVES

FIG. 6

FIG. 7

Saudi Aramco

Visible IP:

Gazprom

Patents Design protection Trademarks

Iraqi oil ministry National Iranian Oil Co. ADNOC ExxonMobil Shell PetroChina

Invisible IP

Rosneft

Trade secrets and know-how (what works and what does not work)   
   
      
  
     
      
  


  

BP Kuwait Petroleum Corp. Lukoil Chevron Qatar Petroleum Pemex Total Sonatrach ConocoPhillips

Gas Oil

Petrobras

Source: Reference 14

NNPC

0 Source: Wood MacKenzie 2009

that is covered by stringent confidentiality procedures. This is termed the IP iceberg (Fig. 6).

Future trends

SUBSEA PROJECTS

250

FIG. 8

Projects awarded 2000-08 Projects to be awarded 2009-12 Petrobras BP Chevron Total Shell Statoil ExxonMobil Eni ONGC Reliance Woodside Pemex Hess Anadarko BHP Billiton Petronas Carigali Forest Oil Murphy Oil Nexen Inpex ConocoPhillips Tullow Oil Marathon Oil Nautical Petroleum Noble Energy

59 35 16 25 56 85 20 25 1 2 13 1 13 36 11 2

Figs. 7 and 8, taken from analysts’ reports, show that national oil companies control an increasing share of the world’s oil and gas reserves, while the influence of the international oil companies is waning. Opportunities exist for contractors to build relationships with NOCs to enter the MFM markets in their countries. The NOCs primarily need me6 ters for onshore, whereas the IOCs still 9 drive the deepwater and subsea technology arenas. 11 5 Major operators have stated a com11 mitment to fully embrace MFM technology for their offshore assets. For 7 example, Petroleo Brasileiro SA (PetroSource: Quest Offshore 2009 bras) would like to include an MFM on each of its subsea wells and trees.11 Statoil, a pioneer of MFM technology, is determined to maintain brownfield production off Norway at present levels by using MFMs to advance well testing so as to improve reser-

Oil & Gas Journal | Mar. 7, 2011

50 100 150 200 Reserves, billion boe

512 254

325 263 234 210 203 180 132

163 209 249 260 195 76 5 25 60 14 44 89 58 19 41 38 42 21 44 18

81 77 70 51 50 47 46 45 42 41 38 30 28 27 26 25 23

770 32 33 34 20 29 36 13 17 7 8 7 6 6 7 8 5 2 10 14 2 7 3 7 3 5

No. of wells/No. of projects

voir understanding.11 A recent study predicts that companies will deploy 1,000 additional subsea MFMs by 2015,12 which agrees with the

71

DRILLING & PRODUCTION

SUBSEA WELL WATER DEPTH

FIG. 9

0

Average water depth/subsea well, m

200 400 600 800 1,000 1,200 1,400 Before 1989

1989-03

1994-98

1999-03

2004-08

2009-13

After 2013

Start-up year

Source: Quest Offshore 2009

TIEBACK DISTANCE

FIG. 10

25

20

16

15

14 11

10 7

01 3 r2

09 -1 3 20

04

-9 8

03 20

Af te

Source: Quest Offshore 2009

94

19

89

-9 3

0

19 99 -2 0

5

-0 8

5

19

Average distance from subsea well to host facility, km

20

trends shown in Figs. 9 and 10 that highlight the industry’s increasing dependence on deepwater exploitation. More cost effective drilling, installation, and intervention, and proven subsea boosting will be paramount to enable new deepwater projects. The new developments with longer subsea-well tiebacks to host facilities and thence to market will need flow assurance, reliable communications and sufficient power supply between the wells and the host and the more cost effective subsea flowlines.

72

MFM costs The capital and operating costs for MFMs is much less than for conventional metering hardware, but occasionally projects also will need conventional hardware and MFMs will be an extra cost. In 2008, MFM prices were $50,00-400,000, depending on the performance specification,6 but operators have quoted meter prices of $1-4 million for subsea or special applications with corrosion-resistant materials and for greater flow rates. A subsea MFM in a tieback development 10 km from the host platform could reduce capital expenditures (capex) by an estimated 62% because of the elimination of test lines. The MFM also would improve production system management, increasing by 6-9% the amount of oil recovered.13 Studies indicate that operating expenses (opex) for an MFM is about 25% of the cost of the meter itself for the first year, then $10,000-40,000/year for both onshore and topsides applications.14 Fig. 11 qualitatively shows an optimum range of acceptable uncertainty, cost, and risk that an operator needs to assess for a given project. Operators want MFM technology to evolve to where they can afford to install a dedicated meter on each well, but this will not happen unless MFM prices fall into the $20,000-60,000 range, which is a long way from present MFM prices. Spending on subsea metering, processing, and boosting will increase as governments continue to encourage operators to improve recovery factors from historic norms. Such improved oil recovery initiatives increase the need for better power supplies, higher wet-gas compression efficiency, and improved reliability of subsea modules via preventative maintenance programs. The associated higher costs mean operators are reluctant to embrace these new technologies, which are unproven in their eyes, and there is resistance to carry out the necessary pilot studies. A forecast of increasing expenditure on subsea MFM is $212 million, $364 million, and $548 million for the periods 2003-07, 2008-12, and 2013-17, respectively (Fig 12).12

New market needs Future growth in the MFM market could include new meters for monitoring injected supercritical CO2 in carbon capture and underground sequestration projects. New meters also are required for geothermal exploitation, to monitor cycled fluids and recovered heat, and managed pressure drilling for real-time mud measurements when drilling through gas hydrates. Operators have ranked highly clamp-on meters in their wish list because these meters have a negligible effect on an existing facility’s layout and, for subsea applications, one could attach these meters onto seabed flowlines with remotely operated vehicles. Unfortunately, relatively few researchers have proposed such meters to date, given the technical challenge of measur-

Oil & Gas Journal | Mar. 7, 2011

DRILLING & PRODUCTION ing flow through the pipe wall, but it is hoped that future research will address this application. OGJ

MFM COST, ACCURACY RELATIONSHIP

FIG. 11

Losses, risks (wrong decisions) increase with increasing uncertainty

References

Market size, $million

Cost

1. Falcone, G., et al., Multiphase Optimum cost per Flow Metering: Principles and Applimeasurement cations, Elsevier, Developments of Petroleum Science series, October 2009. Measurement costs decrease with increasing uncertainty 2. State of the art multiphase flow metering, API Publication 2566, 1st 0 10 20 30 40 50 60 70 80 90 100 Edition, May 2004. Acceptable uncertainty, % Source: Reference 14 3. Mehdizadeh, P., “Wet gas, multiphase meters enable more deepwater production,” OGJ, May 23, 2005, p. 48. 4. Falcone, G., et al., “Multiphase flow metering: 4 years SUBSEA PROCESSING, BOOSTING FIG. 12 on,” 23rd North Sea Flow Measurement Workshop, Tons3,000 berg, Norway, Oct. 18-21, 2005. Boosting 5. Kratirov, V., et al., “Neftemer, a clamp clamp-on mulSeparation tiphase meter for cost cost-effective well monitoring,” NeftMultiphase metering 2,776 2,500 Wet-gas compression emer Ltd., Oct. 21, 2008. 6. “Experiences with Intellectual Property Rights (IPR),” 2,368 Roxar, Mar. 19, 2009. 2,000 7. “Roxar protects its industry-leading multiphase flow meter technologies in Norwegian Supreme Court Ruling,” Roxar news release, Nov. 29, 2005. ~250% 1,500 8. “A new regime for innovation and technology management in the E&P industry,” McKinsey Research Project, July 31, 2001. 9. “Framo Energy and Schlumberger sold 1200 multi1,000 phase flow meters worldwide,” Offshore Energy Today, Norway, http://www.offshoreenergytoday.com/, July 6, 2009. 671 10. Roxar ASA 2008/2013 subordinated PIK bond issue, 500 investor presentation, Apr. 24, 2008. 11. Vieugue, V., “The growth of multiphase meters and the key challenges they are addressing,” Russian Oil & Gas 0 Technologies, May 25, 2010. 2003-07 2008-12 2013-17 12. The subsea processing game-changer report 2008Source: Reference 12 2017, Douglas Westwood Ltd. April 2008. 13. The world deepwater report 2000-2004, Douglasfrom nursing to mature technology,” Hydrocarbon ProducWestwood Ltd., 2004. tion Accounting Workshop, Moscow, Dec. 16-17, 2008. 14. Sheers, L., “Multi-phase flow metering—on its way

The authors Gioia Falcone ([email protected]) is an assistant professor in petroleum engineering, a faculty member of the Ocean Drilling and Sustainable Earth Science partnership, and the Chevron faculty fellow at Texas A&M University. She has worked for ENI-Agip, Enterprise Oil, Shell, and Total. Falcone holds a Laurea in environmental/ petroleum engineering from Sapienza University Rome and an MSc in petroleum engineering and a PhD in chemical engineering from Imperial College London. She is an SPE member.

Oil & Gas Journal | Mar. 7, 2011

Bob Harrison is a consultant petroleum engineer, cofounder and director of Soluzioni Idrocarburi srl. He has worked in the oil and gas industry since 1979. After 20 years with independents British Gas and Enterprise Oil, he is a freelance adviser to many oil and gas companies around the globe. Harrison holds a BSc in electrical engineering from Manchester University, an MSc in petroleum engineering from Imperial College London, and an executive MBA from Cranfield University. He is an SPE member.

73

DRILLING & PRODUCTION

CLOSED-LOOP CIRCULATING— 4 (Conclusion)

Data benefit completion design, field development David Pavel, Brian Grayson

Improved prediction

Weatherford International Ltd. Houston

Downhole pressure data acquired via a closed-loop drilling system provide actionable pressure and flow information to guide the drilling team (Fig. 1). The same information provides data points for real-time pore pressure predictions that further enhance drilling safety and efficiency. To make pore pressure predictions, geopressure specialists examine a wide reange of data collected while drilling. The data fall into two primary groups: quantitative and qualitative. Quantitative data describe absolute, concrete physical information acquired by logging-while-drilling (LWD) tools such as sonic, gamma, and pressure-while-drilling (PWD) measurements. Qualitative measurements include background gas, connection gases, the size and quantity of cuttings and shavings coming over the shakers, and drilling measurements such as torque, rate of penetration, and mud density. Geopressure consultants use all this information to develop a predictive model of pore pressure—effectively a look ahead of the bit. The accuracy and speed of the data acquired from closed-loop instrumentation is an advantage in predrill prediction of pore pressures and a major advance in updating the predictive model in real time based on actual drilling conditions. Typically, pore pressure estimates depend on establishing a normal compaction trend line for a particular area. The trend line is a relatively straight-forward presentation of offset data but accuracy is important. The trend line is the basis for calculating actual pore pressure and if the trend line data are inaccurate, the pore pressure prediction is incorrect. Producing an accurate trend line is something of an art. In addition to accurate information, it requires a highly experienced person to combine all the quantitative and qualitative elements to make a correct prediction of the pore pressure regime.

Pore pressure and well optimization data from closed-loop circulating provide synergies for managing the production life of a well. This concluding part in a series of four articles discusses emerging technologies and applications that further leverage the capabilities of closed-loop systems. These advances extend benefits beyond drilling safety and efficiency into the realm of completion design, production enhancement, and field development. The three previous parts (OGJ, Dec. 6, 2010, p. 84; Jan. 3, 2011, p. 86; and Feb. 7, 2011, p. 84) covered the system fundamentals and manual and automated pressure management.

Closed-loop systems With a closed loop of incompressible drilling fluid, the driller can detect almost immediately microfluctuations in wellbore pressure and flow. The insights gained from this data drive a scalable, modular pressure-management system that ranges from fast, accurate kick and loss detection with conventional mud and blowout preventer procedures to automated process control. These capabilities offer a capability to see and manage influxes and losses before they become well-control events and thus enhance safety and efficiency. Aside from this, the industry only is beginning to understand and apply the full value of these real-time, downhole pressure data. Emerging technologies leveraged by a closed-loop drilling system and combined with its inherent data-acquisition capabilities foretell a new wave of while-drilling capabilities not only to optimize drilling but also to improve completion design, enhance production and field development, and ultimately extend a simple change in the rig circulation system to benefits that affect the life of the well.

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DRILLING & PRODUCTION

In conjunction with the rig operator, the closed-loop system allows a direct inference of pore pressure by ramping down the rig pumps to invite a minute influx. The operator can then use this point of divergence of inflow and outflow to determine pore pressure (Fig. 1).

Better, faster data The workflow for developing and refining pore pressure predictions has three stages. Predrill studies examine offset wells and historical experience to compare predictions with actual pressure points and other data to predict pore pressure for a particular area. On site geopressure services provide 24-hr well monitoring while drilling in order to modify the predrill plan with actual well data being collected from instrumentation and what is coming across the shale shakers. The process entails a real-time comparison of what is happening vs. the theoretical expectation. These on site predictions also benefit from wellsite information transfer standard markup language (WITSML) enabled data transfer that facilitates real-time participation by remote experts. For a recent project in Trinidad, Weatherford pore-pressure experts on multiple rigs collaborated with a colleague

Oil & Gas Journal | Mar. 7, 2011

in Port of Spain who provided an additional source of interpretation. An important distinction between conventional real-time pore prediction and managed pressure drilling (MPD) based operations is data quality. Conventional predictions rely on data acquired with a PWD instrument near the bit. But PWD data do not always provide accurate data points on downhole pressure anomalies. A closed-loop system allows for detection of bottomhole anomalies at the surface within seconds and in increments of only a few degrees of pressure. Consistency can also be an issue. A PWD instrument is unable to acquire data when the mud pumps are off, leaving a potential blind spot at a critical stage of pressure management. Conversely, a key characteristic of an MPD system is that maintaining backpressure while making a connection provides an excellent environment for monitoring wellbore pressure. Integrating the two complementary data sets and

75

DRILLING & PRODUCTION

IMPROVED DRILLING PERFORMANCE

FIG. 2

0 Closed-loop circulating

20 in.

1,000

1 2 3 4 5

Depth, ft

2,000

13 3/8 in.

9 5/8 in.

Conventional

Wellbore ballooning Losses - slow rate of penetration Stuck bottomhole assembly - fishing Losses - stuck pipe Plugged and abandoned, sidetrack, lose well

3,000

1

4,000

2

3 4

5,000

5

7 in.

6,000 0

20

40

60

80

100

120

140

160

180

200

220

Days

using them in unison provides a more comprehensive porepressure analysis. Once the well is drilled, the third step in the process is a post-drill analysis. The study examines the acquired data to determine absolute pressure values for the well. Those figures when compared to the on site prediction are used to update the model. This becomes a continual updating process through the repetition of predrill, drilling, and postdrill workflow phases. The integration of real-time pressure data with this process of refining the pressure profile further reduces uncertainty and enables drillers to better control mud weights, define casing points, and improve overall drilling efficiency and safety. The goal is to reduce uncertainty, not only at the current depth but ahead of the bit.

Integrating geomechanical input An important factor in the success of this pore-pressure prediction capability is its contribution to the larger picture of wellbore stability through integration with geomechanical data. Joining these disciplines to complete a fuller picture is important because borehole stability is not always a function of pore pressure. Often the geomechanics and tectonics regime causes the wellbore to collapse in an event that is unrelated to the pore pressure. A complete understanding of what is being dictated by the tectonic and geomechanical stresses and what is related to pore pressure is important for maintaining wellbore stability.

76

Weatherford approaches this integration with cross-discipline experts using proprietary software and specialized design tools. The design software analyzes the risks of wellbore instability, lost circulation, fracturing, sand production, and fault, fracture or bedding plane slippage. An important aspect of this analysis is the software’s ability to incorporate accurate pore-pressure data acquired during drilling operations. The inclusion of MPD methodologies and closed-loop technology in this integrated wellbore stability analysis provides a proactive means of managing pore pressure with significant gains in safety and efficiency. High-resolution, closed-loop measurements acquired in real time enable on site geopressure analysis with much more accurate information that ultimately results in better predictive models. For instance, the system’s coriolis meters (which measure mass flow past a fixed point per unit of time) are downstream of the choke manifold and have greater accuracy than conventional paddle or rolling flow meters—typically between a gallon and half a barrel, depending on circumstances. The accuracy and immediacy of these data provide a high degree of insight into what is happening downhole and improve the options for response with more flexibility than simply weighting up the mud system.

Well, field optimization The addition of new technology aimed at drilling optimization and reservoir characterization objectives further lever-

Oil & Gas Journal | Mar. 7, 2011

DRILLING & PRODUCTION ages the real-time pressure measurements obtained from a closed-loop system. The addition of a field-deployable X-ray fluorescence device enables a complete elemental break down of the rock cuttings. This data can provide insights into the rock’s geomechanical properties such as brittleness. The inclusion of gas chromatography instrumentation in an MPD system provides the ability not only to see a gas flux but also to characterize its composition. This capability enhances completion and production decisions as well as contributes to drilling safety and efficiency. The assessment takes place in real time while circulating the well. During drilling, surface quantitative gas detection is an important gas data point for kick detection and pressure management that has implications for improved efficiency. Previously available gas analysis on pressurized closed-loop circulation systems relied on conventional trap technology located behind the mud-gas separator where there is considerable alteration of the gas signature and the data have minimum correlation to actual gas volumes at the surface. Combined with inconsistencies in gas extraction methods and efficiencies, this has meant that one could derive little information from surface gas monitoring in these circumstances. With a patented semipermeable membrane gas-extraction process located directly behind the choke manifold and ahead of the mud gas separator, the sampling point becomes part of the enclosed system, which improves the removal of any potential surface gas loss. A series of North Sea wells illustrated the capabilities of the closed-loop system for identifying gas stringers vs. kick events without interrupting drilling operations. Over the course of the drilling program, increased confidence in the data resulted in more aggressive procedures to drill through the stringers. Addition of the gas chromatograph to the MPD system further enhanced the understanding of well behavior and conflicting data derived from traditional mud logging. While mud log data were inaccurate and initially led to confusion regarding the gas events, the chromatograph detected connection gases with much greater precision and accuracy. As a result, the operation experienced improved connection times and a reduced percolation time required before drilling ahead after each connection, saving the operator a considerable amount of time. In total, the combined system cut about 75 days from the drilling operation when compared to the previous well (Fig. 2). This instance illustrates the inaccuracy of standard mud logging and the insights achievable with high-fidelity data. Additional experience in the same drilling program led to increased reliance on the combined gas chromatograph and closed-loop data over the conventional logging system.

Oil & Gas Journal | Mar. 7, 2011

Fluid characterization In addition to identifying gas in the fluid system, the gas chromatograph also provides a very important capability for characterizing the composition of gas from the reservoir. While still developing as a component of the MPD with a closed-loop system, this technology points to a future of increasingly sophisticated capabilities while drilling. These capabilities extend far beyond drilling safety and efficiency to affect completion, production, and life of well considerations. Gas characterization while drilling indicates whether the formation is producing a dry gas, a condensate, mediumgravity oil, or heavy-gravity oil. This directly addresses the objective of drilling the well in the first place—the production value—through more accurate, informed design of completions and production infrastructure. It also has an immediate impact on reducing expenses. For example, in a recent non-MPD deepwater Gulf of Mexico well, a very tight pore pressure/fracture gradient window made deployment of wireline tools problematic. The ability to analyze the fluid type at the surface eliminated the need to acquire downhole fluid samples via wireline. The overall savings was about $3 million including the rig spread rate, nonproductive time, and service expenses. In addition to characterization and concentration of reservoir gases, another related technology being developed by Weatherford is isotope logging while drilling. This advance isotopic analyses of mud gases can reveal if a gas is bacterial or thermogenic in origin and also can characterize the thermal maturity of the rocks that generated a thermogenic gas. One can imagine numerous simple practical applications for such information. For example, if a gas is entirely bacterial in origin, then the likelihood of a downdip oil leg is small. If a gas is thermogenic or is mixed thermogenic and biogenic, however, then it may or may not have an associated oil leg.

Future As these technologies and synergies evolve, the benefits of closed-loop circulating take on new importance as a watershed improvement over conventional drilling operations. From its fundamental drilling safety and efficiency capabilities, the closed-loop system is evolving rapidly as it opens the door for advancements in optimizing the well and exploiting the reservoir. What began as a simple change in the fluids return system now promises new production opportunities over the life of the well. OGJ

77

PROCESSING

SPECIAL

REPORT

Capacity, complexity expansions characterize China’s refining industry past, present, future 78

Kang Wu East-West Center Honolulu

China currently has the world’s second largest refining sector behind the US. After decades of development, its refining industry has expanded spectacularly, with crude distillation capacity rising to 7.1 million b/d in 2005 from 2.1 million b/d in 1985 and has finally exceeded 11 million b/d since mid-2010.

Oil & Gas Journal | Mar. 7, 2011

Capacity; players China’s total refining capacity data are not all reliable. The main reason is the thorny issue of locally owned refineries, dubbed “teapot refineries.” This term is not entirely accurate, as some of these refineries are relatively large. While China’s CDU capacity has expanded substantially since the late 1990s, small refineries were also shut down through the government crackdown on locally owned refineries as well as adjustments made by Sinopec and CNPC/PetroChina. Since 1999, more than 1 million b/d of Sinopec, CNPC/ PetroChina, and locally owned refineries were shut down and scaled back. Since 2003, however, locally owned refineries have staged a comeback when oil markets have become tight with booming oil demand in China. As of today, total refining capacity of locally owned refineries—some of which have already formed alliances or joint ventures with state oil companies such as CNOOC or Sinochem—is esti-

Oil & Gas Journal | Mar. 7, 2011

PetroChina’s Lanzhou refinery has since 2008 raised its charge capacity to 320,000 b/d from 210,000 b/d and will likely expand further to 400,000 b/d in the 12th Year Plan. Photo from CNPC.

mated at more than 2.4 million b/d. The future of these small refineries is uncertain. Under the government’s 12th Five-Year Program (FYP), covering 2011-15, locally owned small refineries will be cracked down upon. If history is any guide, however, only a fraction of these locally owned small refineries will be shut down over the coming years. With all types of refineries included, China’s crude distillation capacity had reached 11.4 million b/d at the start of 2011. This is nearly twice as large as the capacity a decade earlier, as shown in Fig. 1, which also provides an overall

79

PROCESSING

CHINESE CDU CAPACITY*

FIG. 1

12.0 Sinopec CNPC/PetroChina 10.0

Million b/d

8.0

6.0

4.0

2.0

0.0

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

*As of start of each year. 2011 data are preliminary. Source: FACTS Global Energy

CHINESE COMPANIES’ CDU1

FIG. 2

Local 16.1% CNOOC & Sinochem2 7.0% CNPC/ PetroChina 31.7%

Sinopec 45.6% 1As

of Jan. 1. 2011. 2Includes companies’ joint-venture refineries with local companies. Total capacity is estimated at 11.4 million b/d.

picture of the total refining capacity where the major players are featured. Sinopec and CNPC/PetroChina are the dominant refiners in China and have been expanding their CDU capacity continuously. CNOOC has also entered the market with its 100% owned 240,000-b/d Huizhou refinery set up in 2009 in Guangdong Province. Several points are worth noting: • Sinopec has the largest capacity in China. At the start of 2011, Sinopec had nearly 5.2 million b/d of CDU capacity, accounting for 46% of the national total (Fig. 2). Sinopec’s refineries are located mainly in the middle and lower Yang-

80

tze regions, the south, and part of the north but with little presence elsewhere (Table 1). • CNPC/PetroChina has 3.6 million b/d of CDU capacity at present, 32% of the national total. CNPC/PetroChina’s assets are concentrated mainly in the northeast, the northwest, the west, the southwest, and part of the north. However, CNPC/PetroChina has been aggressive in penetrating areas under the Sinopec control. • Other national oil companies, CNOOC and Sinochem, also plan to expand their refining business. CNOOC started its wholly owned 240,000-b/d Huizhou refinery in Guangdong, which is designed to process low-sulfur crudes with high acids in 2009. Both CNOOC and Sinochem have joint ventures with local refineries. The total capacity of CNOOC, Sinochem, and their associated local refineries amounts to some 800,000 b/d at present, accounting for 7% of the nation’s total CDU capacity at the start of 2011. • As for locally owned refineries unrelated to any state oil company, their size as 2011 began we estimate at 1.9 million b/d, accounting for 16% of the national total. These refineries have some unique characteristics: 1. They are mainly located in areas around oil fields or near ports, with particularly high concentrations in provinces such as Shandong, Shaanxi, Guangdong, Liaoning, Hebei, and Henan. 2. Some of local refineries are not small at all. A good example is refineries owned by the local company Yanchang Group in Shaanxi Province, where their combined crude distillation capacity has exceeded 300,000 b/d. Yanchang is indeed the largest local company in China for both upstream

Oil & Gas Journal | Mar. 7, 2011

LAGCOE 2011

Fueling the

Global Quest

for Energy O C T O B E R 2 5 - 2 7, 2 0 11 L A FAY E T T E , L O U I S I A N A

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PROCESSING

CHINESE HYDROCRACKING CAPACITY*

FIG. 3

1,200 1,021

1,065

1,000 797

1,000 b/d

800 625 600

531 453 365

400

200

0

199

1998

225

231

237

1999

2000

2001

271

270

270

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

*As of Jan. 1, 2011; data for 2011 preliminary.

oil production and downstream oil refining. 3. Except for Yanchang Group, which has its own oil fields, crude supply to locally owned refineries is limited. 4. Most of these refineries rely on fuel oil as feedstock one way or another. 5. Facing the continuous cracking down of the government, many of these local refineries that are unwilling to be shut down have chosen to team up with one of the state oil companies or expand their size aggressively so as not to be “small” anymore.

higher than the Asia-Pacific’s average, and only slightly lower than the share in US (Table 2). The high cracking/CDU ratio is attributable to the country’s long history of using mainly domestic crudes, which are heavy and waxy with high pour points, as refinery feedstock. Of the cracking plants, however, fluid catalytic cracking and resid catalytic cracking (FCC/RCC) outweigh the others. As 2011 began, China had 2.6 million b/d of FCC/ RCC capacity, accounting for 50% of total cracking capacity. In addition to FCC/RCC, China’s coking and hydrocracking capacity are also large. Coking capacity has been exConfigurations panded at a rapid pace since 2004, reaching 1.3 million b/d China’s refining configuration has several distinguishing at the start of 2011. Hydrocracking capacity is even more characteristics. dramatic. Before 2004, China only had 270,000 b/d of hyFirst of all, it has a huge amount of cracking capacity. drocracking capacity. By early 2011, China’s hydrocracking In mid 2010, China’s ratio of combined cat cracking, hycapacity has topped 1 million b/d (Fig. 3). drocracking, visbreaking, coking, and thermal cracking to The second characteristic of China’s refinery configuraCDU was 47%. That is nearly twice the share in Japan, much tion is that its cat reforming capacity (nearly 800,000 b/d at the start of 2011, or 7% of CDU capacity) is still lower than the shares of cat reformers in Japan (17%) and the CHINESE REFINING, 2011 Table 1 US (20%). China’s reformer/CDU raSinopec CNPC/PetroChina CNOOC Local Total Region ––––––––––––––––––––––––– 1,000 b/d ––––––––––––––––––––––– Share, % tio is also less than the average ratio of 11% for the Asia-Pacific region. This Northeast –– 1,975 –– 229 2,204 19.3 North 1,762 254 400 1,090 3,506 30.7 difference is again partly due to ChiMid Yangtze 546 –– –– –– 546 4.8 Lower Yangtze 1,658 –– 160 33 1,851 16.2 na’s historical crude slate, of which the South 1,046 220 240 109 1,615 14.2 naphtha yield is low and insufficient Southwest –– 22 –– 22 44 0.4 Northwest 50 605 –– 376 1,031 9.0 to support a large reformer capacity. West 100 506 –– 3 609 5.3 –––––– –––––– –––––– –––––– –––––– –––––– Cat reforming capacity in China at Total 5,162 3,582 800 1,862 11,406 100.0 present, however, is already more than

82

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PROCESSING

CHINESE COMPANIES’ CRUDE RUNS 9 Others Sinopec CNPC/PetroChina

8

FIG. 4

Rapid growth     
 

  
 

8.5 million b/d

7

Million b/d

6 5

4.1 million b/d 4

2.2 million b/d 3 2 1 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010* *Preliminary data.

double the capacity of 316,000 b/d at the start of 2001. Thirdly, China has sharply increased its hydrotreating/ hydrorefining capacity in recent years to address the tightening specification for gas oil and to a lesser extent, gasoline. At the start of 2011, China had 3.2 million b/d of hydrotreating/hydrorefining capacity, a jump from less than 800,000 b/d at the start of 2001. One issue of caution is that since Chinese data do not separate treating of gasoline, kerosine, and diesel/middle distillates, the capacity number reported here appears to be inflated in comparison with hydrotreating capacities of other countries. Fourthly, China’s capability for handling sour crudes has increased substantially since the mid-1990s, especially for Sinopec. China has increased its capability to handle heavy

oil as well as fuel oil as feedstock. This is an area that is penetrated deeply by locally owned refineries, new ventures of state oil companies other than Sinopec and CNPC/PetroChina, such as CNOOC and Sinochem, and to a lesser extent, by CNPC/PetroChina itself whose crudes produced in aging fields in the northeast have become increasingly heavy. Finally, the utilization rate of China’s refining capacity was historically low but has increased since the early 2000s. Before 1986, the government’s policy of maximizing oil exports reduced the availability of feedstock to domestic refineries. Although more crude oil was diverted to domestic refineries thereafter, declining crude production, rapid expansion of refining capacity, and continued existence of small and very small refineries had kept utilization rates low during most of the 1990s. The situation has improved since the 2000s, CHINESE CRACKING CAPACITIES, JULY 2010 Table 2 more on which later. China Japan India Asia-Pacific US1 China’s capability and experience –––––––––––––––––––––––––– 1,000 b/d –––––––––––––––––––––––– in handing sour crudes deserve a speCDU 10,984 4,454 3,752 28,771 17,763 cial note. With some exceptions, such FCC/RCC 2,598 905 734 5,395 5,663 Hydrocracking 1,021 146 332 2,063 1,680 as crudes from Oman, Yemen, part of VBR/TC2 260 –– 174 806 34 Coking 1,321 119 387 1,945 2,419 Abu Dhabi, as well as Arab Extra Light Cat reforming 789 752 282 3,055 3,583 HDT, hydrorefining3 3,168 2,573 1,264 9,319 13,929 from Saudi Arabia, Middle East crudes all have high sulfur content, while –––––––––––––––––––––––––––––– % ––––––––––––––––––––––––––– FCC/RCC-to-CDU ratio 24 20 20 19 32 many Chinese refineries, until the midHDC-to-CDU ratio 9 3 9 7 9 Cracking-to-CDU ratio4 47 26 43 35 55 1990s, were unable to process such Reforming-to-CDU ratio 7 17 8 11 20 crudes. China has since moved to raise HDT/HDR-to-CDU ratio 29 58 34 32 78 its sour-crude handling capability. Start of 2010 data. VBR = visbreaking; TC = thermal cracking. HDT = hydrotreating. In China, it includes gasoline, kerosine, and middle distillate hydrorefining. Cracking includes all of those listed in this table. In the mid-1990s, in anticipation of Source: FACTS Global Energy and Oil & Gas Journal (US data) rising Middle East oil imports, Sinopec 1

2

3

4

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Oil & Gas Journal | Mar. 7, 2011

PROCESSING

CHINESE REFINERY UTILIZATION

FIG. 5

90 86% 85

84% 82%

80 Rate, %

80%

80%

76%

75%

75 71%

71%

2000

2001

76% 74%

70

65

60

64%

1998

65%

1999

2002

2003

2004

2005

2006

2007

2008

2009

2010*

*Preliminary data.

started revamping, upgrading, and expanding its refineries to add sour-crude processing capabilities. These efforts have produced some notable results. At the start of 2011, Sinopec and CNPC/PetroChina together had at least 3.3 million b/d of processing capacity for imported sour crudes. This also means China has about 7 million b/d of refining capacity that can process only sweet crudes, a fact that severely limits China’s choice of imported crudes and prompts China to seek sweet crudes from sources such as Africa and Latin America.

Throughput; utilization Crude runs have been growing vigorously but also unevenly from year to year. For instance, the growth of crude runs reached more than 750,000 b/d in 2004, but it was negative in 1994 and 1998, or as little as 31,000 b/d in 2001. In 2010, crude runs reached 8.5 million b/d, up from 2.2 million b/d in 1990 and 4.1 million b/d in 2000 (Fig. 4). In other words, in a decade China’s refining crude runs quadrupled. In fact, 2010 was a year of historical significance in which the increment of 1 million b/d in crude runs was the highest ever for the country. With stagnated domestic production, accompanying the fast growth of refining crude runs are rapidly rising crude imports. In 2010, China imported 4.8 million b/d of crude oil, 710,000 b/d higher than imports of 2009, which set another record for growth. Compared to 2000, China’s crude imports in 2010 were more than two and half times higher. Of the 4.8 million b/d of crude oil imports in 2010 by China, African supplies accounted for 30%, or 1.4 million b/d. This

Oil & Gas Journal | Mar. 7, 2011

reflects the strong appetite of Chinese refineries for heavy sweet crudes. Based on the national crude runs and refining capacity reported here, Fig. 5 shows the changing utilization rate for Chinese refineries. Both overestimation and underestimation may occur in the numbers. On the one hand, because certain small refineries are not included in the capacity, the calculated rate might have been slightly inflated. On the other hand, the national average rates tend to be underestimated due to the presence of large capacity held by locally owned refineries, which lack access to crude supply. Because of the rise in refining capacity from vigorous expansion of both CNPC and Sinopec, plus the flourishing of small refineries, China’s overall refining utilization rate, defined as the share of throughput in total capacity, was low in the 1990s. In 1998, the overall refinery utilization rate was only 64%, thanks to stagnation in the refining industry. The situation has since improved, however. In 2010, the overall utilization rate reached 76%, down from the recent high of 86% in 2004 but up from 73% in 2009. Among different players, the utilization rate was more than 88% for Sinopec’s and CNPC/PetroChina’s refineries but less than 50% for the rest.

Growth 2011 is the first year of China’s 12th FYP. The preliminary plan shows that China is expected to add some 2 million b/d of new refining capacity during the 5 years ending in 2015. We believe China will exceed this target, which means

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CHINA’S CRUDE OIL BALANCE

FIG. 6

15

10

Million b/d

5

0

–5 Nonrefinery crude1 –10

Refining runs Domestic output Net imports

–15 2005

2006

2007

2008

22010

2009

2011

2012

2015

2020

1

Includes direct use of crude oil, field losses, and inventory variations. 22010 data are estimates; 2011-20 data are projections.

a higher growth in capacity is likely. Despite the fact that China may be long in refining capacity, the Chinese government, led by the National Development Reform Commission, is determined that expansion is needed to keep up with the product demand growth. Achieving self-sufficiency of certain petroleum products, such as diesel, means that China is set to continue the structural imbalances among different refined products, in which some are in surplus and some are short. China’s refining expansions over the next 5 years are led by Sinopec and CNPC/PetroChina, although CNOOC and Sinochem are also trying very hard to expand their bases. Sinopec’s refining expansion plans are in part associated with its continuous drive to build more sour-crude handling capability. By the end of 2015, China is likely to have at least 5.3 million b/d of sour crude handling capacity, where twothirds will be owned by Sinopec. More specifically, Sinopec’s expansion is likely to include the following major projects by 2015: • Sinopec will expand the Chang refinery to 160,000 b/d at the end of 2011 and 200,000 b/d by 2015 from 100,000 b/d at present. • Yangzi refinery will be expanded to 250,000 b/d from 160,000 b/d during the 12th FYP. • Total capacity of the Maoming refinery will be expanded to 510,000 b/d by 2012 from 270,000 b/d at present through completion of the new refinery with the size of 240,000 b/d. • Beihai refinery will be a grassroots refinery of 200,000 b/d on the basis of the existing 12,000-b/d plant, located at

86

a new site. The project will be completed by the end of 2011. • The Sinopec/KPC Zhanjiang refinery is a 300,000-b/d grassroots refinery through a joint venture between KPC and Sinopec. We expect this project to be completed by 2015. • Lanzhou refinery: This 320,000-b/d refinery will likely expand to 400,000 b/d during the 12th Year Plan. • Caofeidian refinery is a new 200,000-b/d refinery and is likely to be built by 2015. Despite its concentration in the northeast, the northwest, and the west, CNPC/PetroChina is taking advantage of its secured crude oil supply (particularly through its overseas investment projects or by building international oil pipelines such as those from Russia and Myanmar) to expand into the southwest as well as areas that considered Sinopec’s turf. Over the next 5 years, CNPC/PetroChina’s refining projects include mainly: • Qinzhou refinery: After its completion in late 2010, this 200,000-b/d refinery is likely to be expanded by another 200,000 b/d by 2015. • Lanzhou refinery: This 320,000-b/d refinery is likely to be expanded to 400,000 b/d during the 12th FYP. • Pengzhou refinery: By end 2011, PetroChina is also likely to start its new 200,000 b/d Pengzhou refinery in Sichuan, although delay to 2012 is also likely. • Huludao refinery: This 200,000 b/d refinery with a local partner is likely to be completed by 2014. • PetroChina/Rosneft Tianjin refinery: Construction for this 300,000 b/d refinery started in 2010, and it is expected to be completed by 2015. • PetroChina/PDVSA Jieyang refinery: This joint-venture

Oil & Gas Journal | Mar. 7, 2011

PROCESSING refinery of 400,000 b/d using Venezuelan crudes is likely to be up and running by 2015. • PetroChina is likely to add a 200,000-b/d refinery in Yunnan by 2015. As mentioned, beyond CNPC/PetroChina and Sinopec, both CNOOC and Sinochem are active in pursuing their refining ambitions and have acquired local refineries through joint ventures. As for CNOOC’s 240,000-b/d Huizhou refinery, the expansion of it by another 200,000 b/d has been delayed but it may be completed by 2015. Sinochem is determined to have its own 240,000-b/d refinery in Quanzhou and strives to complete the project by 2014. These two state oil companies continue to target local refineries for further expansions. Beyond 2015, China is set to build more refineries and have more expansions of existing ones, with huge implications for the country’s oil imports. On the crude side, China is set to become a larger importer. We expect China’s crude

imports to reach 7.3 million b/d in 2015 and 9.5 million b/d in 2020 (Fig. 6). For refined products, the situation is more complicated. China may overbuild the refining sector. If that happens, China is likely to be a sizable exporter of gasoline and diesel although its deficits of fuel oil and naphtha will continue.

The author Kang Wu ([email protected]) is a senior fellow at the East-West Center, Honolulu, and conducts research on energy policies, security, demand, supply, trade, and market developments, as well as energy-economic links, oil and gas issues, and the impact of fossil energy use on the environment. He holds a PhD in economics from the University of Hawaii.


 
 
      
 



    
        

  
 

   
 
  
   
 
  


    


 
  

 


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SPECIAL

REPORT EU REFINING—3 (Conclusion)

Capacity upgrading to cut gasoline exports by 2030 This is the third and final article in a series that presents elements of the European Commission’s “Commission Staff Working Paper: On Refining and the Supply of Petroleum Products in the EU.” This background working paper, presenting an overview and analysis of problems facing European refiners, was released at the same time the EC adopted a “Communication ‘Energy infrastructure priorities for 2020 and beyond—A Blueprint for an integrated European energy network,’” on Nov. 17, 2010. In that document, the commission defines EU “priority corridors” for the transportation of electricity, gas, and oil (OGJ Online, Nov. 18, 2010).

The first article in this Oil & Gas Journal series (OGJ, Jan. 3, 2001, p. 90) examined demand issues as they have and will affect European refining. The second article (OGJ, Feb. 7, 2011, p. 96) presented the working paper’s views on supply issues and the economic viability of the European refining industry. This final article presents the effects of future demand developments on European refining by 2030. Following is a summary of those effects: • EU refining capacity upgrading will lead to significant reductions in exports of (excess supply of) gasoline by 2030, while the import dependence of the EU in gas oil and diesel will continue to increase by 2030.

EU PETROLEUM PRODUCTS DEMAND PROJECTIONS*

FIG. 1

105 Light distillates BL Light distillates REF

100

Middle distillates BL Middle distillates REF

95

Heavy distillates REF

90

Heavy distillates BL Total demand BL

85

Total demand REF

80 75 70 65 60

2005

2010

2015

2020

2025

2030

*PRIMES 2009 Baseline (BL) and Reference (REF) scenarios.

88

Oil & Gas Journal | Mar. 7, 2011

PROCESSING

PRIMES REFERENCE SCENARIO: EU PRODUCT DEMAND PROJECTIONS

FIG. 2

100 90

19

16

16

15

16

16

52

55

56

57

57

56

29

29

28

28

28

28

2010

2015

2020

2025

2030

80 70 60 %

50 40 30 20 10 0

2005

Light distillates

• Depending on assumptions about the development of the crude diet in Europe 2005-30 and taking into account adopted and implemented EU policies, investments required to upgrade European refining capacities in that period could amount to between €17.8 billion and €29.3 billion, of which between €3.3 and €11.7 billion alone will account for future marine sulfur fuel specification changes to be transposed into EU regulation by the end of 2010. These figures result from a scenario of increasing import dependence in gas oil and diesel. • It is estimated that the amount of investments that the refining industry in Europe has already committed to spending (“firm projects”) 2010-20 is on the order of €13.3 billion. • In spite of projections of declining demand for fossil fuels, processing intensity in refining will increase as a result of more stringent product specifications, in particular as a result of new IMO changes. One possible consequence is that refinery CO2 emissions will increase 2005-30, by around 6% (and increasing by 12% 2005-20), mainly as a direct result of the needs for hydrogen in refinery units geared towards producing higher proportions of new International Maritime Organization-compliant fuel. • Significant declines in projected EU demand for transport gasoline by 2030 according to PRIMES (of 20.7% in the Reference scenario) point to the need for gasoline-focused

Oil & Gas Journal | Mar. 7, 2011

Middle distillates

Heavy distillates

refinery plant restructuring, with necessary capacity reductions by up to a third, depending on the type of unit.

Adopted policies This section provides a quantitative assessment of the medium-term impacts of expected demand developments in EU petroleum products on the EU refining industry. It presents the results of running the PRIMES 2009 Baseline (“business as usual”) and PRIMES 2009 Reference (“policy”) scenario petroleum product demand projections on the OURSE refining module of the POLES energy model1 in order to estimate the impacts of evolving demand in terms of: 1. Capacity requirements and capital investment requirements for additional process capacity or upgrade of existing capacity. 2. Production levels. 3. Levels of CO2 emissions. 4. EU import and export levels of petroleum products. PRIMES projections were also run separately in the Concawe refining model,2 and results have also been reported below, for comparison with OURSE outputs. The PRIMES 2009 Baseline demand projections result from developments in the assumed absence of new policies beyond those implemented by April 2009. It is not a forecast of likely developments, given that policies will need to develop. Therefore, there is no assumption in the Baseline

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OURSE MODEL INVESTMENTS: E+3, 2005-30*

Case B assumes no changes in maximum permitted sulfur content in ma140 rine fuel beyond 2012, i.e., ECAs remain at 1% and the rest of the world remains at 3.5%. Note that in compar3.7 120 4.2 ing a case including future IMO chang5.3 1.5 es to one excluding them, in the latter 5.4 5.1 100 6.6 case the changes to 1% and 3.5%, respectively, for the ECAs and the rest of 80 the world have been taken for granted. As was explained in Part 2 of this series (OGJ, Feb. 7, 2011, p. 96; “Up60 83.6 87.9 grade investments”), this is because it is generally regarded that such chang40 es will pose no major problems for refiners—blends can simply be modified 20 to redistribute the higher sulfur components—while the real challenge will 11.6 11.6 be the changes to 0.1% sulfur content 0 Case B and 0.5%, respectively, for the ECAs Case A and the rest of the world, as these will likely require conversion of bunker fuOther Coker Reforming unit and isom. Hydrocracking els to diesel.4 This will require investHDT vacuum gas oil HDS residuals HDS gas oil ment in desulfurization or conversion capacities. *Reference demand projections. HDT = hydrotreating; HDS = hydrodesulfurization; isom. = isomerization. The context for the impacts on the EU refining industry that are reported below in terms of key additional outthat national or overall greenhouse gas or renewable energy puts from the OURSE model, is as follows: source (RES) targets are achieved, nor of non-ETS (EU Emis• Production of petroleum products: The production levsion Trading System) targets; CO2 emissions and RES shares els of EU refineries during 2005-30 will fall by 14%, similar are modeling results. to the projected fall in demand in the PRIMES Reference sceIn contrast, the PRIMES Reference scenario reveals the nario over that period.5 effects of agreed policies, including the achievement of le• Trade flows: Russia will have sufficient refinery cagally binding targets on 20% RES and 20% GHG reduction pacities in middle distillates during the projection period to for 2020. (More details on both the PRIMES 2009 Baseline continue to supply the EU, while North America will not and Reference scenarios can be found in Annex 3: http:// continue to absorb the excess gasoline the EU is projected to ec.europa.eu/energy/infrastructure/strategy/2020_en.htm.) produce; new markets will have to be found. The impacts of the PRIMES demand projections are reAccording to the OURSE model, by 2030 the EU net exported with a variation on the assumptions of the refining ports of gasoline will total 19.4 million tonnes of oil equivamodel with regard to future marine sulfur fuel specifications lent (toe), equivalent to 18% of EU gasoline production for that are expected to be transposed into EU regulation. The that year, while EU net imports of gas oil and diesel will be impacts of such changes are reported separately due to the 37.7 million toe, equivalent to 15% of EU diesel and gas oil important investments that they will require by EU refining demand in 2030. industry if it decides to produce shipping fuel that meets the In comparison, OURSE numbers for 2005 show that EU new specifications. net exports of gasoline amounted to 32.4 million toe, equivaSpecifically, the variations in fuel specification changes lent to 21.5% of its gasoline production in 2005, and gas oil that are modeled here are as follows: and diesel net imports were equivalent to 28.2 million toe, Case A assumes a change in maximum permitted sulfur amounting to 9.7% of EU gas oil and diesel demand in that content in marine fuel for Emission Controlled Areas (ECAs) year.6 in the EU (the Baltic Sea, the North Sea, and the English In short, therefore, the OURSE model projects resulting Channel) from 1.5% to 1% by 2010 and then down to 0.1% trade flows for the economically optimal capacity required to by 2015; and for the rest of the world, from 4.5% to 3.5% in satisfy the PRIMES reference demand. Those flows amount 2012 and then down to 0.5% from 2020.3 to falling gasoline exports and increasing gas oil and diesel Million tpy

FIG. 3

90

Oil & Gas Journal | Mar. 7, 2011

PROCESSING imports by 2030 compared with 2005. NECESSARY CHANGES IN CAPACITY USE, 2005-30* FIG. 4 A key assumption of the OURSE model regards the evolution of the EU Case A 0.852 crude diet. Globally, it assumes that by 0.8048 Case B 2030, the API gravity of conventional 0.6040 crude oil will have slowly decreased, 0.531 0.531 0.508 0.477 while sulfur content should increase 0.4032 slightly. It is expected, however, that 0.221 this will be balanced by an increasing 0.2024 share of condensates used in refinery –0.16 –0.323 –0.126 0.0016 production and the availability of up–0.078 graded crude oil from extra-heavy oil. –0.144 –0.1992 –0.241 In the case of the EU, the OURSE –0.319 –0.4 model assumes relative stability 2005HDS HCK Topping Cat. FCC Coker HDS gas oil 78% conv. residuals reformer 30, both in terms of the API gravity and sulfur content of refineries’ sup*On the basis of the Reference demand; FCC = fluid catalytic cracking; HCK = hydrocracking. ply because along with an increasing share of condensates is included the assumption of an expected doubling of sel and gasoline in favor of the former. the share of high medium distillate-yielding crudes.7 Note in addition that the OURSE model treats the EU27, It is important to note that in both scenarios, the proporSwitzerland, Norway, and Turkey together as forming the tion of middle distillates in total demand increases quite sigregion of Europe, broken down into two zones: Z3 (Northnificantly 2005-10, after which it remains fairly stable. ern Europe) and Z4 (Southern Europe). Impacts are therefore reported for the EU27 plus these three countries. While it Effects on investments cannot be easily estimated what amount of investments and According to the OURSE model, the impacts of the Reference CO2 emissions are EU27 specific, it is useful to note that the scenario in terms of the investments required to upgrade Institut français du pétrole (IFP) simulates EU27 demand EU+3 refining capacities amount to €17.8 billion 2005-30, of into the OURSE model by using topping unit8 capacity prowhich €3.3 billion account for IMO changes.10 portions. This results primarily from investments in extra gas oil By that measure, Norway and Switzerland represent 4% hydrodesulfurization units that will be in short supply on of Z3 capacity and Turkey, 12.5% of Z4 capacity. the basis of both the Baseline and Reference scenarios’ proAs Fig. 1 reveals, whether “business as usual” or “policy” jections. Fig. 2 shows the volumes that will be needed to targets beyond April 2009 are assumed makes little differmeet demand in the Reference scenario, although there is litence in terms of the demand projections in petroleum prodtle difference between the two scenarios. (Baseline demand ucts for the EU. The general trends in both cases can be will require slightly more investments in all of the same summarized: types of units, excepting cokers.11) • A general fall in the level of consumption of petroleum Note that the new IMO regulations will require 14.3 milproducts. lion tonnes/year of extra capacity by 2030 (the difference • The continued gradual erosion of demand for high-sulbetween Case A and Case B in Fig. 3), mainly in terms of fur residual inland fuel and marine bunkers (which make up extra hydrocracking12 units (amounting to 6.6 million tpy), heavy distillates). hydrodesulfurization of residuals (amounting to 5.4 million • An initial increase in demand for middle distillates (intpy), and hydrotreating of vacuum gas oil13 (4.2 million tpy). cluding gas oil, heating oil, kerosine, and jet fuel) followed Thus, the levels of investments required in order to supby an eventual and overall fall, mainly resulting from a deply initially rising (but over the whole period, falling) levels crease in road diesel demand due to regulation to restrict of middle distillates are considerable, and even with such CO2 emissions from cars becoming effective9 as the autoinvestments, imports are likely to rise further. One variamobile fleet is gradually renewed and due also to the spill tion that has been undertaken on the OURSE model runs of over effects from more efficient car engines to those of trucks the PRIMES Reference demand projections is with regard to (truck diesel consumption stabilizes 2020-30). crude oil supply projections. • A continued fall in demand for gasoline (included in As has been highlighted, the OURSE model projections light distillates, along with naphtha). Note that the PRIMES assume a balanced crude diet 2005-30 in Europe, which demand projections do not assume a change in the current along with an increasing share of condensates relies on a taxation regime in the EU, which differentiates between diedoubling of the share of high medium distillate yielding

Oil & Gas Journal | Mar. 7, 2011

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OURSE MODEL CO2 EMISSIONS BY 2030*

FIG. 5

120 100 Millions of tonnes

23.4

19.8

80 60 40

77.3

78

20 0

Case A Processing units

Case B Hydrogen production

*On the basis of the Reference demand projections.

crudes. Simply keeping the share of such crudes constant during that period (with the consequence of an important increase in the overall sulfur content) in the OURSE model, however, results in total investments 2005-30 of €29.7 billion of which €9.3 billion alone account for IMO changes. Running the PRIMES Reference scenario projections on the Concawe model while keeping trade levels 2005-30 constant would require €29.2 billion of investments in that period, of which €13.3 billion would have to be spent due to the new IMO changes. The same demand projections combined imports of gas oil and diesel 2005-20 to 40 million tpy from 20 million tpy (and staying at that level every year thereafter to 2030) will, however, require total investments of €25.8 billion 2005-30, of which IMO changes alone amount to €11.7 billion. Concawe estimates that the amount of investments that the refining industry in Europe has already committed to spending (or what it calls “firm projects”) 2010-20 is on the order of €13.3 billion. Note in addition that according to the Concawe model results, cumulative refining investments 2005-20 are higher than for 2005-30, a reflection of falling demand in petroleum products according to the PRIMES demand projections. This highlights a particular dilemma faced by refiners of investing early in capacity that will only be partially utilized later in the non too-distant future.

Utilization of refining units According to OURSE model results, in terms of changes in refining capacity from 2005 levels by 2030 (Fig. 4), whether or not new IMO regulations are assumed, similar reductions in the use of simple refining capacity can be expected to occur, while similar increases in the use of cokers and hydrodesulfurization units should result. In addition, assuming IMO changes will require a large increase in the use of residual hydrodesulfurization and some 22% increase in the use of hydrocracking units.

92

Note again that there is very little difference between the PRIMES Baseline and Reference cases in terms of the demand projections in petroleum products for the EU.

CO2 emissions

Whether or not IMO changes are assumed in the OURSE model makes little difference in terms of CO2 emissions from EU+3 refineries by 2030, which are projected to emit around 100 million tonnes of CO2 (Fig. 5). This compares with 118.5 million tonnes of CO2 in 2005,14 the fall in emissions resulting from falling production of petroleum products. Note however that in both cases, a growing proportion of the CO2 emissions will come from the needs for hydrogen in refineries (hydrocracking units use hydrogen to upgrade heavier fractions into lighter products while hydrodesulfurization units use hydrogen to chemically remove the sulfur), so that by 2030, 20% of all CO2 emissions from EU refineries will come from hydrogen production, compared with only 14% in 2005. Specifically, CO2 emissions due to the IMO changes amount to 3.3 million tonnes of CO2 in the Reference case, essentially as a result of the extra emissions from hydrogen use. Changing the crude-supply assumptions towards an increase in the sulfur content of the EU crude diet (by keeping the proportion of high middle distillate-yielding crudes, as explained previously) would, however, result in a level of CO2 emissions of 110.3 million tonnes in 2030, 5.6 million tonnes as a direct result of new IMO changes. In contrast, the Concawe refining model’s results reveal that in spite of declining market demand for fossil fuels, processing intensity in refining increases as a result of more stringent product specifications, particularly in the case including IMO changes, and consequently that refinery CO2 emissions will increase somewhat 2005-30, by around 6% (and increasing by 12% 2005-20). OGJ

Notes 1. The POLES (Prospective Outlook for the Long-term Energy System) model simulates the energy demand and supply for 32 countries and 18 world regions. Further details on the OURSE refining module of POLES can be found in an annex to the Working Paper (http://ec.europa.eu/energy/ infrastructure/strategy/2020_en.htm). 2. Concawe is the oil companies’ European association for environment, health and safety in refining and distribution. The Concawe EU refining model simulates the EU (including Switzerland and Norway) refining system. More information on the model can be found on the internet site of the association (www.concawe.be). 3. The Concawe EU refining model makes the same assumptions as OURSE with regard to the timing and nature of the fuel specification changes in the ECAs, while for the

Oil & Gas Journal | Mar. 7, 2011

PROCESSING rest of the world it assumes that the change to 3.5% from 4.5% already occurs in 2010. 4. Current technology cannot achieve reductions in the sulfur content of residues to 0.1% unless a very low sulfur feed is used. Even if it were possible, it is questionable whether refiners would not prefer to focus instead on converting residual fuel to lighter, more valuable fuels, and decide to stop supplying the bunker market altogether. 5. The Concawe model’s supply growth projections reveal an 11% drop in the 2005-30 period. 6. The Concawe European refining model is run with fixed imports and exports outside the EU and therefore keeps the trade situation constant over time. The sensitivity of the model to trade flows was, however, tested by changing the assumptions made with respect to the volumes of exports and imports to reflect the trade situation projected by the OURSE model. 7. The Concawe model assumes no change in crude mix over time. 8. Topping refining is the simplest configuration of refining and a part of the distillation process. It thus involves no treating or conversion. 9. The CO2 from automobile regulations included in the PRIMES Baseline and Reference scenarios require strong reductions in the average fuel consumption of new cars. Binding targets are 130 g/km by 2010 and 115 g/ km by 2020. (It should be noted that the regulation contains a provisional goal of 95 g/km for 2020.) 10. Note that the differences between demand projections under the Baseline scenario and the Reference scenario are not significant enough to make any notable difference in terms of investments according to the OURSE model outputs. 11. Delayed coking units are a type of deep conversion unit, which are the most sophisticated refining units. Cokers crack residual oil hydrocarbon molecules into coker gas oil and petroleum coke.

Oil & Gas Journal | Mar. 7, 2011

12. The process whereby hydrocarbon molecules of petroleum are mainly broken into jet fuel and diesel oil components by the addition of hydrogen under high pressure in the presence of a catalyst. 13. Hydrotreating of vacuum gas oil is a process that removes sulfur and

nitrogen from vacuum gas oil, which is the product recovered from vacuum distillation. 14. IFP estimations of EU refineries’ CO2 emissions. In comparison to 118.5 million tonnes of CO2 emitted in 2005. Note that this does not include emissions related to petrochemical activities.

NELSON-FARRAR COST INDEXES Refinery construction (1946 basis) (Explained in OGJ, Dec. 30, 1985, p. 145, and at www.pennenergy.com/index/research-and_data/oil-and_gas/StatisticDefinitions.html; click “Nelson-Farrar Cost Indices”)

1962 Pumps, compressors, etc. 222.5 Electrical machinery 189.5 Internal-comb. engines 183.4 Instruments 214.8 Heat exchangers 183.6 Misc. equip. average 198.8 Materials component 205.9 Labor component 258.8 Refinery (Inflation) Index 237.6

1980

2007

2008

2009

Nov. 2009

Oct. 2010

Nov. 2010

777.3

1,844.4

1,949.8

2,011.4

2,010.9

2,035.5

2,039.3

394.7

517.3

515.6

515.5

516.4

511.4

509.6

512.6

974.6

990.9

1,023.0

1,025.0

1,025.6

1,014.3

587.3

1,267.9

1,342.1

1,394.8

1,408.4

1,434.7

1,447.8

618.7

1,342.2

1,354.6

1,253.8

1,253.8

1,103.5

1,103.5

578.1

1,189.3

1,230.6

1,239.7

1,242.9

1,222.1

1,222.9

629.2

1,364.8

1,572.0

1,324.8

1,354.7

1,481.9

1,481.1

951.9

2,601.4

2,704.3

2,813.0

2,835.1

2,949.0

2,960.4

822.8

2,106.7

2,251.4

2,217.7

2,242.9

2,362.2

2,368.6

Refinery operating (1956 basis) (Explained in OGJ, Dec. 30, 1985, p. 145, and at www.pennenergy.com/index/research-and_data/oil-and_gas/StatisticDefinitions.html; click “Nelson-Farrar Cost Indices”)

1962

2009

Nov. 2009

Oct. 2010

1,951.3

978.5

1,170.4

1,088.8

994.8

237.9

264.5

277.2

295.6

289.6

1,042.8

1,092.2

1,177.1

1,229.6

1,299.4

1,313.9

483.4

460.8

445.2

443.6

439.6

453.7

1980

2007

2008

100.9

810.5

1,530.7

93.9

200.5

215.8

123.9

439.9

131.8 Invest., maint., etc. 121.7 Chemical costs 96.7

226.3

Nov. 2010

Fuel cost Labor cost Wages Productivity

Operating indexes Refinery 103.7 Process units* 103.6

324.8

777.4

830.8

812.4

821.6

859.0

861.3

229.2

385.9

472.5

406.2

424.8

449.0

462.0

312.7

596.5

674.2

582.6

610.4

628.7

620.1

457.5

872.6

1,045.1

706.1

780.3

770.4

736.5

*Add separate index(es) for chemicals, if any are used. See current Quarterly Costimating in first issues for January, April, July, and October. These indexes are published in the first of each month. They are compiled by Gary Farrar, OGJ Contributing Editor. Indexes of selected individual items of equipment and materials are also published on the Costimating page in first issues for January, April, July, and October.

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PROCESSING

Ethylene markets return to normal Petral Worldwide Inc. Houston

After the turmoil in operations and pricing during first-half 2010, US olefins markets were nearly normal during second-half 2010. Ethylene producers pushed ethane demand to record highs during third-quarter 2010. Demand for ethane declined in fourth quarter due to turnarounds and unplanned outages demand but remained strong by historic standards. Midstream infrastructure constraints (particularly raw mix pipeline capacity) will limit further expansion of ethane supply for the next few years, but ethane production will be sufficient to support demand at 900,000-920,000 b/d during 2011. Despite record high demand, ethane prices in North America remained favorable relative to all other major ethylene feedstocks. In the Gulf Coast propylene market, PL Propylene LLC completed construction on its propane dehydrogenation plant during third-quarter 2010 and began start-up during fourth quarter. This plant has nameplate capacity for polymer-grade propylene of 1.1 billion lb/year. Although output rates from this plant were well below capacity during fourthquarter 2010, the third source of polymer-grade propylene production began to affect price-economic relationships in the Gulf Coast propylene market during third and fourth quarters 2010.

2009, but demand in fourth-quarter 2010 was only 27,000 b/d higher than in fourth-quarter 2009. Despite the year-to-year increase during third and fourth quarters 2010, demand for fresh feed remained 57,000 b/d (3.5%) lower than prerecession levels of first-half 2008. According to Petral survey results, demand for LPG feeds (ethane, propane, and normal butane) averaged 1.32 million b/d during third-quarter 2010 but declined to 1.24 million b/d during fourth-quarter 2010. Demand for LPG feed in third-quarter 2010 was 109,000 b/d (9%) higher than in thirdquarter 2009. Demand for LPG feed in fourth-quarter 2010, however, was only 21,000 b/d (1.8%) higher than in fourth-quarter 2009. Finally, demand for LPG feeds for second-half 2010 was 65,000 b/d (5%) higher than prerecession levels of first-half 2008. LPG feeds accounted for 82% of total fresh feed in third-quarter 2010 and 79% in fourth-quarter 2010. For 2005-07, LPG feeds accounted for 70% total fresh feed. Ethane maintained its increases in share of fresh feed during third and fourth quarters 2010. Ethane’s share of total fresh feed averaged 59% during third-quarter 2010 and 58% during fourth-quarter 2010. Ethane’s share of fresh feed to LPG plants was 81% of fresh feed during third and fourth quarters 2010 and its share of fresh feed to multifeed plants was 47% during third and fourth quarters 2010 vs. only 43% during first and second quarters 2010. Table 1 summarizes trends in olefin plant fresh feed. Based on the view that economic recovery in North America will continue, ethylene producers will increase production to meet growth in demand for polyethylene and other ethylene derivatives during first-half 2011. On this basis, Petral forecasts ethylene plants in the US to operate at 88 92% of nameplate capacity in first and second quarters 2011.

US OLEFINS

Dan Lippe

SECOND-HALF 2010

Feed slate trends Petral’s monthly survey results showed ethylene industry demand for fresh feed averaged 1.62 million b/d for thirdquarter 2010 but declined to 1.56 million b/d for fourthquarter 2010. Demand for fresh feed in third-quarter 2010 was 101,000 b/d higher (about 20%) than in third-quarter

US ETHYLENE FEED SLATE 2010 July August September October November December

Table 1

Naphthas, Ethane Propane n-Butane gas oil –––––––––––––––––– 1,000 b/d –––––––––––––––––––– 955.7 954.0 965.6 902.7 886.4 929.5

292.2 313.5 313.7 303.6 288.7 304.2

Source: Petral Monthly Olefin Feedslate Survey

94

59.3 61.6 33.3 32.9 32.8 31.2

287.5 295.3 315.4 294.2 338.1 337.3

ETHYLENE FROM US STEAM CRACKERS 2010 July August September October November December

Table 2

LPG Multifeed crackers crackers Total ––––––––––– Production, billion lb/month ––––––––– 1.52 1.64 1.62 1.55 1.48 1.72

2.96 2.91 2.82 2.74 2.69 2.74

4.48 4.54 4.44 4.29 4.18 4.46

Source: Petral Monthly Ethylene Feedslate Survey

Oil & Gas Journal | Mar. 7, 2011

PROCESSING

US ethylene production

US ETHYLENE PLANT FEED SLATE

FIG. 1

2.0

Feed, million b/d

Demand for fresh feed will average 1.60-1.65 million b/d during first and second quarters 2011. Demand for LPG feeds will average 1.20-1.25 million b/d during first and second quarters 2010, and ethane will continue to account for 57-58% of industry feed. Fig. 1 illustrates historic trends in ethylene feed.

1.5

1.0

0.5 Ethane

Propane

Others

0.0 Jan.

Apr.

July 2010

Oct.

Petral’s survey results showed ethylene Source: Petral Monthly Olefin Plant Feedslate Survey production from olefin plants totaled 13.5 billion lb in third-quarter 2010 lb less than in third-quarter 2010. but dipped to 12.9 billion lb in fourth-quarter 2010. EthylPropylene production from LPG feeds totaled 1.23 billion ene production for third and fourth quarters 2010 was 845 lb in third-quarter 2010 and 1.11 billion lb in fourth-quarter million lb higher than in first-half 2010. 2010. Production from LPG feeds in third-quarter 2010 was Production from LPG plants totaled 4.78 billion lb in 51 million lb more than in third-quarter 2009. Production third-quarter 2010 and 4.75 billion lb in fourth-quarter from LPG feeds in fourth-quarter 2010 was 53 million lb 2010. Production from LPG plants during second-half 2010 higher than in fourth-quarter 2009. was 257 million lb higher than in first-half 2010. Ethylene Propylene production from heavy feeds totaled 1.06 bilproduction from multifeed crackers totaled 8.69 billion lb in lion lb in third-quarter 2010. Production increased during third-quarter 2010 but dipped to 8.13 billion lb in fourthfourth-quarter 2010 and totaled 1.09 billion lb. Production quarter 2010. Production from multifeed crackers for secfrom heavy feeds in third-quarter 2010 was 62 million lb ond-half 2010 was 536 million lb more than during first-half lower than in third-quarter 2009 but production in fourth2010. quarter 2010 was 22 million lb lower than in fourth-quarter Table 2 summarizes trends in ethylene production. 2009. Petral’s short term outlook is based the expectation that Table 3 shows trends in coproduct propylene supply. LPG crackers will continue to operate at 93-95% capacity rates during first and second quarters 2011. Multifeed crackRefinery propylene supply ers will operate at 88-90% of nameplate capacity vs. 86% of Refinery propylene sales into the merchant market are a capacity during second-half 2010. Fig. 2 illustrates trends in ethylene function of fluid catalytic cracking production. unit feed rates, FCCU operating severity, and economic incentives to sell eedstock prices, coproduct US propylene production propylene rather than use it as alkylvalues, and ethylene plant yields Although ethane’s share of indusate feed. Normally, refineries increase determine ethylene production costs. try feed was at historically high levFCCU feed rates to peaks during secPetral maintains direct contact with els during third and fourth quarters ond and third quarters, and they rethe olefin industry and tracks historic 2010, higher operating rates in mulduce feed rates and operating severity trends in spot prices for ethylene and propylene. We use a variety of tifeed crackers resulted in increased during fourth and first quarters. Prosources to track trends in feedstock use of propane and heavy feeds. As pylene yields from FCC units are genprices. a result, coproduct propylene from erally lower when FCC units operate Some ethylene plants have the steam crackers was higher in third and at lower severity to increase refinery necessary process units to convert all fourth quarters 2010 than in secondyields of distillate fuel oil. coproducts to purity streams. Some quarter 2010. Coproduct propylene US Energy Information Administraethylene plants, however, do not have supply totaled 2.29 billion lb in thirdtion statistics indicate FCCU operating the capability to upgrade mixed or quarter 2010 and was 80 million lb rates diverged from typical seasonal crude streams of various coproducts (3.6%) higher than in second-quarter patterns during third-quarter 2010 and sell some or all their coproducts 2010. but declined as expected in fourthat discounted prices. We evaluate Total industry operating rates quarter 2010. EIA reported FCCU feed ethylene production costs in this arwere slightly lower in fourth-quarter declined by 36,000 b/d in third-quarticle based on all coproducts valued ter 2010 and averaged 5.02 million 2010 and coproduct propylene supply at spot prices. b/d. At this volume, FCCU feed averslipped to 2.20 billion lb, or 83 million

F

Oil & Gas Journal | Mar. 7, 2011

95

PROCESSING

US ETHYLENE PRODUCTION

lower in fourth-quarter 2010 than in third-quarter 2010. Second, spot pric200 es for distillate fuel oil on the Gulf Coast averaged 14.4¢/gal higher than 150 conventional unleaded regular gasoline prices during fourth-quarter 2010. 100 Prices for distillate fuel oil in the Chicago pipeline market also maintained 50 strong premiums vs. unleaded regular Multi-feed plants LPG plants Capacity gasoline during fourth-quarter 2010. 0 Jan. Apr. July Oct. When distillate fuel oil prices are at 2010 premiums to gasoline prices, economSource: Petral Monthly Olefin Plant Feedslate Survey ics generally tell refineries to reduce PROPYLENE PRODUCTION, SALES operating severity for their FCC units. FIG. 3 FCCU propylene yields are lower at 100 lower operating severity. 80 Comparison of ratios of refinery propylene sales to FCCU feed rates 60 shows dramatic increases in fourthquarter 2010 for refineries in the Texas 40 Gulf Coast and South Louisiana. In 20 fourth-quarter 2010, the ratio of proRefinery merchant sales Coproduct production duction to FCCU feed for the Texas 0 Jan. Apr. July Oct. Gulf Coast averaged 8.6-9.6% vs. an 2010 average of 7.5% for third-quarter 2010. Source: Petral Monthly Coproduct Supply Annalysis Petral estimates indicate misreporting inflated refinery-grade propylene by 18-26%, or at least 470 million lb during fourth-quarter aged 33.2% of crude runs and was unchanged from second2010. quarter 2010. In fourth-quarter 2010, EIA statistics indicate Table 4 shows EIA statistics for US refinery merchant proFCCU feed declined 404,000 b/d and averaged 4.62 million pylene sales. b/d, or 31.8%, of refinery crude runs. Based on EIA statistics for refinery-grade propylene (as According to EIA statistics, refinery-grade propylene propublished) and Petral estimates for coproduct supply, doduction totaled 4.51 billion lb in third-quarter 2010 and mestic propylene supply declined in third-quarter 2010 and increased to 4.54 billion lb in fourth-quarter 2010. Refintotaled 6.80 billion lb, or 250 million lb lower than in secery-grade propylene production in third-quarter 2010 was ond-quarter 2010. Petral estimates for coproduct propylene 285 million lb less than in second-quarter 2010, consistent production during fourth-quarter 2010 and EIA statistics for with the atypical decline in FCCU feed rates in third-quarter October and November indicate US propylene production 2010. totaled 6.7 billion lb in fourth-quarter 2010 and was 100 Petral takes issue with EIA statistics that show refinerymillion lb lower than in third-quarter 2010. grade propylene increased 22 million lb in fourth-quarter Based on analysis of FCCU operating rates, however, 2010 for two reasons. First, FCCU feed rates for refineries Petral estimates the actual volume of total US propylene in the Gulf Coast and Midcontinent were 251,000 b/d (7%) Volume, million lb/day

Feed, million lb/day

FIG. 2

COPRODUCT PROPYLENE FROM US STEAM CRACKERS 2010 July August September October November December

From Naphthas, gas Production LPG feeds oil feeds (est.) –––––––––––– Production, billion lb/month –––––––––– 409.6 431.6 385.5 383.7 357.2 384.5

Source: Petral’s “Olefin Markets in North America”

96

Table 3

344.8 349.8 366.2 344.9 387.7 397.2

754.4 781.5 751.7 728.7 744.9 781.7

US REFINERY MERCHANT PROPYLENE 2010 July August September October November December*

Table 4

Other Texas Louisiana areas Total ––––––––––– Production, million lb/month ––––––––––– 638.2 643.1 605.7 660.8 686.2 666.0

558.0 505.4 489.7 486.8 493.8 489.5

367.9 355.5 350.0 365.9 340.6 381.6

1,564.2 1,504.1 1,445.5 1,513.6 1,520.5 1,537.1

*Petral estimate. Source: EIA Petroleum Supply Monthly

Oil & Gas Journal | Mar. 7, 2011

PROCESSING production for fourth-quarter 2010 lower than the second-quarter averPropylene LLC started up declined by 450-500 million lb and age according to PetroChem Wire. The its propane dehydrogenatotaled only 6.3-6.4 billion lb. Finally, contract benchmark averaged 38.3¢/ tion plant (located in the Houston based on EIA statistics, total US prolb, or 7.3¢/lb lower than in secondShip Channel) during fourth-quarter pylene production was 0.9 billion lb quarter 2010. 2010. In the next olefins market higher than in fourth-quarter 2009 The increase in crude oil prices article (OGJ, Sept. 5, 2011), Petral but was only 0.5 billion lb higher than pushed prices for naphtha and gas oil will estimate propylene supply from steadily higher in fourth-quarter 2010. in fourth-quarter 2009, based on adthis plant. Operating rates for both LPG plants justments to refinery-grade propylene and multifeed crackers were also lower supply. in October and November due to turnFig. 3 shows trends in coproduct arounds and unplanned maintenance outages but recovered and refinery merchant propylene sales (as reported by EIA). in December. Spot ethylene prices increased to 38¢/lb in OcEthylene economics, pricing tober and surged to 51¢/lb in November according to PetroProduction costs for ethylene in the Houston Ship Channel Chem Wire. (assuming full spot prices for all coproducts) based on puThe contract benchmark settled higher in October (42.8¢/ lb) and November (50.8¢/lb) but settled lower in December rity-ethane feeds averaged about 17¢/lb in third-quarter but at 48.5¢/lb. For fourth-quarter 2010, spot prices for ethylincreased to 23¢/lb in fourth-quarter 2010. Production costs ene averaged 44.4¢/lb, and the contract benchmark averaged based on ethane for third-quarter 2010 were about 2.5¢/lb 47.3¢/lb. lower than in second-quarter 2010 but were equal to year As ethylene markets returned to normal following the earlier costs. Purity ethane provided ethylene producers turmoil of the second-quarter, margins based on spot pricwith cost savings of 11-13¢/lb vs. naphtha in third-quarter es were also weaker for all feedstocks in third-quarter 2010 2010 and incentives to use ethane vs. naphtha increased to than in second-quarter 2010. Margins based on purity-eth17-19¢/lb in fourth-quarter 2010. ane production costs averaged 16.9¢/ Production costs for purity propane lb in third-quarter and 20.5¢/lb in averaged 22¢/lb in third-quarter 2010 fourth-quarter 2010 vs. 26.7¢/lb for and increased to 32-33¢/lb for fourtheginning in January 2010, a second-quarter 2010. Margins based quarter 2010. Although variable profew US refining companies on propane averaged 11.1¢/lb in thirdduction costs were consistently higher with plants on the Texas Gulf Coast, than ethane, propane provided ethquarter 2010 and 11.3¢/lb in fourthSouth Louisiana, and in the Upper ylene producers with a cost savings quarter 2010 vs. 23.8¢/lb in secondMidwest changed how they reported of 6-8¢/lb relative to light naphtha quarter 2010. components for mixed composition in third-quarter 2010 and 7-11¢/lb in Ethylene producers who continpropane-propylene streams to the fourth-quarter 2010. ued to crack natural gasoline and light US Energy Information AdminisTable 5 summarizes trends in ethylnaphtha experienced much weaker trtion. These changes affected the ene production costs. profitability during third and fourth reported volume of refinery propylene supply and the net availability quarters 2010. Profit margins for natuto the merchant market. Extensive Ethylene pricing, margins ral gasoline feeds averaged 2.0¢/lb in Petral discussions with EIA personAfter ethylene producers resolved opthird-quarter 2010 vs. 11.7¢/lb in secnel confirmed that these refineries erating problems and completed turnond-quarter 2010. Profit margins for now report their propane-propylene arounds during second-quarter 2010, natural gasoline were at breakeven in streams to EIA as 100% propylene. spot ethylene prices fell sharply in fourth-quarter 2010. Previously, these companies reported June and declined to the low for the Fig. 4 shows historic trends in ethmixed composition streams to EIA as year in July. According to daily pricing ylene prices (spot prices and net trans100% propane. data from PetroChem Wire, from an action prices). Fig. 5 illustrates profit This topic will continue to be an average of 32.5¢/lb in July, prices crept margins based on spot ethylene prices important subject of discussion and slowly higher and averaged 37¢/lb in and production costs for ethane-prodebate by the NGL Market InforAugust but slipped to 34¢/lb in Seppane (averaged for purity ethane and mation Committee of the US Gas tember. The contract benchmark price purity propane) and natural gasoline. Processors Association and between settled at 37¢/lb in July but settled at the committee and the EIA. Until it is 39¢/lb for August and September due Refinery, polymer-grade C3= resolved, misreporting will continue to create uncertainty in the EIA statistics to rising production costs. During third-quarter 2010, spot prices for refinery propylene supply. For third-quarter 2010, spot pricfor refinery-grade propylene moved es averaged and 34.4¢/lb, or 12.3¢/lb gradually higher and averaged 44.5¢/

PL

B

Oil & Gas Journal | Mar. 7, 2011

97

PROCESSING

ETHYLENE PRICES 70

Price, ¢/lb

60 50 40 30 20 10 0

Jan.

Apr.

July 2010

Source: Petral market research

ETHYLENE PROFIT MARGIN 50 Ethane/propane

Margin, ¢/lb

40 30 20 10 0 –10

Jan.

Apr.

July 2010

Source: Petral analysis

ETHYLENE COSTS, HOUSTON SHIP CHANNEL 2010 July August September October November December

Table 5

Purity Purity Normal Light Industry ethane propane butane naphthas composite ––––––––– Variable, direct fixed cash costs, ¢/lb –––––––– 15.8 16.8 18.5 21.7 24.6 23.7

19.0 21.8 25.6 33.1 33.3 30.4

15.2 16.5 22.0 29.2 31.1 28.4

26.8 28.5 31.1 40.5 42.6 41.2

17.7 19.2 21.6 26.6 29.0 27.5

Source: Petral Consulting Co. production cost analysis

lb vs. 43.5¢/lb in second-quarter 2010. Spot prices for refinery-grade propylene continue to move gradually higher in October and November but were sharply higher in December 2010 and averaged 60.1¢/lb for the month and averaged 51.3¢/lb for fourth-quarter 2010 according to PetroChem Wire. The surge in refinery-grade propylene pricing during December 2010 was inconsistent with EIA’s reports of increased refinery-grade propylene production during fourthquarter 2010. The premium for refinery-grade propylene prices vs. unleaded regular gasoline prices averaged 12.4¢/lb for thirdquarter 2010 vs. 9.4¢/lb for second-quarter 2009. Premiums move gradually higher during fourth-quarter 2010 and averaged 12-13¢/lb for October and November but surged to 22.6¢/lb for December 2010. For fourth-quarter 2010, pre-

98

miums averaged 16.1¢/lb. Inventory trends for refinery-grade propylene provided support for stronger spot prices during third and fourth quarters 2010. During first-half 2010, according to EIA weekly inventory statistics, refinery-grade propylene inventory averaged 522 million lb. Inventory averaged 509 million lb during Spot Contract third-quarter 2010 but averaged only 371 million lb during fourth-quarter Oct. 2010, or 151 million lb (29%) lower than the first-quarter average. Propylene buyers began to anFIG. 5 ticipate supply from the propane dehydrogenation plant during fourthLight naphtha quarter 2010. This new supply source had a bearish impact on trends in the premium for polymer-grade propylene vs. refinery-grade propylene even before the new plant started up. During third-quarter 2010, the contract benchmark for polymer-grade propylene averaged 57.7¢/lb, or 7.2¢/lb lower Oct. than the average for second-quarter 2010. Additionally, the premium for polymer-grade propylene contract prices vs. spot refinery-grade propylene prices narrowed to 13.2¢/lb in third-quarter 2010. During fourth-quarter 2010, the contract benchmark averaged 58.8¢/lb, or a bare 1.2¢/ lb higher than during third-quarter 2010. Furthermore, the premium for polymer-grade propylene vs. refinery-grade propylene narrowed to 7.6¢/lb. During fourth-quarter 2010, the premium narrowed to 0.4¢/lb in December vs. 12.6¢/lb in October. FIG. 4

First-half 2011 outlook Spot prices for West Texas Intermediate crude oil began a sustained rally in late September, reaching almost $91/bbl during the last week of December. The cumulative increase of almost $16/bbl (21%) occurred even though domestic inventories of crude and distillate fuel oil were at historic highs. Globally, key producers in the Middle East maintained strict discipline in accord with Organization of Petroleum Exporting Countries’ production quota agreements, according to EIA statistics. Furthermore, EIA production data showed the rate of decline in North Sea production accelerated during 2009-10. Finally, in the global distillate fuel-oil market, according to various news sources, China experienced shortages of diesel fuel, and the scramble to export diesel fuel contributed to strong bullish pressures on crude oil prices. As a result, WTI prices moved well beyond the established trading

Oil & Gas Journal | Mar. 7, 2011

PROCESSING range of $70-80/bbl during fourth-quarter 2010. Price forecasts for naphtha and distillate fuel oil and ethylene production costs are based on the more bullish view of global supply-demand trends; Petral forecasts WTI prices will average $85-100/bbl during first and second quarters 2011. Variable production costs for light naphtha have been a key driver for spot ethylene prices since 2008. Those spot prices averaged only 0.9¢/lb higher than variable production cost for natural gasoline during third and fourth quarters 2010. Petral forecasts variable production costs for natural gasoline will average 41-44¢/lb and spot ethylene prices will average 44-48¢/lb during first and second quarters 2011. Petral forecasts ethylene production costs will average 2326¢/lb for purity ethane and 31-34¢/lb for purity propane during first and second quarters 2011. Profit margins will average 18-22¢/lb for purity ethane and 12-15¢/lb for purity propane. Petral also forecasts polymer-grade propylene will average 70-75¢/lb during first-quarter 2011 and 65-68¢/lb dur-

ing second-quarter 2011. Based on differentials of 3-5¢/ lb, refinery-grade propylene prices will average 66-72¢/ lb during first-quarter 2011 and 60-62¢/lb during secondquarter 2011. The author Daniel L. Lippe ([email protected]) is president of Petral-Worldwide Inc., Houston. He founded Petral Consulting Co. in 1988 and cofounded Petral Worldwide in 1993. He has expertise in economic analysis of a broad spectrum of petroleum products including crude oil and refined products, natural gas, natural gas liquids, other ethylene feedstocks, and primary petrochemicals. Lippe began his professional career in 1974 with Diamond Shamrock Chemical Co., moved into professional consulting in 1979, and has served petroleum, midstream, and petrochemical industry clients since that time. He holds a BS (1974) in chemical engineering from Texas A&M University and an MBA (1981) from Houston Baptist University. He is an active member of the Gas Processors Association and serves on the NGL Market Information Committee.

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99

TRANSPORTATION

The ExxonMobil Corp.-operated Golden Pass LNG terminal, on the Sabine Pass waterway near Port Arthur, Tex., received its first commissioning cargo in October 2010. The 15.6-million-tpy (peak) terminal is a joint venture of Qatar Petroleum International 70%, ExxonMobil 17.6%, and ConocoPhillips 12.4% (photo from ExxonMobil).

100

Oil & Gas Journal | Mar. 7, 2011

SPECIAL

REPORT

Global LNG capacities rising to meet increasing demand Warren R. True Chief Technology Editor—LNG/Gas Processing

Taken together, 2010-11 may represent that point in the evolution of natural gas trade when gas comes into its own among hydrocarbon fuels. With the advent of unconventional gas, especially from previously locked shale formations, the surge in means to move natural gas around the world via LNG and long-distance pipelines, and the decoupling in some markets of gas prices from those for oil and liquids all suggest the global natural gas industry may have entered a new era. This vision gained some credibility at yearend 2010 when the international natural gas organization Cedigaz, Paris, reviewed major trends for the year. It noted that world natural gas production had increased by 4% over 2009 with only European production falling (Fig. 1). The same report, however, showed global gas trade in 2010 vs. 2009 contracted by 6.4%. The bright spot in that trade, however, was LNG, which increased its share of gas trade. Oil & Gas Journal data show global gas reserves at Jan. 1, 2011, stood at 6,647 tcf, compared with 6,609 tcf at the beginning of 2010, an increase of nearly 38 tcf (OGJ, Dec. 6, 2010, pp. 48-49). Combined, the production and reserves figures should soften perennial concerns about the adequacy of global natural gas supply and stimulate overall gas trade in the near term. Cedigaz emphasized that, although liquefaction capac-

Oil & Gas Journal | Mar. 7, 2011

101

TRANSPORTATION

WORLD GAS SUPPLY SURGE IN 2010* 900

+1.3%

FIG. 1

+4.4%

800

World gas production growth prospects in 2010

2008

Billion cu m

700 600

+7.7%

500

2009

2010

+10.5%

400

-3.6%

300

+4.6%

200

+3.6%

100 0

North America

CIS

Asia; Oceania

Middle East

Europe

Africa

Latin America

*Estimates; Cedigaz Reference Scenario: demand growth of 4% in 2010. Source: Cedigaz, Paris

ity in 2010 rose, it is likely to see a much greater increase in 2011. The report’s numbers paint a robust picture of the growth in liquefaction capacity from the end of 2010 through 2015, saying more the 48 million tonnes/year (tpy) of capacity will come on stream during the period. Atlantic Basin LNG trade will rise at 9.5%/year over the period, reaching nearly 190 billion cu m for the trading region. In the Pacific Basin, trade will grow more slowly, at 4%/year…but grow nonetheless (Fig. 2). Regasification capacity 2009-15 will also see impressive growth, as 72 million tpy of import capacity were under construction at yearend 2010 and due to come on line by 2015, as much as 24 million tpy will be in Europe and 16 million tpy in the US (Fig. 3). Cedigaz’s analysis points to LNG markets moving from production overhang by yearend 2012 to probable supply “tensions” by yearend 2013.

Middle East In December of last year, the Arabian Gulf state of Qatar celebrated reaching LNG production capacity of 77 million tpy, solidifying it as the world’s largest single country supplier of LNG. The celebration might have seemed a bit premature, since the massive trains clustered at Ras Laffan north of Doha only reached the 77-million tpy threshold with the start-up last month of Qatargas 4’s 7.8-million-tpy Train 7. Nevertheless, the country has reached its position in a scant 14 years from the first production of LNG. In that time, its growth has overtaken other major producers of long standing, mainly Indonesia and Malaysia. So confident that its position is unassailable and so concerned are the Qataris that reckless production might dam-

102

age North field’s reservoir that holds the world’s largest non-associated natural gas reserves, that also in December of last year, the country’s energy minister said flatly there would be no more large LNG projects. There will be only needed debottlenecking and revamping of the megatrains the country has built in recent years with cooperation of, among others, US international oil companies ExxonMobil and ConocoPhillips. Qatar’s decision also responds to forecasts of much higher gas demand among gulf states. In December, Qatargas delivered the first LNG cargo to Dubai via the permanently moored floating storage and regasification vessel Golar Freeze at the port of Jebel Ali (OGJ Online, Dec. 6, 2010). The 210,000-cu m (Q-flex) Al Bahiya LNG carrier, dedicated under long-term contract by Nakilat to Quatargas Train 4, delivered the cargo intended for the local market under contract between Shell and the Dubai Supply Authority. The LNG was produced by Qatargas 2. A report earlier this year from FACTS Global Energy said Dubai plans to meet gas demand of about 1.5 bcfd with pipeline imports from Qater, Abu Dhabi, and Sharjah, as well as the 400-MMscfd floating regasification and storage vessel moored at Jebel Ali (OGJ Online, Jan. 25, 2011). The gulf’s first LNG importing country, Kuwait, started up a GasPort system from Excelerate Energy, Houston, in 2009. The FGE analysis sees Dubai becoming a gas hub, importing LNG and exporting gas through existing pipelines to northern emirates.

Asia central The centrality of Asia in global LNG trade was highlighted last year by a report from Denver-based analyst Bentek. It projected demand for LNG in Asia-Pacific by 2015 will reach 25.4 bcfd, up from 7.8 bcfd in 2010. That demand growth will be pushed mainly by emerging

Oil & Gas Journal | Mar. 7, 2011

In 1988, when we introduced Polyguard’s RD-6 non-shielding pipeline corrosion coating system, we were excited to have an answer to cathodic shielding, which corrosion experts had told us was a serious problem. Our sales grew steadily over the next 15 years, but growth was nothing like we had expected. Most pipeline companies ignored the shielding problem. Corrosion engineers understood the problem, but few others seemed to. And corrosion engineers were being laid off as the industry consolidated and cut back. So, around 2003, we committed resources to teaching the industry about cathodic shielding through presenting papers, advertising, and selling efforts. This campaign has been successful, making us one of the fastest growing companies in the industry. In 2009 U.S. DOT regulators began to explicitly require non-shielding corrosion coatings (CFR § 192.112). Make certain that your company is not ignoring the cathodic shielding problem.

TRANSPORTATION

LNG DEMAND GROWTH

FIG. 2 FIG. 2a

Atlantic Basin 200 180

+9.5%/year

Others

160

Billion cu m

140

+30% (27 billion cu m)

Chile Spain

120

Italy

100

Brazil

80

Mexico

60

US

40

UK

20 0

2009

2010

2011

2012

2013

2014

2015 FIG. 2b

Pacific Basin, Middle East 250

+4%/year

+15% (23 billion cu m)

Billion cu m

200

Middle East 150

Other Asia Taiwan

100

India South Korea China

50

Japan 0

2009

2010

2011

2012

2013

2014

2015

Source: Cedigaz, Paris

demand centers China and India and by traditional demand centers in Japan, South Korea, and Taiwan as their economies recover from recession. In addition emerging markets in Bangladesh, Pakistan, Thailand, Singapore, and the Philippines will drive LNG demand growth. An example of the growth of LNG imports into China is the month of August 2010. The country’s General Administration of Customs reported LNG imports that month more

104

than doubled those for August 2009: more than 995,000 tonnes exceeded volumes in 2009 by more than 115%. Those same August 2010 imports surpassed July 2010’s figures by almost 40%. The increases were attributed to unseasonably hot weather and the ramp up of recovery from the global recession that hit almost 2 years earlier. China’s construction of LNG terminals continued apace in 2010 with Dapeng LNG in Guangdong province starting

Oil & Gas Journal | Mar. 7, 2011

TRANSPORTATION

GLOBAL REGASIFICATION PLANT

FIG. 3 Fig. 3a

Atlantic Basin

450

350

350

300

300

250 Billion cu m

Billion cu m

Pacific Basin, Middle East

400

400

Fig. 3b

250 200

200 150

150 100

100

50

50

0

0

2009

2010

2011

2012

2013

2014

2015

2009

2010

2011

2012

2013

Other Europe

Italy

UK

Other Americas

Middle East

India

Taiwan

Netherlands

France

Spain

Mexico

Other Asia

China

South Korea

US

2014

2015

Japan

Source: Cedigaz, Paris

up an expansion, taking terminal inlet capacity to 6.7 million tpy. In 2011, two more terminals will begin operating: • Dalian in Liaoning province will start up 3.5 million tpy in its first phase. • Rudong in Jiangsu province will start up its first-phase 3.5 million tpy. At yearend 2011, China will operate 19.3 million tpy of inlet capacity, up from 3.7 million tpy in 2006. Under construction are three terminals that will begin accepting shipments in 2012-13. Ningbo in Zhejiang province will start up its Phase 1 of 3 million tpy in 2012 for majority owner CNOOC; Quingao in Shandong province will start up its first phase (3 million tpy) in 2013 for owner Sinopec; and another CNOOC terminal is set to open in 2013 at Jinwan, Zhuhai, Guangdong. Terminals in Tangshan (PetroChina, 2013), Hainan Island (CNOOC; 2014), Shenzhen, Guangdong (PetroChina, 2014+), and another in Shenzhen (CNOOC, unknown start-up) will be able to handle 11.5 million tpy. Four terminals have been approved for expansion and three others await approval by the National Development and Reform Commission. In India, Asia’s other major emerging LNG market, Royal Dutch Shell opened its Hazira LNG terminal on India’s west coast to Gujarat State Petroleum Corp. The 132,000-cu m Iberica Knutsen reached Hazira with a cargo from Trinidad & Tobago, according to Reuters. Shell owns 74% of Hazira LNG Pvt and Total SA owns the rest. The terminal can handle 3.6 million tpy of LNG and can be expanded to 5 million tpy.

Oil & Gas Journal | Mar. 7, 2011

Petronet LNG Ltd. will install two more storage tanks at its LNG receiving and regasification terminal at Dahej in Gujarat. Added to the existing four tanks, this will raise total capacity to 15 million tpy from 10 million tpy. The company also reported it is in the process of setting up a second LNG jetty at Dahej to accommodate larger LNG carriers. Petronet LNG, a joint venture of GAIL India, Oil and Natural Gas Corp., Indian Oil Corp., and Bharat Petroleum Corp., is also constructing a 2.5-million tpy terminal at Kochi with targeted commissioning of mid-2012. For that terminal, Petronet has a long-term gas supply contract with ExxonMobil for LNG from Gorgon field. Plans to expand the terminal will increase capacity to 5 million tpy from 2.5 million tpy. The second phase will probably be added by third or fourth quarter 2012. Although not a large market by Chinese or Indian standards, Singapore’s installation of its first LNG terminal has wider implications for the region. It is currently building a terminal to handle 3.5 million tpy and to open in 2013. In November last year, Singapore LNG announced plans to add a third storage tank at the Jurong Island site to be ready by early 2014. The new 180,000cu m tank would take terminal capacity to 6 million tpy. The third tank signals an expansion in the mission of the terminal itself. The initial terminal design envisioned small LNG cargoes of about 100,000 cu m. Cargoes of this size are adequate only for satisfying the terminal’s commitment to BG for the initial 3 million tpy of capacity. Adding the tank

105

TRANSPORTATION DSLNG to 59.9%. Mitsubishi said Kogas will also be a partner in the SPC, making the project the first joint LNG project among Japan, Korea, and Indonesia, and “opening up a new era of cooperation in the energy sector for these three nations,” according to the announcement. The partners in the SPC include Mitsubish 45%, PT Petamina 29%, Kogas 25%, and PT Medco Energi with 11%. Mitsubishi said JGC Corp. will build the plant on Sulawesi Island under an engineering, procurement, and construction contract.

Australian supply Last year saw advances on the supply side of the Asia-Pacific region, as well as on its market side. In November, BG Group announced it had made an FID to proceed with its planned $15 billion coal seam gas-toThis artist’s conception shows an LNG carrier moored onto the floating liquefaction LNG plant on Curtis Island near Gladdesign for Shell’s Prelude project off northwestern Australia (image from Shell; Fig. 4). stone in Queensland. The two-train, 8.5-million-tpy plant will be built over the next 4 years along with field facilallows it to expand its service to a variety of customers in ities in the Surat-Bowen basins and a 540-km (about 335 the highly industrialized area, SLNG Chief Operating Ofmiles) pipeline from the fields to the plant. ficer Neil McGregor told OGJ. BG Group expects first exports of LNG to begin in 2014 McGregor said the terminal may eventually function as underpinned by agreements in Chile, China, Japan, and Sina part of an active gas hub for the wider region, taking cargapore for the purchase of up to 9.5 million tpy. goes of various sizes, moving vaporized LNG to a variety of In January 2011, another Queensland-based coal seam industrial and petrochemical customers, and even perhaps LNG project moved ahead: Partners in Gladstone LNG sending smaller LNG carriers back out to local markets that liquefaction project reached FID on the $16-billion (Aus), have installed small-scale LNG storage and vaporization, as 7.8-million-tpy project. Australia’s Santos, a 30% partner, in Japan. said the company expects to begin exporting LNG in 2015. In late January of this year, Mitsubishi Corp. announced that partners in Indonesia’s $2.8 billion Donggi-Senoro LNG Other partners are France’s Total (27.5%), Malaysia’s Petronas (27.5%), and South Korea’s Korea Gas (15%). That project had reached a final investment decision (OGJ Onownership firmed up in 2010 after Santos agreed to sell Koline, Jan. 25, 2011). rea Gas and Total a 7.5% stake each. At the same time, PetroMitsubishi said the project is being spearheaded by PT nas also agreed to sell 7.5% of its GLNG equity to Kogas. Donggi-Senoro LNG, a joint venture of Mitsubishi and subKogas also agreed to buy 3.5 million tpy of LNG from the sidiaries of Indonesia’s state-owned PT Pertamina, and PT project. Its 20-year agreement provides for 1.7 million tpy of Medco International. the contracted volumes to be delivered from GLNG Train 1 By second-half 2014, PT DSLNG aims to produce and deliver 2 million tpy of LNG, along with associated condensate and 1.8 million tpy from Train 2. of 47,000 boe/d. PT DSLNG has signed a heads of agreement Petronas also has a 20-year agreement to buy 3.5 milfor an LNG sales and purchase agreement with Chubu Eleclion tpy of LNG from GLNG, of which 1.8 million tpy would come from Train 1 and 1.7 million tpy from Train 2. tric Power Co. and Kyushu Electric Power Co, while negotiaTwo other LNG export projects from Queensland’s coal tions are being finalized with Korea Gas Corp. seam gas are likely. Mitsubishi said it will transfer its shares of PT DSLNG to In August 2010, Shell and PetroChina completed their a special purpose company (SPC), which will take over some of PT Medco’s shares as well, bringing its total stake in PT

106

Oil & Gas Journal | Mar. 7, 2011

TRANSPORTATION $3.4 billion (Aus.) joint acquisition of Australia-based coal seam gas company Arrow Energy Ltd. Shell and PetroChina have taken over Arrow’s coal seam gas assets in Queensland to backstop a planned four-train, 16-million-tpy plant to be built on Curtis Island. At the time of the transaction Arrow held equity interests in more than 25,000 sq miles of CSG exploration tenements and five producing projects that accounted for about 20% of the state’s gas consumption. Arrow was also developing a pipeline to move gas from the Surat basin to Gladstone. In January of this year, the ShellPetroChina joint venture invited tenders for the front-end engineering and design phase of its project; those tenders were due by the end of last month. Stage 1 includes construction of two trains of 4 million tpy. An FID is set for 2012, leading to the project being on stream in 2017. In November of last year, the Queensland government approved construction of a fourth LNG project based on CSG reserves. Australia Pacific LNG proposes yet another LNG plant on Curtis Island. The $35 billion (Aus.) APLNG project, a 50:50 joint venture between Australia’s Origin Energy and ConocoPhillips, now requires only environmental approvals from the Australian federal government in Canberra. The environmental clearances are the last major regulatory hurdles to be overcome by the project, although by January this year it had not announced the securing of any LNG customers. APLNG project could eventually consist of up to four, 4.5-milliontpy trains. In addition to the plant, work involves further development of APLNG’s coal seam gas resources in Queensland’s Surat and Bowen basins, and Queensland environmental approval to build a 279-mile pipeline from the gas fields to Gladstone. Under the APLNG joint venture, Origin would be responsible for building and managing the coal seam

Oil & Gas Journal | Mar. 7, 2011

gas resources and related facilities, and ConocoPhillips would oversee construction of the LNG plant and export on behalf of APLNG. The other important news of the year out of Australia is the likely installation of the world’s first floating LNG plant for Shell’s Prelude project 475 km north-northeast of Broome on the Kimberley coast of northwest Australia (Fig. 4). In March 2010, Royal Dutch Shell signed two contracts with a joint venture of France’s Technip and South Korea’s Samsung Heavy Industries for design and potential construction of the proposed Prelude floating liquefaction vessel. The first contract covers front-end engineering and design for the project; the second sets the terms under which the FLNG would be built, pending FID. Shell had already signed a master agreement in mid-2009 with the Technip-Samsung consortium for design, construction, and installation of multiple floating LNG facilities over 15 years. In addition, Shell said in late 2009 the world’s first FLNG production would be designed to produce 3.6 million tpy of LNG as well as 400,000 tpy of LPG and 1.3 million tpy of condensate. It would include six LNG storage tanks with total capacity of 220,000 cu m, four LPG storage tanks with total capacity of 90,000 cu m, and six condensate storage tanks to hold as much as 126,000 cu m. In October 2010, Shell reported it was on track to approve Prelude early in this year, despite several environmental delays during 2010. Those delays were resolved in November when Shell received environmental approval from the Australian government for Prelude. Environment Minister Tony Burke imposed strict conditions on the development to protect the marine environment. Shell will have to develop an oil-spill contingency plan to the government’s satisfaction that outlines how the company will minimize the

risk of oil spills while also reducing the environmental impact of any spill. In the event of a spill, Shell will be responsible for the entire bill for environmental rehabilitation and will have to develop a greenhouse-gas strategy that is “transparent and publicly available.” Burke said his department would have the power to conduct a project audit at any time to ensure Shell is complying with the approval conditions. With all going according to plan, Shell expects to begin commissioning in 2015 and produce its first LNG in 2016 (OGJ Online, Nov. 12, 2010).

US: an LNG exporter? Whereas only a few years ago the US saw more than 50 proposals to import LNG, as analysts widely—and, it now appears, wildly—predicted a natural

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TRANSPORTATION

An artist’s rendering shows how liquefaction Phases 1 and 2 might be installed adjacent storage at Cheniere’s existing Sabine Pass regasification terminal in Cameron Parrish, La. (image from Cheniere Energy; Fig. 5).

gas shortage in the country’s immediate future, the likelihood now of the US exporting LNG from domestically produced natural gas seems very bright. Last June, Cheniere Energy announced the first concrete plans to export US gas as LNG from the Lower 48 as it made plans to build liquefaction at its existing—and recently completed—import terminal on the Sabine Pass, Cameron Parrish, La. Cheniere announced it would export as much as 1 bcfd by 2015, possibly expanding later to 2 bcfd. Major shale-gas producer Chesapeake Energy indicated its willingness to send as much as 500 MMcfd of its gas to the proposed liquefaction plant for export to higher-paying markets. Cheniere’s proposal to export LNG from its Sabine Pass terminal would cost $1.6 billion, if it finds market interest for four liquefaction trains with combined capacity of 14 million tpy. Cheniere has said in an application to the US Federal Energy Regulatory Commission that, through subsidiary Sabine Pass Liquefaction, it wants to start construction of the project in January 2012. Cheniere would build two 3.5-million-tpy liquefaction trains in Stage 1 and two more 3.5-million-tpy trains in Stage 2, providing sufficient market demand (Fig. 5). Each train would employ ConocoPhillips’s Optimized Cascade liquefaction technology and include gas treatment to remove condensates, water, solids, CO2, sulfur, and mer-

108

cury. Each would have six LM2500-G4 turbine-driven refrigerant compressors. The US Department of Energy in September approved Cheniere Energy’s plans, moving the terminal closer to becoming the first facility ever in the Lower 48 and the first of a cluster of Gulf of Mexico import terminals to export natural gas produced in the US. On its web site, the company calls its plans the “world’s first bidirectional LNG facility.” The DOE’s approval allows Cheniere’s subsidiary to export LNG to any nation that currently can import LNG and with which the US currently has entered or may in the future enter into a Free Trade Agreement, including Canada, Mexico, Chile, and Singapore. Cheniere planned to file a separate application for authorization to export LNG to countries with which an FTA applicable to natural gas and LNG isn’t in effect. This second application would be subject to more rigorous public interest review and analysis by DOE, the company said in the application. In November came news that, under an agreement Cheniere Energy signed with ENN Energy Trading, natural gas production from the Lower 48 could be exported to China. Cheniere said in a statement at the time that the memorandum of understanding could allow China’s ENN to contract for 1.5 million tpy of bidirectional processing capacity at the Sabine Pass LNG terminal. Talks were to lead to a contract for 20 years with mutually agreed extension, subject to certain conditions. Those include Sabine’s receipt of regulatory approvals and reaching FID to build liquefaction, and ENN reaching FID to build an LNG receiving terminal. And only 2 months ago, Cheniere announced that Sabine Pass Liquefaction had signed yet another MOU, this time with EDF Trading, London (OGJ Online, Jan. 21, 2011). Under that agreement, EDF Trading intends to contract for 0.7-1.5 million tpy of processing capacity at the Sabine Pass terminal. Under the MOU, EDF Trading, a wholly owned subsidiary of EDF SA, and Sabine Pass agreed to negotiate definitive agreements for EDF Trading to contract bidirectional capacity. The agreement is subject to, among other conditions, receipt by each party of internal approvals, Sabine’s receipt of regulatory approvals, and an FID by Sabine Pass to build liquefaction adjacent to the import terminal. EDF stated it intends to enter into contracts for at least 500 MMcfd/train of liquefaction capacity. The announcement said LNG export could begin as early as 2015, assuming Sabine Pass obtains regulatory approvals and reaches FID. The announcement came about the same time as the news that Cheniere had signed a non-binding MOU with Morgan Stanley Capital Group that would permit Morgan to buy import capacity and about 20% of a proposed 7 million

Oil & Gas Journal | Mar. 7, 2011

TRANSPORTATION tpy of liquefaction capacity at the South Louisiana terminal. Under the MOU, Morgan Stanley would be able to export or import 1.7 million tpy of LNG from the terminal (OGJ, Jan. 17, 2011, Newsletter). And at the end of January, Cheniere Energy announced that subsidiary Sabine Pass Liquefaction had entered into yet another nonbinding MOU with Sumitomo Corp. under which Sumitomo intends to contract up to about 1.5 million tpy of processing capacity at the Sabine Pass LNG terminal (OGJ Online. Jan. 28, 2011). Under the MOU, Sumitomo and Sabine have agreed to proceed with negotiations of definitive agreements for Sumitomo to contract bidirectional capacity, subject to certain conditions, including receipt by each party of requisite internal approvals, Sabine’s receipt of regulatory approvals and reaching FID to construct liquefaction. In September of last year, another newly built LNG terminal along the Texas Gulf Coast, at Freeport, Tex., loaded out a shipment of LNG as reexport aboard the 138,000 cu-m Excalibur, from Excelerate Energy’s fleet This was the second such reexport for the terminal and reflected how LNG shippers can take advantage of US terminals to store and

reexport gas to higher-priced markets in Asia and Europe. In November, Freeport LNG and Macquarie Bank agreed to build an export plant on the terminal site. It would be able to export 1.4 bcfd equivalent in LNG by 2015 and will cost about $2 billion. Freeport LNG will operate the plant, with Macquarie contributing to development costs. Macquarie and Freeport plan jointly to market half of the export plant’s capacity, with the other half being offered to Freeport’s existing import customers, Dow Chemical and ConocoPhillips. Also in September, Sempra LNG applied to the FERC to export LNG from its very recently completed terminal in Cameron Parish downstream of the long-standing Panhandle LNG Lake Charles terminal. Cameron LNG asked for 2-year authority to reexport up to 250 bcf. In December, the DOE approved Sempra LNG’s application to export; in late January, the FERC was still studying Sempra LNG’s construction application. The DOE order allows reexports to any country that can import LNG from ocean tankers and with which trade is not prohibited by US law or policy.

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Oil & Gas Journal | Mar. 7, 2011

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TRANSPORTATION

LNG SHIPPING FLEET 70

Capacity (est.) Vessels, no.

400

60

LNG shipping fleet

350

50

300 250

40

200

30

150

20

100 10

50

Capacity (est.), million cu m

450

FIG. 1

0

0 1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Source: Argus and National Energy Board, Canada, estimates

Is LNG a global commodity...yet? Simon Bonini Consultant London

The global LNG industry will become increasingly flexible as the number of players willing and able to participate increases and LNG volumes and infrastructure grow. There is certainly a role for intermediaries who have the patience to join in this process. The LNG market will slowly gain liquidity, but LNG will not become a commodity for many years, if ever.

Trading trends LNG producers and buyers, as well as international banks and major commodity trading houses, have been monitoring the evolution of LNG trade over the last few years, looking for signs the product is moving towards becoming a commodity. By “commodity,” I mean LNG will have hundreds of buyers and sellers actively executing thousands of trades each day on open exchanges with transparent global prices driven by supply-demand balances. Perhaps, however, it will instead remain a point-to-point industry dominated by principal producers and importing utilities with little need for a clearing market to intermediate.

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Two areas bear examination in considering the future of LNG trading: 1. The product itself and how easy it is to SPECIAL REPORT gain access to it. 2. The underlying nature of destination markets. LNG today does not trade freely in the same way oil, wheat, coal or steel do. Those in the business cannot guarantee that on a given day they will be able to buy even a single additional cargo of LNG. Moreover, there is no liquid marketplace for LNG. Neither physical outcry market nor electronic bulletin boards exist where a would-be buyer and seller could appear and trade. There are also no financial or “paper” markets for LNG. The only way to participate in the LNG market today is by buying and selling the physical product. Any company wishing to become a player in LNG needs to be able to participate in the physical trade, which means gaining access to some part of the logistics chain.

Infrastructure access LNG is a cryogenic liquid needing custom-built ships and tanks for transportation and storage and importation via terminals connected to natural gas networks. LNG producers tend to be major international oil and gas companies working in partnership with national oil companies selling

Oil & Gas Journal | Mar. 7, 2011

TRANSPORTATION

GLOBAL LNG TRADE, 2009

FIG. 2

US, UK spot markets 11% Asia long-term contracted 61%

Europe spot LNG 1% Asia spot LNG 5%

Europe long-term contracted 22% 15-20 year term contracted LNG Spot market LNG Source: Poten & Partners, New York

their output, typically, under 20-year contracts. The buyers are overwhelmingly Asian or European utilities with large downstream gas and power businesses. Upstream producers, therefore, need the utility buyers’ credit and large dependable physical markets to finance multi-billion dollar upstream production facilities. Until recently a typical LNG export project would deliver to the buyer’s import terminal on a “CIF” basis (carriage, freight, and insurance paid) under a contract that is in essence a point-to-point trade with no alternate delivery possibilities. Production, shipping and stock planning, and coordination and logistics are key components in the buyer and seller’s ability to ensure security and reliability of supply. The LNG supply chain places control of infrastructure exclusively with the buyers and sellers.

Shipping, import capacity The rapid growth in the LNG fleet over the past decade (Fig. 1) has created an increasing amount of spare capacity, leaving carriers available for short-term charter. Third parties can use this excess capacity to effect intermediate trades between exporters and importers, and it is in the shipping market that new traders are most active. A trader may charter a vessel for just a few weeks to buy a cargo in, for example, Trinidad and sell it to an Asian buyer, taking ownership of LNG at a jetty in Trinidad and selling it as the LNG leaves the ship at a jetty in South Korea. Gaining access to regasification and storage facilities at an import terminal facilitates trading. The number of terminals in the Americas and Europe with underutilized capacity and

Oil & Gas Journal | Mar. 7, 2011

no long-term supply contracts has grown. The owners of idle capacity are eager to gain incremental income by making their facilities available to third parties. Market participants have also been re-exporting LNG delivered to the US and Belgium from the Middle East to Asia and the UK. Only a few years ago the lack of sufficient LNG terminal capacity would have made such trades impossible. Only in Europe (including the UK) and the US are regulations in place allowing third parties access to terminals.

Pricing A key feature of a true commodity is use of commonly used pricing points. Prices between these points may vary in quality, freight, or other logistical consideration, but they are used by the market at large. Brent or WTI crude oil pricing quotes, for instance, indicate the price of oil globally. LNG’s price, by comparison, varies greatly depending on its destination, thus creating large price disparities between markets. The North American and UK markets have established pipeline gas as a commodity, with the price being settled by balancing supply and demand at particular locations. Abundant shale gas supplies have lowered US natural gas prices at Henry Hub. Long-term contracts that link the price of natural gas to crude oil determine gas pricing in Europe and Asia. LNG can move between these markets, offering considerable gains if the price spreads can be captured. The difference between Henry Hub and Asian gas prices typically runs as high as $5/MMbtu. At the height of the

111

TRANSPORTATION pricing cycle, some LNG producers successfully demanded “oil parity” pricing for their gas, ~$16/MMbtu at $100/bbl, while Henry Hub traded around $6/MMbtu. These differentials are driving the trading community’s interest in LNG and the projects to export US gas as LNG.

The weakening of US gas prices has created opportunities to remarket LNG to alternate customers, mostly in Asia, but this remarketing is so far being carried out by the producers themselves and has not created opportunities for intermediaries.

The future

The author

Without question, the LNG industry is moving towards an increasing level of trading and flexibility. And although LNG remains far from being a global commodity, the increased flexibility is valuable to the industry in meeting seasonal demand variations and in buyers and sellers having access to versions of the risk-management products that come with a traded commodity market. The lack of sufficient trading volumes remains the major obstacle to LNG becoming a commodity. Producers continue to sell the bulk of LNG on long-term contracts (Fig. 2) to utilities with formula pricing referenced to oil. The figure shows that 83% of LNG is bought under contracts with physical supply for 15-20 years.

Simon Bonini ([email protected]) is currently an independent consultant in international energy. He has more than 25 years’ experience, most recently as director LNG for Centrica, the UK’s largest utility. He has previously served as chief operating officer of 4Gas, Rotterdam, and president of Woodside Natural Gas Inc., Los Angeles. He spent 17 years in various capacities at BG developing its global LNG business, including president of BG Trinidad, president of BG Shipping, and vice-president global LNG. Bonini holds a masters in chemical engineering from the Imperial College at the University of London and an MBA from INSEAD Fontainebleau, France. He is a chartered engineer and a fellow of the Institution of Chemical Engineers.

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TRANSPORTATION

Conditions improving for floating LNG production John Vautrain Purvin & Gertz Inc. Singapore

Christopher Holmes Purvin & Gertz Inc. London

Historically LNG has relied on a small number of land-based production and regasification sites, but this is changing. As more remote and deeper water gas resources have been identified, the limits of land-based LNG production have come into greater focus. Floating LNG (FLNG) technology holds promise economically to open new areas to production.

FLNG In this article we will focus on three key issues related to capital cost, modularity, and the insurance attributes of FLNG installations. Capital cost and modularity provide key advantages that support selection of FLNG over land-based LNG installations when the conditions are right. Insurance is a potentially important area that could contribute to decisions on scale and modularity of the FLNG installation chosen. We believe the capital cost of FLNG is not always a hurdle. Depending on the situation, FLNG can be less costly than land-based LNG development.

LNG DEVELOPMENT OPTIONS

114

Subsurface and production

FPSO

Subsurface and production

FLNG

Export pipeline

SPECIAL

REPORT

The modular aspect of FLNG technology offers the ability to redeploy expensive assets at appropriate times in the overall project life, thereby achieving capital efficiency. Modularity can improve the economics of FLNG installations by reducing capital employed at key times. Insurance is a potential stumbling block for FLNG, since no such installation has ever been insured. We have investigated insurance-industry attitudes toward FLNG and determined that insurability may be a function of scale, something to be considered in developing FLNG projects.

Capital cost Fig. 1 shows the two alternatives considered. In conventional LNG development, an offshore gas field is developed through an FPSO at the production site. The FPSO recovers condensate and LPG and dehydrates the gas for export via a subsea pipeline to onshore LNG production. The FLNG option combines the functions of the FPSO and LNG production onto a floating vessel at the production site. Condensate is exported from the FLNG vessel in addition to LNG. In the event LPG is produced, that too would be loaded from the FLNG vessel. FLNG is most appealing when the export pipeline would be particularly long or costly. In those cases the capital cost savings achieved by avoiding the requirement for the export pipeline along with the FPSO are sufficient to offset the extra capital and operating costs associated with FLNG. The costs of gas pipelines to LNG production ashore can be substantial. For remote offshore locations the cost of a gas export pipeFIG. 1 line to the shore-based LNG production can add perhaps 40% or more to the cost of the LNG plant. Avoiding this cost in favor of FLNG can provide Onshore LNG attractive increases to the project’s economic returns. Some gas resources have been discovered for which export pipelines may cross seismically active areas. Risk is associated with such lines in the event of an earthquake that causes lateral displacement across the line.

Oil & Gas Journal | Mar. 7, 2011

TRANSPORTATION

LNG production, million tpy

FLNG example cases 5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0

FIG. 2

One FLNG module needed

Two FLNG modules needed 1

5

10

15

20

Years

Table 1 shows the capital costs of a 4 million tonne/year (tpy) shore-based LNG plant and two cases of FLNG for the same capacity. The field production costs are equal for these examples. Costs for the FPSO and export pipeline, however, are not incurred in the FLNG cases. The export pipeline in this example is estimated for 600 km (about 373 miles) to shore. Laying large-diameter export pipelines in deep water and possibly seismically active zones is quite expensive; the estimated cost in this example is $2.5 billion (about $6.7 million/mile). The capital cost advantage for FLNG does not entirely depend on a costly export pipeline. In this example even excluding the pipeline costs, FLNG costs are comparable or slightly lower than onshore costs. That difference is attributable to the cost savings of not requiring a separate FPSO, offsetting the higher costs of the FLNG vessel as compared with the onshore LNG plant. FLNG vessels incorporate functions of the FPSO and the shore-side LNG production into one vessel. Large-hull sizes are required not only to provide deck space for gas liquefaction and other functions but also to provide needed LNG and condensate storage. The footprint for the required processing and living quarters establishes the overall hull out-

LNG CAPITAL COSTS

Table 1

– Floating options – 1x4 2x2 Onshore million million option tpy* tpy* ––––––––––– $ billion –––––––––– Production facilities FPSO Export pipeline LNG plant Total *Tonnes per year.

1.9 1.2 2.5 5.5 –––– 11.1

1.9 __ –– 5.8 ––– 7.7

1.9 –– –– 6.6 ––– 8.5

line. The hull depth is a function of the need for storage and for strengthening the hull. In the examples above the hulls are quite large. For the smaller, 2-million-tpy FLNG vessels, the hull’s overall length (LOA) may be about 320 m, on the order of a very large crude carrier. Storage would be required for more than 200,000 cu m of LNG. Ability to store sufficient LNG and condensate is critical in the sizing of the vessel. The larger, 4-million-tpy FLNG vessel would be considerably larger and provide substantially more storage. But the LOA of this vessel may be as much as 500 m, considerably larger than a VLCC. Many shipyards will be able to accommodate the smaller FLNG vessels as opposed to the larger vessels, construction of which will pose difficulties. FLNG technology is under active development. Generic designs from several technology providers may be suitable for the smaller FLNG size presented above. Design at the larger scale is less well developed. Consequently technology risk associated with scale-up will be higher and more time may be required to develop the larger FLNG scale. Offsetting the scale-up risk and time, economy of scale would tend to make larger FLNG trains more cost-effective up to limits imposed by the hull. The cost of a floating LNG vessel often is higher than the corresponding cost of shore-side LNG production of the same capacity. That is attributable to the requirement for a hull as well as the need for more compact designs. The cost of the 4-million-tpy production vessel in the example is about $300 million higher for FLNG of the same capacity. Overall capital cost savings of $3.4 billion are possible with FLNG in lieu of onshore LNG in this example. Installing two smaller FLNG vessels carries higher capital cost than the single FLNG vessel option.

Scale, modularity The optimal design is not always the cheapest. For this example we have shown an option of two independent FLNG units sized at 2 million tpy, each needed to achieve the required overall capacity. Economy of scale in the LNG facilities makes the multiple-unit option considerably more ex-

Oil & Gas Journal | Mar. 7, 2011

115

TRANSPORTATION

FLNG ILLUSTRATIVE ECONOMICS

Table 2

– Floating options – 1x4 2x2 Onshore million million option tpy* tpy* –– $ million/yr, except as noted –– Capital cost, $ billion Annual capital recovery Annual cost of service return Annual capital charge Fixed operating costs Sustaining capital Variable operating cost Total annual cost LNG production, million tpy* LNG production, million MMbtu/yr Total liquefaction cost, $/MMbtu

11.0 367 1,100 1,467 220 84 10 1,780

7.7 257 770 1,027 164 97 11 1,299

8.5 283 850 1,133 200 113 11 1,458

4.0 208 –––– 8.56

4.0 208 –––– 6.25

4.0 208 –––– 7.01

*Tonnes per year.

pensive than the single FLNG option by $800 million, but still less expensive than the onshore option. How could the greater capital cost of the multiple FLNG vessels be justified? Two key factors bear consideration when selecting FLNG unit size: • The ability to scale the FLNG production unit over time to match the required capacity. • The ability to insure the FLNG unit. In Fig. 2, the 4-million-tpy LNG rate is maintained for 7 years. Field and market development requires 3 years and after Year 10, production decline begins. The first LNG vessel would begin production in Year 1, whereas the second vessel is not required until Year 3. After Year 14 the second vessel can be relocated to production duties elsewhere. While the maximum capital employed in the case of two LNG vessels is higher than the capital employed for one larger vessel, the efficiency achieved by being able to relocate the one vessel to new production duties offers overall savings and optimal returns. The opportunity to redeploy capital in response to natural production decline is valuable. This attribute of FLNG technology facilitates monetizing smaller gas resources particularly in the 3-tcf and smaller range.

Insurability A second advantage of using smaller FLNG vessels is insurability. Insurance is important and insurance companies, while generally familiar with the FLNG concept, have not yet faced the task of actually writing policies for FLNG. Despite FLNG technology having elements of novelty, the key concern is the attitude of the insurance market toward offshore risk in general and the capacity of the offshore insurance market to absorb that risk. These factors tend to support use of smaller FLNG vessels. Many insurance companies organize themselves into the upstream and downstream segments. The upstream segment

116

insures offshore and floating facilities. The downstream segment would insure onshore LNG plants and the like. Insurance for offshore gas developments and FPSOs is very common and is not a factor relevant to determining whether to pursue floating or onshore LNG. Likewise, insuring onshore LNG plants is common, and insurers well understand the risks. Insurance issues distinguishing FLNG and onshore LNG can be identified as the gas export pipeline in the case of the onshore plants and the FLNG vessel itself in the FLNG option. Depending on location, the gas export pipelines may present unusual technical features and challenges requiring unusual insurance considerations. Deepwater pipelines are common in the Gulf of Mexico and the number of vessels capable of laying the lines is increasing. Nevertheless, the technology is still relatively new. In locations with unusual seismic features or bottom conditions, deepwater pipeline considerations will increase. Insuring deepwater pipelines is likely to appeal to only a narrow segment of the insurance industry. Insuring such lines in the presence of unusual technical or seismic features is likely to narrow the field and increase insurance costs further. Nevertheless, we consider it probable that in even difficult cases such insurance could be obtained. The FLNG vessel will pose its own insurance problems. The estimated maximum loss (EML) for an onshore LNG plant can be determined by indentifying single events that might inflict the most damage on the plant. Loss of LNG containment leading to vapor cloud explosion is such an event. Designers of onshore LNG plants can mitigate the effect of such an event by providing spacing between equipment so that the EML of the plant might be 30% of the plant cost. In the hypothetical case that an onshore LNG plant will cost $5.5 billion, the EML might be estimated at $1.65 billion. For an FLNG unit, the EML is higher. EML for an offshore structure typically is considered to be 100%. In the case of an FLNG vessel, the insurers would consider the possibility that the vessel suffer sufficient calamity to cause it to sink. The ability of individual insurers to accept risk for any one calamity is limited. That is, the insurers have a maximum amount of money they are allowed to put at risk at a single facility. In the hypothetical circumstance described above, an insurer would consider that $1.65 billion is at risk on the $5.5 billion facility. If a particular insurer has a limit of $200 million, then it could accept about one eighth of the risk on the facility and would need to find syndicate partners to accept the remaining seven eighths. In the case of FLNG unit, if the overall capital cost of a unit is $5.8 billion, then that same insurer might find that it could accept only 3.4% of the overall project insurance and would need to find syndicate partners to accept the other 96.6%, a far more difficult proposition. Furthermore, the capacity of the offshore insurance in-

Oil & Gas Journal | Mar. 7, 2011

TRANSPORTATION dustry is limited to perhaps $3-3.5 billion/calamity. The requirement to insure a risk of $5.8 billion probably exceeds the capacity of the industry. More insurance capacity might be developed to handle such a risk but developing such capacity is costly. In the case of the dual LNG vessels, the overall insurance requirement is larger at $6.6 billion. But the maximum calamity to be insured is $3.3 billion, since single events causing both vessels to sink are highly improbable. The need to expand the capacity of the insurance industry is far smaller than in the case of one larger FLNG vessel. In practice the insurer would need to consider not only the loss of the facility but also the business interruption loss as well. In that event, if the required insurance were to exceed the maximum underwriting capacity of the market, then the facility might be uninsurable. The novelty of the FLNG technology is a negative factor from an insurance point of view. Some insurance companies may be reluctant to participate in FLNG insurance until an FLNG unit has been operating for several years. Consequently the insurance capacity available from existing underwriters may be less than the $3-3.5 billion estimated above in early years of FLNG technology operation. We believe that FLNG units would be insurable, but the capacity and willingness of the offshore industry to underwrite the insurance could be limiting. Larger FLNG vessels may be so costly that the need to increase insurance industry capacity may make securing insurance so expensive that the insurance cost would become a material factor favoring smaller, multiple units.

Overall liquefaction costs Table 2 illustrates overall economics for the three options considered. Capital recovery for each case is assumed to occur over a 30-year operating life. As discussed above, the operating-life assumption for FLNG can carry less risk than for onshore options since the plant can be relocated in the event that gas reserves are depleted. Invested capital requires a cost-of-service rate of return. In practice the rate of return is a function of the capital structure and includes debt and equity components and is charged against the undepreciated part of the invested capital. In this example, we assigned a 10%/year return on the total invested capital to represent a utility rate of return. The total capital charge is the sum of the capital recovery and the cost-of-service return portion. Ongoing costs must be recovered. These include both fixed and variable operating costs as well as sustaining capital. Sustaining capital is an allowance for capital replacements of operating items which are necessary to continue operations. Sustaining capital excludes investments for new capacity. Total annual costs include all the components above. Di-

Oil & Gas Journal | Mar. 7, 2011

viding total annual costs by the annual throughput provides the full costs of liquefaction. In this example FLNG production offers superior economics compared with onshore LNG production. Avoided costs of the FPSO and export pipeline were keys in favoring FLNG. Larger scale FLNG vessels are favored over smaller versions on grounds of cost of liquefaction, but smaller vessels have advantages from insurance and modular-unit-redeployment point of view. Of course these results will not be universally favored. As the scale of the LNG installation increases, the attractions of FLNG are considerably less. Nevertheless, FLNG will find its place in LNG production and contribute beneficially in the right circumstances.

The authors John Vautrain (jhvautrain@ purvingertz.com) is vice-president and director for Purvin & Gertz Inc., Singapore. Before joining Purvin & Gertz in 1981, he worked for Phillips Petroleum Co. and Union Carbide Corp. Vautrain was manager of Purvin & Gertz’s Long Beach office 1987-2000. Elected director in 1997, he has been based in Singapore since 2000. His Asian consulting activities include crude marketing, petroleum refining, LPG, natural gas, and LNG. Vautrain holds a BA in chemistry from the University of Texas and an ME in chemical engineering from the University of Utah. Chris Holmes ([email protected]) is a vice-president with international energy consultants Purvin & Gertz Inc. in its London office. He has worked for Amoco (UK) Ltd., as a process engineer at its Milford Haven refinery and as a refined products trader in London, and for international energy advisers Gaffney, Cline & Associates as a senior consultant. He holds a BSc (honors) in chemical engineering from the University of Birmingham.

117

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118

This firm’s K-System, H-System, and Z-Series intrinsically safe solutions have received Bureau Veritas, Germanischer Lloyd, Lloyds Register, and Det Norske Veritas approvals for use in marine-type operations. K-System intrinsic safety barriers are a range of products designed for discrete or analog signals. These barriers connect easily with the exclusive PowerRail system. By using PowerRail, a group of safety barriers is energized from an AC or DC source and monitored for group fault conditions. H-System intrinsic safety barriers are backplane mounted isolated barriers. Z-Series zener diode barriers are a hardware method for solving hazardous area barrier and intrinsic safety applications. The company’s zener diode barriers feature an encapsulated housing, are suited for DIN rail mounting, and are fit for AC and DC applications.

NEW INTERACTIVE TOOL FOR INSTRUMENTATION DESIGN The instrumentation business value calculator (BVC) is a new interactive tool that calculates the savings that can be achieved by engineering companies by adopting the latest instrumentation technology. The BVC assists with estimating the time and cost savings a business could achieve by implementing this firm’s life cycle solution for designing, installing, and maintaining instrumentation in plants and offshore vessels. The company says the BVC demonstrates the savings that are achievable in a project. Using parameters such as head count, hourly costs, and input/ outputs that users can input themselves, the tool calculates savings in man-hours and money across a number of deliverables. The tool highlights benefits such as more productivity through catalogs and rule-based automation, and better proj-

ect quality through right first time design and automatic, accurate materials and production information. Source: AVEVA Solutions Ltd., High Cross, Madingley Rd., Cambridge, CB3 0HB, UK.

NEW GAS STANDARDS GENERATOR The new FlexStream automated permeation tube system combined with secondary dilution module SD creates variable concentration gas mixtures in constant output flow. The developer says many contamination exposure applications require a

constant and often rather large flow of the test gas mixture. This system simplifies production and reduces the cost of supplying the required test gas mixtures, the firm notes. When using permeation tubes, mixture concentration is typically adjusted by varying dilution flow. Changing from 1 ppm to 100 ppb, for example, might require changing dilution flow from 500 cc/min to 5 l./min. This creates no problem so long as the dilution flow exceeds the minimum flow required for the application. But for applications with high minimum flow, the flow required to create even a 10X concentration reduction can be impractically large, the company points out. In the FlexStream/SD system, primary mixture concentration can be varied over a 10:1 range in the permeation unit. An adjustable aliquot of that mixture is added to a constant dilution flow in the SD module. The resulting concentration adjustability is more than 100:1. Source: KIN-TEK Laboratories Inc., 504 Laurel, La Marque, TX 77568.

Oil & Gas Journal | Mar. 7, 2011

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SERVICES | SUPPLIERS GE OIL & GAS, Florence, Italy, has agreed to acquire John Wood Group PLC’s well support division for about $2.8 billion. The deal is expected to close later this year, subject to customary approvals and closing conditions. The well support division comprises business groups for electric submersible pumps, pressure control, and logging services. The acquisition would provide GE entry into the artificial lift business and expand its offering in unconventional oil and gas production. Additionally, Wood Group and GE have agreed to negotiate a potential commercial arrangement on turbomachinery services. GE Oil & Gas is a world leader in advanced technology equipment and services for all segments of the oil and gas industry, from drilling and production, LNG, pipelines, and storage to industrial power generation, refining, and petrochemicals. GE Oil & Gas also provides pipeline integrity solutions. It is part of GE, a diversified infrastructure, finance, and media company. Wood Group is an international energy services company with three divisions—engineering and production facilities, well support, and gas turbine services—that provide engineering, production support, maintenance management and industrial gas turbine overhaul and repair services to the oil and gas and power generation industries worldwide.

HB RENTALS, Broussard, La., has named Erica Toussaint human resources business partner. Based in Broussard, Toussaint will be responsible for embedding corporate HR strategy and providing professional HR guidance and support to relevant Toussaint internal client groups. She also will manage an HR team both in the US and internationally. Previously, Toussaint served as HR manager for The Shaw Group Inc. HB Rentals is the world’s largest sup-

120

plier of temporary onshore and offshore accommodation modules, operating from Broussard, Aberdeen, and Singapore. It is part of New Orleans-based Superior Energy Services, a leading provider of specialized oil field services and equipment focusing on production, intervention, workover, well services, and rental tools.

PETRIS TECHNOLOGY INC., Houston, has agreed to provide Norway’s Statoil AS borehole data management technology that would allow the operator to manage and ensure the quality of data flow from the drilling rig and throughout the organization. Statoil would leverage PetrisWINDS Recall software to provide automated data quality verification and data publishing workflow and PetrisWINDS Enterprise to integrate data from several internal and third-party petrophysical applications within existing corporate workflows at Statoil. Petris is a leading supplier of practical data management solutions and geosciences applications to the global energy industry.

KNOWLEDGE RESERVOIR INC., Houston, has formed a real-time systems (RTS) division to provide situational awareness system implementation to the upstream oil and gas industry. Marv LeBlanc will lead the RTS division. Knowledge Reservoir’s solution comprises an LeBlanc integrated alliance with proven applications for events-based surveillance, command and control, complex events processing, and knowledge-based decision-making in real-time drilling and production environments. Knowledge Reservoir will provide services to develop knowledge management-based situational awareness tools and integrate, test, operate, and maintain RTS to client operations facilities. The company’s RTS division will provide integrated systems and services for real-time command and control and events-based surveillance solutions. LeB-

lanc is an expert in systems engineering, telecommunications, program management, and corporate organizational development. Previously, LeBlanc was vice-president, systems engineering, and CTO of Cimarron Software Services Inc. He was also chief of systems engineering, mission control, with NASA. Knowledge Reservoir provides geoscience and engineering consulting and resource solutions to clients worldwide.

REGAL PERFORMANCE WELDING, Lafayette, La., has agreed to merge with Stabiltec Downhole Tools, Parks, La. The Stabiltec Regal division will remain at its current location in Broussard, La. Current Regal Pres. Keith Boutte has been named vice-president of business development for Stabiltec. He has more than 30 years of precision welding, hard coating, and downhole motor experience. Stabiltec is a fully integrated, highprecision manufacturing facility for the production of new stabilizers and machine shop/repair center for refurbishing used stabilizers and other downhole tools. Stabiltec also manufactures mud motor stabilizers, housings, mandrels, subs, flex collars, stubbing for rotors and stators, API rotary connections, lift subs, and API drill pipe crossover subs. Regal uses proprietary techniques in the application of hard surface coatings to extend the life of downhole tools.

TOPNIR SYSTEMS SAS, Aix en Provence, France, has opened two new offices in Asia. James Ooi was named manager of business development for the new Singapore office. He has many years of experience in the Asian refining industry. Hu Xin will head up the Topnir China support and service center in Beijing, hosting a technical team for local service in China. Xin has worked for more than 10 years in the refining industry. Topnir provides near-infrared analyzers, offering a full suite of online and at-line systems, as well as laboratory analyzers and modeling services to the downstream industry.

Oil & Gas Journal | Mar. 7, 2011

STATISTICS IMPORTS OF CRUDE AND PRODUCTS — Districts 1-4 — — District 5 — ———— Total US ———— 2-18 2-11 2-18 2-11 2-18 2-11 *2-19 2011 2011 2011 2011 2011 2011 2010 ––––––––––––––––––––––––— 1,000 b/d ––––––––––––––––––––––––— Total motor gasoline ............. Mo. gas. blending comp. ..... Distillate............................... Residual .............................. Jet fuel-kerosine .................. Propane-propylene .............. Other ...................................

793 683 152 141 21 86 114

935 827 211 525 16 150 (260)

14 14 19 39 3 (14) 169

0 0 0 0 45 (92) 171

807 697 171 180 24 72 283

935 827 211 525 61 58 (89)

846 624 444 521 102 140 68

Total products ......................

1,990

2,404

244

124

2,234

2,528

2,745

Total crude ...........................

6,865

7,372

1,240

893

8,105

8,265

9,084

Total imports ........................

8,855

9,776

1,484

1,017

10,339

10,793

11,829

*Revised. Source: US Energy Information Administration Data available in OGJ Online Research Center.

PURVIN & GERTZ LNG NETBACKS—FEB. 25, 2011 –––––––––––––––––––––––––––– Liquefaction plant –––––––––––––––––––––––––––––––– Algeria Malaysia Nigeria Austr. NW Shelf Qatar Trinidad –––––––––––––––––––––––––––––––– $/MMbtu ––––––––––––––––––––––––––––––––––––

Receiving terminal Barcelona Everett Isle of Grain Lake Charles Sodegaura Zeebrugge

8.47 3.99 7.35 1.78 6.54 7.76

6.52 1.65 4.66 –0.35 8.61 5.61

7.50 3.58 6.55 1.50 6.75 7.17

6.41 1.74 4.56 –0.14 8.27 5.55

6.75 2.24 5.35 0.10 7.43 6.34

7.42 4.31 6.60 2.48 5.71 7.22

Additional analysis of market trends is available through OGJ Online, Oil & Gas Journal’s electronic information source, at http://www.ogj.com.

OGJ CRACK SPREAD *2-25-11 *2-26-10 Change Change, ———–—$/bbl ——–—— % SPOT PRICES Product value Brent crude Crack spread

115.56 109.98 5.58

FUTURES MARKET PRICES One month Product value 116.19 Light sweet crude 96.71 Crack spread 19.49 Six month Product value 121.19 Light sweet crude 100.60 Crack spread 20.59

86.46 76.25 10.21

29.10 33.73 -4.63

33.7 44.2 -45.3

86.55

29.65

34.3

79.37 7.18

17.34 12.31

21.8 171.5

90.16

31.02

34.4

81.14 9.03

19.46 11.56

24.0 128.1

*Average for week ending. Source: Oil & Gas Journal Data available in OGJ Online Research Center.

Definitions, see OGJ Apr. 9, 2007, p. 57. Source: Purvin & Gertz Inc. Data available in OGJ Online Research Center.

CRUDE AND PRODUCT STOCKS —–– Motor gasoline —–– Blending Jet fuel, ————— Fuel oils ————— PropaneCrude oil Total comp.1 kerosine Distillate Residual propylene ———————————————————————————— 1,000 bbl —————————————————————————

District PADD 1 ..................................... PADD 2 ..................................... PADD 3 ..................................... PADD 4 ..................................... PADD 5 .....................................

11,114 100,885 169,618 16,118 49,005

64,817 55,091 77,673 7,027 33,689

52,293 28,325 52,665 2,164 29,581

9,167 7,472 12,675 738 10,422

58,095 33,539 51,568 3,377 13,358

13,412 1,635 17,794 226 4,336

2,957 10,912 14,848 1 828 ––

Feb. 18, 2011 ........................... Feb. 11, 2011............................ Feb. 19, 20102 ...........................

346,740 345,916 337,537

238,297 241,096 231,170

165,028 167,332 146,990

40,474 41,435 43,650

159,937 161,270 152,664

37,403 39,452 40,017

29,545 30,972 27,364

1

Includes PADD 5. 2Revised. Source: US Energy Information Administration Data available in OGJ Online Research Center.

REFINERY REPORT—FEB. 18, 2011 REFINERY –––––– OPERATIONS –––––– Gross Crude oil inputs inputs ––––––– 1,000 b/d ––––––––

District

–––––––––––––––––––––––––––– REFINERY OUTPUT ––––––––––––––––––––––––––– Total motor Jet fuel, ––––––– Fuel oils –––––––– Propanegasoline kerosine Distillate Residual propylene –––––––––––––––––––––––––––––––– 1,000 b/d –––––––––––––––––––––––––––––––

PADD 1 .............................................. PADD 2 .............................................. PADD 3 .............................................. PADD 4 .............................................. PADD 5 ..............................................

926 3,297 6,778 538 2,422

947 3,258 6,561 537 2,233

2,884 2,256 1,988 330 1,504

83 223 627 30 408

318 979 2,037 173 472

55 42 355 10 98

43 236 661 1 58 ––

Feb. 18, 2011 ...................................... Feb. 11, 2011 ...................................... Feb. 19, 20102.....................................

13,961 14,291 14,358

13,536 13,864 14,107

8,962 8,891 8,863

1,371 1,240 1,344

3,979 4,012 3,591

560 536 530

998 954 1,081

17,594 Operable capacity 1

79.4% utilization rate

2

Includes PADD 5. Revised. Source: US Energy Information Administration Data available in OGJ Online Research Center.

Oil & Gas Journal | Mar. 7, 2011

121

STATISTICS OGJ GASOLINE PRICES

BAKER HUGHES RIG COUNT

Price Pump Pump ex tax price* price 2-23-11 2-23-11 2-24-10 ————— ¢/gal ————— (Approx. prices for self-service unleaded gasoline) Atlanta .......................... 269.7 308.9 Baltimore ...................... 271.8 313.7 Boston ........................... 266.6 308.5 Buffalo .......................... 256.5 319.7 Miami ............................ 270.9 323.3 Newark .......................... 280.8 313.7 New York........................ 268.3 331.5 Norfolk........................... 270.4 308.3 Philadelphia .................. 260.3 311.0 Pittsburgh ..................... 273.3 324.0 Wash., DC...................... 281.6 323.5 PAD I avg .................. 270.0 316.9

257.7 263.7 259.7 275.1 274.8 257.6 273.2 255.1 268.6 267.2 269.2 265.6

Chicago ......................... Cleveland ...................... Des Moines .................... Detroit ........................... Indianapolis .................. Kansas City ................... Louisville ....................... Memphis ....................... Milwaukee ..................... Minn.-St. Paul ............... Oklahoma City ............... Omaha .......................... St. Louis ........................ Tulsa ............................. Wichita .......................... PAD II avg .................

290.4 267.0 277.0 277.2 274.3 271.4 276.1 262.6 268.1 272.8 266.9 268.0 279.6 268.9 263.0 272.2

348.4 313.4 317.4 331.4 327.4 307.1 317.0 302.4 319.4 318.4 302.3 314.4 315.3 304.3 306.4 316.3

291.5 281.5 256.5 283.5 274.5 251.5 264.5 253.9 272.5 256.5 231.5 255.5 243.5 229.5 241.5 259.2

Albuquerque .................. Birmingham .................. Dallas-Fort Worth .......... Houston ......................... Little Rock ..................... New Orleans .................. San Antonio ................... PAD III avg ................

261.9 264.3 262.1 260.3 261.0 266.1 267.8 263.3

299.1 303.6 300.5 298.7 301.2 304.5 306.2 302.0

251.5 250.5 244.5 246.5 242.5 250.6 254.5 248.7

Cheyenne....................... Denver ........................... Salt Lake City ................ PAD IV avg ................

271.0 272.8 261.4 268.4

303.4 313.2 304.3 307.0

252.4 275.4 257.4 261.7

Los Angeles ................... Phoenix.......................... Portland ........................ San Diego ...................... San Francisco................ Seattle........................... PAD V avg ................. Week’s avg. .................. Feb. avg. ....................... Jan. avg......................... 2011 to date ................. 2010 to date .................

280.2 290.3 286.3 284.4 306.1 293.7 290.2 272.5 267.0 261.9 263.3 222.9

347.6 327.7 329.7 351.8 373.5 349.6 346.7 317.8 312.3 307.2 308.6 267.7

290.5 271.6 283.6 291.6 293.6 286.6 286.2 263.2 264.7 269.7 –– ––

*

Includes state and federal motor fuel taxes and state sales tax. Local governments may impose additional taxes. Source: Oil & Gas Journal. Data available in OGJ Online Research Center.

REFINED PRODUCT PRICES 2-18-11 ¢/gal

2-18-11 ¢/gal

Spot market product prices Motor gasoline No. 2 Distillate (Conventional-regular) Low sulfur diesel fuel New York Harbor ......... 254.00 New York Harbor ......... Gulf Coast .................. 250.50 Gulf Coast .................. Los Angeles ................ Motor gasoline Kerosine jet fuel (RBOB-regular) New York Harbor ......... 277.80 Gulf Coast ..................

280.20 276.10 281.60 280.60

Propane No. 2 heating oil New York Harbor ......... 271.10 Mt. Belvieu ................. 136.10

2-25-11

OGJ PRODUCTION REPORT 1

2-26-10

Alabama............................................ Alaska ............................................... Arkansas ........................................... California .......................................... Land................................................ Offshore .......................................... Colorado ............................................ Florida ............................................... Illinois ............................................... Indiana.............................................. Kansas .............................................. Kentucky............................................ Louisiana .......................................... N. Land ........................................... S. Inland waters .............................. S. Land............................................ Offshore .......................................... Maryland ........................................... Michigan ........................................... Mississippi ........................................ Montana ............................................ Nebraska ........................................... New Mexico........................................ New York............................................ North Dakota ..................................... Ohio................................................... Oklahoma .......................................... Pennsylvania ..................................... South Dakota..................................... Texas ................................................. Offshore .......................................... Inland waters .................................. Dist. 1 ............................................. Dist. 2 ............................................. Dist. 3 ............................................. Dist. 4 ............................................. Dist. 5 ............................................. Dist. 6 ............................................. Dist. 7B ........................................... Dist. 7C ........................................... Dist. 8 ............................................. Dist. 8A ........................................... Dist. 9 ............................................. Dist. 10 ........................................... Utah .................................................. West Virginia ..................................... Wyoming............................................ Others—NV-4 ...................................

8 6 35 38 38 0 60 1 0 0 23 4 171 115 15 19 22 0 1 9 8 1 73 0 150 8 158 110 0 738 3 1 70 49 44 44 73 56 5 59 205 27 32 70 27 20 46 4

4 11 42 26 25 1 48 1 2 0 17 8 209 137 14 18 40 0 0 11 7 2 59 1 84 7 111 67 0 565 4 0 22 20 39 50 77 76 7 55 113 24 35 43 24 24 37 6

Total US ........................................ Total Canada ................................

1,699 623

1,373 576

Grand total ................................... US Oil rigs ......................................... US Gas rigs ....................................... Total US offshore ............................... Total US cum. avg. YTD .....................

2,322 783 906 25 1,715

1,949 456 905 46 1,295

(Crude oil and lease condensate) Alabama ................................. 18 Alaska .................................... 634 California ............................... 615 Colorado ................................. 72 Florida .................................... 3 Illinois .................................... 26 Kansas ................................... 108 Louisiana ............................... 1,549 Michigan ................................ 13 Mississippi ............................. 60 Montana ................................. 67 New Mexico............................. 174 North Dakota .......................... 352 Oklahoma ............................... 187 Texas ...................................... 1,460 Utah ....................................... 61 Wyoming ................................. 137 All others ................................ 67 5,603 Total .................................. 1 OGJ estimate. 2Revised. Source: Oil & Gas Journal. Data available in OGJ Online Research Center.

*Current major refiner’s posted prices except North Slope lags 2 months. 40° gravity crude unless differing gravity is shown. Source: Oil & Gas Journal.

Data available in OGJ Online Research Center.

WORLD CRUDE PRICES $/bbl1

0-2,500 2,501-5,000 5,001-7,500 7,501-10,000 10,001-12,500 12,501-15,000 15,001-17,500 17,501-20,000 20,001-over Total

189 62 142 314 386 292 164 149 6 1,704

3.1 46.7 25.3 3.5 9.0 2.3 –– –– –– 7.0

INLAND LAND OFFSHORE

15 1,724 19

2-26-10 Rig Percent count footage* 115 51 128 253 288 220 175 76 49 1,355 13 1,295 47

*Rigs employed under footage contracts. Definitions, see OGJ Sept. 18, 2006, p. 42.

6.9 64.7 23.4 6.3 7.9 1.3 –– –– –– 8.3

2-18-11

United Kingdom-Brent 38° ..................................... Russia-Urals 32° ................................................... Saudi Light 34° ...................................................... Dubai Fateh 32° ..................................................... Algeria Saharan 44°............................................... Nigeria-Bonny Light 37° ........................................ Indonesia-Minas 34°.............................................. Venezuela-Tia Juana Light 31° ............................... Mexico-Isthmus 33° ............................................... OPEC basket........................................................... Total OPEC2 ............................................................ Total non-OPEC2 ..................................................... Total world2 ............................................................ US imports3

SMITH RIG COUNT 2-25-11 Percent footage*

2-25-11 $/bbl* 85.74 103.50 99.30 107.45 87.88 94.00 89.50 94.50 94.50 87.50 86.50 93.50 82.75

Alaska-North Slope 27° ......................................... South Louisiana Sweet .......................................... California-Midway Sunset 13° .............................. Lost Hills 30° ........................................................ Wyoming Sweet ..................................................... East Texas Sweet ................................................... West Texas Sour 34° .............................................. West Texas Intermediate........................................ Oklahoma Sweet.................................................... Texas Upper Gulf Coast ......................................... Michigan Sour ....................................................... Kansas Common ................................................... North Dakota Sweet ...............................................

Source: Baker Hughes Inc. Data available in OGJ Online Research Center.

Rig count

17 635 617 69 4 24 114 1,551 18 65 47 165 261 184 1,437 59 139 68 5,474

US CRUDE PRICES

Rotary rigs from spudding in to total depth. Definitions, see OGJ Sept. 18, 2006, p. 42.

Proposed depth, ft

2 2-25-11 2-26-10 –—— 1,000 b/d —–—

101.57 99.28 99.72 98.22 103.73 104.82 103.40 91.82 91.71 99.66 99.35 95.46 97.78 89.25 -

-

1

Estimated contract prices. 2Average price (FOB) weighted by estimated export volume. 3Average price (FOB) weighted by estimated import volume. Source: DOE Weekly Petroleum Status Report. Data available in OGJ Online Research Center.

US NATURAL GAS STORAGE1 2-18-11

Producing region ................ Consuming region east ...... Consuming region west ...... Total US ............................. Total US2 ............................

2-11-11

2-18-10

–——––—— bcf —––——– 687 698 616 880 937 949 263 276 313 1,830 1,911 1,878 Change, Dec. 10 Dec. 09 % 3,107

3,130

Change,

% 11.5 –7.3 –16.0 –2.6

–0.7

1

Source: DOE Weekly Petroleum Status Report. Data available in OGJ Online Research Center.

122

Source: Smith International Inc. Data available in OGJ Online Research Center.

Working gas. 2At end of period. Source: Energy Information Administration Data available in OGJ Online Research Center.

Oil & Gas Journal | Mar. 7, 2011

STATISTICS PACE REFINING MARGINS

US Gulf Coast West Texas Sour ............................... Composite US Gulf Refinery.............. Mars (Cracking) ............................... Bonny Light ...................................... US PADD II Chicago (WTI)................................... US East Coast Brass River ...................................... East Coast Comp ............................. US West Coast Los Angeles (ANS) ............................ NW Europe Rotterdam (Brent) ............................ Mediterranean Italy (Urals) ...................................... Far East Singapore (Dubai) ............................

WORLDWIDE NGL PRODUCTION

Dec. Jan. Feb. Feb. 2010 2011 2011 2010 Change ——––—––––— $/bbl –––––––––——

Change, %

10.14 9.01 2.19 2.06

479.5 168.2 –22.6 –110.0

14.69 23.37 11.55 15.40 2.61 2.60 2.62 4.67

4.03 5.74 3.36 2.23

19.34 9.66 –0.76 2.45

6.67

9.59 15.04

1.43

13.61

954.8

5.34 7.11

4.19 6.36

2.84 5.13

4.20 5.16

–1.36 –0.03

–32.3 –0.5

13.36 22.04

10.40

11.64

111.9

15.38 3.06

2.08

1.19

2.39

–1.20

–50.2

0.11

0.81 –3.65

––

–3.65

––

3.95

5.03

2.39

1.49

62.4

3.88

11 month Change vs. average previous Nov. Oct. –– production –– –––— year —– 2010 2010 2010 2009 Volume ————–—–––— 1,000 b/d ———––———— %

Source: Jacobs Consultancy Inc. Data available in OGJ Online Research Center.

US NATURAL GAS BALANCE DEMAND/SUPPLY SCOREBOARD Dec. Total YTD Dec. Nov. Dec. 2010-2009 ––– YTD ––– 2010-2009 2010 2010 2009 change 2010 2009 change ——————————— bcf ——————————— DEMAND Consumption ................... Addition to storage .......... Exports ............................ Canada ......................... Mexico .......................... LNG ............................... Total demand ..................

2,725 66 121 76 30 15 2,912

1,968 163 124 84 30 10 2,255

2,484 44 116 81 28 7 2,644

241 22 5 –5 2 8 268

24,134 22,839 3,298 3,315 1,123 1,072 733 701 325 338 65 33 28,555 27,226

1295 –17 51 32 –13 32 1329

SUPPLY Production (dry gas) ........ Supplemental gas............ Storage withdrawal.......... Imports ............................ Canada.......................... Mexico ........................... LNG................................ Total supply .....................

1,890 5 732 301 271 1 29 2,928

1,823 6 238 262 230 0 32 2,329

1,717 5 738 349 311 3 35 2,809

173 0 –6 –48 –40 –2 –6 119

21,571 20,580 67 65 3,303 2,966 3,683 3,751 3,222 3,271 30 28 431 452 28,624 27,362

991 2 337 –68 –49 2 –21 1,262

4,305 3,107 7,412

4,304 3,773 8,077

4,300 3,847 8,147

4,277 3,130 7,407

91 617 368 2,068 200

80 599 368 2,057 200

82 614 377 1,996 200

78 641 369 1,905 200

3 –26 8 90 ––

4.5 –4.1 2.1 4.7 ––

213

210

204

201

2

1.1

3,557

3,514

3,473

3,395

78

2.3

Norway................................. United Kingdom ................... Other Western Europe............................. Western Europe .............

271 112

278 107

258 114

276 127

–19 –14

–6.8 –10.6

10 393

10 395

10 381

10 414

–– –32

–1.4 –7.8

Russia ................................. Other FSU ............................ Other Eastern Europe............................. Eastern Europe ..............

425 150

425 150

435 150

422 150

13 ––

3.2 ––

13 588

14 589

14 599

14 586

–– 13

–3.2 2.2

Algeria ................................. Egypt ................................... Libya.................................... Other Africa ......................... Africa..............................

350 70 80 154 654

350 70 80 153 653

350 70 80 151 651

345 70 80 143 637

5 –– –– 9 14

1.6 –– –– 6.2 2.3

Saudi Arabia........................ United Arab Emirates .......... Other Middle East ................

1,600 250 1,570

1,560 250 1,570

1,528 250 1,554

1,415 250 1,359

113 –– 194

8.0 –– 14.3

Middle East.....................

3,420

3,380

3,331

3,024

307

10.2

Australia.............................. China................................... India .................................... Other Asia-Pacific................ Asia-Pacific .................... TOTAL WORLD .................

64 650 –– 174 888 9,501

71 650 –– 174 895 9,425

71 650 –– 174 894 9,330

70 650 –– 169 889 8,944

1 –– –– 5 6 386

1.1 –– –– 2.9 0.6 4.3

Totals may not add due to rounding. Source: Oil & Gas Journal. Data available in OGJ Online Research Center.

OXYGENATES Dec. Nov. YTD YTD 2010 2010 Change 2010 2009 Change ———————––—––– 1,000 bbl –––—————————

NATURAL GAS IN UNDERGROUND STORAGE Dec. Nov. Oct. Dec. 2010 2010 2010 2009 Change —————————— bcf —————————— Base gas Working gas Total gas

Brazil ................................... Canada................................ Mexico ................................. United States ...................... Venezuela ............................ Other Western Hemisphere ..................... Western Hemisphere..................

28 –23 5

Source: DOE Monthly Energy Review. Data available in OGJ Online Research Center.

Fuel ethanol Production .................. Stocks .........................

28,457 17,940

27,745 18,029

712 –89

MTBE Production .................. Stocks .........................

1,328 561

1,351 765

–23 –204

315,018 256,149 17,940 16,711

13,499 561

16,115 1,294

58,869 1,229

–2,616 –733

Source: DOE Petroleum Supply Monthly. Data available in OGJ Online Research Center.

US HEATING DEGREE-DAYS Jan. 2011

Jan. 2010

Normal

2011 % change from normal

New England ................................................................ Middle Atlantic ............................................................. East North Central........................................................ West North Central ....................................................... South Atlantic .............................................................. East South Central ....................................................... West South Central....................................................... Mountain ...................................................................... Pacific ..........................................................................

1,309 1,228 1,363 1,470 710 893 617 936 511

1,203 1,131 1,320 1,456 724 924 643 902 490

1,246 1,158 1,302 1,390 643 820 593 951 564

5.1 6.0 4.7 5.8 10.4 8.9 4.0 –1.6 –9.4

3,708 3,373 3,851 4,057 1,960 2,399 1,455 2,787 1,710

3,683 3,231 3,780 4,180 1,785 2,355 1,644 3,065 1,713

3,708 3,349 3,774 4,085 1,726 2,230 1,498 3,098 1,817

–– 0.7 2.0 –0.7 13.6 7.6 –2.9 –10.0 –5.9

US average*............................................................

956

931

917

4.3

2,682

2,662

2,656

1.0

Total degree-days ———––July 1 through Jan. 31 ––——— 2011 2010 Normal

% change from normal

*Excludes Alaska and Hawaii. Source: DOE Monthly Energy Review. Data available in OGJ Online Research Center.

Oil & Gas Journal | Mar. 7, 2011

123

MARKETPLACE DEADLINE for MARKETPLACE ADVERTISING is 10 A.M. Tuesday preceding date of publication. Address advertising inquiries to MARKETPLACE SALES, 1-800-331-4463 ext. 6301, 918-832-9301, fax 918-832-9201, email: [email protected]. • DISPLAY MARKETPLACE: $390 per column inch, one issue. 10% discount three or more CONSECUTIVE issues. No extra charge for blind box in care. Subject to agency commission. No 2% cash discount.

E M P L O YM E N T

TapCo International, Inc. Oil & Gas Systems Division, Sales & Marketing seeks International Business Development Manager in Houston, TX to identify & set up representative network in Asia Pacific region. Review technical specs & evaluate process conditions, required metallurgy, available utilities, site conditions, space restrictions to generate technical feasibility. Analyze process parameters, facility layout & operational data such as production costs, process flow charts & production schedules. Provide sales & tech training to agents & customers, to include steam requirement, cooling water, & electrical availability. Interact with in-house mechanical, electrical, instrumentation & systems engineers re customer requirement. Liaise with engineering & process licensors to develop products. Manage independent representatives as it relates to leveraging existing clients & bus development. Perform situation analysis of market competitor activities & recommend best channel for product promotion in region. Assist inside sales department with drafting quotes, provide support in negotiating & closing contracts. Survey customers for satisfaction, investigate & resolve issues & provide after-market support. Good understanding & work within ASTM, ANSI, API, ASME standards on piping, SIL, Explosion proof ratings. Understand the instrumentation, controls & PLC reqs & terminologies. Requires BS in Ind Eng, Marketing, Bus or rel. & 5 yrs exp in industrial valve sales. Exp must include: customer process & controls; valve, actuators & control products & their applications; bus dev mgmt; project planning & marketing; intl Sales or Business Dev. To apply send resume to TapoCo International: Attn Human Resources, PO Box 10630, Houston, TX 77206-0630

124

• UNDISPLAYED MARKETPLACE: $4.00 per word per issue. 10% discount for three or more CONSECUTIVE issues. $80.00 minimum charge per insertion. Charge for blind box service is $60.00 No agency commission, no 2% cash discount. Centered/Bold heading, $12.00 extra. • COMPANY LOGO: Available with undisplayed ad for $85.00. Logo will be centered above copy with a maximum height of 3/8 inch. • NO SPECIAL POSITION AVAILABLE IN MARKETPLACE SECTION. • PAYMENT MUST ACCOMPANY ORDER FOR MARKETPLACE AD.

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SBM Atlantia, Inc. in Houston, TX seeks Lead Engineer – Marine & Drilling. Qualified applicants will possess a Bachelor’s degree in Marine Engineering or related engineering discipline and five years of experience in job offered or five years of offshore project related experience. Email resume to [email protected]. Must put job code 3052019 on resume.

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SBM Atlantia, Inc. in Houston, TX seeks Naval Architect. Qualified candidate will possess a BS in Naval Architecture or a related field and 2 years of experience in the job offered or 2 years offshore project experience in naval architecture including marine fabrication materials, procedures and capabilities, procedures and capabilities. Email resume to [email protected]. Resume must include job code 3052015. Friede & Goldman, Ltd. seeks Sr. Structural Engineer to work in Houston, TX to develop environmental and motion induced loading criteria based on provided specifications and design economical structural drawings for vendor provided equipment. Master’s degree and relevant experience required. Submit resume to Jennifer Bardsley at eng.HR@fng. com. Must put job code SE-04 in subject line and on resume. Det Norske Veritas Classification (Americas), Inc. seeks a Marine Surveyor in Long Beach, CA to carry out inspections and certification of ships in service, with some survey activities related to the inspection and certification of various machinery, materials and equipment and certification of dynamic positioning systems both onboard ships and at manufacturer. Requires a Bachelor’s in Marine Eng. or related field and relevant exp. Extensive travel required. Authorization to work permanently in the U.S. required. Apply at https://dnvna.tms.hrdepartment.com/ cgi-bin/a/searchjobs_quick.cgi Champion Technologies, Inc. is seeking a Senior Polymer Research Chemist in Fresno, TX to provide support consistent with goals determined by technology management and be responsible for the formulation work and testing of products. Qualified applicants should send their resumes to 3200 SW Freeway, Suite 2700, Houston, TX 77027 attn: Njsane Courtney. Please reference job code 1721 in all correspondence.

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Oil & Gas Journal | Mar. 7, 2011

MARKETPLACE E Q U I P M EN T F O R SA L E

E QUIPME NT F OR S A L E

NOT ICE OF S A L E

SURPLUS GAS PROCESSING/REFINING EQUIPMENT

FOR SALE/RENT

THE TEXAS A&M UNIVERSITY SYSTEM NOTICE OF SALE OF OIL, GAS, AND SULPHUR LEASE

Bexar Energy Holdings, Inc. Phone 210 342-7106 Fax 210 223-0018 www.bexarenergy.com Email: [email protected]

1 Billion PPY Ethylene Glycol Plant For Sale Produces MEG, DEG, TEG Plant features Boiling Water Reactor installed in 1991 Office: 225-923-3602 Email: [email protected] www.LCEC.com FOR SALE/RENT

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The Board of Regents of The Texas A&M University System, pursuant to provisions of V.T.C.A., Education Code, Chapter 85, as amended, and subject to all policies and regulations promulgated by the Board of Regents, offers for sale at public auction in Suite 2079, System Real Estate Office, The Texas A&M University System, A&M System Building, 200 Technology Way, College Station, Texas, at 10:00 a.m., Wednesday, March 23, 2011, an oil, gas and sulphur lease on the following described land in Loving County, Texas. The property offered for lease contains 1,620.5 net mineral acres, more or less, and described as follows: Sections 18, 30, 34, 40, and 44, Block 54, Township 1, T&P RR Co. Survey, Loving County – 3/16th mineral interest; North Half of Section 8, Block 54, Township 2, T&P RR Co. Survey, Loving County – 1/8th mineral interest; South Half of Section 8, Block 54, Township 2, T&P RR Co. Survey, Loving County – 7/16th mineral interest; Section 6, Block 54, Township 2, T&P RR Co. Survey, Loving County – 1/4th mineral interest; Sections 12, 24, and 36, Block 55, Township 1, T&P RR Co. Survey, Loving County – 3/16th mineral interest; Sections 46 and 48, Block 55, Township 1, T&P RR Co. Survey, Loving County – 1/8th mineral interest; North Half of Section 3, and North Half & Southwest Quarter of Section 12, Block 55, Township 2, T&P RR Co. Survey, Loving County – 1/8th mineral interest; Southeast Quarter of Section 12, Block 55, Township 2, T&P RR Co. Survey, Loving County – 1/16th mineral interest; and Section 13 East of the Pecos River, Block 56, Township 2, T&P RR Co. Survey, Loving County 1/8th mineral interest. The lease will be without warranty of any kind. Each bidder will be required to conduct its own due diligence to confirm title to the mineral interests being leased. For inquiries regarding minimum lease terms, please call: Melody Meyer The Texas A&M University System System Real Estate 200 Technology Way, Suite 2079 College Station, Texas 77845-3424 979-458-6350

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MARKETPLACE R E A L E STATE

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Oil & Gas Journal | Mar. 7, 2011

ADVERTISING SALES

ADVERTISERS INDEX

Houston

COMPANY NAME

U.S. Sales Manager, Marlene Breedlove; Tel: (713) 9636293, E-mail: [email protected]. Regional Sales Manager, Mike Moss; Tel: (713) 963-6221, E-mail: [email protected]. PennWell - Houston, 1455 West Loop South, Suite 400, Houston, TX 77027. Fax: (713) 963-6228

South / Southwest / Texas / Northwest / Midwest / Alaska Marlene Breedlove, 1455 West Loop South, Suite 400, Houston, TX 77027; Tel: (713) 963-6293, Fax: (713) 963-6228; E-mail: [email protected]

Northeast / Texas / Southwest Mike Moss, 1455 West Loop South, Suite 400, Houston, TX 77027; Tel: (713) 963-6221, Fax: (713) 963-6228; E-mail: [email protected]

AFLAC

PAGE

13 25 18

www.barnesdistribution.com

BCCK Engineering, Inc.

11 18

Stan Terry, 1455 West Loop S. Ste. 400, Houston, TX 77027; Tel: (713) 963-6208, Fax: (713) 963-6228; E-mail: [email protected]

Cameron

19

Champion Technologies

Roger Kingswell, 9 Tarragon Road, Maidstone, ME16 0UR, United Kingdom; Tel. 44.1622.721.222; Fax: 44.1622.721.333; Email: [email protected]

France / Belgium / Spain / Portugal / Southern Switzerland / Monaco Daniel Bernard, 8 allee des Herons, 78400 Chatou, France; Tel: 33(0)1.3071.1119, Fax: 33(0)1.3071.1119; E-mail: [email protected]

Germany / Austria / Northern Switzerland / Eastern Europe / Russia / Former Soviet Union Sicking Industrial Marketing, Kurt-Schumacher-Str. 16, 59872, Freienohl, Germany. Tel: 49(0)2903.3385.70, Fax: 49(0)2903.3385.82; E-mail: wilhelms@pennwell. com; www.sicking.de Andreas Sicking

Japan

C2

99

www.nasindustrial.com

113

www.offshoreindia.com

17

Conference Connection

61 119 112 109 9

Expotim International Fair Organizations, Inc.

Brazil

51

www.hytorc.com

C3 7

Kronos

Michael Yee, 19 Tanglin Road #05-20, Tanglin Shopping Center, Singapore 247909, Republic of Singapore; Tel: 65 9616.8080, Fax: 65.6734.0655; E-mail: yfyee@singnet. com.sg

www.kronos.com

Lagcoe

India

Linde AG

Rajan Sharma, Interads Limited, 2, Padmini Enclave, Hauz Khas, New Delhi-110 016, India; Tel: +91.11. 6283018/19, Fax: +91.11.6228 928; E-mail: rajan@ interadsindia.com

Marcus Evans

21

57

Shell Global Solutions

29

Siemens AG

2

Siirtec

41

www.sini.it

35

SPE

83

www.spe.org

15

Statoil

C4

www.statoil.com

81

USAEE

16

www.usaee.org

www.lagcoe.com

23

Victory Energy Operations, LLC

67

www.victoryenergy.com

www.linde.com www.marcusevans.com

Scott Health & Safety

www.siemens.com

www.kobelco.co.jp

Singapore / Australia / Asia-Pacific

52

www.shell.us

www.iri-oiltool.com

Kobelco/Kobe Steel, Ltd.

Reprints

www.scotthealthsafety.com

37

Industrial Rubber

17

[email protected]

www.fwc.com/green

Hytorc

63

www.primenergy-production.com www.rainforrent.com

www.fmctechnologies.com

Foster Wheeler

53

www.postle.com

Rain for Rent

www.expotim.com

FMC Technologies, Inc.

103

www.polyguardproducts.com

Primenergy

www2.emersonprocess.com

65

www.pennenergyequipment.com

Postle Industries, Inc.

www.instrument.eitep.de

Emerson Process Management

118, 126

www.PennEnergyResearch.com

Polyguard

www.eage.org

EITEP

72a

www.wyman-gordon.com

PennEnergy Equipment

www.deepoffshoretechnology.com

EAGE

31

www.panalpina.com

PennEnergy Research

www.cconnection.org

Deep Offshore Technology

87

www.ogj.com

PCC / Wyman Gordon

www.cit.com

e.x.press sales division, ICS Convention Design Inc. 6F, Chiyoda Bldg., 1-5-18 Sarugakucho, Chiyoda-ku, Tokyo 101-8449, Japan, Tel: +81.3.3219.3641, Fax: 81.3.3219.3628; Kimie Takemura, Email: [email protected]; Manami Konishi, E-mail: [email protected]; Masaki Mori, E-mail: masaki. [email protected]

Grupo Expetro/Smartpetro, Att: Jean-Paul Prates and Bernardo Grunewald, Directors, Ave. Erasmo Braga 22710th and 11th floors Rio de Janeiro RJ 20024-900 Brazil; Tel: 55.21.3084.5384, Fax: 55.21.2533.4593; E-mail: [email protected] and bernardo@ pennwell.com.br

Nachurs Alpine Solutions Industrial

Panalpina Management, Ltd.

www.champ-tech.com

CIT United Kingdom / Scandinavia / Denmark / The Netherlands

20

Oil & Gas Journal app www.c-a-m.com

Louisiana / Canada

Mustang Engineering

Offshore India

www.bcck.com

Cajun Crawfish Boil

33

www.mustangeng.com

www.bakerhughes.com

Barnes Distribution

PAGE

MTU Detroit Diesel www.mtu-online.com

www.aflac.com

Baker Hughes

COMPANY NAME

47

Weatherford

4, 5

www.weatherford.com

Italy Ferruccio Silvera, Viale Monza, 24 20127 MILANO Italy; Tel:+02.28.46 716; E-mail: [email protected]

Oil & Gas Journal | Mar. 7, 2011

This index is provided as a service. The publisher does not assume any liability for errors or omission.

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From the Subscribers Only area of

www.ogj.com

THE EDITOR’S PERSPECTIVE

MARKET JOURNAL

Shale plays show how resource work helps economies

Libyan fight favors refiners

by Bob Tippee, Editor The economic goodness of resource development is, or should be, axiomatic. With inputs of labor and capital, resources yield wealth, the generation of which creates jobs, incomes, and tax revenue for governments. In towns surrounded by active oil and gas development, prosperity becomes manifest in no-vacancy signs aglow outside motels, new pickup trucks cruising streets, parking lots overflowing around steak houses. For practical economic analysis, quantification is unnecessary. Who, besides the owner, needs sales figures from the convenience store? Most people can deduce what they need to know about business conditions from shelves empty by sundown every Friday in the beer cooler. Still, numbers can be instructive for anyone squeamish about the drilling of holes and extraction of hydrocarbons. A new report by the University of Texas at San Antonio Institute for Economic Development’s Center for Community and Business Research shows how the Eagle Ford shale play helps 24 Texas counties. Last year, says the study, which was funded by America’s Natural Gas Alliance, Eagle Ford activity generated $2.9 billion in total revenue and supported 12,601 full-time jobs, yielding $511.8 million in salaries and benefits to workers. The activity contributed $1.3 billion to gross state product, boosting state-government revenue by $61 million and local government revenue by $48 million. In a similar study last year for the American Petroleum Institute, Timothy J. Considine of Natural Resources Economics Inc., Laramie, Wyo., estimated the Marcellus shale play in 2009 contributed $4.8 billion to gross regional product of West Virginia and Pennsylvania. Marcellus activity generated more than 57,357 jobs and local, state, and federal tax collections totaling $1.7 billion, Considine said. In a country where 13.9 million people are looking for work and many states face insolvency, numbers like these deserve more attention than they receive in ludicrous discussions about the supposed need to limit shale drilling. Nobody close to the action needs gee-whiz data to see that people in booming shale plays are working hard and eating steak. Most have places to stay. ONLINE FEB. 25, 2011 | [email protected]

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by Sam Fletcher, Senior Writer In the last full week of February, front-month crude posted the largest weekly gain in 2 years in the New York market as turmoil in Libya shut in 850,000 b/d of crude production. After oscillating around $100/bbl during the week, the April contract for benchmark US light, sweet crudes closed at $97.88/bbl Feb. 25 on the New York Mercantile Exchange, up 1% for the day and 9% for the week. In London, the April IPE contract for North Sea Brent crude continued its advance to $112.14/bbl. “The Libyan crisis currently presents the most serious geopolitical risk to global oil supply in recent memory,” said analysts in the Houston office of Raymond James & Associates Inc. “The oil market is fearful not just of continued Libyan production disruptions but the risk of them spreading to Algeria and, in an ‘Armageddon scenario,’ the Arabian Peninsula. The Organization of Petroleum Exporting Countries could cope with a total Libyan shutdown, and even a concurrent Algerian shutdown would be difficult but generally manageable, “albeit with much higher prices.” However, Raymond James analysts said, “There is simply no precedent for a Saudi-sized supply disruption, and to say that the oil market would go berserk in such a situation is an understatement. All in all, we wouldn’t lose sleep over this extreme-case scenario, but it would seem that $100/bbl WTI (add $10 for Brent) is here to stay, courtesy of the Middle East.”

Refining outlook Anuj Sharma, research analyst at Pritchard Capital Partners LLC, Houston, said, “Although Saudi Arabia has reiterated its commitment to put more supplies into the market, the challenge is that Libyan production is of sweeter grade than what could be replaced by the Saudi supplies; and the European refineries, which process low-sulfur Libyan crude, would most likely not be able to process higher-sulfur Saudi crude.” If Libyan oil exports are disrupted for an extended period, it could create a severe shortage of sweet crude in the global market. Paul Sankey at Deutsche Bank Equity Research for North America, cautioned, “Don’t make the mistake of thinking that Libya is bad for refining.” Global oil prices are not yet high enough to destroy demand; therefore, “refining trade can keep working, especially if one takes the view that the loss of Libyan barrels will tighten Atlantic Basin product markets,” he said. Sankey said, “Libya has been a stable, long term, nearby source of light sweet crudes for European refiners, notably the Italians. Replacing those barrels with a somewhat heavier, sourer, and more distant Saudi supply will require more tankers, more time, and yield less transport fuels. That supports a bullish [US] Midcontinent and Gulf Coast refining stance. By contrast this is highly challenging to East Coast and northwest European refiners, using light sweet Brent priced grades.” Despite increased export of petroleum products, US stocks remain at multiyear highs. “There is not enough internal demand for the US refining sector and moving to a model of net exporter of products has not managed to reduce the domestic stock levels,” said Olivier Jakob at Petromatrix, Zug, Switzerland. On a yield basis, the US is running 2.2 million b/d for distillate exports and 1.1 million b/d for gasoline exports. If US refining focused on domestic rather than international markets, Jakob said, “It could be running with at least 1.1 million b/d less crude oil in its refining system. The US imports 1.1 million b/d of crude from Saudi Arabia.” If US refineries focused on the domestic market instead of exporting products, he said, “The US could cut totally its imports of crude oil from Saudi Arabia and not face any domestic supply shortages. “The dependency of the US on oil from the Middle East is therefore much lower than suggested by the crude oil import numbers, given that a large portion of crude oil imported in the US is being processed for the export of products, not for the domestic market.” ONLINE FEB. 28, 2011 | [email protected]

Oil & Gas Journal | Mar. 7, 2011

Offshore LNG loading is like threading a needle on a trampoline: It takes highly specialized equipment. Seven years ago we began developing the world’s first offshore LNG loading system. We designed it with constant motion swivels to handle rapid, unpredictable motions. We developed a patented cable targeting system to enable connection under these same conditions. And we helped make offshore LNG both practical and cost-effective. To see what we’ve done and how we’re approaching a next generation, worst-condition solution, visit www.fmctechnologies.com/offshoreLNG

We put you first. And keep you ahead. www.fmctechnologies.com © 2011 FMC Technologies. All rights reserved.

Maximizing Upstream Performance PetrisWINDS Operations Management Suite Implement the complete suite or begin with one module and add functionality as you need it.

Integrated Solutions for:

AFE Management Drilling and Production Operations Asset Tracking and Management Supplement to:

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The last few years have been a harsh reminder

of just how cyclical, volatile and unpredictable the oil and gas industry can be. Global economic and geopolitical forces combined with industry-internal issues are creating a unique set of twenty-first-century challenges for oil and gas operators: •

Uncertain worldwide demand, price volatility and risk.

•

To replace reserves, operators must work in increasingly challenging environments that impact time to market and pose inherent complexity and risk for drilling, completion, and production operations.

•

The industry workforce faces retiring experienced workers, mid-career staff gaps, and a limited pool of qualified new candidates.

•

An exponential growth of data is overloading everyone. The inability to properly manage and use that data is itself creating challenges. Data is often incomplete, conflicting or can’t be located, which wastes time and increases uncertainty, risk and regulatory delays.

•

Need for safety vigilance continues. Though safety has long been an integral part of industry culture, the April 2010 tragedy in the Gulf of Mexico is a chilling reminder of the inherent risk in upstream operations.

Against this backdrop, operators are striving to safely maintain and improve reserves, reduce cycle times and costs, and maximize their ability to take advantage of all possible opportunities.

Custom Publishing VP, PennWell Custom Publishing Roy Markum [email protected]

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Jim Pritchett, President and CEO

Introducing OMS Petris solutions can help operators meet these challenges. We’re proud to be launching the latest addition to our solution portfolio, PetrisWINDS Operations Management SuiteTM (OMS). OMS is an enterprise-wide, modular solution that provides complete coverage of the well operations lifecycle by supporting capital planning, drilling operations, production management, regulatory reporting, land and facilities. The modular design lets operators choose components in “bite-size” pieces, beginning with the module(s) that are most crucial for their specific, immediate needs, with options to easily add modules to meet emerging needs. As an integrated suite, data is entered only once and used throughout the process, simplifying workflows and reporting while ensuring data integrity. OMS is the only system to deliver AFE, drilling and production operations integrated in a single solution. While drilling and production are distinct phases in the upstream development lifecycle, they share a common asset—the well. There is real synergy and value to be realized in this integration. Page 3 provides more details about the unique value that OMS delivers for drilling and production operations. OMS is derived from a product that we acquired several years ago, with a solid customer base of about 50 E&P companies, as a strategic complement to our existing PetrisWINDS suite of upstream solutions. We’ve invested considerable resources to redesign and re-engineer that great concept into a robust and scalable solution that can be used across global E&P operations. To

President and CEO, Petris Jim Pritchett Managing Editor Marla S. Wunderlich [email protected]

Presentation Editor Chad Wimmer Production Manager Shirley Gamboa Circulation Manager Tommie Grigg

learn more about the underlying architecture, how it enables field data capture, and delivers a foundation for the future, see page 4. OMS delivers robust data governance capabilities to assure continued accuracy and quality once data is captured. To achieve initial data quality, PetrisWINDS DataVeraTM provides solutions to assess, clean, and migrate data—a vital first step when moving from a legacy environment to OMS. To learn more, see page 5. To complete the business picture, OMS has been designed to work closely with Petris’ integration and business intelligence platform, PetrisWINDS EnterpriseTM and Analytics. These allow OMS to share data with line-ofbusiness systems through one interface and deliver powerful tools for charting, dashboards and analysis. For more on integration and business intelligence, see pages 6 and 7. Petris solutions are designed to be deployed on an operator’s in-house computing environment or in our applicationand data-hosting “cloud” computing environment, which has been designed specifically to meet the security, reliability, and performance needs of 24/7/365 global oil and gas operations. Petris knows that using OMS as part of an integrated upstream solution provides compelling value to your business. The combination of our technology solutions, processes, and know-how can help your company clean and migrate your data then implement solutions and processes to maintain that quality—so you can trust your data, and be confident in the decisions that you make based on that data. Please review the next few pages to learn more about OMS and how Petris’ broad range of solutions and consulting services can help your E&P company maintain and improve reserves, reduce cycle times, and maximize your ability to take advantage of all possible opportunities. To ask questions, learn about industry best practices, see an OMS demo or arrange for a trial, contact us today.

PennWell Petroleum Group 1455 West Loop South, Suite 400 Houston, TX 77027 U.S.A. 713.621.9720 • fax: 713.963.6285

PennWell Corporate Headquarters 1421 S. Sheridan Rd., Tulsa, OK 74112 P.C. Lauinger, 1900–1988 Chairman, Frank T. Lauinger President/CEO, Robert F. Biolchini

Sponsored by:

Supplement to:

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Focus on the Well: Integrating Drilling Operations and Production Management in a Single Solution Drilling challenges center on a continuous need to reduce non-productive time (NPT) and improve efficiency, to drill and complete the well and reach the Production phase— when a well begins to make money. For Production Operations, the challenge is to keep the well flowing and profitable. This involves monitoring production, identifying problems, and determining remedial actions to optimize production, maximize recovery, and extend the producing life of the well. Drilling and Production Operations have stringent, varied, and dynamic reporting requirements, which can change frequently, for example, because of new asset partners or increased regulatory oversight. These reports include: daily drilling operations, production operations and hydrocarbon allocations, partner and many regulatory reports, to name a few. The accuracy and timeliness of these reports are crucial to decision quality, credibility, and legal and growing regulatory requirements.

Data Assets to Manage Physical Assets Data about and from these operations and assets can be used to monitor progress, identify and solve problems, and make better decisions to improve operations in service of the overarching goals of improving efficiency, reducing costs, improving reserves and realizing maximum asset value. The data itself is an asset that must be managed and maintained. But many E&P organizations struggle with how to capture and manage drilling and production data. While Drilling and Production are separate phases in the upstream development lifecycle, activities for both phases revolve around a single, primary asset—the well. Yet Drilling and Production Operations have traditionally been managed in different systems with separate data sources.

Multiple and conflicting data sources mean that workers can’t find the data they need, can’t trust the data they find, and lack the necessary tools to analyze data for answers and decisions.

Realizing Data Value to Improve Operations PetrisWINDS Operation Management Suite™ (OMS) delivers drilling operations and production management capabilities in a single integrated solution. Data for a well is entered once, and then managed, maintained and accessed from a common database. Composed of five integrated modules, OMS is an enterprise solution for the acquisition, management and reporting of operational data and workflows. A scalable master data management solution, OMS provides robust data governance to ensure a high degree of corporate data quality and consistency. An enterprise-wide solution, OMS provides complete coverage of the well operations lifecycle by supporting capital planning and AFEs, drilling operations, production management, and facilities,

and makes it possible to share information throughout an E&P organization, regardless of location.

One Integrated Source for Well and Asset Data OMS provides a common environment for master well data management through an open and integrated database, named the PetrisWINDS Operations Data Model, which is based on the Professional Petroleum Data Management (PPDM) data model (www. ppdm.org), an oil and gas industry standard (see page 5). OMS also uses several key upstream data standards including WITSML (Well Information Transfer Markup Language), and PRODML (Production Markup Language), data-exchange standards from Energistics (www.energistics.org) that enable easy integration with external systems and seamless workflows within and across domains.

Unique Value OMS is the only product that integrates drilling and production operations management in a single solution. The integrated modules built on a standards-based architectural framework and that access a single flexible data source make it possible for an operator to define an operational hierarchy of all its assets, and manage those assets from a single solution. OMS’ modular design allows companies to start with the OMS module(s) they need most and easily add other modules to meet emerging needs.

The Oilfield Lifecycle Acquire

Mapping /

Reconnaissance

Prospect Generation

OMSTM is Asset Focused OMS is composed of these five integrated modules that access a common data model to manage the lifecycle of oil and gas assets.

Discovery

Reservoir Delineation

Facilities

Primary Production

Enhanced Revovery

Divest

Property MasterTM Authoritative tool to define and manage master well and asset data in OMS.

$

AFE ManagerTM AFE Ceation, Workflow-based Approval and Reporting Well Lifecycle ManagerTM Morning Reporting, Drilling and Completion Well Life Cycle Data Management Production ManagerTM Production Data Management, Hydrocarbon Allocation and Reporting Material Transfer ManagerTM Managing Inventory, Tracking and Approval of Movement

PertisWINDS Operations Data Model (PODM)

3

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WITSML

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ag

Pro

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4

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Input Files Inp

to be deployed on an operator’s inhouse computing environment or in our application- and data-hosting Microsoft cloud computing environment, which has been designed specifically to meet the security, reliability, and performance needs of 24/7/365 global oil and gas operations.

Maximum Flexibility The tiered-architecture and componentbased system design reduce complexity, ensure extensibility (easy to add or extend functionality) and make OMS easy to deploy and maintain, allowing companies to start with the OMS module(s) they need most and easily add other modules to meet emerging needs. Using Microsoft SQL Server, OMS delivers a data store that is centralized for data integrity and easy management, scalable to support the needs of the largest organizations, and compatible with many powerful and flexible reporting tools so that you can use that data for analysis, answers and better, quicker decisions. OMS can be deployed on a variety of devices, such as desktop and laptop computers, making the data and applications available anytime and anywhere. Petris solutions are designed

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PetrisWINDS Operations Management SuiteTM (OMS) is built on an architectural framework and technology that are crucial to delivering the information, workflows and functionality that operators need to support safe, efficient, and cost-effective operations. Moreover, the architecture provides a modern, state-of-the-art foundation to quickly and easily leverage emerging technologies and approaches, such as digital oilfield initiatives, which ensures that OMS can continue to evolve and meet the dynamic operations, business, and regulatory demands of upstream oil and gas. Key elements of the OMS foundation include a tiered, smart-client architecture that is fully service-oriented architecture (SOA) compliant, development on the Microsoft .NET Framework and Microsoft SQL database, and use of several key industry standards (which were described on page 3).

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Leveraging Technology to Maximize Business Performance

Security Role-based security supports Windows authentication and allows full implementation of corporate user hierarchies based on rights and permissions ensuring authorized access to OMS modules and data.

Regulatory Compliance Reporting OMS provides traceability using a logging module to track and log data and configuration changes across the system. Underlying technology provides easy-to-use reporting capabilities across OMS including transaction data reports, such as daily reports and summary reports, and analytical and comparison reports for operations and regulatory compliance. Reports can be easily customized for varying regulatory requirements in different countries or as needs and regulations change.

FIELD DATA CAPTURE Deployable on a laptop or workstation, OMS allows remote workers a mobile solution to access and gather data from the rig floor or field. Using WellSite ReporterTM for drilling and Field ReporterTM for production, remote workers can upload and synchronize operational data with the central OMS data store, at a regional or corporate office. Additionally, OMS supports automatic data imports from telemetry systems such as SCADA devices. PRODML data management use cases (for production) are also supported. For drilling operations, the OMS architecture supports the reference and transfer of WITSML report objects. This field-based data capture capability reduces errors and increases data quality and efficiency.

PETRIS MAXIMIZING UPSTREAM PERFORMANCE

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Achieving Lasting Data Quality through Data Governance

Common Master Data Store The keystone of OMS is a common database environment for asset operations

Facilities that manage hydrocarbons, such as pipelines, tank batteries and separators. Support facilities, such as roads, rigs and warehouses that support operations. Property Master lets you automate and seamlessly integrate data governance workflows with operations workflow, making it possible for you to achieve and maintain data quality, which ultimately maximizes your limited human resources and significantly contributes to sounder and quicker decisions, operational efficiency, profitability, safety, and regulatory compliance.

Managing Assets with Property Master PetrisWINDS Property MasterTM is the OMS module for defining and managing assets in the OMS database. These assets include: Sources of hydrocarbons such as wells, leases, pools/reservoirs and zones.

The OMS architecture features a secure, reliable central database, integrated OMS modules, and use of industry data management and exchange standards.

Presentation Layer

Achieving Data Quality Smart Client UI

Reports

Graphs

Charts/Trends

Service Layer

Well Lifecycle Manager

Property Master

Production Manager

Data Files

AFE

Material Transfer

Data Integration

Security

<WITSML/> SCADA Financials 3rd Party

Business Layer Licensing

Logging

Application Framework

Windows Services

Reports

Web Services

Validation

To achieve initial data quality, PetrisWINDS DataVeraTM provides solutions to assess, clean, and migrate data—a vital first step when moving from a legacy environment to OMS. Designed specifically for operators with large amounts of data from multiple sources, DataVera uses a growing set of industry-specific business rules and technology to automate QA/QC activities.

Equipment, physical hardware components such as pumps, compressors and drill bits.

and well data management, based on the industry standard Professional Petroleum Data Management (PPDM) framework. OMS provides a single, reliable, secure data source for all critical operations data, which can be accessed across the enterprise, from the well to the corporate office, to support sound decisions. A single data source means workers no longer have to waste time trying to figure out where to find data, or trying to resolve or manipulate data from disparate sources. A single data source also makes it possible to apply a uniform set of business rules and standards to ensure consistent data quality.

Workflow

Operators know that poor data quality increases uncertainty and risk, with impact on safety, efficiency, profitability, and regulatory compliance. For example, incorrect formation pressures can lead to bad decisions about proper mud weights to use while drilling, which could ultimately lead to a blow out. Consequently, it can take a long time for people to make a decision, while they try to confirm the accuracy of the data on which they are basing that decision. Good quality data means that it is accurate, current, easy to find, and easy to access. To ensure and maintain data quality, E&P organizations need well defined data governance programs that include: clearly defined data responsibilities, identification of official data sources, responsible parties and policies for update, and reliable yet flexible security for data access and usage. But given the challenges described above, how can organizations achieve and maintain data quality? Petris solutions leverage technology, industry-defined standards, and industry know-how to seamlessly integrate data governance processes and workflows with operations workflows and help operators achieve and maintain data quality.

Data Access Layer PODM

5

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Delivering Visibility and Streamlining Workflows through Integration To expand the view from operations to your overall business, PetrisWINDS Operations Management SuiteTM (OMS) has been designed to work with our data integration and interoperability application, PetrisWINDS EnterpriseTM (PWE). PWE is a robust and comprehensive data integration system and search engine that allows you to access all of your company’s vital information in one easyto-reach place. PWE seamlessly integrates OMS and other E&P and line-of-business systems, such as real-time data collection, financials and enterprise resource planning (ERP), land records, regulatory systems, and more.

Visibility This approach transparently federates multiple autonomous data sources into a single, persistent data store, the PWE catalog, which delivers visibility into your data, making it possible for you to see the complete picture—operations, business, regulatory all brought together in one logical view.

Consistency The PWE catalog also resolves variations in data type names from disparate data sources, providing standard naming conventions across the catalog. For example, if one application refers to “well” and another to “well name” those differences are resolved with a single common name.

New Workflows Though federated through PWE, the individual data sources also continue to operate with their native applications. However, PWE can be used to transfer data between applications, and those transfers can be automated using business rules. These types of transfers may be

6

used to synchronize data or they may be used to process through new workflows. For example, when a new well is to be drilled, first an AFE must be created, which is typically initialized in ERP and land systems, then is manually routed for approval through various internal and external levels. With PWE, OMS can be integrated with ERP and other systems and the same workflow can be automated, reinforcing an approval delegation of authority to ensure SOX compliance. This ensures consistency and greater accuracy from the start across your enterprise. Additionally, OMS provides Web Service access to all its data through PWE’s Web services module. This means you can build applications on top of OMS, access its database, and keep the data integrity intact.

PWE AND OMS VS. ERP ERP systems are based on accounting data, which is often 30 to 45 days in arrears, and limited to a historical look. With OMS—designed specifically for the unique needs of Drilling and Production Operations—data is entered daily, as it occurs, so operators have the most current data on which to make decisions to help manage operations and costs. Integration with PWE provides combined access to OMS and other legacy systems, delivering flexible, new ways to manage and use that data for faster and more reliable decisions.

Easy, Secure Access PWE delivers a robust and comprehensive text- and GIS map-based interface to the integrated systems, and allows you to search and manage your structured and unstructured data and information. The seamless and easy-to-use interface delivers secure global 24/7 access to your company’s data using a simple Web browser.

PetrisWINDS Enterprise Catalog Visibility

𰁴

Consistency

𰁴

New Workflows

PetrisWINDS Enterprise federates multiple data sources into a single virtual data store fostering data visibility and consistency, and new automated workflows.

Land

Seismic

Wellbore

OMS

ERP

PETRIS MAXIMIZING UPSTREAM PERFORMANCE

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Maximizing the Value from your Data with Business Intelligence In the last few pages we looked at Petris solutions that help you organize, integrate, find, clean and maintain the quality of your data. Now let’s look at how Petris helps you analyze that data so that you can better understand your operations and your business to reduce risks, improve efficiency, and minimize costs.

Better, Quicker Decisions An operator’s success depends on the ability to use its data to make better, quicker decisions and focus on critical issues that impact operating and financial performance. Analytics, a module in PetrisWINDS EnterpriseTM, makes it possible for you to efficiently measure and manage results across your organization through business intelligence reports and online dashboards that provide real-time access to technical and financial data. Integration with PetrisWINDS Operation Management SuiteTM (OMS) and PetrisWINDS EnterpriseTM (PWE) delivers integrated access to all data from systems across your enterprise. PWA delivers the tools and technology to transform huge volumes of raw and real-time data into actionable information.

Take drilling operations, for example. In a recent article published in Digital Energy Journal (DEJ, Drilling: Time for better data?, January 2011) one operator described a case where a drill bit was changed because it was thought to be the cause of reduced rate of penetration (ROP). Even after the new drill bit was installed, ROP still did not improve significantly. More examination of log data revealed that the drill bit had moved into a formation with different resistivity and the decreased ROP was probably due to the mud interacting differently with the rock. A change in the mud properties solved the problem— however, only after the additional cost and non-productive time of the bit change. With Analytics, this type of incident could have been mitigated with a dashboard environment that brings together all key operational attributes in one view and enables easy collaboration for better analysis, problem solving and decisions. Analytics offers mobile applications for access to reports using smart phones and other devices, and users can use data and perform analytics even when working offline.

Analytics delivers powerful and flexible analytical capabilities to help you discover root problems or the real source of problems.

Fast, Accurate Analysis With Analytics you can quickly and easily create custom dashboards, reports and charts that let you visualize key performance indicators (KPI) and trends before they become problems. This capability enables decision makers and executives to access a full range of technical, operational, and business information for their oil and gas assets. Analytics delivers powerful and flexible analytical capabilities to help you discover root problems or the real source of problems.

7

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The PetrisWINDS® Family of Products Improving information management reduces errors and inefficiencies, saving time and creating value. Enterprise Information and Business Intelligence Enterprise OneTouch

Data, Quality and Workflow Management Operations Management Suite Recall Data Management OneSource DataVera

E&P S Software Applications ZEH Plotting Solutions Recall Applications DrillNET OneCall

About Petris Petris is a leading supplier of practical data management solutions utions and geoscience applications to the global energy industry. Founded in 1994 and with over 500 clients throughoutt the world, Petris leverages its knowledge and insight to design technology that integrates information from diverse data stores tores including managerial, seismic, borehole, production, drilling, and pipeline to enable continually better decision making and application transparency. Our suite of data management and integration solutions helps E&P &P companies extract the most value from their existing data investment and gives users access to trustworthy information where re they want it, when they want it and in the format required. Petris enhances each of its solutions with a range of professional nal services to help identify, aggregate, review/clean, and manage data over its lifecycle. High quality integrated data helpss users and managers make better decisions in less time. Petris can ensure accuracy, consistency, and completeness to inspire nspire user confidence in the data.

To learn more about Petris, visit

www.Petris.com

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