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Oil and gas journal volume 109, issue 3

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International Petroleum News and Technology




Jan. 17, 2011







Volume 109.3


16 Spill panel seeks overhaul
of safety culture, regulation
Bob Tippee

The report by a presidential commission
studying last year’s Macondo well disaster in
the Gulf of Mexico calls for overhaul both of
the oil and gas industry’s safety culture and of
offshore regulation.

19 Stronger-than-expected
demand to drive oil prices,
experts say
Nick Snow

20 EIA: Global oil markets
to tighten in next 2 years

Outlooks in four states

23 NTSB recommends safety actions
in San Bruno line blast probe
Nick Snow

24 Talisman to grow
in high-return shale plays

Alan Petzet

Is Iraq going nuclear?

Nick Snow

21 Chamber to fight EPA’s GHG
program, excessive reform
Nick Snow

The video below, courtesy of Range Resources Corp., Fort Worth, features a virtual
field tour of the company’s Midcontinent division.


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Visit our video library

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U.S. Sales Manager, Marlene Breedlove; Tel: (713) 9636293, E-mail: marleneb@pennwell.com. Regional Sales
Manager, Mike Moss; Tel: (713) 963-6221, E-mail:
mikem@pennwell.com. PennWell - Houston, 1455 West
Loop South, Suite 400, Houston, TX 77027. Fax: (713)

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: marleneb@pennwell.com

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
Chief Editor-Exploration
Chief Technology Editor-LNG/Gas Processing
Production Editor
Pipeline Editor
Senior Editor-Economics
Senior Editor

Northeast / Texas / Southwest
Mike Moss, 1455 West Loop South, Suite 400, Houston,
TX 77027; Tel: (713) 963-6221, Fax: (713) 963-6228;
E-mail: mikem@pennwell.com

Louisiana / Canada
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77027; Tel: (713) 963-6208, Fax: (713) 963-6228;
E-mail: stant@pennwell.com

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The Netherlands
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com; www.sicking.de Andreas

e.x.press sales division, ICS Convention Design Inc.
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Grupo Expetro/Smartpetro, Att: Jean-Paul Prates and
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Rajan Sharma, Interads Limited, 2, Padmini Enclave,
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Ferruccio Silvera, Viale Monza, 24 20127 MILANO Italy;
Tel:+02.28.46 716; E-mail: info@silvera.it

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Senior Writer
Senior Staff Writer
Survey Editor/News Writer
Vice-President/Group Publishing Director
Vice-President/Custom Publishing

Bob Tippee, bobt@ogjonline.com
Alan Petzet, alanp@ogjonline.com
Warren R. True, warrent@ogjonline.com
Guntis Moritis, guntism@ogjonline.com
Christopher E. Smith, chriss@ogjonline.com
Marilyn Radler, marilynr@ogjonline.com
Steven Poruban, stevenp@ogjonline.com
Sam Fletcher, samf@ogjonline.com
Paula Dittrick, paulad@ogjonline.com
Leena Koottungal, lkoottungal@ogjonline.com
Jim Klingele, jimk@pennwell.com
Paul Westervelt, pwestervelt@pennwell.com
Roy Markum, roym@pennwell.com

PennWell, Tulsa office
1421 S. Sheridan Rd., Tulsa, OK 74112
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Jim Stilwell, jims@pennwell.com
Michelle Gourd, michelleg@pennwell.com
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Charlie Cole
Shirley Gamboa

Tel 703.533.1552
Washington Editor
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Los Angeles
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Oil Diplomacy Editor
Eric Watkins, hippalus@yahoo.com

OGJ News
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PennWell Corporate Headquarters
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President/Chief Executive Officer

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

Member Audit Bureau of Circulations & American Business Media
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Jan. 17, 2011


International News
for oil and gas professionals

Marathon Oil to spin off refining, pipeline assets
Marathon Oil Corp. will spin off its downstream business,
forming an independent refiner to be named Marathon Petroleum Corp. based in Findlay, Ohio. The parent company, Marathon Oil, will remain in Houston.
Gary R. Heminger, now Marathon Oil downstream executive vice-president, will be president and chief executive officer
of Marathon Petroleum. Clarence P. Cazalot Jr. remains Marathon Oil president and chief executive officer. Marathon Oil
expects the transaction to be effective June 30.
Refinery locations and capacities to be operated by the spunoff company are Garyville, La., 464,000 b/d; Catlettsburg, Ky.,
212,000 b/d; Robinson, Ill., 206,000 b/d; Detroit, 106,000 b/d;
Canton, Ohio, 78,000 b/d; and Texas City, Tex., 76,000 b/d.
Crude capacity of the Detroit refinery is being expanded by
15,000 b/d in a project that will increase heavy-oil processing
capacity by about 80,000 b/d.
Marathon Petroleum also will operate wholesale and retail
operations, including the Speedway retail chain, and Marathon
Pipe Line LLC. Through the pipeline subsidiary, the new company will own, operate, lease, or have ownership interests in
about 9,700 miles of oil and product pipelines.
Marathon Oil’s core exploration and production areas are
the US, Equatorial Guinea, Libya, and the North Sea. Other areas in which the company is active include Angola, Indonesia,
the Iraqi Kurdistan region, and Poland.
The upstream company also holds a 20% interest in the
Athabasca Oil Sands Project, a joint venture with Shell (60%)
and Chevron (20%) that includes the Muskeg River and Jackpine mines, the Scotford upgraders, and more than 215,000
acres of potentially mineable land.
Marathon Oil also has an integrated gas unit that includes a
60% interest in a 3.7-million-tonne/year LNG plant and 45% in
a methanol company in Equatorial Guinea.
Before the spinoff, Marathon Petroleum plans to borrow
$2.5-3 billion to establish a cash balance of at least $750 million. It will use cash above that level repay intercompany debt
with Marathon Oil. Remaining proceeds will be distributed to
Marathon Oil before the spinoff date.
JP Morgan and Morgan Stanley will provide a $2.5 billion,

Oil & Gas Journal

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

364-day bridge facility. The firms also will provide Marathon
Petroleum a $2 billion, 4-year revolving credit facility.
Before the spinoff, Marathon Oil will reduce its long-term
debt by about $2.5 billion through cash on hand and proceeds
of the debt repayment from Marathon Petroleum. It will continue servicing the remaining $5 billion in long-term debt after
the spinoff.

Cheaspeake Energy to cut spending, sell assets
Chesapeake Energy Corp. announced plans to reduce its longterm debt by 25% by substantially reducing leasehold spending
and by reducing its 2-year production growth rate to 25% from
its previously planned growth rate of 30-40% for 2011-12.
Aubrey K. McClendon, Chesapeake’s chief executive officer,
said the latest plan is a shift from Cheaspeake’s “aggressive asset
accumulation of the past few years.” The growth plan reduction
will be achieved “through asset monetizations,” a news release said.
Chesapeake said its 2011-12 strategic plan update will not
involve issuing any common or preferred stock to achieve its
debt reduction objective. Chesapeake reported net debt of $11.4
billion as of Sept. 30, 2010.
The company did not specify which assets it might sell.
Chesapeake of Oklahoma City said its full-year 2010 production of 2.8 bcfd of gas equivalent marked a 14% increase over
its 2009 production.

US starts 2011 with 1,700 rigs drilling
US drilling activity increased slightly during the first week of
2011, up by 6 rotary rigs to 1,700 working, compared with
1,220 at work a year ago, Baker Hughes Inc. reported. The US
rig count exceeded 1,700 units drilling in 4 of the last 5 weeks
of 2010, finishing the year with 1,694 working the final week.
Land operations accounted for the bulk of the latest gain, up
by 5 units to 1,661 working. Offshore drilling increased by 1
rig to 25, all in the Gulf of Mexico. Inland waters activity was
unchanged with 14 rigs drilling.
Of the US rigs working, 914 were drilling for natural gas,
5 fewer than the previous week. The number drilling for oil
increased by 12 to 777. There were 9 rotary rigs unclassified.
Horizontal drilling increased by 19 to 966. Directional drilling
dropped 1 to 211.
Among the major producing states, Oklahoma and Colorado


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4 wk.

Latest week 12/31

Jan. 5

Jan. 6

Jan. 7

Jan. 10

Motor gasoline
Jet fuel
Other products

Jan. 5

Jan. 6

Jan. 7

Jan. 10





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







Crude runs to stills
Input to crude stills
% utilization







Jan. 11

Latest week 12/31





Stock cover (days)4
Jan. 5

Jan. 6

Jan. 7

Jan. 10

Jan. 11


Same week
year ago1 Change


Stocks, 1,000 bbl
Crude oil
Motor gasoline
Jet fuel–kerosine




Change, %

Motor gasoline
Futures prices5 1/7






Change, %





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








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

Jan. 5

Jan. 6

Jan. 7

Jan. 10

Jan. 11





Dec. 09

Jan. 5

Jan. 6

Jan. 7

Jan. 10

Jan. 11



Supply, 1,000 b/d



YTD avg.
year ago1


Jan. 11








Product supplied, 1,000 b/d


4 wk. avg.
year ago1

Jan. 10

Feb. 10

Mar. 10

Apr. 10

May 10 Jun. 10

Jul. 10

Aug. 10

Sept. 10

Oct. 10

Nov. 10

Dec. 10

Note: Monthly average count

1,70 0


1, 220




Jan. 5


Jan. 6

Jan. 7

Jan. 10

gasoline blendstock for oxygen blending
2Nonoxygenated regular unleaded


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Jan. 11


10/30/09 11/13/09 11/27/09














11/26/10 12/10/10 12/24/10






Note: End of week average count

Oil & Gas Journal | Jan. 17, 2011

1/13/11 1:34 PM

had the biggest increases in their rig counts, up 4 each to 164
and 64, respectively. Texas and Wyoming gained 2 rigs each
with respective counts of 733 and 47. North Dakota increased
by 1 to 151. Pennsylvania, New Mexico, California, and Arkansas were unchanged at 103, 69, 38, and 37, respectively.
West Virginia and Alaska were down 1 rig each to 20 and 5.
Louisiana reported the biggest loss, down 8 rigs with 168 still

Shell Todd plans comprehensive review of Maui field
Shell Todd Oil Services Ltd. plans a major review of the Maui
gas field region in the Taranaki basin off New Zealand.
The JV contracted drillship Noble Discoverer to drill an
exploration well, Ruru-1, on the edge of the field in February
to March. It also engaged Electromagnetic Geoservices ASA of
Norway to conduct an electromagnetic survey (New Zealand’s
first) across the Maui field itself.
The Ruru prospect, previously known as Hohonu, was delineated in recent years and is believed to have potential to add
large reserves—1 tcf was mentioned unofficially—to the Maui
development. Depending on the result of the wildcat well, it
may be developed as a separate project or as an adjunct to the
existing Maui system.
Ruru is a fault trap prospect on the southeast boundary of
the Maui production lease and crosses into adjoining permit PEP
381203, also operated by Shell Todd and in which Australian
company OMV has an interest. The Eocene-age Kapuni formation reservoir target is the same as the producing horizon at Maui.
The multimillion dollar electromagnetic survey is being run
by the Boa Galatea vessel and is expected to take a month to
complete. It will begin with laying a grid of receivers on the
seabed across production lease PEP 381012 before transmitting
electromagnetic waves during the survey.
Maui field, discovered in 1969, had initial gas reserves of 3
tcf and once supplied 90% of New Zealand’s demand that exceeded 200 petajoules/year. The field now supplies only about
30% of the current annual market of 150-170 petajoules.
However the new exploration initiative indicates Shell Todd
thinks more reserves can be found to prolong the field’s life
and lead to renewing the production lease before it expires in
June 2015.

Tweneboa appraisal well confirms potential
The Tweneboa-3 appraisal well on the Deepwater Tano block off
Ghana encountered gas-condensate and confirmed the Greater
Tweneboa area’s resource base potential.
The group led by Tullow Oil PLC plans to evaluate development options for Tweneboa and Enyenra, formerly Owo, fields.
Tweneboa-3 well was drilled with two deviated boreholes.
The first leg was drilled to calibrate the potential of an area that
had a weak seismic response. This leg encountered 29 ft of gascondensate pay, in line with expected results.

Oil & Gas Journal | Jan. 17, 2011

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The well was then sidetracked 1,808 ft west to test an area of
strong seismic response. This leg encountered a gross vertical
reservoir interval of 214 ft and penetrated 112 ft of net gascondensate pay in high-quality stacked reservoir sandstones in
two zones.
Tweneboa-3 well is 7.5 miles southeast of the Tweneboa-1
discovery well. The Deepwater Millennium dynamically positioned drillship drilled Tweneboa-3 to a total depth of 12,816
ft in 5,253 ft of water. The well will be suspended for potential
future use in field development.
The drillship will remain on the block to drill the top-hole
section of the Tweneboa-4 appraisal well and suspend it. Then
the drillship will drill the Enyenra-2A well, which will appraise
the Owo-1 discovery well.
Deepwater Tano block interests are Tullow Oil 49.95%,
Anadarko Petroleum Corp. and Kosmos Energy Inc. 18% each,
Sabre Oil & Gas Holdings Ltd. 4.05%, and Ghana National Petroleum Corp. has a 10% carried interest.

Multizone gas find gauged off Mauritania
A group led by Korea National Oil Corp. subsidiary Dana Petroleum has tested gas from one of four separate gas columns in an
exploratory well in the Atlantic off Mauritania.
Cormoran-1 is in Block 7 about 2 km south of the late 2003
Pelican-1 gas discovery (see map, OGJ, Oct. 23, 2006, p. 38).
Cormoran-1’s main purpose was to test the Cormoran prospect, which adjoins but lies at a greater depth than Pelican. A
secondary objective was the Petronia prospect beneath Cormoran. A further objective was to provide appraisal data on the
Pelican gas discovery.
Cormoran-1 went to 4,695 m below sea level in 1,630 m
of water. It encountered generally thin but good quality gasbearing sands in the Upper Pelican Group at 3,376-3,420 m
true vertical depth subsea (TVD ss) and in the Lower Pelican
Group at 3,691-3,711 m TVD ss.
The well also encountered good quality gas-bearing sands
in the Cormoran prospect in the gross interval from 4,351 m
to 4,471 m TVD ss and at the top of the Petronia prospect in
the gross interval from 4,660 m to 4,695 m TVD ss. Drilling
stopped at 4,695 m due to elevated pore pressures, and the well
was still in gas-bearing reservoir at total depth.
The well stabilized at 22-24 MMscfd of gas on a 32∕64 -in.
choke on a drillstem test of the Lower Pelican Group at 3,6793,712 m TVD ss. The flow rate was constrained by the need to
avoid sand production. Substantially higher flow rates could
have been achieved if not for this operational constraint, Dana
Petroleum said. The company plugged and abandoned the well
so that it can be reentered.
Participating interests in Block 7 are Dana Petroleum (E&P)
Ltd. 36%, GDF Suez Exploration Mauritania BV 27.85%, Tullow
Petroleum (Mauritania) Pty. Ltd. 16.2%, PC Mauritania Pty.
Ltd. 15%, and Roc Oil (Mauritania) Co. 4.95%.


1/13/11 1:34 PM

BP, CNPC increase production from Iraq’s Rumaila field
Output at Iraq’s giant Rumaila oil field has increased by more
than 10% above the 1.066 million b/d target established in
December 2009, when BP PLC and China National Petroleum
Corp. (CNPC) signed a technical service contract to expand
“This production increase is an important step for Iraq and
demonstrates the success of the contracts awarded,” said Iraq’s
oil minister Abdul Kareem Luaibi, referring to the contract
awarded to the two firms, along with Iraq’s State Oil Marketing
Co. (SOMO).
Management of the field’s development has been carried
out by the Rumaila Operating Organization (ROO), which was
originally staffed by 4,000 employees from Iraq’s state-owned
South Oil Co. along with 100 technical experts and managers
from BP and CNPC.
BP said that the pace of activity on Rumaila has built
steadily over the past year, with 20 new rigs now mobilized
in the field. Altogether over the past year, BP said 41 wells
have been drilled, 103 workovers completed, and 122 km of
flowlines laid. Employment has more than doubled to 10,000
On signing the TSC in 2009, BP and CNPC said they
planned to invest $15 billion in cash over the 20 year lifetime of
the contract with the intention of increasing plateau production
to 2.85 million b/d during 2005-10.
“Once production has been raised by 10% from its current
level of about 1 million b/d, costs will start to be recovered, and
fees of $2/bbl earned on the incremental oil production,” BP
said at the time.
“Increasing production at Rumaila, the world’s fourth largest oilfield, has been a massive undertaking,” said BP Chief Executive Bob Dudley this week, adding that “We look forward to
working with our partners to make Rumaila the world’s second
largest oil field.”
In April 2010, BP let contracts worth about $500 million to
three firms for drilling. Schlumberger, in partnership with Iraqi
Drilling Co., received a contract for three rigs; Daqing Drilling
a contract for three rigs; and Weatherford a contract for one rig
(OGJ Online, Apr. 5, 2010).
The Rumaila consortium is comprised of BP, 38%, CNPC
37%, and SOMO, 25%.

Petrobras approves more FPSOs for Santos basin
Petroleo Brasileiro SA (Petrobras) approved the installation of
two floating production, storage, and offloading vessels for installation on Guara Norte and Cernambi presalt Santos basin
oil fields off Brazil.
Cernambi previously was known as the Iracema area.
The company said the FPSOs are part of the first production
development phase of Guara Norte (Block BMS-09) and Cernambi (Block BMS-11) and will enable early production from


110117OGJ_8 8

these areas to start in 2014 compared with the previously proposed start of after 2014.
Each of the vessels will be designed to handle 150,000 bo/d
and 8 million cu m/day of gas. The company expects to have
the units converted and the modules built and integrated in
Brazil with a target local content index above 65%.
Petrobras is the operator for both blocks and has a 45% interest in BMS-9 and a 65% interest in BMS-11.
BG Group 30% and Repsol Brasil SA 25% are its partneres
in BMS-9. Its partners in BMS-11 are BG Group 25% and Galp
Energia 10%.

Albemarle, Petrobras to build HPC plant in Brazil
Albemarle Corp., Baton Rouge, and Brazil’s Petroleo Brazileiro
SA (Petrobras) have signed a memorandum of understanding
to construct a world-scale hydroprocessing catalyst (HPC) production plant in Santa Cruz, Brazil.
The new facility, to be constructed on the site of the two
firms’ existing joint venture Fabrica Carioca de Catalisadores
SA (FCC SA), will complement existing production of fluid
catalytic cracking (FCC) catalysts.
The two firms said the new plant will be constructed ahead
of “significant demand growth for hydroprocessing catalysts”
as Brazil begins to implement more stringent specifications for
ultralow-sulfur diesel and Petrobras begins to introduce new
hydrotreaters to existing and new refineries.
Albemarle said it will provide FCC SA with its leading technology for the manufacture of HPC, enabling the production of
STARS catalysts, which have enabled the broad implementation of the most stringent sulfur specifications in fuels in North
America, western Europe, and Japan.
“The plant will be ideally placed to serve growing needs for
HPC in South America,” the two firms said.
Petrobras and Albemarle said they also are enhancing their
partnership by engaging into a joint technical cooperation aimed
at the further development of advanced hydroprocessing catalysts.
In 2008, UOP LLC signed a technology cooperation agreement with Petrobras and Albemarle Corp. to demonstrate and
further commercialize its catalytic crude upgrading (CCU) process technology (OGJ Newsletter, Oct. 13, 2008).
Last October, Albemarle said it completed the R&D laboratory facilities and begun construction on its Yeosu, South Korea
manufacturing facility, which will begin intermediate commercial operations in mid-2011, with the commercial facility being
fully operational in 2012.
Albemarle said the new site will produce finished catalysts,
activators like methylaluminoxane (MAO) and metallocene
components, as well as “High Purity Metal Organics for the
HBLED market.”

Oil & Gas Journal | Jan. 17, 2011

1/13/11 1:34 PM

Dominion secures plant site for Marcellus gas
Dominion, Richmond, Va., has reached agreement with PPG
Industries on an option for Dominion to buy land at PPG’s Natrium, W.Va., site for construction of a 300 MMcfd natural gas
processing plant.
Dominion Transmission, Dominion’s natural gas pipeline
and storage subsidiary, plans to process gas and separate NGLs
at the 56-acre site as part of its previously announced Marcellus
404 Project (OGJ, June 7, 2010, p. 52). Engineering design and
project planning for the plant are under way, said the Dominion
announcement; financial terms were not disclosed.
The plant will also have fractionation capacity for up to
38,000 b/d of NGLs.
Natrium, on the Ohio River in Marshall County about 9
miles north of New Martinsville, W.Va., is close to Dominion’s TL-404 pipeline, an existing transmission line in Ohio
and West Virginia that Dominion plans to convert into wet-gas
service. Natrium is also close to rail, pipeline, and barging for
marketing NGLs.

Canada’s Montney shale to get gas plant
AltaGas, Calgary, has let a contract to IMV Projects, a Wood
Group company also based in Calgary, for the engineering, procurement, and construction management for the $235 million
(Can.) Gordondale sour gas processing plant and associated gas
The 120-MMcfd plant will lie about 100 km northwest of
Grande Prairie in the Gordondale area of the Montney shale
gas play. It will include deep-cut liquids extraction to recover
NGL before the gas enters the sales gas pipeline and will be on
stream by fourth-quarter 2012, following regulatory approval.
IMV Projects has been involved with development of the
project since its inception, performing the original scoping
study and the front-end engineering design, said the company’s
IMV Projects also designed the expansion of AltaGas Ante
Creek processing plant, currently under construction, that includes a new amine train, refrigeration, and gathering.

Flint Hills to buy ethanol plants in Iowa
Flint Hills Resources LP plans to buy two ethanol plants in
Iowa from Hawkeye Renewables LLC, which last year restructured its finances under bankruptcy protection.
Flint Hills will buy a 100-million-gal/year plant in Iowa
Falls and a 115-million-gal/year plant in Fairbank.
The company, part of Koch Industries Inc., has more than
800,000 of distillation capacity in refineries in Texas, Alaska,
and Minnesota.
The refiner already owns ethanol plants with capacities of
110 million gal/year each in Menlo and Shell Rock, Iowa.
In Iowa, it operates a fuel terminal and asphalt plants at Algona, Davenport, and Dubuque. It also distributes fuels in the
Flint Hills didn’t disclose the purchase price.

Oil & Gas Journal | Jan. 17, 2011

110117OGJ_9 9

Alyeska restarts TAPS while readying bypass
Alyeska Pipeline restarted the Trans Alaska Pipeline Jan. 11
following a 4-day shut down. The company’s operations control center began the start-up sequence of opening valves and
bringing pumps on line at 7 p.m. local time (OGJ Online, Jan.
10, 2011).
Alyeska shut down the pipeline at 8:50 a.m. on Jan. 8 after
crews discovered a leak into containment in the basement of a
booster pump building at Pump Station 1.
The restart is part of a multistep plan to restore pipeline
operations. The pipeline will run at reduced rates for several
days while a 157-ft bypass segment is staged for installation.
Once staged, Alyeska will shut TAPS down again while crews
complete the bypass project.
The restart will help increase temperatures in tanks and the
pipeline, Alyeska explained, reducing the potential for wax in
the oil to accumulate or for water in the oil to freeze. It also allows flowing oil to move a cleaning pig from its current location
between Mileposts 419 and 420 to Pump Station 8.
The pig could affect the pump station equipment if left in
the pipeline too long in cold temperatures. With the pipeline
operating again, crews can trap the pig between two valves in
the mainline and route crude oil around through bypass piping, Alyeska said.
Alyeska said the restart solves three problems: It avoids a
more complex cold restart process, it avoids additional problems that would occur if the pig were in the line when the pipeline begins to get too cold, and it allows North Slope producers
to increase production, which will help mitigate freeze concerns on the North Slope.

Harvest to build Eagle Ford crude oil pipeline
Harvest Pipeline Co. has started to construct a 25-mile crude
oil pipeline from near Cotulla in LaSalle County, Tex., to an
interconnect near Fowlerton, Tex., with its existing 140-mile
Pearsall pipeline.
The lateral represents the next phase of Harvest’s continuing expansion of its Arrowhead Pipeline in an effort to increase
shipments of Eagle Ford crude to refining and terminal facilities in Corpus Christi.
Harvest expects the Cotulla line to enter service in the third
quarter. The Cotulla line will be supported with volume commitments from large producers in LaSalle and Dimmit counties, according to Harvest.
Harvest operates pipeline systems running through the Eagle Ford trend from Maverick County to San Patricio County,
Harvest also operates oil and gas gathering and mainline
systems across south Texas and Louisiana.
Koch Pipeline Co. LP received shareholder approval to build
a 120,000-b/d Eagle Ford pipeline to Corpus Christi in December 2010 (OGJ Online, Dec. 17, 2010).


1/13/11 1:34 PM

Denotes new listing or Global Energy Forum,
Houston, (206) 829a change in previously
1376, (206) 441-6369
published information.
(fax), website: http://
Plant Maintenance in
the Middle East Annual Chem/Petrochem
Meeting, Abu Dhabi, +44 and Refinery Asset
(0) 1242 529 090, +44 Management and
(0) 1242 529 060 (fax), Integrity Conference,
e-mail: wra@theenergy- New Orleans, (312) 540exchange.co.uk, website: 3000, ext. 6583, e-mail:
com, website: www.
com. 16-19.
IADC South Central
Asia Drilling Technology 18-19.
Conference & Exhibition,
Gas Transport & Storage
Mumbai, (713) 292Summit, Berlin, +44
1945, (713) 292-1946
(fax), e-mail: info@iadc. (0)20 7202 7690, +44
org, website: www.iadc. (0)20 7202 7600 (fax),
org/conferences. 17-18. e-mail: richard.jones@
wtgevents.com, website:
Offshore Development
Exhibition and Conference, Singapore, +44
(0) 1242 529 090, +44 ME TECH 2011, Dubai,
(0) 1242 529 060 (fax), +44 20 7357 8394, +44
e-mail: wra@theenergy- 20 7357 8395 (fax),
exchange.co.uk, website: e-mail: conferences@
www.theenergyexchange. europetro.com, website:
co.uk/3/13. 17-20.
Asian Offshore Congress, event<emid=240.
Singapore, 65 6407
1498, 65 6407 1501
(fax), e-mail: d.tung@en- API Inspection Summit
ergyexchangeasia.com, & Expo, Galveston, Tex.,
(202) 682 8000, (202)
website: www.theenergyexchange.co.uk/3/13/ 682-8222 (fax), website:
www.api.org. 24-27.
index.php. 17-20.
World Future Energy
Summit, Abu Dhabi,
+9712 409 0445, e-mail:
micheele.boyd@eedexpolae. website: www.
worldfutureenergysummit.com. 17-20.
International Forum
Process Analytical
Technology (IFPAC), Baltimore, (847) 543-6800,
(847) 548-1811 (fax),
e-mail: info@ifpacnet.org,
website: www.ifpac.com.


110117OGJ_10 10

European Gas Conference, Vienna, +44 207
067 1800, +44 207
430 0552 (fax), e-mail:
z.nathan@theenergyexchange.co.uk, website:
articles/214.php 25-27.
Oil Sands Water
Management Initiative
Conference, Calgary,
(866) 921-7782, 1 (800)
714-1359 (fax), e-mail:
website: www.worldoils.
com. 26-27.
API/AGA Joint Committee
on Oil and Gas Pipeline
Welding Practices, Fort
Worth, Tex., (202) 682
8000, (202) 682-8222
(fax), website: www.api.
org. 26-28.
Russian & CIS Executive
Summit, Dubai, +44
20 7357 8394, +44
20 7357 8395 (fax),
e-mail: conferences@
europetro.com, website:

Pipe Tech Americas
Summit, Houston, (416)
214-1144, e-mail: laurence.allen@wtgevents.
com, website: www.
API Exploration and Pro- program. 27-28.
duction Winter Standards
Meeting, Fort Worth,
Tight Oil Shale Plays
Tex., (202) 682-8000,
World Congress, Denver,
(202) 682-8222 (fax),
(866) 921-7782, 1 (800)
website: www.api.org.
714-1359 (fax), e-mail:
website: www.worldoils.
Shale Gas Symposium,
Calgary, Alta., (877) 927- com. Jan. 30-Feb. 1.
7936, (877) 927-1563
(fax), website: www.
Annual Gas Arabia
Summit, Abu Dhabi, +44
energy_resources/Shale- 207 067 18 00, e-mail:
Gas.htm. 25-26.
c.pallen@theenergyexchange.co.uk, website:
www. www.theenergy-

articles/135.php. Jan.
30-Feb. 2.
Offshore Production
Technology Summit,
London, +44 (0)20
7202 7690, +44 (0)207
202 7600 (fax), e-mail:
wtgevents.com, website:
com. Jan. 31-Feb. 1.

IPAA OGIS Florida, Hollywood, Fla., (202) 8574722, (202) 857-4799
(fax), website: www.ipaa.

NACE Northern Area
Western Conference,
Regina, Sask., (281)
228-6200, (281)
228-6300 (fax), e-mail:
website: www.events.
SPE Middle East Uncon- nace.org/sarwebsites/
ventional Gas Conference NorthernAreaWestern/
and Exhibition, Muscat, conference11/index.
+971 4 390 3540, +971 asp. 6-8.
4 366 4648 (fax), e-mail:
spedub@spe.org, web- Pipeline Coating Intersite: www.spe.org. Jan.
national Conference,
31-Feb. 2.
Vienna, +44(0)117 924
9442, +44(0)117 989
2128 (fax), e-mail: info@
amiplastics.com, website:
IADC Health Safety
Environment and Training code=C369&sec=1222.
Conference & Exhibition, 7-9.
Houston, (713) 292Arctic Technology
1945, (713) 292-1946
(fax), e-mail: info@iadc. Conference, Houston,
org, website: www.iadc. (888) 945-2274, ext.
617, website: www.arctorg/conferences. 1-2.
Topsides Conference & org/. 7-9.
Exhibition, Galveston,
ARC World Industry
(918) 831-9160, (918)
Forum, Orlando, (781)
831-9161 (fax), e-mail:
wendyl@pennwell.com, 471-1000, e-mail: info@
website: www.topsidesev- arcweb.com, website:
ent.com/index.html. 1-3. www.arcweb.com/
Events/ARC-Orlando-FoGlobal LNG Forum, Bar- rum-2011/Pages/default.
aspx. 7-10.
celona, +421 257 272
112, +421 255 644 490,
e-mail; beata.kyblova@ International Gas Analysis
jacobfleming.com, web- Symposium & Exhibition,
site: www.jacobfleming. Rotterdam, +31 (0) 15
2 690 147, +31 (0) 15
com. 2-3.
2 690 190 (fax), e-mail:
gas@nen.nl, website:
East African Petroleum
www.gas2011.org. 9-11.
Conference & Exhibition (EAPCE), Kampala,
+256 414 320714, +256 SPE Project and Facilities
Challenges Conference
414 320437 (fax),
at METS, Doha, +971
e-mail: eapce11@
petroleum.go.ug. website: 4 390 3540, +971 4
366 4648 (fax), e-mail:
www.petroleumafrica.com/en/eventdetail. spedub@spe.org, webphp?Eventld=522. 2-4. site: www.spe.org. 13-16.

Pipeline Pigging &
Integrity Management
Conference, Houston,
(713) 521-5929, (713)
521-9255 (fax), e-mail:
info@clarion.org, website:
www.clarion.org. 14-17.
Unconventional Oil &
Gas Europe, Prague, 1
(888) 299-8016, 1 (888)
299-8057 (fax), e-mail:
com, website: www.
Russia Offshore Annual
Conference & Exhibition,
Moscow, +44 207 067
1800, +44 207 430
0552 (fax), e-mail: wra@
co.uk, website: www.
php. 15-17.
IPAA International
Forum, Houston, (202)
857-4722, (202) 8574799 (fax), website:
www.ipaa.org. 16.
NAPE Expo, Houston,
(972) 993-9090, (972)
993-9191 (fax), e-mail:
website: www.napeexpo.
com. 16-18.
EPNanoNet Forum on
Advanced Materials for
E&P, Houston, +44 (0)
1483 598000, e-mail:
com, website: www.deaeurope.com. 17-18.
Laurance Reid Gas
Conditioning Conference, Norman, Okla.,
(405) 325-2248, (405)
325-7164 (fax), e-mail:
bettyk@ou.edu, website:
ou.edu. 20-23.
IP Week, London, +44
0 20 7467 7116, e-mail:

Oil & Gas Journal | Jan. 17, 2011

1/13/11 1:34 PM

website: www.energyinst. Annual Petcoke Conorg.uk. 21-23.
ference, San Diego,
(832) 351-7827, (832)
Nitrogen+Syngas Inter- 351-7887 (fax), e-mail:
national Conference &
website: www.petcokes.
Exhibition, Dusseldorf,
+44 (0) 20 7903 2438, com. 25-26.
+44 (0) 20 7903 2432
(fax), e-mail: conferCorrosion UAE Conferences@crugroup.com,
ence, Abu Dhabi, 00 971
website: www.crugroup. 50 264 1202, e-mail:
com. 21-24.
c.pallen@theenergyexchange.co.uk, website:
www. www.theenergySUBSEA Tieback
Forum & Exhibition, San exchange.co.uk/3/13/
Antonio, (918) 831-9160, articles/157.php. Feb.
27-Mar. 1.
(918) 831-9161 (fax),
e-mail: registration@pennwell.com, website: www.
MARCH 2011
com. 22-24.
NPRA Security ConferSPE European Conference & Exhibition,
ence on Health Safety
Houston, (202) 457and Environment in Oil
0480, (202) 457-0486
and Gas Exploration,
(fax), e-mail: info@npra.
Vienna, +44 (0)1224
org, website: www.npra.
318088, website: www. org. 1-2.
spe-uk.org. 22-24.
Annual Arctic Gas
Pipe Line Contractors
Symposium, Calgary,
Association Convention, Alta., (877) 927-7936,
Maui, (214) 969-2700,
(877) 927-1563 (fax),
e-mail: plca@plca.org,
website: www.arcticgaswebsite: www.plca.org.
html. 1-2.
Shale Gas Asia Conference, New Delhi, 1 (800)
721-3915, 1 (800) 7141359 (fax), e-mail: info@
american-business-conferences.com, website:

SPE/IADC Drilling Conference, Amsterdam, +44
20 7299 3300. +44 20
7299 3309 (fax), e-mail:
spelon@spe.org, website:
www.spe.org. 1-3.

APPEX/AAPG Property &
Prospect Expo, London,
AOG Australasian Oil &
+44 (0) 207 434 13
Gas Exhibition & Confer- 99, e-mail: Europe@
ence, Perth, +61 3 9261 aapg.org. website: www.
4500, +61 3 9261 4545 europetro.com. 1-3.
(fax), e-mail: aog@divexhibition.com.au, website: Turkmenistan Asia Oil &
Gas Summit, Singapore,
+44 (0) 20 7328 8899,
+44 (0) 20 7624 9030
GPA Europe Conference, (fax), e-mail: info@
Amsterdam, +44 (0)
1252 625542, website: website: www.summitwww.gpaeurope.com/
tradeevents.com/Holdevents/event/16. 23-25. ingA2011.php. 3-4.

Oil & Gas Journal | Jan. 17, 2011

110117OGJ_11 11

Libya International Petro
& Energy Fair, Tripoli,
00971 4 2988144,
00971 4 2987886 (fax),
e-mail: nafees@orangefairs.com, website: www.
orangefairs.com. 7-10.

Process Safety, Chicago,
(800) 242-4363, (203)
775-5177 (fax), website:
index.aspx. 13-17.

1737 855482 (fax), email: info@gastech.co.uk,
e-mail: www.gastech.
co.uk. 21-24.

IADC Drilling HSE Asia
Pacific Conference &
Offshore West Africa
Exhibition, Singapore,
API Spring Committee
Conference & Exhibition, (713) 292-1945, (713)
on Petroleum Measure- Accra, Ghana, (918) 831- 292-1946 (fax), e-mail:
ment Standards Meeting, 9160, (918) 831-9161
info@iadc.org, website:
Dallas, (202) 682 8000, (fax), e-mail: registrawww.iadc.org/confer(202) 682-8222 (fax),
ences. 23-24.
website: www.api.gor.
website: www.offshore7-10.
westafrica.com. 15-17.
OMC Offshore Mediterranean Conference,
CERA Week, Houston,
World Heavy Oil ConRavenna, +39 0544
(713) 840-8282, (713) gress, Edmonton, Alta., 219418, e-mail: confer599-9111 (fax), e-mail:
(888) 799-2545, (403) ence@omc.it, website:
info@cera.com, website: 245-8649 (fax), website: www.omc.it/2011. 23-25.
www.cera.com. 7-11.
www.worldheavyoilcongress.com. 15-17.
SPE Production and
Renewable Energy World
Operations SympoConference & Expo
TUROGE Turkish
sium, Oklahoma City,
North America, Tampa, International Oil & Gas
(800) 456-9393, (972)
(918) 831-9160, (918)
Conference & Showcase, 952-9435 (fax), e-mail:
831-9161 (fax), e-mail:
Ankara, +44 (0) 20 7596 spedal@spe.org, website:
5000, +44 (0) 20 7596 www.spe.org. 27-29.
com, website: www.
5111 (fax), e-mail: enrenewableenergyworld- quiry@ite-exhibition.com, NPRA International Petevents.com. 8-10.
website: www.turoge.
rochemical Conference,
com. 16-17.
San Antonio, (202) 457European Fuels Confer0480, (202) 457-0486
ence Annual Meeting,
NPRA Annual Meeting, (fax), e-mail: info@npra.
Paris, +44 (0)207 430
San Antonio, (202) 457- org, website: www.npra.
9513, +44 (0)207 430
0480, (202) 457-0486 org. 27-29.
9513 (fax), e-mail:
(fax), e-mail: info@npra.
e.huiban@theenergyex- org, website: www.npra. Howard Weil Annual
change.co.uk, website:
org. 20-22.
Energy Conference, New
Orleans, (504) 582com/2/4/articles/205.
MEOS/SPE’s Middle East 2500, website: www.
php. 8-11.
Oil & Gas Conference & howardweil.com/energyExhibition, Manama, +44 conference.aspx. 27-30.
DEA(e) Technical Oil & (0)20 7840 2139, +44
Gas Conference on Well (0)20 7840 2119 (fax), e- Middle East Downstream
Control, Bad Bentheim, mail: meos@oesallworld. Week Annual Meeting,
+44 (0) 1483 598000, com, website: www.
Abu Dhabi, +44 (0) 1242
e-mail: dawn.dukes@
meos2011.com. 20-23. 529 090, +44 (0) 1242
otmnet.com, website:
529 060 (fax), e-mail:
GPA Europe at GasTech wra@theenergyexchange.
Conference & Exhibition, co.uk, website: www.
Amsterdam, +44 (0)
NACE Corrosion Confer- 1737 855000, +44 (0) 27-30.
ence & Expo, Houston, 1737 855482 (fax), e(800) 797-6223, (281)
mail: info@gastech.co.uk, ACS National Meeting
228-6329 (fax), website: e-mail: www.gastech.
& Exposition, Anaheim,
co.uk. 21-24.
Calif., (202) 872-4600,
conferences/c2011/ine-mail: help@acs.org,
dex.asp. 13-17.
GASTECH International website: www.acs.org.
Conference & Exhibition, 27-31.
AIChE Spring Meeting
Amsterdam, +44 (0)
& Global Congress on
1737 855000, +44 (0)

Purvin & Gertz International LPG Seminar, The
(713) 331-4000, (713)
236-8490 (fax), e-mail:
com, website: www.
purvingertz.com. 28-31.
SPE European Well
Abandonment Seminar,
Aberdeen, +44 1224
495051, e-mail: jane.
com, website: www.speuk.org. 29.
Woodford Shale
Summit, Norman, Okla.,
(405) 525-3556, ext.
117, (405) 525-3592
(fax), e-mail: amy.
ok.us, website: www.
GIOGIE Georgian
International Oil & Gas
Energy and Infrastructure
Conference, Tbilisi, +44
207 596 5135, +44 207
596 5106 (fax), e-mail:
ilyas.idigov@ite-exhibitions.com, website: www.
giogie.com/2011/. 29-30.
Offshore Asia Conference
& Exhibition, Singapore,
(918) 831-9160, (918)
831-9161 (fax), e-mail:
com, website: www.
IRO On & Offshore
Exhibition, Gorinchem,
+31 523 289866, e-mail:
antoinettehulst@evenementenhal.nl, website:
SEG Shale Gas Forum,
Chengdu, Sichuan,
(918) 497-5500, (918)
497-5557 (fax), website:
www.seg.org. 30-31.


1/13/11 1:34 PM


Encana: ‘We own the Piceance’
When listing the public companies that want to be
associated with liquids resource plays as opposed
to gas plays, don’t include Encana Corp.
The Calgary firm has refocused its operations
on North America and is a large participant in
several resource plays in Canada and the US. The
Piceance basin Williams Fork tight sand and the
North Louisiana Haynesville shale are two of the
company’s large US ventures.
In the Piceance basin, Encana owns 869,000
net acres bounded roughly by Rangely, Grand
Junction, Rifle, and Meeker, Colo. More than 70%
of the lands are undeveloped.
Jeff Wojahn, executive vice-president of Encana and president of its USA Division, told an
investment conference Jan. 5, “We own the basin.”
In the 2010 third quarter, Encana at about 3.2
Chief Editor-Exploration
bcfd of companywide gas production was behind only ExxonMobil Corp. at 4.2 bcfd in North
American gas output.

Piceance position
At its current pace, Encana has a 35-year inventory
of drilling locations in the Williams Fork formation
The company has built its Piceance net production to 440 MMcfd of gas in 2010 from 325 MMcfd
in 2005, increasing flow every year except 2009,
when pipeline capacity was insufficient to take all
of its gas. Output grew at a compound rate of more
than 30%/year from 2002 to 2008.
“Our capacity-reduced production from 2009
came back on line better than expected, and many
of the Piceance wells that we’ve recently completed are performing well above expectations,”
Wojahn said.
Using what the company calls a “gas factory”
approach, Encana has drilled as many as 52 wells
from a single pad in the Piceance basin.
“I am proud to say that in just a few short years,
the Piceance gas factory has progressed from the
conceptual stage to full implementation…. Since
2005, Encana has reduced its drilling cycle times by
as much as 65% in some areas of the Piceance basin.”
Encana is expanding the use of its Piceance gas
factory approach throughout the company’s operations to gain efficiencies. Those include sharply


110117OGJ_12 12

reducing truck trips in the field, fewer pad-to-pad
rig moves, shorter drilling and completion cycle
time, and optimizing frac efficiency and production via gas lift.
Without giving details, Wojahn said Encana is
diversifying its supplier base and is engaging industry players to develop fit for purpose completion equipment.

Haynesville shale
Encana holds 429,000 net acres in the heart of the
Haynesville shale play, where it drilled 90 net wells
in 2010.
The company was to average 290 MMcfd of
Haynesville net production in 2010 and ended
the year at about 400 MMcfd. Output is to rise to
more than 1 bcfd by 2014.
“Though our 2010 program focused on drilling
for land retention, we’re nowhere near optimizing
our surface or drilling operations,” Wojahn said.
“This year we have one gas factory pilot plant
that will see eight wells drilled from a single pad.
This will be the first step in a long-term exercise of
continued optimization and cost reduction.”
The company sees overall field savings of as
much as 20% when it fully implements the gas
factory method in the Haynesville, Wojahn said.

Joint venture capital
Encana has attracted more than $4 billion in third
party capital to its projects in the last 3 years,
Wojahn said.
The company targets total joint venture investment of $1-2 billion/year, and current expected
2011 partner spending on Encana’s behalf is about
$500 million. A joint venture with China National
Petroleum Co. could contribute further.
Such capital infusion enables Encana to drill
wells that would otherwise remain dormant in its
inventory for far too long, Wojahn said.
In 2010, Encana had more than $900 million in third party joint venture commitments in
place. It was involved in more than 30 deals in
Canada and had more than 30 partners in the
US. The deals involved gross well commitments
of more than 760 wells in Canada and 1,784
wells in the US.

Oil & Gas Journal | Jan. 17, 2011

1/13/11 1:34 PM

unconvent ional





aug us t 3 0 - s ep tembe r 1 , 2 0 1 1
H E N RY B . G O N Z A L E Z C O N V E N T I O N C E N T E R / S A N A N T O N I O, T X / U S A







110117OGJ_13 13

1/13/11 1:36 PM


The spill report—1
First, the shortcomings.
The report to US President Barack Obama by
the National Commission on the BP Deepwater
Horizon Oil Spill and Offshore Drilling has drawbacks. As a foundation for further regulatory response to the Macondo disaster last April, however, it’s important to oil and gas producers. It also
contains solid ideas for real and obviously necessary improvement in offshore safety and regulation.
The drawbacks will be dispensed with here. The
solid ideas will receive attention in later weeks.

Length and agenda
At nearly 400 pages, the report is unnecessarily
long. In too many places, historical excursions few
will read obscure important messages about the future. Normally, excessive length would be merely
annoying. In this case, it seems to betray political
For example, the report traces in dreary length
the history of the old Minerals Management Service. Created in 1982 by then-Interior Sec. James
Watt, whose desire to open the whole federal offshore for oil and gas leasing became a celebrity
cause of environmentalism, MMS in its last years
had become, even before the Macondo tragedy, a
whipping post for the political left.
About MMS, only two points need to be made:
1. that combining royalty collection with lease
management might have tilted regulation toward
revenue generation at the expense of operational safety and therefore might bear on Macondo
lapses, and 2. that a post-Macondo reorganization makes the issue old news. These points are
easily lost in the spill commission’s retelling of
the whole MMS story, which a thousand or so
words into the narrative begins to feel like political scab-picking.
Political leanings also seem to be at work in the
report’s contention that “systemic failures by industry management” beyond BP and its contractors
were at play at Macondo. The judgment is valid
to the extent that operators routinely provided assurances about their abilities to respond to a major
deepwater spill that Macondo repudiated.
Behind those assurances lay a determination,
now discredited, not to let such a spill occur. But a


110117OGJ_14 14

catastrophic spill occurred in one deepwater well.
That fact requires urgent attention and strong response. But no catastrophic spill has occurred from
more than 2,500 other deepwater wells drilled
since 2006 in the Gulf of Mexico. That fact needs
to be part of the response framework. The report’s
extrapolations skew this essential perspective.
From its thusly distorted stance on pre-Macondo
regulation and industry practice, the commission
leaps to suggestions for impossibly aggressive regulation. It recommends creation of a new agency in
the Department of Interior and new involvement in
offshore decision-making by existing agencies outside the department.
Yet the problem isn’t that there hasn’t been
enough bureaucracy focused on offshore regulation. The problem, as the commission report duly
notes, is that offshore activity bypassed oversight
capability in its volume and technical complexity.
Oversight needs to improve, to be sure. But complicating the administrative structures dedicated to
oversight will only dissipate resources and hamper

NEPA emphasis
The commission also puts too much emphasis on
regulation under the National Environmental Policy Act, the law requiring the government to assess
environmental effects of its major activities. Adding
layers of NEPA review, as the Interior Department
already is doing, multiplies administrative hurdles
without enhancing safety.
The problem at Macondo wasn’t that an insufficient number of NEPA reviews had been conducted; it was that broad-area assessments contained
the standard assurances about response capability
that proved unfounded. More reviews would have
generated more unfounded assurances without
preventing the accident.
The goals now should be to prevent recurrence
of anything like the Macondo accident and to develop spill preparedness hitherto lacking without
slowing development of oil and gas resources. The
report suggests changes able to help the industry
and government achieve those goals.
One such change will be discussed here next

Oil & Gas Journal | Jan. 17, 2011

1/13/11 1:34 PM

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110117OGJ_15 15

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1/13/11 1:35 PM


Spill panel seeks overhaul
of safety culture, regulation
Bob Tippee

The report by a presidential commission studying last year’s
Macondo well disaster in the Gulf of Mexico calls for overhaul both of the oil and gas industry’s safety culture and of
offshore regulation.
Published Jan. 11, the report to President Barack Obama
from the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling faults regulations in place
when the Macondo well blew out on Apr. 20, destroying the
Transocean Deepwater Horizon semisubmersible drilling rig
and killing 11 workers. It also excoriates the industry.
“Government oversight must be accompanied by the oil
and gas industry’s reinvention: sweeping reforms that accomplish no less than a fundamental transformation of its
safety culture,” it says.
In separate chapters of the 398-page report, the commission recommends a broad range of changes by the industry
and federal government.

The report contrasts the US and European systems for
safety regulation. The US uses prescriptive regulations with
inspections in conjunction with voluntary recommended
safety practices developed by the industry.
In response to offshore accidents in the 1980s, the UK,
Norway, and Canada have adopted systems, known as safety
cases in the UK, in which governments set minimum standards for structural and operational integrity but put the
burden on industry for identifying risks and demonstrating
that each offshore facility can manage those risks.
The report faults the American Petroleum Institute for resisting efforts to move US regulation in that direction with
an approach using “safety and environmental management
It also expresses regret about diminishing research and
development related to safety.
“Safely managing industrial hazards for oil and gas drilling requires experience and knowledge,” it says, adding,
“Such knowledge and experience within the industry may
be decreasing.”

Industry changes


For the industry, the report embeds recommendations in
a long discourse critical of the safety cultures of the oil and
gas business generally and of BP particularly.
Under the heading “Absence of Adequate Safety Culture
in the Offshore US Oil and Gas Industry,” it says, “The pervasive riskiness of exploring for and producing offshore oil
and gas does not explain the extent to which approaches to
safety differ among companies nor why they differ within
companies depending on where they are working.”
During 2004-09, the report says, fatalities in the offshore
oil and gas industry were “more than four times higher per
person-hours worked” in the US than they were in Europe.
“This striking statistical discrepancy reinforces the view
that the problem is not an inherent trait of the business itself
but rather depends on the differing cultures and regulatory
systems under which members of the industry operate,” the
report says.
At the company level, effective safety culture requires
“unwavering commitment to safety at the top of an organization.” Across industry, “leadership needs to come from the
CEOs collectively, who can apply pressure on their peers to
enhance performance.”

The report also calls for enhanced self-policing by the industry “as an important supplement to government oversight.”
It describes a nonprofit organization set up by the nuclear
power industry after the meltdown in 1979 of the radioactive core of a unit at the Three Mile Island generating plant
near Harrisburg, Penn. The mission of the organization, the
Institute of Nuclear Power Operations (INPO), is “to promote the highest levels of safety and reliability—to promote
excellence—in the operation of commercial nuclear power
plants.” INPO’s work includes inspecting 104 reactors operated by 26 utilities at 66 nuclear sites every 24 months.
“In the aftermath of the Deepwater Horizon spill,” the report asks, “could the oil and gas industry similarly improve
its safety culture by creating a self-policing entity like INPO
as a supplement to government oversight?”
Beyond improving its safety culture, the report says, the
industry must improve its capacity for containment and response when spills occur.
It approvingly notes two initiatives in these areas that followed the Macondo tragedy, the Marine Well Containment
Co. and Helix Energy Solutions Group, but says they have



110117OGJ_16 16

Oil & Gas Journal | Jan. 17, 2011

1/13/11 1:35 PM


Was there a less-risky
alternative available?

Less time than alternative?


Not waiting for more centralizers of preferred design


Saved time

BP on shore

Not waiting for foam stability test results and/or
redesigning slurry


Saved time

Halliburton (and perhaps BP) on

Not running cement evaluation log


Saved time

BP on shore

Using spacer made from combined lost circulation
materials to avoid disposal issues


Saved time

BP on shore

Displacing mud from riser before setting surface
cement plug



BP on shore

Setting surface cement plug 3,000 ft below mud line
in seawater



BP on shore (approved by MMS)

Not installing additional physical barriers during
temporary abandonment procedure


Saved time

BP on shore

Not performing further well integrity diagnostics in
light of troubling and unexplained negative pressure
test results


Saved time

BP (and perhaps Transocean) on rig

Bypassing pits and conducting other simultaneous
operations during displacement


Saved time

Transocean (and perhaps BP) on rig

Source: Obama Administration’s National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

One is that “the systems are not designed to contain all
possible catastrophic failures, only the next Deepwater Horizon-type spill.” The other limitation is that neither group,
the report says, “is structured to ensure the long-term ability to innovate and adapt over time to the next frontiers and

Recommendations for government
The commission bases its recommendations for the government in part on what its report calls “inadequacies” of federal standards evident in decisions leading to the Macondo
“Federal authorities lacked regulations covering some of
the most critical decisions made on the Deepwater Horizon
that affected the safety of the Macondo well,” the report says,
citing the lack of “meaningful regulations” governing well
cementing and negative pressure-testing of well integrity—
two areas of concern in the blowout.
“On many of these critical matters, the federal regulations
either failed to account for the particular challenges of deepwater drilling or were silent altogether,” the report says.
These are the report’s specific recommendations for the
government, edited only to clarify meaning:
• The Department of the Interior should supplement the
risk-management program with prescriptive safety and pollution-prevention standards that are developed and selected
in consultation with international regulatory peers and that
are at least as rigorous as the leasing terms and regulatory
requirements in peer oil-producing nations.
• Interior should develop a proactive, risk-based performance approach specific to individual facilities, operations,

Oil & Gas Journal | Jan. 17, 2011

110117OGJ_17 17

and environments, similar to the “safety case” approach in
the North Sea.
• Working with the International Regulators’ Forum and
other organizations, Congress and Interior should identify
those drilling, production, and emergency-response standards that best protect offshore workers and the environment, and initiate new standards and revisions to fill gaps
and correct deficiencies. These standards should be applied
throughout the Gulf of Mexico, in the Arctic, and globally wherever the international industry operates. Standards
should be updated at least every 5 years as under the formal
review process of the International Organization for Standardization (ISO).
• Congress and Interior should create an independent
agency within Interior with enforcement authority to oversee all aspects of offshore drilling safety (operational and occupational), as well as the structural and operational integrity of all offshore energy production facilities, including both
oil and gas production and renewable energy production.
• Congress and Interior should provide a mechanism,
including the use of lease provisions for the payment of regulatory fees, for adequate, stable, and secure funding to the
key regulatory agencies—Interior, Coast Guard, and National Oceanic and Atmospheric Administration (NOAA)—to
ensure that they can perform their duties, expedite permits
and reviews as needed, and hire experienced engineers, inspectors, scientists, and first responders.
• The Council on Environmental Quality and Interior
should revise and strengthen the National Energy Policy Act
policies, practices, and procedures to improve the level of
environmental analysis, transparency, and consistency at all
stages of the Outer Continental Shelf planning, leasing, ex-


1/13/11 1:35 PM

ploration, and development process.
• Interior should reduce risk to the environment from
OCS oil and gas activities by strengthening science and interagency consultations in the OCS oil and gas decisionmaking process.
• Congress, by enacting legislation, and Interior, through
its lease provision, should require the oil and gas industry to
pay fees that support environmental science and regulatory
review related to OCS oil and gas activities to enable cooperating agencies to carry out these responsibilities.
• Interior should create a rigorous, transparent, and
meaningful oil spill risk analysis and planning process for
the development and implementation of better oil spill response.
• The Environmental Protection Agency and the Coast
Guard should establish distinct plans and procedures for responding to a “spill of national significance.”
• EPA and the Coast Guard should bolster state and local
involvement in oil spill contingency planning and training
and create a mechanism for local involvement in spill planning and response similar to the regional citizens’ advisory
councils mandated by the Oil Pollution Act of 1990.
• Congress should provide mandatory funding for oil
spill response research and development and provide incentives for private-sector research and development.
• EPA should update and periodically review its dispersant-testing protocols for product listing or preapproval and
modify the preapproval process to include temporal duration, spatial reach, and volume of the spill.
• The Coast Guard should issue guidance to establish
that offshore barrier berms and similar dredged barriers
generally will not be authorized as an oil spill response measure in the national contingency plan or any area contingency plan.
• The National Response Team should develop and
maintain expertise within the federal government to oversee
source-control efforts.
• Interior should require offshore operators to provide
detailed plans for source control as part of their oil spill response plans and applications for permits to drill.
• The National Response Team should develop and
maintain expertise within the federal government to obtain accurate estimates of flow rate or spill volume early in a
source-control effort.
• Interior should require offshore operators seeking its
approval of proposed well design to demonstrate that:
1. Well components, including blowout preventer stacks,
are equipped with sensors or other tools to obtain accurate
diagnostic information—for example, regarding pressures
and the position of blowout preventer rams.
2. Wells are designed to mitigate risks to well integrity
during post-blowout containment efforts.
• The Coast Guard, through the federal on-scene coordinator, should provide scientists with timely access to the re-


110117OGJ_18 18

sponse zone so that they can conduct independent scientific
research during an oil spill response and long-term monitoring in the future.
• The trustees for natural resources should ensure that
compensatory restoration under the natural resource damage assessment process (under the Oil Pollution Act) is transparent and appropriate.
• EPA should develop distinct plans and procedures to
address human health impacts during a spill of national significance (statutorily defined as one “that due to its severity,
size, location, actual or potential impact on the public health
and welfare or the environment, or the necessary response
effort, is so complex that it requires extraordinary coordination of federal, state, local, and responsible party resources
to contain and clean up the discharge”).
• Congress, federal agencies, and responsible parties
should take steps to restore consumer confidence in the aftermath of a spill of national significance.
• Congress should dedicate 80% of the Clean Water Act
penalties to long-term restoration of the Gulf of Mexico.
• Congress and federal and state agencies should build
the organizational, financial, scientific, and public outreach
capacities needed to put the restoration effort on a strong
• The appropriate federal agencies, including EPA, Interior, and NOAA, and the trustees for natural resources should
better balance the myriad economic and environmental interests concentrated in the gulf region going forward. This
would include improved monitoring and increased use of
sophisticated tools like coastal and marine spatial planning.
Many of these tools and capacities will also be important to
manage areas of the OCS outside the gulf.
• Congress should significantly increase the liability cap
and financial responsibility requirements for offshore facilities.
• Congress should increase the limit on per-incident
payouts from the Oil Spill Liability Trust Fund.
• Interior should enhance auditing and evaluation of the
risk of offshore drilling activities by individual participants
(operator, driller, other service companies). Interior, insurance underwriters, or other independent entities should
evaluate and monitor the risk of offshore drilling activities to
promote enhanced risk management in offshore operations
and to discourage unqualified companies from remaining in
the market.
• The Department of Justice’s Office of Dispute Resolution should conduct an evaluation of the Gulf Coast Claims
Facility once all claims have been paid out in order to inform
claims processes in future spills of national significance. The
evaluation should include a review of the process, the guidelines used for compensation, and the success rate for avoiding law suits.
• Increase and maintain congressional awareness of the
risks of offshore drilling in two ways. First, create additional

Oil & Gas Journal | Jan. 17, 2011

1/13/11 1:35 PM

congressional oversight of offshore safety and environmental
risks. Second, require the appropriate congressional committees to hold an annual oversight hearing on the state of
technology, application of process safety, and environmental protection to ensure these issues receive continuing congressional attention.
• Congress should enact legislation creating a mechanism for offshore oil and gas operators to provide ongoing
and regular funding of the agencies regulating offshore oil
and gas development. OGJ

Stronger-than-expected demand
to drive oil prices, experts say
Nick Snow
Washington Editor

Stronger-than-anticipated global demand apparently is the
main reason crude oil prices began to rise late in 2010, four
experts suggested. Growth in China has been particularly
robust, they agreed.
More details will emerge when the US Energy Information Administration issues its latest Short-Term Energy Outlook on Jan. 11 and the International Energy Agency publishes its next Monthly Oil Report on Jan. 18. But IEA Chief
Economist Fatih Birol warned on Jan. 5 that a recovering
global economy faces a threat from rising crude prices.
“Oil prices are entering a dangerous zone for the global
economy,” Birol said. “The oil import bills are becoming a
threat to the economic recovery. This is a wake-up call to the
oil-consuming countries and to the oil producers.”
Birol’s observation followed a recent IEA analysis that
found that oil import prices for Organization for Economic
Cooperation and Development member countries climbed
by $200 billion to $790 billion by yearend 2010. The trend
toward higher prices emphasizes the need for consuming
countries to increase efforts to reduce the amount of oil they
use, particularly for transportation, he suggested.
That would need to take place amid oil demand that was
surprisingly strong last year, experts told OGJ. “Contributing factors include a cold winter in the United States, and
increased demand in China from diesel use restricting grid
generation,” American Petroleum Institute Senior Economist
Sara Banaszak said. “Economies also are recovering worldwide, and demand also has been strong domestically.”

‘More pressure’
Lost production from the Gulf of Mexico following the Apr.
20 Macondo well accident and subsequent oil spill also may
have contributed to higher prices, but other factors were
more important, Banaszak said. “[US President Barack]

Oil & Gas Journal | Jan. 17, 2011

110117OGJ_19 19

Obama came into office with prices around $70/bbl, and his
years in office gave us a break from oil price pressure. Certainly, we all want the economy to recover, but it will put
more pressure on oil prices,” she said.
David Pumphrey, energy and national security deputy
director at the Center for Strategic and International Studies, said, “Certainly, on the fundamentals side, there’s been
a strong economic recovery from a couple of years ago. China’s economy barely stumbled before starting to recover. But
there also is a pretty big surplus capacity within [the Organization of Petroleum Exporting Countries], particularly
in Saudi Arabia. So in fundamental terms, prices should be
more stable.”
They have climbed, however, which Pumphrey said
makes him wonder if investors are putting more money into
oil. “There’s still a sense of trying to separate supply/demand
fundamentals from the role oil plays as a longer-term investment. That’s still uncertain,” he said, adding, “On balance, I
think what we’re seeing is a kind of perception that oil is a
good place to put money because the supply-demand fundamentals are exerting a lot of upward pressure.”
Adam Sieminski, chief energy economist at Deutsche
Bank’s global markets and commodities research department, said that group’s analyst who follows China says that
demand grew there by just over 1 million b/d in 2010, compared with IEA’s 880,000 b/d estimate. “We think demand
in China is likely to be up 880,000 b/d in 2011, while the
IEA is only looking for 450,000 b/d. It’s key because it’s so
big. There were internal policies there which encouraged
more consumption,” he said.
“The good news, from the consumer’s standpoint, is that
there‘s plenty of spare capacity in OPEC and spare inventory,” Sieminski continued. “That said, demand was higher
in 2010 than expected and is fairly robust at the beginning
of 2011. OPEC’s supply, while solid, looks as if it’s going to
be plateauing in the next 3-5 years.” That perception could
be affecting global crude markets, which respond more to
what could lie ahead than what’s happening now, he said. “I
think it’s reasonable to assume that markets will be tighter.
They don’t wait for supplies to tighten; they react now, and
this economic reality always seems to surprise politicians,”
Sieminski said.

Weakening US dollar
Christopher Guith, vice-president for policy at the US
Chamber of Commerce’s Institute for 21st Century Energy,
also noted that China did not feel the recession as much as
the rest of the world did and it began to recover sooner. But
he also suggested that the US has used monetary policy to
make the dollar more liquid, which has reduced its global
purchasing power.
“China, which is not tied to the US dollar, could buy the
same amount of oil for less. My economist friends tell me
the dollar is becoming more stable and it should be less of


1/13/11 1:35 PM

an issue,” he told OGJ. “They also seem to generally believe
we won’t see the kind of oil-price spikes we saw in 2008 because we’re in better supply shape and OPEC is more likely
to keep incremental production at its marginal sweet spot.”
Sieminski also did not consider the current situation
similar to 2008. “There was no spare production capacity
then. Most of it had been used up between 2004 and 2008,
and there also was very little spare refining capacity,” he explained. “To be more precise, there was spare production

capacity but it was largely heavy oil and there were no refineries to take it. In the first half, everyone seemed to think we
were in a new era of no recession and demand was growing.
“That seems to contradict charges of rampant speculation,” he maintained. “With everybody thinking that demand would move up continually, the markets responded
accordingly. Then the recession solved the problem of spare
capacity—in a very nasty way.”
Sieminski said OPEC may need to be careful now to not
let the global oil market get too carried away. “The Saudis

EIA: Global oil markets to tighten in next 2 years
Nick Snow
Washington Editor
The US Energy Information Administration anticipates that
global crude oil markets will tighten over the next 2 years
as annual consumption grows by an average 1.5 million b/d
and growth in supplies outside the Organization of Petroleum
Exporting Countries increases less than 100,000 b/d yearly,
EIA said in its latest Short-Term Energy Outlook.
“Consequently, EIA expects the market will rely on both
inventories and significant increases in production of crude
oil and non-crude liquids in OPEC member countries to meet
world demand growth,” it said. “While onshore commercial
oil inventories in the Organization for Economic Cooperation and Development (OECD) countries remained high last
year, floating oil storage fell sharply in 2010, and EIA expects
OECD oil inventories will decline over the forecast period.”
Many significant uncertainties could push oil prices
higher, the report suggested. They include OPEC’s not
increasing production as demand growth recovers, uncertain
economic recovery rates domestically and globally, Chinese
government efforts to address growth and inflation concerns,
and unforeseen production issues, it said.
The Jan. 11 forecast, which was the first by EIA to cover
periods through December 2012, raised its prediction of
spot West Texas Intermediate crude prices by $7/bbl from
a month earlier to about $92/bbl after WTI prices averaged
more than $89/bbl in December, about $5/bbl more than
November’s average. It said that WTI spot prices could average $93/bbl during 2011, reaching an average $99/bbl in
the fourth quarter, and average $98/bbl in 2012.
It expects non-OPEC crude and liquids production to
rise by 160,000 b/d in 2011 and 20,000 b/d in 2012, with
increases concentrated in a few countries, notably China,
Canada, and Brazil. EIA anticipates that each of these overseas producers’ output will grow by 120,000-150,000 b/d in
2011 and 2012. Ghana became a new non-OPEC producer
in December with the startup of its Jubilee field, it noted.


110117OGJ_20 20

Non-OPEC declines
Other non-OPEC countries’ production will decline, EIA predicted. It expects Mexico’s production to drop by 200,000
b/d in 2011 and 80,000 b/d in 2012. “Similarly, the United
Kingdom is expected to see production declines of an average 120,000 b/d in both 2011 and 2012 since oil production
and the discovery of new reserves have not kept pace with
the maturation of existing fields,” it said.
It said that while OPEC is not scheduled to meet until
June to discuss its production targets, EIA anticipates that
the cartel and its members will continue to increase production to accommodate growing demand, especially since
non-OPEC supplies’ growth will be limited. OPEC’s total
production could grow by 500,000 b/d in 2011 and 1 million
b/d in 2012, while its non-crude liquids production, which is
not subject to targets, could climb by 700,000 b/d this year
and 400,000 b/d next year, it indicated.
EIA said that it expects OPEC’s surplus crude oil production capacity to fall from about 4.7 million b/d at the end of
2010 to 4.3 million b/d at the end of 2012.
Domestically, it said that preliminary data indicate that US
consumption of petroleum and non-petroleum liquid fuels
grew by 350,000 b/d, or 1.9%, during 2010. Most of the
increase came with distillate fuel oil, where demand climbed
by 130,000 b/d, or 3.7%, and motor gasoline, where demand
rose by 60,000 b/d, or 0.7%, it said. EIA projected that total
US liquid fuels consumption would grow by 160,000 b/d, or
0.8%, in 2011 and 170,000 b/d, or 0.9%, in 2012, reaching
an average 19.4 million b/d at the end of that year.
It said that it expects US crude oil production, which
grew by 150,000 b/d in 2010 to 5.51 million b/d, to decline
by 20,000 b/d in 2011 and 130,000 b/d in 2012. The 2011
forecast includes declines of 50,000 b/d in Alaska and
220,000 b/d in federal Gulf of Mexico production, which
are almost offset by a projected 250,000 b/d increase in
non-gulf production in the Lower 48 states, it said. In 2012,
EIA said that it expects Lower 48 non-gulf output to grow by
70,000 b/d, Alaskan production to fall by 20,000 b/d, and
output in the gulf to decrease by 180,000 b/d.

Oil & Gas Journal | Jan. 17, 2011

1/13/11 1:35 PM

can turn the spare production on now, but people may be
thinking that in 3 more years, we’ll be back in the same boat
we were in back in 2008,” he said, adding, “Even though
speculators may have had something to do with the forward
momentum, other major forces, essentially the economy
driving demand and investment cycles driving supply, are
much more significant.”

Overseas production
The production growth outlook outside North America appears mixed, the experts said. “Russian production has been
coming back up. It recently set a record for the post-Soviet
period. It hasn’t been below expectations,” Pumphrey observed. “Venezuelan expectations have been written down
for a while. It seems to be producing as much as it can. The
Saudis seem to be very strong. OPEC behavior matters as
well. Most statements, particularly from the Saudis, say they
don’t benefit from a price runup. How quickly they can accommodate increased demand is another issue.”
Sieminski surmised, “Venezuela and Nigeria have obvious internal political problems. As far as Russia is concerned, they’ve actually been an up-side surprise in 2010,
starting at the beginning of the year, and could continue that
way in 2011. EIA has Russian production down 150,000 b/d
in 2011. We believe it will be flat-to-up.”
Guith told OGJ: “Over the long run, Venezuela, Russia,
and Nigeria always pose production risks because of their
reliability. On the other hand, countries like Brazil are making their production grow, and there’s much more exploration off Southeast Asia as well. They’re more expensive to
produce, but as North America grows more and more inaccessible, that’s where companies are going.”
That trend has accelerated since US Interior Sec. Ken
Salazar removed most of the US Outer Continental Shelf
from the next 5-year program because of concerns emerging
from the Macondo accident, Guith said. “Ultimately, it could
become a political issue, but if you look at what America
spent on imports last year, it rose by $72 billion,” he said.
“The more we take domestic supplies off-line, make them
inaccessible, or delay their production for decades, the more
we have to import at a time when we can least afford it from
an economic standpoint.”
The question of what resources actually will be available
onshore as well as offshore may have a long-term effect on
prices, Pumphrey said. “Investors may hesitate, especially
since the presidential commission report indicates there are
still issues with regulatory processes,” he said.

The Iraq question
Oil markets also aren’t certain about Iraq’s production prospects, particularly since production there hasn’t changed
much in the last 5 years, Pumphrey told OGJ, while Sieminski separately observed, “We need stability in Iraq to have
stability in the oil markets.”

Oil & Gas Journal | Jan. 17, 2011

110117OGJ_21 21

Sieminski maintained that if any single force was responsible for oil prices rising so much in 2010, the simplest explanation is that global oil demand grew by more than 2.5
million b/d—“a huge climb.” He said, “No one was talking
about an oil shortage, but the growth was about twice the
level of what people were talking about a year ago.”
He added that the seemingly inexorable rise in OPEC’s
market power is also closer. “People who thought things
would be tight around 2015 at the beginning of 2010 now
see a year’s faster-than-expected growth in demand, so now
it seems more like 3 years instead of the 4 years it would
have been if demand hadn’t been so strong,” Sieminski said.
“OPEC can produce the oil, but in the next 5 years, the world
will need Iraq’s capacity to grow to keep OPEC’s spare capacity from shrinking.” OGJ

Chamber to fight EPA’s GHG
program, excessive reform
Nick Snow
Washington Editor

The US Chamber of Commerce will continue efforts to keep
the US Environmental Protection Agency from implementing greenhouse gas emission regulations under the Clean Air
Act, Chamber Pres. Thomas J. Donahue said in his annual
State of American Business address. Chamber also plans to
fight excessive financial reforms that would unduly restrict
use of derivatives, he added.
The rules are part of a federal “regulatory tsunami” that
poses the biggest single threat to jobs, US global competitiveness, and the future of American enterprise, Donahue
“At the federal level alone, regulations already fill 150,000
pages of fine-print text and cost Americans $1.7 trillion/
year,” he said. “Many of these rules are necessary and business strongly supports them. Yet in recent years, we have
seen an unprecedented explosion of new regulatory activity.
Furthermore, the [Obama] administration is likely to turn
increasingly to the regulatory agencies now that getting legislation out of Congress could be more difficult.”
Donahue said the nation’s largest business organization
would go on fighting what it considers unilateral regulation of GHGs under the CAA, which EPA began to develop
following a 2007 US Supreme Court ruling that the federal
agency has that authority. The regulations began to go into
effect at the beginning of 2011 with a tailoring rule which
initially targets refiners, chemical plants, and other major
industrial facilities believed to be the largest GHG emitters.
The regulations, if unchecked, eventually could involve 6 million entities, including small businesses, hotels,


1/13/11 1:35 PM



Washington Editor | Blog at www.ogj.com

Outlooks in four states
State oil and gas associations headed
into the 2011 legislative season cautiously optimistic as Republicans took
control or increased majorities in several houses and senates. They also expect governors and lawmakers to grapple with budget questions as revenue
growth remains elusive.
But when OGJ asked four state association executives how they planned to
proceed, they sounded strikingly like
their national counterparts despite facing sometimes different situations.
“The industry and the businesses
which support it supply very good jobs
for many people in California,” said
Catherine Reheis-Boyd, president of
the Western States Petroleum Association in Sacramento.
She noted that Democrat Jerry
Brown, who is back as governor after
28 years, expressed support for a green
economy as long as it didn’t imperil
existing businesses.
“If he’s serious, we’ll have a lot to
talk about,” she said, adding, “We need
to encourage [exploration and production] and refining abilities to produce
cleaner fuels.”
She also expects WSPA to begin serious outreach in the state’s assembly,
and hopes to get support from moderate Democrats there.
Republicans gained ground in the
legislatures of Pennsylvania, Kansas,
and Montana, but state association
leaders there aren’t resting easy.
Louis D’Amico, president of the
Pennsylvania Independent Oil & Gas
Association in Wexford, noted that
Republican Tom Corbett clearly ap-


110117OGJ_22 22

pears less likely to raise taxes as governor than his predecessor. Republicans
also took control of the House and increased their majority in the Senate, he

Talk of a fee
“However, there’s been a lot of media campaigning for a severance tax,”
D’Amico said, adding, “Although the
governor-elect has said he’s against it,
there’s been talk of some sort of fee.”
Edward P. Cross, president of the
Kansas Independent Oil & Gas Association in Topeka, said the group built
good relations with new Gov. Sam
Brownback when he was a US senator.
“There probably will be some spending cuts when the budget is released.
Our industry wants any tax question
addressed fairly. We don’t want to be
singled out,” Cross said.
David A. Galt, executive director of
the Montana State Petroleum Association in Helena, sounded the most optimistic. “There’s an overwhelming majority of new state representatives who
have put support of natural resourcebased industries at the top of their
agendas,” he explained.
While the state was one of the few
to finish 2010 with a positive balance,
Galt expects lawmakers to look closely
at budgets and spending. “I think we
just have to be thoughtful in our submissions,” he said. “A lot of members
are trying to find ways to make Montana as active in oil and gas as North
Dakota, and we’ll try to find ways to
help them.”

warehouses, and churches, Donahue
warned. “Before any of these facilities
could build or expand, they would
have to get preconstruction permits
that take 6-9 months to obtain at a
cost in excess of $100,000/permit,”
he said. “Even then, the permits could
be challenged in court. This could seriously disrupt construction activity
across our nation and throw a lot of
people out of work.”
He said Chamber would support bipartisan legislation that would delay or
stop EPA’s current GHG program and
return efforts to address global climate
change to Congress.

Dodd-Frank reforms
Donahue said Chamber also is heavily involved in the regulatory rulemaking triggered by passage of the
Dodd-Frank Wall Street Reform and
Consumer Protection Act. He noted
that the new law contains 259 mandated rulemakings, 188 suggested
rulemakings, 63 reports, and 59 studies, adding, “My grandchildren will be
old and retired before it is all implemented.”
“We are particularly concerned that
the new Consumer Financial Protection Bureau does not use its broad authority in ways that deny small businesses and consumers the credit and
financial products they need,” he said.
“We want to make sure that Main
Street end-users are still able to use derivatives in an effective way to manage
their legitimate business risk—without sidelining billions of dollars in
productive capital and costing tens of
thousands of jobs.
“And although our pending litigation against the [US Securities and
Exchange Commission] over its proxy
access rule has delayed its implementation, that battle is far from over,” Donahue said. “We’ll continue to oppose
proposals that would expand the ability of special interest shareholders such
as unions to exploit proxy access rules
to the detriment of companies, jobs,
and all shareholders.”
He said Chamber would use a broad

Oil & Gas Journal | Jan. 17, 2011

1/13/11 1:35 PM

array of tools to address these and other regulations that it
considers excessive, including efforts to limit funding and
more applications of the Congressional Review Act. “Yet the
time has come to reform the regulatory process itself—to
restore some badly needed balance and accountability to the
system. This could be done by giving Congress the right to
vote up or down on major rules before they take effect, and
by strengthening the burden of proof that all agencies would
have to demonstrate in court when they are imposing major
rules,” he suggested.
Donahue said new regulations also provide new opportunities for lawsuits. “The need for legal reform as well as
courtroom advocacy on behalf of business will be greater
than ever in the coming year and beyond,” he said. “Our
Institute for Legal Reform and our law firm, the National
Chamber Litigation Center, will therefore play a critical role
in the Chamber’s ongoing program of work.”
Chamber also will form a new group of regulatory experts
to tell policymakers, the media, and the public the story of
massive impacts of regulations on business, he said.

NTSB recommends safety actions
in San Bruno line blast probe
Nick Snow
Washington Editor

The National Transportation Safety Board issued seven safety recommendations, six of them classified as urgent, as a
result of its investigation of the Sept. 9, 2010, natural gas
pipeline rupture and explosion in San Bruno, Calif., which
killed eight people. It also scheduled a hearing for Mar. 1-2
as part of its inquiry.
“This accident has exposed issues that merit further attention and have implications for the pipeline infrastructure
throughout the country,” said NTSB Chairwoman Deborah
A.P. Hersman. “The hearing will gather additional factual
information for the investigation and will also provide the
pipeline industry, state, and federal regulators, and our citizens with an opportunity to hear more about this accident
and important safety issues as the investigation progresses.”
NTSB noted in a Dec. 14, 2010, investigation update that
while records of the gas distribution pipeline’s operator, Pacific Gas & Electric Co., showed the line in the rupture area
was seamless, it at least partially was constructed of longitudinal steel pipe. Some of the seams in this pipeline section were welded from both the inside and the outside, while
others were welded only from the outside, it added.
“It is critical to know all the characteristics of a pipeline
in order to establish a valid [maximum allowable operating
pressure (MAOP)] below which the pipeline can be safely

Oil & Gas Journal | Jan. 17, 2011

110117OGJ_23 23

operated,” the independent federal agency said in letters to
PG&E, the California Public Utility Commission (CPUC),
and the US Pipeline and Hazardous Materials Safety Administration. “NTSB is concerned that these inaccurate records
may lead to incorrect MAOPs.”

Recommendations for PG&E
NTSB said it issued three safety recommendations, two of
which were urgent, to PG&E as a result. It urgently recommended that the utility intensify the search of its records to
identify all of its gas lines that have not undergone a testing
regiment to validate a safe operating procedure. It urgently recommended that the utility determine the maximum
operating pressure (MOP) based on the weakest section of
pipeline or component identified in that records search. And
if PG&E is unable to validate a safe operating procedure in
this manner, it should determine one by a specified testing
Kirk Johnson, PG&E’s vice-president of gas engineering
and operations, said the company was giving NTSB’s recommendations “close and serious attention.” He said PG&E has
been intensively reviewing all of its pipeline records, scrutinizing and verifying thousands of documents to confirm
the data’s accuracy. “We are managing this process across
PG&E’s entire system as part of our ongoing commitment to
place the highest priority on safety,” he indicated.
PG&E has been working closely with NTSB on its investigation as well as thoroughly reviewing its own records to
confirm their accuracy, according to Johnson. “PG&E will
continue to work closely with the NTSB, CPUC, and PHMSA
to ensure we fully understand and are responsive to their
recommendations,” he said.
The independent federal agency also expressed concern
other gas pipeline operators may have similar discrepancies
in their records that could compromise safety. It urgently
recommended PHMSA expeditiously inform the pipeline industry of the San Bruno accident’s circumstances and investigative findings so pipeline operators can quickly implement corrective measures.

PHMSA advisory bulletin
PHMSA issued an advisory bulletin on Jan. 4, reminding operators of gas and liquid pipelines of their responsibilities
under federal integrity management regulations to perform
detailed threat and risk analyses that integrated accurate
data and information from their entire pipeline system, especially when calculating MAOP and MOP, and to use these
analysis methods to identify appropriate assessment methods and identify prevention and mitigation steps.
NTSB also directed three urgent recommendations to the
CPUC, which regulates intrastate pipelines in California. It
asked the CPUC to ensure that PG&E “aggressively and diligently” search documents and records to determine which
pipeline segments have not gone through the testing regi-


1/13/11 1:35 PM

men it recommended to the utility, and to provide oversight
of any testing by PG&E if a documents and records search
can’t be satisfactorily completed. CPUC also was asked to
immediately notify other California intrastate gas pipeline
operators of the San Bruno accident’s circumstances so they
might implement corrective measures on their own systems.
Paul Clanon, CPUC’s executive director, immediately
sent letters to Southern California Gas Co., San Diego Gas
& Electric Co., and Southwest Gas Corp. as well as PG&E
directing the companies to report steps they are taking in
response to NTSB’s recommendations to him by Feb. 1.
In a Jan. 5 statement, the American Gas Association,
which has primarily gas utilities as members, said it is encouraged by NTSB’s recent focused recommendations on operators’ need to have accurate records to ensure pipelines are
operating at a proper pressure. “As this process continues,
we look forward to learning more about the possible causes
of this tragic incident, as well as additional recommendations for improving the gas utility industry’s already strong
record of safety,” it said. OGJ

Talisman to grow
in high-return shale plays
Alan Petzet
Chief Editor-Exploration

Talisman Energy Inc. plans to hike production and reserves
in the Montney, Marcellus, and Eagle Ford shale plays in
North America and will explore for shale gas in northern
Poland in 2011.
Rob Broen, president of the US shale business unit based
in Pittsburgh, said, “We have enough lands and resource
to support production growth to 1 bcfd for the company in
each one of these plays.”
At 760,000 net acres the company also has the largest
contiguous land position in a shale play initially targeting
Ordovician Utica shale in Quebec’s St. Lawrence Lowlands,
where it is working with government and industry to establish a regulatory system, service sector, and infrastructure.
Talisman’s overall 2010 production of 415,000 b/d of oil
equivalent is balanced in liquids and gas, and 50% of projected 2011 growth volumes are liquids, said Broen.
Of (US) $4 billion in 2011 worldwide capital spending,
Talisman will invest $1.7 billion in North America, $1.3 billion of it on shale properties. In the three main plays Talisman’s portfolio allows it to control the development pace,
so it is not chasing land and isn’t required to spend to hold
land, Broen said.
In the Marcellus shale in Pennsylvania, Talisman has an
$800 million in 2011 capital program. It will run as many


110117OGJ_24 24

as nine rigs, compared with 12 at present and six at the start
of 2010.
Production is centered on 218,000 net acres in Tioga,
Bradford, and Susquehanna counties in northeastern Pennsylvania, where Talisman has identified more than 2,000
drilling locations and a 6 tcf contingent resource. The company also cites a 5 tcf Marcellus on lands it holds in New
Talisman expects to average 350-400 MMcfd of production in 2011 compared with 181 MMcfd in 2010. It ended
2010 at 315 MMcfd.
It has secured up to 600 MMcfd of pipeline capacity for
Marcellus gas. The company had no Marcellus activity in
2008, when it was a Trenton-Black River explorer in the Appalachian basin, Broen noted. Drilling and completion costs
have fallen 70% to $400,000/well or a full-cycle breakeven
cost of $3.50/Mcf.
Wells are generally on line within 3-4 days of completion.
Talisman drills 5,700-ft laterals and applies 16-18 frac stages
to generate 30-day average initial production of 4-5 MMcfd
and estimated ultimate recovery of more than 5 bcf/well.
In the Montney shale in Northeast British Columbia, Talisman operates the Greater Cypress and Farrell Creek areas
west of Fort St. John and participates in the Shell-operated
Greater Groundbirch area south of the city.
The company has 44 tcf of contingent resource in 271,000
net acres in the Montney, which is as thick as 1,400 ft spread
over three horizons. Talisman estimates full-cycle breakeven cost below $4/Mcf.
Talisman is moving from four rigs to eight in 2011, when
it expects to average 50-60 MMcfd net production. It is expanding the Farrell Creek processing plant to 180 MMcfd
from 120 MMcfd and has secured 500 MMcfd of pipeline
sales capacity. Well metrics are 5 MMcfd initial rates and 7
bcf EURs, Broen said.
Talisman sold 50% of 52,000 net acres at Farrell Creek
to South Africa’s Sasol in late 2010 for $1 billion. The 5050 properties have an estimated 9.6 tcf contingent resource.
The companies will drill 35 wells net to Talisman in 2011,
and Talisman is examining alternate marketing options including Sasol’s gas-to-liquids technology.
Talisman has a $300 million capital program in the Eagle
Ford shale and will grow from four rigs to eight in 2011,
spending a net $300 million, Broen said. Talisman, operator in 50-50 partnership with Statoil, sees 1,500 locations
on 135,000 net acres and a 1.1 billion boe contingent resource in the liquid-rich part of the play. Well results are
1,200 boe/d initial rates and 660,000 boe projected EURs.
The company will drill three vertical wells in Poland’s
Baltic basin in 2011 seeking gas in shales with favorable estimated technical parameters: 220-1,550 bcf/sq mile gas in
place, 600-2,300 ft thickness, 8,000-14,000 ft depth, and
0.9-9% total organic carbon. Talisman holds the Gdansk
West, Braniewo, and Szczawno blocks. OGJ

Oil & Gas Journal | Jan. 17, 2011

1/13/11 1:35 PM

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