International Petroleum News and Technology | www.ogj.com AUG. 1, 2011 | USD 10 HYDRAULIC FRACTURING LEGAL ISSUES IRAQ’S AHDAB OIL FIELD JAPAN RELIES MORE ON LNG OFFSHORE EUROPE PIPELINE REPORT
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International Petroleum News and Technology | www.ogj.com
AUG. 1, 2011 | USD 10
HYDRAULIC FRACTURING LEGAL ISSUES
IRAQ’S AHDAB OIL FIELD
JAPAN RELIES MORE ON LNG
OFFSHOREEUROPE
PIPELINEREPORT
110801ogj_digital_C1 C1 7/27/11 1:30 PM
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110801ogj_C2 C2 7/27/11 12:12 PM
0.70 1.40 2.10 2.80 3.50 4.20 4.90 5.60 6.30 7.00
Kiloelectron volts
Spot analysis
CN
O
FeSi
P
S
Cl
KCa
Fe
ESEM IMAGES,* EDS X-RAY SPOT ANALYSIS
z10
06
21
OG
J
FIG. 1
*At 2 microns magni�cation.
CONTENTSAug. 1, 2011 Volume 109.15
Study opens pathto optimized MIC assaysMazen Al-Saleh, Peter Sanders
Taw� q Al-Ibrahim, Susanne Juhler
Ketil Sorensen, Thomas Lundgaard
90 MULTIPRODUCT OPERATIONS—1:Discrete-event simulation guides pipeline logisticsVanina Cafaro, Diego C. Cafaro,
Carlos A. Mendez, Jaime Cerda
98
SPECIAL REPORTPIPELINE REPORT
REGULAR FEATURESNEWSLETTER 6
LETTERS 16
CALENDAR 16
JOURNALLY SPEAKING 18
EDITORIAL 20
EQUIP./SOFTWARE/LITERATURE 112
SERVICES/SUPPLIERS 113
STATISTICS 116
MARKETPLACE 119
ADVERTISERS’ INDEX 123
EDITOR’S PERSPECTIVE/
MARKET JOURNAL 124
Baker Institute: US shale gas might weaken Russia, IranPaula Dittrick
35
US House passes billto expedite Keystone XL permit decisionNick Snow
36
State utility regulatorscall for moreCCS-EOR projectsNick Snow
37
WATCHING GOVERNMENT
Keeping counties in the loop
38
WATCHING THE WORLD
Iran’s oil minister nominee
40
BP gains blocks off Trinidad and TobagoCurtis Williams
40
GENERAL INTEREST
Hydraulic fracturing: protecting against legal and regulatory riskBlaine D. Edwards,
E. James Shepherd, Nick Deutsch
22
FOCUS: UNCONVENTIONAL OIL & GAS—Industry upbeat Marcellus shale holds great economic potentialPaula Dittrick
30
COVERThe Northern Producer � oating production platform is on station at West Don
� eld 150 km northeast of the Shetland Islands in the northern UK North Sea
for EnQuest PLC, London, the largest UK indpendent producer in the UK North
Sea. An article about trade group Oil & Gas UK’s efforts to keep UK North Sea
exploration and development operations competitive in the face of a 2011 UK
tax increase starts on p. 42 in the annual Offshore Europe special report. Oil &
Gas Journal’s special Pipeline Report, beginning on p. 90, examines advances in
discrete-event simulation in scheduling multiproduct pipelines and details Saudi
Aramco’s efforts to better predict and mitigate microbiologically induced corrosion
in its crude system. Photo courtesy of EnQuest.
90
SPECIAL REPORTOFFSHORE EUROPE
Industry lobby group sees declining government revenue in UK tax hikeMike Tholen
42
30
42
110801ogj_1 1 7/28/11 12:02 PM
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110801ogj_rev_2 2 7/27/11 5:18 PM
EXPLORATION & DEVELOPMENT
Industry lobby group sees declining government revenue in UK tax hikeMike Tholen
42
Have the stars alignedfor higher oil prices?Rafael Sandrea
48
Reflectance standard adopted for dispersed vitrinite in sediment52
BP mulls $15 billion investment in Omani tight gas fields54
Canada sees 78 tcf marketable inHorn River basin56
Louisiana, Mississippi marine shaleoil play growsAlan Petzet
58
DRILLING & PRODUCTION
Iraq’s Ahdab oil field development limits contractor profitabilityMuhammed Abed Mazeel
62
DRILLING CONSORTIUM—2 (Conclusion): Drilling campaign obtains continuous improvementBjorn Thore Ribesen, Arild Saasen,
Kjell Arild Horvei, Tove Magnussen,
Tormod Veiberg
68
TRANSPORTATION
Study opens path to optimized MIC assaysMazen Al-Saleh, Peter Sanders,
Taw� q Al-Ibrahim, Susanne Juhler
Ketil Sorensen, Thomas Lundgaard
90
MULTIPRODUCT OPERATIONS—1:Discrete-event simulation guides pipeline logisticsVanina Cafaro, Diego C. Cafaro,
Carlos A. Mendez, Jaime Cerda
98
Water-injection testing improves terminal operationsMohammad Zahedi,
Kourosh Tahmasbi Nowtarki
106
PROCESSING
LNG figures heavily in Japan’s postdisaster energy demandTomoko Hosoe
74
NPRA Q&A—2:Discussion expandsto includecoking, corrosion82
Nelson-Farrar monthly cost indexes88
380
Demobilizations16 Wells
5 Mobilization
bases
360
Mobilizations
3,891
Cargo baskets,
13,295 tons
52
68
Kashima (oil; Tepco)
Halted but hasresumed operation
Remain halted
Not affected
Noshiro (coal; Tohoku)
Akita (oil; Tohoku)
Higashi Niigata
(oil & LNG; Tohoku)
Niigata (oil & LNG;
Tohoku)
Higashi-dori (nuclear; Tohoku)
Hachinohe (oil; Tohoku)
Onagawa (nuclear; Tohoku)
Sendai (LNG; Tohoku)
Shin Sendai (LNG; Tohoku)
Haramachi (coal; Tohoku)
Hirono (oil & coal; Tepco)
Fukushima Daiichi (nuclear; Tepco)
Fukushima Daini (nuclear; Tepco)
Tokai Daini (nuclear; Japco)
Hitachinaka (coal; Tepco) 74
Jet mix Static mix Power mix
Installation
Maintenance
Pressure loss
Hot tap
External
Immeasurable
Cut, �ange
Minimal, nonremovable
n/a
Cut, �ange “T”
Dif�cult; depressurize, draw
Low 106
110801ogj_3 3 7/28/11 12:02 PM
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PennWell, Houston of� ce
1455 West Loop South, Suite 400, Houston, TX 77027
Telephone 713.621.9720 / Fax 713.963.6285
Web site www.ogj.com
Editor Bob Tippee, [email protected]
Chief Editor-Exploration Alan Petzet, [email protected]
Chief Technology Editor-LNG/Gas Processing Warren R. True, [email protected]
Production Editor Guntis Moritis, [email protected]
Pipeline Editor Christopher E. Smith, [email protected]
Senior Editor-Economics Marilyn Radler, [email protected]
Senior Editor Steven Poruban, [email protected]
Senior Writer Sam Fletcher, [email protected]
Senior Staff Writer Paula Dittrick, [email protected]
Survey Editor/News Writer Leena Koottungal, [email protected]
Publisher Jim Klingele, [email protected]
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Associate Presentation Editor Michelle Gourd, [email protected]
Statistics Editor Laura Bell, [email protected]
Illustrators Mike Reeder, Kay Wayne
Editorial Assistant Donna Barnett, [email protected]
Production Director Charlie Cole
Production Manager Shirley Gamboa
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Copyright 2011 by PennWell Corporation (Registered in U.S. Patent & Trademark Of� ce). All rights reserved. Oil & Gas Journal or any part thereof may
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110801ogj_4 4 7/28/11 12:02 PM
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NewsletterOGJ®
International News for oil and gas professionals
For up-to-the-minute news, visit www.ogjonline.com
6 Oil & Gas Journal | Aug. 1, 2011
Aug. 1, 2011
GENERAL INTEREST QUICK TA K ES
US Senate panel defers vote on sharing revenueDissension over revenue sharing with states kept the US Sen-
ate Energy and Natural Resources Committee on July 21 from
voting on a bill to reform federal management of resources on
the US Outer Continental Shelf. The committee lost its quo-
rum soon after two of its members, Mary L. Landrieu (D-La.)
and Lisa Murkowski (R-Alas.), the committee’s ranking minor-
ity member, introduced their revenue sharing amendment, and
the vote was postponed.
Several committee members spoke in favor of the amend-
ment, Murkowski said afterward. She said she planned to work
with them in the days ahead to refine the amendment’s lan-
guage to include funding for renewable energy projects at the
state level, and to reschedule the markup soon so that S. 917,
the Outer Continental Shelf Reform Act, and the amendment
could be voted on.
“Those who understand the importance of inviting coastal
states to be partners in our efforts to increase the nation’s en-
ergy security are not going to let this issue go away,” Murkows-
ki said. “It is in our best interest to have American workers
producing American energy, and revenue sharing will help us
reach that goal.”
The Landrieu-Murkowski revenue sharing amendment
would allow coastal states to retain a portion of the revenues
generated by energy production in federal waters, beginning in
2019. It would apply to all forms of energy production, from oil
and gas to wind and hydrokinetic. Murkowski’s new language
would create a coastal state clean energy fund with 12.5% of the
overall federal revenue from offshore production.
Meanwhile, the committee passed S. 916, the Oil and Gas
Facilitation Act, by voice vote. The bill would extend a federal
permit processing improvement pilot program through 2020,
authorize coproduction of geothermal energy on oil and gas
leases, mandate a comprehensive inventory of OCS resources,
establish an Alaska OCS permit processing coordination office,
and phase-out deepwater royalty relief.
Aramco, Dow announce JV chemicals projectSaudi Aramco and Dow Chemical Co. reported the approval of
the formation of a joint venture to build and operate a world-
scale, fully integrated chemicals complex at Jubail Industrial
City in Saudi Arabia.
Aramco Chief Executive Officer Khaled Al Falih said the
venture with Dow would “enable significant development in
the country’s conversion industry, thereby supporting Saudi
Arabia’s ambition to be a magnet for downstream manufactur-
ing investments that add significant value to the kingdom’s hy-
drocarbon resources.”
The companies said authorization for the JV, to be called
Sadara Chemical Co., comes after an extensive project feasi-
bility study and front-end engineering and design effort that
began in 2007.
Sadara, an Arabic word meaning “in the lead,” should have
annual sales of $10 billion within a decade of opening and cre-
ate thousands of jobs, the companies said.
Comprised of 26 manufacturing units building on Aramco’s
project management and execution expertise, and utilizing
many of Dow’s technologies, the complex will be one of the
world’s largest integrated chemical facilities, and the largest
ever built in one single phase.
The complex will possess flexible cracking capabilities and
will produce more than 3 million tonnes/year of chemical prod-
ucts and performance plastics.
Construction will begin immediately and the first produc-
tion units will come on line in second-half 2015, with all units
expected to be up and running in 2016.
Total investment for the project, including third-party in-
vestments, will be $20 billion. Sadara will become an equal
venture between Aramco and Dow after an initial public of-
fering. Sadara will have responsibility for product marketing
within a local zone of eight countries. Dow will market and sell
on behalf of Sadara to all countries outside of the Middle East.
Hilcorp to acquire Chevron’s Cook Inlet assetsHilcorp Alaska LLC, Houston, will acquire Cook Inlet assets
from Chevron Corp.’s Union Oil Co. of California unit for an
undisclosed sum.
Closing is expected by yearend. Chevron had put the assets
on the block in October 2010.
The assets are producing 3,900 b/d of oil and 85 MMcfd of
gas net to Unocal. Reserves weren’t revealed.
The assets include Unocal contracts and interests in Granite
110801ogj_6 6 7/28/11 12:23 PM
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Optimizing field-development plans. Unlocking unconventional plays.
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you’re facing tough challenges, look no further. Halliburton has the experienced,
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Consulting and Project Management
110801ogj_7 7 7/27/11 9:52 AM
July 20 July 21 July 22 July 26July 25
July 20 July 21 July 22 July 26July 25
July 20 July 21 July 22 July 26July 25
July 20 July 21 July 22 July 26July 25
July 20 July 21 July 22 July 26July 25
July 20 July 21 July 22 July 26July 25
WTI CUSHING / BRENT SPOT
$/bbl
118.00
114.00
110.00
106.00
102.00
98.00
94.00
90.00
$/bbl
118.00
114.00
110.00
106.00
102.00
98.00
94.00
90.00
NYMEX NATURAL GAS / SPOT GAS - HENRY HUB
IPE GAS OIL / NYMEX HEATING OIL
NYMEX GASOLINE (RBOB)1/ NY SPOT GASOLINE2
IPE BRENT / NYMEX LIGHT SWEET CRUDE
PROPANE - MT. BELVIEU / BUTANE - MT. BELVIEU
¢/gal
312.00
310.00
308.00
306.00
304.00
302.00
300.00
298.00
¢/gal
193.00
187.00
181.00
175.00
169.00
163.00
157.00
151.00
¢/gal
314.00
312.00
310.00
308.00
306.00
304.00
302.00
300.00
$/MMbtu
4.55
4.50
4.45
4.40
4.35
4.30
4.25
4.20
1Reformulated gasoline blendstock for oxygen blending2Nonoxygenated regular unleaded
Feb. 11 Mar. 11Jan. 11Sept. 10 Oct. 10 Nov. 10 Dec. 10Jun. 10 Jul. 10 Aug. 10 Apr. 11 May. 11 Jun. 11
1,200
1,800
1,600
2,000
1,400
400
600
200
0
BAKER HUGHES INTERNATIONAL RIG COUNT: TOTAL WORLD / TOTAL ONSHORE / TOTAL OFFSHORE3,900
3,600
3,300
3,000
2,700
2,400
2,100
1,800
1,500
300
0
3,256
2,925
333
Note: End of week average count
BAKER HUGHES RIG COUNT: US / CANADA
Note: Monthly average count
376
6/4/10 6/18/10 7/2/10 7/16/105/7/10 5/21/10
1,916
5/14/10 5/28/10 6/11/10 6/25/10 7/9/10 7/23/10 5/13/11 5/27/11 6/10/11 6/24/11 7/8/11 7/22/11
6/3/11 6/17/11 7/1/115/6/11 5/20/11 7/15/11
349
1,585
8 Oil & Gas Journal | Aug. 1, 2011
US INDUSTRY SCOREBOARD — 8/1
Motor gasoline 9,226 9,308 –0.9 9,012 9,044 –0.4Distillate 3,510 3,703 –5.2 3,749 3,756 –0.2Jet fuel 1,463 1,443 1.4 1,410 1,380 2.2Residual 505 463 9.1 541 533 1.5Other products 4,211 4,276 –1.5 4,333 4,459 –2.8TOTAL PRODUCT SUPPLIED 18,915 19,193 –1.4 19,045 19,172 –0.7
Supply, 1,000 b/d
Crude production 5,585 5,381 3.8 5,576 5,466 2.0NGL production2 2,165 1,992 8.7 2,059 2,084 –1.2Crude imports 9,220 8,572 7.6 8,844 9,201 –3.9Product imports 2,306 2,578 –10.6 2,559 2,583 –0.9Other supply2 3 2,161 1,795 20.4 2,096 1,744 20.2TOTAL SUPPLY 21,437 20,318 5.5 21,134 21,078 0.3
Refining, 1,000 b/d
Crude runs to stills 15,265 15,505 –1.6 14,432 14,541 –0.8Input to crude stills 15,657 15,935 –1.7 14,862 14,900 –0.3% utilization 88.4 90.6 — 84.2 84.5 —
4 wk. 4 wk. avg. Change, YTD YTD avg. Change,Latest week 7/15 average year ago1 % average1 year ago1 %
Product supplied, 1,000 b/d
Latest Previous Same week Change,Latest week 7/15 week week1 Change year ago1 Change %Stocks, 1,000 bbl
Crude oil 355,456 358,580 –3,124 353,096 2,360 0.7Motor gasoline 211,699 212,539 –840 221,036 –9,337 –4.2Distillate 145,028 142,061 2,967 162,640 –17,612 –10.8Jet fuel–kerosine 44,415 43,333 1,082 47,769 –3,354 –7.0Residual 37,984 37,805 179 41,343 –3,359 –8.1
Stock cover (days)4 Change, % Change, %
Crude 23.3 23.6 –1.3 23.2 0.4Motor gasoline 22.9 22.8 0.4 23.7 –3.4Distillate 41.3 39.7 4.0 43.9 –5.9Propane 65.6 55.5 18.2 62.5 5.0
Futures prices5 7/22 Change Change %
Light sweet crude ($/bbl) 96.71 97.10 –0.39 74.40 22.31 30.0Natural gas, $/MMbtu 4.39 4.23 0.16 4.51 –0.12 –2.7
1Based 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
110801ogj_8 8 7/28/11 12:23 PM
10 Oil & Gas Journal | Aug. 1, 2011
Point, Middle Ground Shoal, Trading Bay, and MacArthur River
fields, interests in 10 offshore platforms, interests in onshore
gas fields including the Ninilchik and Beluga River units, and
two gas storage facilities.
The package also includes interests in Cook Inlet Pipe Line
Co. and Kenai Kachemak Pipeline LLC. Chevron will retain its
nonoperated joint venture interests on the Alaska North Slope
and its 1.36% interest in the Trans-Alaska Pipeline System.
Hilcorp, founded in 1989, is one of the largest private US in-
dependent exploration and production companies. It employs
more than 700 people working nine operating areas including
the Gulf Coast, Gulf of Mexico, and Rocky Mountains. The
company participates in conventional and resource plays.
EXPLORATION & DEVELOPMENT QUICK TA K ES
Madalena tests oil in Vaca Muerta shaleMadalena Ventures Inc., Calgary, tested 40 b/d of 32° gravity oil
from untreated Lower Cretaceous Vaca Muerta shale at the CAS
X-1 well on the southern part of the 405 sq km Coiron Amargo
block in Argentina’s Neuquen basin.
Further testing of the well, including a large hydraulic frac
program, is expected to be completed in this year’s third quar-
ter. If successful, Madalena could try to accelerate testing its
other wells on the block using additional frac capacity being
brought into the basin as well as proceed with preparations for
a large, multiwell drilling program in 2011-12 specifically for
Vaca Muerta shale oil.
Meanwhile, the CAN X-4 exploratory well on Coiron Amargo
tested as much as 650 b/d of 39° gravity oil and 780 Mcfd of gas
at 700-900 psi wellhead pressure on 4 to 8-mm chokes from the
conventional Sierras Blancas formation. TD is 11,027 ft.
Both oil and gas shows were evident during the drilling of
the Vaca Muerta and Sierras Blancas formations at CAN X-4.
The Vaca Muerta shale interval is 456 ft thick. In the northern
and southern parts of the block, Madalena has drilled into the
Vaca Muerta formation five vertical wells, each of which ap-
pears similar on electric logs and have had indications of hy-
drocarbons.
YPF SA of Argentina earlier this year announced the delin-
eation of a technically recoverable resource of as much as 150
million bbl of oil equivalent in the Vaca Muerta shale about 10
km west of the Coiron Amargo block. The shale appears to be
gas prone along the broad western margin of the basin farther
west of Coiron Amargo.
Dwayne Warkentin, Madalena president and chief executive
officer, said, “The flow of oil from the Vaca Muerta shale in the
CAS X-1 well prior to any fracture stimulation combined with
the fracture stimulated results from the Vaca Muerta shale for-
mation in the nearby Loma La Lata block provide the company
with an excellent resource base in combination with the con-
ventional Sierras Blancas oil play on the Coiron Amargo Block.”
On the Cortadera Block, the CorS x-1 exploratory well is
drilling at 9,760 ft targeting the Quintuco, Mulichinco, Vaca
Muerta shale, and Tordillo formations. It is expected to reach
TD of 14,100 ft in early August.
On the Curamhuele block, Madalena is finalizing plans to
test several Lower Cretaceous Avile sands and the Lower Cre-
taceous Lower Troncoso formation encountered by the Yapai
X-1001 drilled in June.
Based on electric logs, the well encountered 23 ft of poten-
tial gross hydrocarbon column in the Lower Troncoso at 4,640
ft measured depth, 4,394 ft true vertical depth. As programmed
the well also encountered multiple stacked Avile formations at
6,800 ft MD, 6,530 ft TVD, to 10,620 ft MD, 10,360 ft TVD.
Testing is to start in August.
Hess, Petroceltic to explore blocks in IraqA partnership of Hess Corp. and Petroceltic International PLC
signed production sharing contracts with the Kurdistan Re-
gional Government for the Dinarta and Shakrok exploration
blocks northeast of Erbil, Iraq.
Each PSC has an initial 3-year exploration period in which
the joint venture plans to shoot 2D seismic and drill at least
one exploratory well. Hess is operator and has 64% participat-
ing interest and 80% paying interest. Petroceltic has 16% par-
ticipating interest and 20% paying interest, and the KRG has a
20% carried interest in each block.
Dinarta is a highly prospective undrilled block in a proven
but largely unexplored area. The 1,319 sq km block lies along
trend from the Shaikan, Atrush, and Swara Tika oil discoveries.
Dinarta has a number of identified surface structures, the
largest of which, the Chinara anticline, is 25 km along strike
from the Swara Tika-1 well, reported to be testing a significant
new discovery. The other structures also have large potential
surface closure areas with multiple reservoir targets believed
likely to be present in Jurassic and Triassic.
Shakrok is an undrilled block in a proven but largely unex-
plored area. It covers 418 sq km along trend from Taq Taq oil
field and the Bina Bawi oil discovery. The block itself contains
large surface anticlines with multiple reservoir Jurassic and Tri-
assic targets likely to be present.
Petroceltic said its total financial commitment during the
first license period is expected to be $72 million, the majority
of which will be incurred in the next 6 months. The amount
includes all signature and capacity building bonuses payable to
the KRG under the terms of the PSCs.
Harvest adds Dentale oil at presalt find off GabonHarvest Natural Resources Inc., Houston, has discovered a sec-
ond oil accumulation at its Gamba presalt oil discovery off Ga-
bon. Log evaluation, pressure data, and a fluid sample indicate
the discovery of 35 ft of oil pay in the Middle Dentale secondary
objective at the Dussafu Ruche Marin-1 well on the Dussafu
Marin PSC.
Harvest operates the block with 66.667% interest. The well
went to 11,355 ft true vertical depth subsea in 380 ft of water.
Harvest has appraised the Gamba discovery by drilling a
110801ogj_10 10 7/28/11 12:23 PM
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110801ogj_11 11 7/27/11 9:52 AM
12 Oil & Gas Journal | Aug. 1, 2011
sidetrack ¾-mile southwest to test the lateral extent and struc-
tural elevation of the Gamba reservoir. The sidetrack was drilled
to a TD in the Upper Dentale of 11,562 ft, 9,428 ft TVD ss, and
found 19 ft of oil pay in the Gamba reservoir.
Harvest will now sidetrack the DRM-1 well to the northwest
of the original DRM-1 wellbore to further appraise the extent
and structural elevation of the Gamba and the commerciality of
the Ruche discovery.
DRILLING & PRODUCTION QUICK TA K ES
Saudis start Karan gas flow in gulfSaudi Aramco began flowing natural gas last month from Karan
field in the Persian Gulf via subsea pipeline to the Khursaniyah
gas treatment plant onshore in Saudi Arabia.
The project constitutes Saudi Aramco’s first offshore nonas-
sociated gas field project (OGJ, June 6, 2011, p. 88).
Saudi Aramco discovered Karan in April 2006 in gulf waters
160 km north of Dhahran. The field has five production plat-
form complexes connected to a main tie-in platform, installed
with associated electrical power, communication, and state-
of-the-art remote monitoring and control facilities for safe and
reliable operations from onshore. Detailed design work began
in March 2009.
The field was discovered when the Karan-6 well drilled into
Khuff formations, finding gas in carbonate reservoirs laid down
200-300 million years ago in the Permian and Triassic periods.
At as thick as 1,000 ft, Karan’s is the thickest Khuff reservoir
section ever encountered in Saudi Arabia. The Khuff formation
at Karan lies at 10,500-13,700 ft in 40-60 m of water.
Shipped via a 110-km subsea pipeline, Karan gas is treated
at Khursaniyah through a number of trains that include facili-
ties for gas sweetening, acid-gas enrichment, gas dehydration,
and supplementary propane refrigeration. The onshore facili-
ties also include a cogeneration plant, a sulfur recovery unit
with storage tank, substations, and a transmission pipeline
linked to the kingdom’s Master Gas System (MGS).
Karan, designed to produce 1.8 bscfd of raw dry gas by 2013
to support the MGS, will be produced from 21 wells distributed
over five offshore wellhead platforms.
Five wells producing 120 MMscfd/well have been commis-
sioned so far. Early production is targeted for peak summer de-
mand, with an average production of more than 400 MMscfd,
Saudi Aramco said. Drilling is under way on 14 more wells on
three other platforms, and only four wells are left to be drilled.
The wells will be completed, tied in, and put on stream by June
2012 at 1.5 bscfd.
The remaining two wells and platform will be ready in April
2013, bringing the field to full capacity.
Whiting to buy power plant CO2 for EORFor enhancing oil recovery, Whiting Petroleum Corp. signed a
15-year agreement to buy carbon dioxide from a planned Perm-
ian basin coal-fueled power plant at Penwell, Tex., near Odessa.
The sellers of the CO2 are Summit Power Group LLC and
Blue Strategies LLC. Summit expects to start construction of
the plant by yearend and commence operations in late 2014 or
early 2015.
Whiting plans to purchase 80 MMcfd of compressed CO2
during the first 5 years of the plant’s operation, which is about
60% of the CO2 that the plant will capture. After 5 years, Whit-
ing will gradually buy less CO2 although it has an option to
extend purchases.
In the Permian basin fields, each 6 Mcf of CO2 injected can
recover about 1 bbl of oil, according to the companies selling
the CO2.
Summit said its Texas Clean Energy Project (TCEP) will be a
first-of-its-kind, integrated gasification combined cycle (IGCC)
400 Mw power-polygen plant. It is designed to capture 90%
of the CO2, 99% of the sulfur, more than 95% of the mercury,
and eliminate more than 90% nitrogen oxides produced by the
process.
The plant received a final air quality permit last December.
Summit and Blue Strategies partnered in October 2009 to
market TCEP’s 2.5 million tons/year of CO2 to oil producers in
the West Texas Permian basin.
The agreement with Whiting is the first of several CO2 off-
take agreements with TCEP that the companies expect to sign.
TCEP received a $450 million award in 2010 from the US
Department of Energy’s clean coal power initiative.
Whiting operates CO2-EOR floods in Postle field, Texas
County, Okla. and in North Ward Estes field, Ward and Win-
kler Counties, Tex.
CNOOC restarts Bozhong 28-2 South productionCNOOC Ltd. restarted production from the Bozhong 28-2
South (BZ 28-2S) oil fields in Bohai Bay off China.
CNOOC suspended operations in April because rough
weather caused a malfunction with the single-point mooring
of the Haiyanshiyou 102 floating, production, storage, and
offloading vessel. The FPSO also receives production from BZ
28-2 SN, BZ 34-1N, and BZ 29-4 oil fields.
CNOOC said the production capacity has recovered to the
level before the incident, reaching about 39,000 bo/d.
Production started from BZ 28-2S in 2009 (OGJ Online,
Mar. 19, 2009). The field, discovered in 2006, lies in 21 m of
water. CNOOC operates the fields with a 100% interest.
PROCESSING QUICK TA K ES
Murphy agrees to sell Wisconsin refineryAs part of a strategy announced last year to exit the refining
business, Murphy Oil Corp. has entered an agreement to sell its
33,250-b/cd refinery at Superior, Wisc., to Calumet Specialty
Products Partners, Indianapolis.
The sales price is $214 million plus the value of hydrocarbon
inventory, subject to adjustments. On June 30, the inventory
value was $260 million.
110801ogj_12 12 7/28/11 12:23 PM
110801ogj_13 13 7/27/11 9:53 AM
14 Oil & Gas Journal | Aug. 1, 2011
In addition to the Superior facility, Murphy hopes to sell
its 125,000-b/cd refinery at Meraux, La., and its 106,000-b/cd
refinery at Milford Haven, Wales. The company, based in El
Dorado, Ark., also plans to sell its UK retail system (OGJ, Aug.
2, 2010, Newsletter). It will concentrate on exploration and pro-
duction and US retailing.
Products of Calumet Specialty Products, which has six
plants in Northwest Louisiana, Pennsylvania, Texas, and Illi-
nois, include naphthenic and paraffinic oils, aliphatic solvents,
white mineral oils, petroleum waxes, petrolatum, and hydro-
carbon gels. Calumet officials said acquisition of the Superior
refinery will boost the company’s total throughput capacity by
50% to about 135,000 b/d.
Canadian company to restart Polish refineryA new Canadian company has acquired and plans to restart a
small refinery in southern Poland under a strategy that includes
the possible gasification of heavy feedstock and production of
synthetic fuels. Hudson Oil Corp. Ltd., Toronto, reports pro-
duction capacity of the Glimar refinery at 3,500 b/d of mainly
lubricant base oils and gasoline. The original refinery on the
site at Gorlice, Poland, was built in 1883 to distill oil mined in
the Galicia region. It was dismantled during World War II and
rebuilt in 1949.
Glimar now has a fractional (atmospheric-vacuum) distil-
lation column unit and a hydrocracking complex installed in
2000 by Lurgi GMBH with units, including isocracking, li-
censed by Chevron Lummus Global. The facility also has zeo-
forming units, installed by Lurgi in 1997 under a license from
the Novosibirsk Scientific Engineering ZEOSIT Center in Rus-
sia, for production of motor fuel.
Hudson said it is studying the use of Glimar’s hydroprocess-
ing units to produce liquid fuels via modified Fischer-Tropsch
technology from coal, natural gas, or municipal waste
TRANSPORTATION QUICK TA K ES
Crosstex expands Eunice NGL fractionationCrosstex Energy LP is completing engineering studies, pipeline
routing, and environmental permitting for an expansion of its
Eunice NGL fractionation facilities and extension of its Cajun-
Sibon NGL pipeline.
A 130-mile, 12-in. OD line will connect the Eunice frac-
tionation facilities to Mont Belvieu supply pipelines, extending
Crosstex’s 440-mile Cajun-Sibon NGL pipeline, and will have
an initial capacity of 70,000 b/d of raw-make NGLs. Crosstex
will expand the Eunice NGL fractionation facilities to 55,000
b/d from 15,000 b/d, increasing its interconnected fractionation
capacity in Louisiana to about 97,000 b/d.
Construction of the NGL pipeline will begin in second-
quarter 2012 and Crosstex expects the facilities to enter service
first-quarter 2013. Crosstex estimates project costs at $180-220
million.
Crosstex has entered into a long-term ethane sales agree-
ment with Williams Olefins LLC, a subsidiary of Williams Cos.
The ethane will flow into Williams’ ethane pipeline system in
Louisiana. Crosstex will feed its expansion from both its own
Texas gas plants and supplies from other companies. The com-
pany is negotiating additional long-term commitments for the
system expansion.
Crosstex says the project will improve the reliability and di-
versity of NGL supply to the Louisiana petrochemical and re-
finery markets. The company reached agreement with Apache
Corp. to jointly develop a gas processing plant in the Permian
basin in West Texas (OGJ Online, July 12, 2011). Permian sup-
plies are among those Crosstex expects to transport through its
new pipeline.
Chevron signs first LNG contract for WheatstoneChevron Australia has signed a binding sales and purchase
agreement with Tokyo Electric Power Co. (Tepco) for delivery
of as much as 3.1 million tonnes/year of LNG from Chevron’s
Wheatstone development off Western Australia.
Chevron, together with partners Apache Energy and Kuf-
pec, will make the deliveries over 20 years.
Chevron also is in discussions with Tepco to purchase an
equity share in the Wheatstone project fields as well as a share
in Chevron’s stake in the downstream processing plant and
facilities. The front-end engineering and design phase of the
Wheatstone project is nearing completion and is on track for
Chevron to make a final investment decision on the develop-
ment by yearend.
The onshore plant site is earmarked as Ashburton North
about 12 km west of Onslow on the Western Australian coast.
The project will begin with two LNG trains with a total capac-
ity of 8.9 million tpy of LNG. There will also be a domestic gas
plant with sales gas feeding into the Western Australian grid.
Qatargas signs 20-year LNG deal with MalaysiaQatargas has signed an agreement to supply Petronas LNG Ltd.
of Malaysia with 1.5 million tonnes/year (tpy) of LNG for at
least 20 years starting in 2013.
The deal marks the first time Qatargas signed a heads of
agreement for the supply of LNG to the southeast Asian mar-
ket, according to Qatargas Chief Executive Officer Khalid Bin
Khalifa Al Thani.
“We are very pleased with this achievement as it represents
the first long-term agreement for supplying LNG to one of the
world’s fastest-growing LNG markets,” Al Thani said.
Gas from the Qatargas 2 joint venture will be delivered to
Malaysia’s’ first regasification terminal, now under construction
on the west coast of Peninsular Malaysia. The facility will be
operational by mid-2012.
Last month, Qatargas announced the signing of an HOA for
the long term supply of LNG to Energia Argentina Sociedad
Anonima (Enarsa). Under the HOA, Qatargas will deliver 5 mil-
lion tpy of LNG to Enarsa at the Southern Cone LNG Hub in
Argentina for 20 years beginning in 2014.
110801ogj_14 14 7/28/11 12:23 PM
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16 Oil & Gas Journal | Aug. 1, 2011
2011-2012 EVENT CALENDAR
Murray AB, (403) 209-
3555, (403) 245-8649
(fax), website: www.
petroleumshow.com.
13-14.
AIPN International
Conference, Banff, AB,
(281) 558 7715, (281)
558 7073 (fax), e-mail:
website: www.aipn.org/
Events/IC2011.aspx.
13-16.
Offshore India Confer-
ence/Unconventional
Oil & Gas India Confer-
ence, Mumbai, 1 (888)
299-8016, 1 (888)
299-8057 (fax), e-mail:
registration@pennwell.
com, website: www.
offshoreoilindia.com/
index.html. 14-16.
European Autumn Gas
Conference (EAGC),
Paris, +44 (0) 203 180
6570, e-mail: lynner-
oberjot@dmgevents.
com, website: www.
theeagc.com. 15-16.
China International
Pipeline Expo, Beijing,
860316 6078902,
86010 86757867,
(fax), e-mail: Annie@
pipechina.com, website:
www.pipelinechina.
com.cn/en. 17-19.
SEG International
Exhibition and Annual
Meeting, San Antonio,
(918) 497-5500, (918)
497-5557 (fax), website:
www.seg.org. 18-23.
Global Gas Trading &
Technology Interna-
tional Conference &
Exhibition, Perth, +44
(0) 1798 874887, +44
(0) 2089 406211 (fax),
website: www.globalgas.
info. 19-21.
American School of Gas
Measurement Technol-
ogy (ASGMT) Event,
Houston, website: www.
asgmt.com. 19-22.
Oil & Gas Maintenance
Technology (OGMT)
North America Confer-
ence & Exhibition,
Galveston, 1 (888)
299-8016, 1 (888)
299-8057 (fax), e-mail:
registration@pennwell.
com, website: www.
ogmtna.com. 20-22.
GPA Europe Annual
Conference, Prague,
+44 1252 625 542,
e-mail: admin@gpaeu-
rope.com, website:
www.gpaeurope.com/
events/event/19/. 21-23.
Oil & Gas Indonesia
Conference (OGI),
Jakarta, +44 (0)20
7840 2139, +44 (0)20
7840 2119 (fax), e-mail:
website: www.oilgasin-
donesia.com. 21-24.
AAPG Eastern Section
Annual Meeting, Wash-
ington, D.C., (918) 560-
2679, (918) 560-2684
(fax), website: www.
aapg.org. 25-27.
MEOS/SPE Middle East
Oil & Gas Show and
Conference, Manama,
+44 (0)20 7840 2139,
+44 (0)20 7840 2119
(fax), e-mail: meos@
oesallworld.com, web-
site: www.meos2011.
com. 25-28.
IPAA OGIS San Fran-
cisco, (202) 857-4722,
(202) 857-4799 (fax),
website: www.ipaa.org/
meetings/index.php.
26-28.
Exploration and
Production Technol-
ogy Summit, Houston,
(416) 214-1707, (416)
214-3403 (fax), e-mail:
laurence.allen@wt-
gevents.com, website:
www.exproevent.com/
program. 27-28.
Denotes new listing or
a change in previously
published information.
AUGUST
Annual Chem/Petro-
chem & Refinery Shut-
downs and Turnarounds
Conference, San
Antonio, (312) 540-
3000, ext. 6649, (312)
552-2155 (fax), e-mail:
kellyw@marcusevansch.
com, website: www.
marcusevans.com/
marcusevans-confer-
ences-event-details.
asp?EventID-16667.
2-3.
International Congress
of the Brazilian Geo-
physical Society, Rio
de Janiero, (918) 497-
5500, (918) 497-5557,
e-mail: eventos@sbgf.
org.br, website: www.
cf.seg.org/calendar/
index.cfm. 15-18
NAPE Conference &
Expo, Houston, (972)
993-9090, (972)
993-9191 (fax), e-mail:
[email protected], web-
site: www.napeexpo.
com. 17-19.
Petroleum Association
of Wyoming Annual
Meeting & Trade Show,
Casper, (307) 234-
5333, (307) 266-2189
(fax), e-mail: suz@
pawyo.org, website:
www.pawyo.org. 23-24.
IADC Well Control Con-
ference of the Americas
& Exhibition, San An-
tonio, (713) 292-1945,
(713) 292-1946 (fax),
e-mail: [email protected],
website: www.iadc.org/
conferences. 25-26.
ACS International Sym-
posium on Hydrotreat-
ing/Hydrocracking
Technology and Na-
tional Meeting, Denver,
(202) 872-4600, (614)
447-3713 (fax), website:
www.acs.org. Aug. 28-
Sept. 1.
Unconventional Oil &
Gas International Con-
ference, San Antonio,
(888) 299-8016, (888)
299-8057 (fax), krisl@
pennwell.com, website:
www.unconventionaloil-
gas.com. 29-31.
Unconventional Oil &
Gas International Con-
ference, San Antonio,
(888) 299-8016, (888)
299-8057 (fax), krisl@
pennwell.com, website:
www.unconventionaloil-
gas.com. Aug. 30-Sept.
1.
3P Arctic Polar
Petroleum Potential
Conference & Exhibi-
tion, Halifax, +44 (0)20
7840 2139, +44 (0)20
7840 2119 (fax), e-mail:
website: www.3parctic.
com. Aug. 30-Sept. 2.
SEPTEMBER 2011
DEA(e) Technical Oil
& Gas Conference on
HPHT, Copenhagen,
+44 (0) 1483 598000,
e-mail: dawn.dukes@
otmnet.com, website:
www.dea-europe.com.
1-2.
SPE Offshore Europe
Oil and Gas Conference
and Exhibition, Aber-
deen, +44 (0)20 8439
8860, +44 (0)20 8439
8897 (fax), website:
www.offshore-europe.
co.uk. 6-8.
GPA Rocky Mountain
Annual Meeting, Den-
ver, (918) 493-3872,
(918) 493-3875 (fax),
e-mail: pmirkin@
gpaglobal.org, website:
www.gpaglobal.org. 8.
International Pump Us-
ers Symposium parallel
with Turbomachinery
Symposium, Houston,
(979) 845-7417, (979)
845-1835 (fax), e-mail:
edu, website: www.
turbolab.tamu.edu.
12-15.
IPLOCA Convention,
Beijing, +41 22 306
02 30, +41 22 306 02
39 (fax), e-mail: info@
iploca.com, website:
www.iploca.com. 12-16.
Oil Sands Trade Show
and Conference, Fort
LETTERS
Surplus capacity doubted
Six months on, after the turbulent events in the Middle East-North Africa region and the International Energy Agency’s futile and self-dam-aging gesture with the drawdown of strategic oil inventories, it is begin-ning to look ever more doubtful that OPEC’s “surplus extraction capacity” actually exists. If that is the case, global oil supply will simply not be able keep up with growing demand.
I am sure that the gulf states, especially Saudi Arabia, UAE, Qatar, and Kuwait, appreciate the need to keep oil prices within a band that does not ruin the still-feeble eco-nomic growth of the Organization for Economic Cooperation and Develop-ment. But they appear helpless to demonstrate that any significant “sur-plus supply capacity” actually exists, let alone grow fast enough to supply Asian demand. One is uncomfortably reminded of events in 2008.
If something doesn’t happen quite soon and oil prices rise much further than they have already, we will see another price spike to (say) $140/bbl followed by a double dip and, of course, another round of demand destruction, and so on and so on.
Is it not time that Oil & Gas Jour-nal reopened the question of wheth-er, this time, we are on the cusp of falling supplies of truly affordable oil? If so, we must, absolutely must, plan for the awesome consequences.
Hugh Sharman
Principal, Incoteco (Denmark) ApS
Aalborg, Denmark
2011-2012 EVENT CALENDAR
110801ogj_16 16 7/27/11 12:02 PM
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18 Oil & Gas Journal | Aug. 1, 2011
JOURNALLY SPEAKING
Online energy conversationOnline communication offers a benefit that ranks below the more-obvious delights, such as connec-tivity and speed, but that is important nevertheless.
As anyone with a web site knows, online wiz-ardry makes communications more measurable than ever before. It’s now possible to count visits, page views, clicks, tweets, posts, and nearly ev-erything else that happens on the internet. In fact, online communication generates so many num-bers that making sense of them all requires special computer programs and technical training. It also gives analysts a chance to assess what’s important to the public—or at least that part of it that’s active in cyberspace.
Window on opinionChevron Corp. is using online traffic data as a win-dow on public opinion about energy. The quarterly Chevron Pulse Report assesses what it calls “the energy conversation” on the basis of English-lan-guage, online “posts.” A post, the report says, is “a piece of online content, such as a blog post, tweet, photo, video, or discussion comment.”
Posts show up across a wide spectrum of me-dia outlets, including blogs, Twitter, Facebook, YouTube, and Flickr. A lot of them do. According to the current version of Chevron’s report, 5.7 mil-lion posts discussing energy appeared in the fourth quarter of 2010. In the 18 months that ended last Dec. 31, energy posts totaled 20.8 million.
As always, interpreting that much data is tricky. Working with Edelman, a public relations consul-tancy, Chevron has been collecting and analyzing online post data since 2008, employing what Rob-ert Raines, the oil firm’s interactive communications manager, describes as “rigorous methodology.”
The analysis concentrates on eight topics in three categories. One category, energy resources, includes access, energy reserves, and energy se-curity. Another category, energy and technology, includes energy efficiency, technology and inno-vation, and alternatives and renewables. And the energy-and-environment category covers environ-ment, resources, and policy and climate change.
Beyond counting posts in these categories, fur-ther divided into 74 subcategories, the report ana-lyzes sentiment on the basis of a dictionary of key words developed by Edelman. It displays the finely parsed results in digestible charts, which in the
current edition occupy most of 63 pages. Even with the graphic help, the numbers can be baffling.
The report does, however, offer a narrative sum-mary of possibly meaningful changes between re-porting periods. During the 18 months ending last December, the summary says, only one of the three categories, energy and technology, received a posi-tive net sentiment score. That category also gener-ated the largest volume, with more than 12 million posts. The category with the lowest volume was energy resources, 2.2 million posts. Energy and environment scored lowest in assessed sentiment. Energy resources was close behind.
Among the eight topics, alternatives and renew-ables generated the largest volume, with 5.8 mil-lion posts. Climate change accounted for more than 20% of the 18-month online conversation but had the lowest sentiment score.
The energy-reserves topic had only slightly more than 6% of the discussion volume.
All three energy-and-technology topics had positive sentiment scores, energy efficiency highest among them. All three topics under energy resourc-es were negative in sentiment; among them, access scored lowest.
Between the third and fourth quarters of last year, the volume of online, energy-related conver-sation increased by 30% to 5.7 million posts, with energy and technology accounting for 62% of the discussion. But sentiment in that category slipped from positive to neutral, drawing its lowest score in six quarters.
Among the three categories, energy resources had the lowest conversation volume and net senti-ment score in the fourth quarter. The online dis-cussion about energy and environment rose 47% in volume from the third quarter but scored a 3.1% decrease in conversation sentiment.
More numbersMake of those numbers what you will. Many more are available at www.ChevronPulseReport.com.
Why is Chevron collecting and analyzing all this data?
The goal, Raines said at the Special Libraries Association annual meeting in June, is to “position Chevron as a thought-leader.”
Numbers must be available on how it’s doing. Probably somewhere online.
BOB TIPPEEEditor
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20 Oil & Gas Journal | Aug. 1, 2011
EDITORIAL
want to develop oil and gas projects” in contrast to similar favors for “people who want to develop clean-energy industries in Ontario.” McGuinty’s Green Energy Act, which provides premiums to producers of renewable energy and has driven up electricity prices, is under assault from opposi-tion conservatives. And Ontario’s manufacturing economy is struggling. The province has become a net recipient of “equalization payments” under an economic balancing program of the federal gov-ernment.
McGuinty’s squawking about oil and gas sub-sidies rankled analysts in resource-rich Alberta, a net equalization payer. “The oil and gas indus-try isn’t being subsidized by Ontario or any other taxpayers for that matter,” wrote Licia Corbella, a columnist and editorial page editor of the Calgary Herald. She said Derek Fildebrandt, until recently acting director of the Canadian Taxpayers Federa-tion, told her a search by his group for oil and gas subsidies turned up nothing.
“We looked and we looked and discovered that these often-cited subsidies to the oil and gas in-dustry simply weren’t there,” Fildebrandt said in a July 22 column by Corbella. “There were some tax-deferral mechanisms with regard to capital costs on multibillion-dollar plants, but the fed-eral government closed those loopholes so there is nothing now at all.” Fildebrandt also said Mc-Guinty’s program of support for renewable energy “is bankrupting Ontario and its businesses.”
Easy fodderThe idea that large, profitable companies in a wide-ly distrusted industry escape taxation at public ex-pense is abhorrent. It thus makes easy fodder for populist opportunism. But the idea conflicts with reality. In the US, effective tax rates paid by large oil companies, the usual political targets, are in fact high in comparison with big companies in other industries.
Obama needs cash to fund the Keynesian futil-ity with which he has doomed fiscal policy. Mc-Guinty needs someone to blame for costly mistake with renewable energy. So both leaders stoke pop-ular misunderstanding with repetitious falsehood. Eventually, voters will see the ruse.
Misrepresentation of tax mechanisms unique to the oil and gas industry occurs not just in the US. Politi-cians in Canada, too, have deployed the “subsidy” smear—and elicited an instructive response.
In the US, the tactic has become political boil-erplate. President Barack Obama went out of his way last month to assert that tax preferences he wants to jettison are special favors. “Before we stop funding clean energy research, let’s ask oil compa-nies and corporate jet owners to give up the tax breaks that other companies don’t get,” he said July 22 at the University of Maryland. “I mean, these are special tax breaks.”
Special breaks?Technically, the president is correct. Companies outside the oil and gas industry don’t have deduc-tions for intangible drilling costs, for example. But those companies don’t have intangible drilling costs, so why would they? Other industries can deduct normal business expenses; IDC expensing simply adapts the deductibility of business expens-es to oil and gas drilling. The mechanism and other industry tax preferences under threat are not spe-cial tax breaks, and Obama shouldn’t suggest oth-erwise. Cutting IDC expensing and other industry tax preferences would amount to raising taxes. The increased cost would discourage work in the oil and gas industry. The damage would propagate through the economy.
Adaptation of tax law to industry peculiari-ties isn’t the same as subsidization, as Obama and other Democrats recklessly assert, confident that most Americans won’t recognize the deception. So mechanisms that apply specifically to oil and gas—plus some, such as the manufacturers’ tax deduction, available to all industries—are under siege. And an industry that performs important work and directly or indirectly employs 9 million Americans faces a discriminatory tax increase at a time of economic peril. Incredible.
Confusion over this issue created an East-West stir in Canada last month when Ontario Premier Dalton McGuinty implied at a government meet-ing in Vancouver that his province was subsidiz-ing oil and gas activity in the Canadian West. He spoke of “preferential tax treatment for people who
Canada’s subsidy smear
110801ogj_20 20 7/28/11 12:02 PM
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22 Oil & Gas Journal | Aug. 1, 2011
GENERAL INTEREST
Hydraulic fracturing: protectingagainst legal and regulatory risk
used napalm because the material possessed the viscosity required for the pumping project. Since that time, frac fluids have progressed from flammable hydrocarbons to refined oils to gelled crude at the end of the 1950s. Water-based frac fluids came into heavy use in the early 1960s, followed by advancements in water-soluble polymers, synthetic poly-mers, and guar-based polymers. Today, hydraulic fractur-ing companies possess a variety of complex fluids and ad-ditives designed to provide customized properties for each well with the goal to provide specific viscosities and desired conductivity for well stimulation.
Early frac jobs were fairly simple—fluid, proppant, and enough hydraulic horsepower to break down the formation. Current frac jobs are much more complicated. New frac fluid choices include slick water, borate cross-linked, metallic ion cross-linked, oil-based fluids, nitrogen and carbon dioxide foams, emulsions, and a variety of unconventional frac flu-ids. Additives for hydraulic fracturing jobs can now include gelling agents, cross-linkers, breakers, clay stabilizers, sur-factants, buffers, biocides, friction reducers, and other spe-cific additives designed to assist the frac or protect the for-mation. Due to advances in product design over the years, each one of these products can now contain any number of chemicals, ingredients, or additives.2
Two issues
Recently, two issues have emerged relating to hydraulic frac-turing. The first issue arises from the recent contention that the operation pollutes underground sources of drinking wa-ter (USDW). The second issue centers on the disclosure of chemicals used in hydraulic fracturing operations.
Water concerns, EPANews reports have led large numbers of people to believe that hydraulic frac-turing has polluted numerous sources of drinking water. The media slant on this issue has been largely limited to hyperbole, conjecture, and reports of
tap water containing methane or other hydrocarbons.A recent documentary, “GasLand,” asserted that hydrau-
lic fracturing was responsible for water pollution. However, the accusations made in this video have been thoroughly
Blaine D. Edwards
E. James Shepherd
Nick Deutsch
Shook, Hardy & Bacon LLP
Houston
Newspaper articles and television reports make hydrau-lic fracturing appear to be a new technology that pollutes drinking water, causes flames to leap from kitchen faucets, and constitutes the next great threat to freedom and democ-racy. The truth differs from the media reports.
The issue focuses on a sophisticated well-completion op-eration that, used in conjunction with horizontal drilling, has made possible the production of large volumes of oil and gas that are otherwise immobile in reservoirs of extremely low permeability. For the US, heavy-handed regulation or outright prohibition of the technique would foreclose de-velopment of an energy supply that grows as the industry gains experience with unconventional hydrocarbon reser-voirs such as shales, coalbeds, and tight sands. For oil and gas producers, regulatory and legal issues have created im-mediate hazards.
This article discusses media and public relations issues relating to hydraulic fracturing, as well as legislative, regu-latory, and litigation trends, and provides guidance to the industry to avoid legal pitfalls.
An established technique
Contrary to assertions that hydraulic fracturing is new and untested, the first documented use of the technique oc-curred over 60 years ago at the Klepper Gas Unit No. 1 in Hugoton gas field in western Kansas. The well was fraced in four zones with surplus napalm and a primitive packer system.1 The Klepper Gas Unit frac job did not use proppant.
Since then, materials used in hy-draulic fracturing have changed dra-matically. Operators began using sand and, later on, various other proppants such as bauxite, ce-ramic beads, and resin-coated sand.
The carrier fluids for frac treatments have evolved even more since the first frac job was performed. The Klepper frac
To date, charges made against hy-draulic fracturing do not live up to
the facts.
110801ogj_22 22 7/28/11 12:02 PM
Oil & Gas Journal | Aug. 1, 2011 23
researched and debunked by an oil and gas organization, Energy In Depth.3
In 2010 the US Environmental Protection Agency at the direction of Congress commissioned a study to determine whether hydraulic fracturing causes or contributes to pol-lution of USDW. In conjunction with this study, the EPA first requested ex-tensive historical hydraulic fracturing information from a number of opera-tors and service companies by infor-mal request in 2010.4 The agency then conducted meetings gathering com-ments from environmental groups, state regulatory agencies, citizens, op-erators, service companies, and other interested parties.5
The EPA will break the study into two groups. The prospective group will monitor hydraulic fracturing throughout the life cycle of local wells in the Haynesville shale in DeSoto County, La., and the Marcellus shale in Washington County, Pa. The retrospective portion of the study will examine areas to de-termine if historical hydraulic fracturing operations have affected USDW in the Marcellus shale (Bradford, Susque-hanna, and Washington counties, Pa.), Barnett shale (Wise and Denton counties, Tex.), Bakken shale (Kildeer and Dunn counties, ND), and the Raton basin (Las Animas County, Colo.).6
To date, charges made against hydraulic fracturing do not live up to the facts. In over 60 years, hydraulic fracturing has never been linked to the pollution of USDW.7 However, results of the EPA study will likely add fuel to the public re-lations fire on this issue.
Historically, the EPA has not regulated oil and gas op-erations or hydraulic fracturing. The agency’s little-known first foray into hydraulic fracturing happened in early 2003 because of concerns about potential pollution of USDW in coalbed methane formations. That EPA study did not show that hydraulic fracturing had affected USDW. However, the EPA entered into a memorandum of agreement (MOA) with the three largest hydraulic fracturing service companies to alleviate concerns and reduce risk to the environment.
The service companies voluntarily agreed that they would stop using diesel fuel when hydraulically fracturing “into coalbed methane production wells in USDWs.” The MOA also stated that the service companies would notify the EPA if they changed their policy and decided to use diesel fuel in coalbed methane reservoirs and would provide 30 days’ no-tice to the EPA of a change in company policy regarding the use of diesel fuel in the coalbed wells in USDWs.8 There was no requirement or agreement that diesel fuel not be used as a fracturing fluid in any other type of oil or gas reservoir.
In 2007, Congress requested information from the service companies that originally signed the MOA regarding com-
pliance with the MOA. The service companies responded to Congress with the requested information. Subsequently, more publicity started to emerge regarding hydraulic frac-turing, and in 2009 the FRAC Act was introduced in the House of Representatives and the Senate. Among the FRAC
Act’s requirements was the disclosure of chemicals used in hydraulic fractur-ing.9
The 111th Congress adjourned, and the act was reintroduced in the 112th Congress in March 2011. A follow-up request by Congress to various compa-nies was also sent out in 2009 seeking additional information regarding frac-turing.
In 2005, during the Bush admin-istration, hydraulic fracturing was exempted from the Clean Water Act.
Specifically, the relevant section states that the term “under-ground injections” excludes “the underground injection of fluids or propping agents (other than diesel fuels) pursuant to hydraulic fracturing operations related to oil, gas, or geo-thermal production activities.”10
Between the start of the MOA and mid-2009, no one thought that the EPA would ever start regulating hydrau-lic fracturing. However, in the fall of 2009, EPA posted a note on its web site stating: “While the [Safe Drinking Water Act] specifically excludes hydraulic fracturing from [Under-ground Injection Control] regulation under SDWA §1421 (d)(1), the use of diesel fuel during hydraulic fracturing is still regulated by the UIC program. Any service company that performs hydraulic fracturing using diesel fuel must receive prior authorization from the UIC program. Injection wells receiving diesel fuel as hydraulic fracturing additives will be considered Class II wells by the UIC program. The UIC regulations can be found in Title 40 of the Code of Federal Regulations Parts 144-148.”11
This position by the EPA surprised the oil and gas in-dustry. Nothing by the EPA beforehand had indicated that the agency was trying to prohibit the use of diesel fuel in hydraulic fracturing operations outside of coalbed methane wells in USDW. EPA had never issued any policy statements on this issue and never promulgated any regulations to ad-dress this new concern. In response to the EPA statements, the Independent Petroleum Association of America sued the EPA in Federal District Court in Washington, DC, seeking to prevent enforcement by the EPA on this issue.12 This liti-gation continues, with oral arguments before the court ex-pected in the fall of 2011.
Although the EPA has not issued any regulations or real guidance concerning the use of diesel fuel in hydraulic frac-turing operations, a real risk of EPA enforcement exists for operators and service companies that now use diesel fuel in any type of frac job (acid fracs, gelled oil fracs, using diesel
Nothing by the EPA beforehand had indicated that the agency was trying to prohibit the use of diesel fuel in hydraulic fracturing opera-tions outside of coalbed methane wells in underground sources of
drinking water.
110801ogj_23 23 7/28/11 12:02 PM
GENERAL INTEREST
24 Oil & Gas Journal | Aug. 1, 2011
terested parties can seek to protect certain information by declaring it trade secret or confidential business proprietary information. Upon such declaration, the regulatory agencies become subject to state and federal open-records or free-dom-of-information laws, which have provisions to protect
trade secret or confidential business information.15 If a third party later re-quests access to confidential informa-tion, the affected party may block the disclosure based on provisions of the applicable state or federal statute.
At this point, the disclosure of chemical constituents to state regula-tory authorities has started in a num-ber of states. Wyoming now requires full disclosure of all chemical constit-uents in all frac fluids and additives.
The Wyoming regulators understand the trade secret and confidential business information issues and have worked very well with the industry to gather the information and protect the business and confidentiality concerns of the in-dustry participants. Arkansas is also requiring “full disclo-sure” both up front and on a well by well basis.
The other form of disclosure, adopted by Texas and be-ing considered by a number of states, is best described as “modified disclosure.” It basically requires the disclosure to regulators of all toxic, hazardous, or carcinogenic chemicals in hydraulic fracturing fluids or additives.16 Modified disclo-sure rules basically follow the requirements for disclosure currently required for material safety data sheets (MSDS) under federal regulations.17
Regardless of which type of disclosure regimen applies, operators and service companies must now disclose much more information than ever before.
New risks
With the current EPA position and changing regulatory en-vironment, the legal environment for operators and service companies is fraught with risk.
EPA has started developing guidance documents con-cerning the diesel fuel issue. The best estimate is that a draft guidance docu-ment will go to the US Office of Man-agement and Budget late this summer with publication and comment period to occur sometime in the fall. Unfor-tunately, the EPA’s current position raises more questions than it answers.
The SDWA only states “diesel fuel” and does not address or provide any further definition re-garding that particular product. Valid questions include: What exactly constitutes diesel fuel? Do we need to elimi-nate diesel fuel, kerosine, or both? What constitutes hydrau-
as a cleanout fluid prior to a frac job). EPA statements sug-gest that a producing oil or gas well could be reclassified as a Class II injection well and subject to the entire rules and regulations attendant to injection wells.
Regulatory disclosureThe second legal issue involves the dis-closure of chemical constituents of hy-draulic fracturing fluids and additives. Historically, states have regulated the drilling and permitting of oil and gas wells. In response to the recent con-troversies, state legislatures and regu-lators have begun to enact new laws and regulations concerning hydraulic fracturing.
At this point, the new regulations focus on the disclosure of chemicals used in hydraulic frac-turing operations.13 The disclosure regimens basically fall into one of two broad categories: full disclosure and modi-fied disclosure.
However, an inherent problem exists with disclosure. The service companies that develop new fracturing fluid systems often spend millions of dollars on research and development of new products. They consider their formulas and ingredi-ents proprietary. Service companies and operators also buy chemicals and other ingredients from third-party vendors, which also have proprietary and trade secret chemicals in their products. Ultimately, a major frac job might have 10 or more major suppliers, all of which have trade secret con-cerns with disclosure mandates.
The legal analysis for the disclosure of proprietary or trade secret information can, and does, fill textbooks. This discussion is necessarily condensed.
Under the state and federal statutes, a business may le-gally protect its trade secret and business proprietary infor-mation from disclosure to the public, competitors, or third parties.14 Outside parties such as litigants in a lawsuit can seek disclosure of such information from a service company or operator, such as in a case where one party alleges that its water well has been polluted by drilling or fracturing opera-tions. In such a situation, the rules of discovery allow the aggrieved party to receive such information, usually sub-ject to an order that will keep the in-formation confidential (only to be used by the parties, experts, and attorneys in a lawsuit).
In the current environment, state regulatory authorities have requested information concerning all chemical constituents of hydrau-lic fracturing fluids or processes. To the extent operators and service companies have such information for all products they must provide the requested information. However, in-
A real risk of EPA enforcement exists for operators and service companies that now use diesel fuel in any type of frac job (acid fracs, gelled oil fracs, using diesel as a clean out fluid prior to a frac job).
Operators and service companies must now disclose much more in-
formation than ever before.
110801ogj_24 24 7/28/11 12:02 PM
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GENERAL INTEREST
26 Oil & Gas Journal | Aug. 1, 2011
not used and that the fracture initiation pressure was never reached.
3. Don’t use kerosine in hydraulic fracturing operations.4. Don’t use benzene, ethylene, xylene, or toluene in hy-
draulic fracturing operations.5. Work with reputable service companies that have
knowledge concerning the products they are supplying or the products they have received from third-party vendors.
6. Get statements from vendors that diesel fuel is not contained in any of their products and that diesel fuel is not a constituent product or additive to any of the products they supply or receive from other vendors.
7. Keep documentation in well files; if the EPA raises the issue, the
burden of proof that diesel wasn’t used in a frac job likely will fall on the operator.
Regulatory issuesAs additional states enact disclosure requirements for hy-draulic fracturing products, that ability to do business or procure drilling permits in a particular state will require
lic fracturing? Does fracture initiation pressure have to be reached, or will the term “hydraulic fracturing” include oth-er activities that historically have not been considered frac jobs (acid wash or acid jobs)? Does diesel fuel also include the various constituents of diesel fuel so that the use of ben-zene, ethylene, toluene, and xylene are now prohibited in any type of hydraulic fracturing? Are these chemicals pro-hibited as additives in hydraulic frac-turing fluids?
EPA issuesGiven all of these uncertainties, op-erators and service companies should consider the following steps to protect against potential future liability from the EPA and the potential reclassifica-tion of a producing oil well into a Class II UIC well:
1. Do not use diesel fuel in hydraulic fracturing opera-tions.
2. When using diesel fuel to clean out tubing or casing, have proof that pressure was not great enough to fracture the formation. If challenged, the company might need to produce documents showing that hydraulic pressure was
With the current EPA position and changing regulatory environ-ment, the legal environment for operators and service companies is
fraught with risk.
110801ogj_26 26 7/28/11 12:02 PM
Oil & Gas Journal | Aug. 1, 2011 27
GENERAL INTEREST
2. Retain in well files the informa-tion, printouts, and MSDS sheets for the products pumped into the well. The information can serve as proof in lawsuits that may arise about what was and what was not pumped into the well.
3. Determine which chemicals should not be used. Work with ven-
quality. Practical considerations for the avoidance of litigation from neighbors, municipalities, water districts, and other parties include the following:
1. Know what is being pumped into the subsurface. Get the MSDS sheets for each product from the rel-evant service company and outside vendors.
compliance. For service companies, development of a computer program or other type of assistance to provide de-tailed disclosures on a well by well ba-sis will prove helpful. In this light, the authors recommend that operators:
1. Know exactly what products are being pumped into each well.
2. Keep a copy of invoices, well product listings, and disclosures pro-vided by service companies and out-side vendors.
3. Make certain before a well pro-gram begins that all products and fluid systems to be used have been disclosed and approved by state regu-lators.
4. Be careful about inserting or substituting new products or additives (breakers, surfactants, etc.) during the actual frac job. These products may not be been approved or disclosed to regulators.
5. Be wary of using new vendors or new third-party chemical suppliers on a frac job. These vendors may not know about the disclosure require-ments and might be supplying unap-proved products.
6. For service companies and chemical suppliers, be prepared to protect proprietary and trade secret in-formation provided to state regulators. Be sure to have followed the applicable law for labeling and designating confi-dential information. Also, ensure that the regulators know whom to notify if third parties or competitors seek ac-cess to confidential information. A company might have to file suit on very short notice to protect informa-tion from disclosure.
7. Cover trade secret and propri-etary information in lawsuits with a protective or confidentiality order.
Third-party litigationThe real issue driving disclosure and EPA action the last several years is the concern, whether real or not, that hydraulic fracturing has impact-ed USDW. Citizens, landowners, and neighbors adjacent to oil and gas op-erations are all concerned about water
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GENERAL INTEREST
28 Oil & Gas Journal | Aug. 1, 2011
4. “Hydraulic Fracturing,” US Environmental Protection Agency, accessed July 14, 2011, http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/index.cfm.
5. “Outreach,” EPA, accessed July 14, 2011, http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/wells_hydroout.cfm.
6. EPA, “EPA Identifies Case Stud-ies for Hydraulic Fracturing Study/Agency to conduct field work in vari-ous regions of the country starting this summer,” accessed July 14, 2011, http://yosemite.epa.gov/opa/admpress.nsf/0/57D665864627766F852578B8005C8813.
7. EPA, “Evaluation of Impacts to Underground Sourc-es of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs,” (2004 study concluding that there was little to no risk of fracturing fluid contaminating ground-water).
8. A Memorandum of Agreement Between the United States Environmental Protection Agency and BJ Servic-es Co., Halliburton Energy Services Inc., and Schlum-berger Technology Corp.: Elimination of Diesel Fuel in Hydraulic Fracturing Fluids Injected into Underground Sources of Drinking Water During Hydraulic Fracturing of Coalbed Methane Wells, Dec. 12, 2003, accessed July 15, 2011, http://www.epa.gov/ogwdw000/uic/pdfs/moa_
dors and service companies to eliminate use of those chemi-cals.
4. Get statements or information from vendors that prod-ucts used do not contain the embargoed chemicals.
5. When drilling within 1-2 miles of water wells, meet with the landown-er or owner of the water well and test the well before drilling to determine if any pollutants are present. Baseline information is always the best way to defend a lawsuit.
6. Test the water well after drilling to ensure that pollutants did not enter the USDW from casing leaks, drilling operations, or some other problem. It is much easier to fix this problem early than it is later on when people have been drinking from a contaminated well.
7. Be a good neighbor. Explain to adjacent landowners and citizens of the community exactly what will happen. Explain how the well architecture protects USDW and what happens during drilling (use of pits, cementing, casing, etc.) to protect the environment and USDW. Go on a public rela-tions offensive.
8. Be proactive. Try to act ahead of problems. Don’t think problems will go away. In this environment, plaintiffs’ law-yers constantly troll for cases. The cost of defense and subse-quent judgment in a polluted-well case is generally more ex-pensive than the cost to fix the problem as soon as it arises.
9. Make sure that all information is contained in well files, and do not destroy or delete any documents except in accordance with an accepted document retention schedule. Otherwise, it will always be assumed that missing docu-ments will be detrimental to the company.
Oil and gas drilling and hydraulic fracturing in particular exist in a highly unstable regulatory climate at this time. In such a situation, being proactive and moving to protect the company’s interest can potentially save millions of dollars in future costs of litigation and judgments if an USDW be-comes contaminated.
References1. Tony Martin and Peter Valko, “Hydraulic Fracture
Design for Production Enhancement,” in Modern Fractur-ing: Enhancing Natural Gas Production, edited by Michael J. Economides and Tony Martin (Houston: ET Publishing, 2007), p. 93.
2. D.V. Satyanarayana Gupta and Peter Valko, “Fractur-ing Fluids and Formation Damage,” in Modern Fractur-ing: Enhancing Natural Gas Production, edited by Michael J. Economides and Tony Martin (Houston: ET Publishing, 2007), pp. 227-30.
3. “Debunking GasLand,” Energy in Depth, accessed July 14, 2011, http://www.energyindepth.org/2010/06/debunk-ing-gasland/.
The authorsBlaine D. Edwards is a partner in the tort practice of Shook, Hardy & Bacon LLP, where he focuses on energy, complex tort, products liability, and commercial litigation. He previously was associate general counsel for BJ Services Co. Edwards holds a JD from St. Mary’s Univer-sity School of Law and a BBA in accounting and finance from Texas A&M University.
E. James Shepherd is managing partner of Shook, Hardy & Bacon in Houston. With ad-ditional background in basic sciences with an emphasis in chemistry, Shepherd has a general litigation practice focusing on the defense of pharmaceutical and toxic tort cases. Shepherd holds a JD from Tulane Law School and a BS from Louisiana State University.
Nicholas N. Deutsch is an associate with Shook, Hardy & Bacon and a member of the firm’s tort section. His practice areas include commercial litigation and products liability. Deutsch is a graduate of the University of Texas School of Law and Southern Methodist University.
The real issue driving disclosure and EPA action the last several years is the concern, whether real or not, that hydraulic fracturing has impacted underground sources
of drinking water.
110801ogj_28 28 7/28/11 12:02 PM
GENERAL INTEREST
30 Oil & Gas Journal | Aug. 1, 2011
B-19; New York Dept. of Environmental Conservation, “Pre-liminary Revised Draft SGEIS on the Oil, Gas and Solution Mining Regulatory Program”; Tex. SB 1930, 82nd Leg., R.S. (2011); Wyoming Oil & Gas Conservation Commission Rules, Ch. 3, § 1(a).
14. See, e.g., Fed. R. Civ. Proc. 26(c)(1)(D); In re Bass, 113 S.W.3d 735, 739 (Tex. 2003).
15. Freedom of Information Act, 5 U.S.C. § 552; Texas Open Records Act, Tex. Gov’t. Code Ch. 552.
16. Tex. SB 1930, 82nd Leg., R.S. (2011).17. 40 CFR 370.21.
uic_hyd-fract.pdf.9. S. 1215, 111th Cong. (2009); H.R. 2766, 111th Cong.
(2009).10. SDWA § 1421(d)(1), 42 U.S.C. 300h(d).11. EPA, “Regulation of Hydraulic Fracturing by the Of-
fice of Water,” accessed July 14, 2011, http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/wells_hy-droreg.cfm.
12. Independent Petroleum Association of America v. US Environmental Protection Agency, No. 10-1233 (D.C. Cir.).
13. See, e.g., Arkansas Oil & Gas Commission Rule
Paula Dittrick
Senior Staff Writer
Oil and natural gas executives along with various econo-mists laud the resource and the economic potential of the Marcellus shale play, and a recent Pennsylvania State Uni-versity study concluded Marcellus production could supply 25% of US natural gas needs by 2020.
The Marcellus gas play is Devonian black shale extending from southern New York across Pennsylvania, and into west-ern Maryland, Virginia, West Virginia, and eastern Ohio. The play covers an estimated 95,000 sq miles.
Researchers from Advanced Resources International Inc. of Arlington, Va., named the Marcellus in late 2009 as hav-ing likely recoverable re-source of 200 tcf, largest of the top five US shale plays, from an overall Marcellus resource esti-mate of 2,100 tcf.
Although operators in the Appalachian basin have known the Marcellus formation to be a reservoir rock for more than 75 years, the shale became an important gas play in recent years given energy prices along with advances in horizon-tal drilling and completion technology, including hydraulic fracturing—which has attracted much attention regarding chemicals used in the fracturing fluid and whether the prac-tice can affect groundwater supplies.
Pennsylvania figures among seven case studies the US En-vironmental Protection Agency is examining from across US unconventional oil and gas plays regarding potential impact of fracing on drinking water resources. A final report from the EPA’s congressionally mandated study is scheduled for 2014.
Fracing questionedMeanwhile on a regional level, lawmakers and citizens in the
Marcellus shale states also have expressed concerns about the large volumes of water required for shale drilling and completions. Water must be recovered and disposed before the gas flows. Public planners and others question the avail-ability of water supplies needed for production and seek de-tails about wastewater disposal logistics.
Kathryn Klaber, president and executive director of the Marcellus Shale Coalition (MSC), said industry has commit-ted to recycling as much water as possible rather than dis-posing of it through wastewater facilities.
MSC members include 40 oil and gas companies repre-senting 95% of the rigs running in Pennsylvania.
Geologists report the most prospective areas are where the shale is at least 5,000 ft below ground and where the
shale is 50-250 ft thick. Most Marcellus devel-
opment and production has focused on Pennsyl-vania and, to a lesser ex-tent, West Virginia. New
York state lawmakers and regulators are reviewing environ-mental assessment procedures and regulations, preventing all horizontal drilling activities in New York at this time.
The pace of Marcellus development in West Virginia is accelerating. A study done by All Consulting LLC for the US Department of Energy forecast 900 Marcellus wells/year will be drilled in West Virginia by 2020 compared with 299 wells drilled in 2008.
The recent Penn State study, commissioned by the MSC, estimates Marcellus shale production in Pennsylvania will average 3.5 bcfd of gas equivalent in 2011 compared with an average 1.3 bcfed in 2010. This includes dry gas and petro-leum liquids.
Production at yearend 2010 in Pennsylvania was near-ly 2 bcfd, the report said. The study, taken in tandem with DOE projections released earlier this year, said the shale in
Industry upbeat Marcellus shaleholds great economic potential
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GENERAL INTEREST
32 Oil & Gas Journal | Aug. 1, 2011
The Penn State study was the third in a series of reports documenting Marcellus shale development. The latest report said 2010 Marcellus production in Pennsylvania averaged 1.3 bcfd equivalent of gas.
Marcellus producers operating in Pennsylvania told re-searchers they plan to spend more than $12.7 billion during 2011 compared with $3.2 billion in 2008. Estimates suggest 2011 spending could support 160,000 jobs. Royalty pay-ments are expected to rise to $1.86 billion during 2012 from $346 million during 2010, Penn State researchers said.
Operators upbeatRange Resources of Fort Worth estimates ultimate recovery of a Marcellus horizontal well averaged 5.7 bcf equivalent based upon the production performance of 103 horizontal wells that came on stream during 2009-10. The 5.7 bcfe EUR averaged 4 bcf of gas and 281,000 bbl of natural gas liquids
Pennsylvania has the potential to produce 17.5 bcfd by 2020, which would be about 25% of US gas (see figure).
The MSC study estimates that by 2020, Marcellus devel-opment could support 256,420 jobs and generate $20 billion in added value to Pennsylvania’s economy.
The Pennsylvania Department of Environmental Protec-tion reports 1,405 Marcellus wells were spudded during 2010 of which 1,213 were horizontal.
Operators are producing dry gas in the northeastern Pennsylvania counties of Susquehanna, Bradford, and Tioga and wet gas in the southwestern Pennsylvania counties of Greene, Washington, and Butler.
A Marcellus shale advisory commission to Pennsylvania Gov. Tom Corbett said geologists anticipate the number of sweet spots will grow across the central portion of the Ap-palachian Plateau through Centre, Clearfield, Indiana, and Westmoreland counties.
MARCELLUS DRILLING AND PRODUCTION IN PENNSYLVANIA
Source: Marcellus Shale Coalition after Pennsylvania State University’s study “The Pennsylvania Marcellus Natural Gas Industry: Status, Economic Impacts, and Future Potential”
2011 forecast of production 2010 forecast of production 2011 forecast of drilling activity
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
2,300
2,4082,433
2,471 2,480 2,487 2,492 2,497
2,4592,446
2,600
2,400
2,200
2,000
1,800
1,600
1,400
Num
ber
of
wells
dri
lled
Bcfd
gas
equiv
ale
nt
20
18
16
14
12
10
8
6
4
2
0
3.4
2.5
6.6
4.0
8.8
5.3
10.5
6.5
12
7.6
13.3
8.7
14.5
9.9
15.6
11.1
16.6
12.3
13.5
17.5
110801ogj_32 32 7/28/11 12:02 PM
What Are Your Logs Telling You?®
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Historically, Utica Shale/Point Pleasant inter-vals have been considered likely source units for hydrocarbons produced from Tren-ton and Black River reservoirs. The Utica Shale/Point Pleasant units are now receiving attention as potential hydrocarbon producing intervals themselves and may become the next important unconventional play in North America. The Point Pleasant deposition occurred at the end of the Middle Ordovician and was followed by Utica Shale deposition during the beginning of the Upper Ordovician as part of the Cincinnati Group. Deposition of these sediments occurred between 465 and 455 million years ago. The Point Pleasant formation consists of in-terbedded limestones and calcareous shales and black shales that were deposited in the Utica Shale/Point Pleasant sub-basin of the Central Appalachian Basin located between the Lexington and Trenton platforms. Depo-sition of the Utica Shale was more extensive than the deposition of the Point Pleasant for-mation and consists of organic-rich shales. These units were deposited in a low-energy environment with restricted circulation result-ing in organic rich sedimentation of source/reservoir rocks.
For more information on all of the area studies or to learn more about
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110801ogj_33 33 7/27/11 9:57 AM
GENERAL INTEREST
34 Oil & Gas Journal | Aug. 1, 2011
the potential to produce gas and NGLs from the Marcellus shale, the Upper Devonian shale above the Marcellus, and the Utica shale about 1,000-2,000 ft below the Marcellus.
“A very significant advantage we’ll have in developing the Upper Devoni-an and Utica will be that we’ll be drill-ing where we’ve been drilling Marcel-lus wells,” Pinkerton said.
He estimates the incremental costs to develop the Upper Devonian and Utica will be reduced by one-third compared with developing those zones on a stand-alone basis. Range already will have “incurred the cost for acre-age, roads, surface location, water management, gas lines, and compres-sion.”
Chesapeake Energy Corp. entered the Marcellus through its 2005 acqui-sition of Columbia Natural Resources, a West Virginia gas producer active in the Marcellus since the mid-1990s. Chesapeake, the play’s largest lease-hold owner with 1.7 million net acres, reported 450 Marcellus wells produced more than 100 bcfe during 2010.
For 2011, Chesapeake plans to drill 300 wells, and the Oklahoma City independent had 33 drill-ing rigs running in the play during the first half of the year.
Regulatory pressuresChesapeake Appalachia LLC voluntarily suspended comple-tion operations in Pennsylvania shortly after a well-control incident in Bradford County on Apr. 19. Chesapeake re-sumed its completion operations during May after providing 700 pages of response documentation to the Pennsylvania Department of Environmental Protection (PDEP).
A failure at a valve flange connection to the wellhead re-sulted in a fluid discharge. Chesapeake said 240 bbl of a mixture of well fluid and rain water flowed over the top of a containment berm onto nearby land with a limited amount of that entering an unnamed tributary of Towanda Creek.
“An equipment failure of this type is extremely rare in in-dustry and is the first valve flange failure of this magnitude in more than 15,000 wells Chesapeake has completed since its founding in 1989,” the company said.
Cabot Oil & Gas Corp. faced regulatory pressure for al-legedly causing methane seepage that led to a January 2009 explosion at a Susquehanna County residence.
PDEP ordered Cabot to temporarily shut down operations and demanded that it sign a “nonnegotiable” agreement in which Cabot was to admit responsibility for gas leaks. The
and crude oil although the gas:liquids ratio varied depend-ing upon well location.
Of those 103 horizontal wells, the lateral length averaged 2,802 ft with nine fracturing stages in the southwest liquid-rich gas area of the Marcellus.
Jeffery L. Ventura, Range president and chief operating officer, said a 35-mile stepout well in Washington County in southwest Pennsylvania proved to be one of Range’s best wells. The well tested 18.6 MMcfd on a 5-day test.
Range executives believe Marcellus wells have the poten-tial to produce two or three times as much gas as did the company’s former properties in the Barnett shale in North Texas. The Fort Worth independent sold its Barnett shale properties in April.
John H. Pinkerton, Range chairman and chief executive officer, said on July 18, “We have already made up roughly half of the production that we sold. By the end of the third quarter, we expect to have fully replaced all of the Barnett production” through Marcellus shale and Midcontinent re-gion production. Range anticipates its Marcellus production will grow to 400 MMcfd net by yearend 2011 and more than 600 MMcfd by yearend 2012 compared with just over 200 MMcfd at yearend 2010.
Speaking with analysts during March, Pinkerton called the Marcellus region “really three plays in one” because of
The Nomac 290 drilling rig works in Marshall County, W.Va., for Chesapeake Energy Corp., which plans to drill about 300 wells in the Marcellus during 2011. Photo from Chesapeake.
110801ogj_34 34 7/28/11 12:02 PM
Oil & Gas Journal | Aug. 1, 2011 35
Baker Institute: USshale gas mightweaken Russia, IranPaula Dittrick
Senior Staff Writer
Rising US natural gas production from shale formations has weakened Russia’s hold on its European customers, and this trend will accelerate in coming decades, concluded research-ers from Rice University’s Baker Institute.
In a study entitled “Shale Gas and US National Security,” researchers forecast Russia’s gas market share in Western Europe could decline to 13% by 2040 from 27% in 2009.
Iran’s ability to tap energy diplomacy as a means to strengthen its regional power also could be hindered by ris-ing US gas production, the study said.
“The geopolitical repercussions of expanding US shale gas production are going to be enormous,” said Amy My-ers Jaffe, director of the energy forum at the Baker Institute and one of three authors of the study.The study forecast US shale production could quadruple by 2040 from 2010 levels
company commissioned a study showing the presence of methane in area drinking water before gas drilling began.
During 2011, Cabot surpassed 400 MMcfd of production from the Marcellus shale in northeast Pennsylvania after completing upgrades of the Lathrop Compressor Station that included new compression, new dehydration, and adding a second suction line to the station.
Talisman Energy Inc. has Marcellus shale assets in New York and Pennsylvania. The company holds 223,000 net acres in Pennsylvania having 2,000 net drilling locations. In February, Talisman said it plans to drill 100 net wells in the Pennsylvania Marcellus in 2011.
Most of Talisman’s Marcellus wells for 2011 have been permitted, and Talisman said it has secured sufficient pipe-line capacity, water access, and disposal services. Talisman had Marcellus production of 315 MMcfd at yearend 2010, up from 65 MMcfd at yearend 2009.
Anadarko Petroleum Corp. was averaging gross Marcel-lus production of more than 500 MMcfd from 125 wells in late July. Its output in the quarter ended June 30 set a weekly high of 456 MMcfd gross, 116 MMcfd net, from 117 wells.
The company spud 29 operated wells in the quarter with eight rigs, participated in 33 wells with about 15 nonoper-ated rigs, and reduced quarterly cycle time to 19.6 days from 26.8 days.
Since 1968
110801ogj_35 35 7/28/11 12:02 PM
GENERAL INTEREST
36 Oil & Gas Journal | Aug. 1, 2011
the measure’s sponsor. “All we’re asking is that the president make his decision by Nov. 1. Enough time has passed.”
Energy and Commerce Committee Chairman Fred Upton (R-Mich.) noted, “Our northern ally Canada has discovered an oil resource comparable in size to Saudi Arabia, and they want to send the oil here to the United States. Five major labor unions have thrown their support behind the pipe-line because it is going to create more than 100,000 jobs. Yet this administration has allowed the permit application to languish for nearly 3 years, even saying that they were ‘in-clined’ to support it almost a year ago in October.”
Opponents responded that HR 1938 would interfere with an established process that is moving ahead, bypassing the proper reviews to ensure that it will be safe and not pollute the environment either with ruptures and leaks, or by pro-moting more US refining of heavy crude recovered from Al-berta’s oil sands. “My concern is that Keystone XL will make us more reliant on the dirtiest source of oil available,” said Henry A. Waxman (D-Calif.), the Energy and Commerce Committee’s ranking minority member.
Hidden purposeDemocrats also charged that TransCanada would use the project to divert oil south and raise prices above the border. They alleged that it actually is designed to ship oil to the US Gulf Coast for export to global markets instead of refining for consumption in the US.
“There are no guarantees in this bill,” said Edward J. Mar-key, the Natural Resources Committee’s ranking minority member. Republicans refused to consider his amendment that would have required that all oil shipped in the pipeline be sold in the US, he said.
Republicans entertained 11 amendments from Democrats that would have reduced HR 1938’s impact. All were defeat-ed, along with a motion to recommit.
Some Democrats supported the measure, including Gene Green (Tex.) who said it would give the five refineries in his district an additional supply source, and Nick J. Rahall (W.Va.), who said TransCanada already has negotiated con-struction labor agreements with major US unions. “I appre-ciate the Department of State’s recent statement that it is on track to issue a decision by Dec. 31,” Green said. “Maybe it wouldn’t have made that announcement if this bill hadn’t been in the House.”
Passage applaudedThe bill’s prospects are uncertain since it would have to be passed by the US Senate and signed into law by President Barack Obama, who has indicated that it believes it is not necessary. Oil and gas trade associations and other business groups nevertheless applauded its passage in the House.
“The project has undergone extensive analysis and review and it is time to move forward so that we can create jobs and further strengthen our relationship with America’s No.
of more than 10 bcfd, reaching more than 50% of total US natural gas production by the 2030s.
“By increasing alternative supplies to Europe in the form of LNG displaced from the US market, the petropower of Russia, Venezuela, and Iran is faltering on the back of plenti-ful American natural gas supply,” Jaffe said.
US shale gas development could limit the need for the US to import LNG for at least 20-30 years, thereby reduc-ing negative energy-related stress on the trade deficit and economy, researchers said.
The study’s other two authors were Rice economics ad-junct professor and Baker Institute fellow Kenneth Medlock along with Rice economics professor Peter Hartley.
By creating greater competition among gas suppliers in global markets, shale gas also could lower the cost to aver-age Americans of reducing greenhouse gases as the country moves to lower carbon fuels, researchers said.
The Baker Institute study dismissed the notion that shale gas is a transitory occurrence. The study also concluded US shale gas production could achieve the following:
• Reduce competition for LNG supplies from the Middle East and thereby moderate prices and spur greater use of natural gas.
• Combat the long-term potential monopoly power of a potential organization of gas producers resembling the Or-ganization of Petroleum Exporting Countries.
• Reduce US and Chinese dependence on Middle East gas supplies, lowering incentives for geopolitical and com-mercial competition between the two largest consuming countries and providing both countries with ways to diver-sify energy supply.
US House passes billto expedite Keystone XL permit decisionNick Snow
Washington Editor
The US House approved a bill setting a Nov. 1 deadline for the Obama administration to decide on TransCanada Corp.’s application for a cross-border permit for its proposed Key-stone XL crude oil pipeline project. HR 1938 passed by 279 to 147 votes on July 26 despite charges by Democratic ener-gy leaders that it would raise US gasoline prices and facilitate sale of the imported oil to overseas customers.
Supporters argued that the bill does not specify, but only seeks, a decision from the Obama administration 3 years after TransCanada applied for the permit. “This is the single most studied pipeline in US history,” said Rep. Lee Terry (R-Neb.),
110801ogj_36 36 7/28/11 12:02 PM
Oil & Gas Journal | Aug. 1, 2011 37
State utility regulators call for moreCCS-EOR projectsNick Snow
Washington Editor
US state utility regulators called on more states and groups of states to develop financial and other policies encourage the capture of carbon dioxide from electric power plants for enhanced oil recovery (EOR) as the National Association of Regulatory Utility Commissioners (NARUC) concluded its 2011 summer meeting in Los Angeles on July 20.
NARUC members approved a resolution that also urges the 112th Congress and the Obama administration “to re-store and increase funding as soon as possible, and eliminate regulatory impediments including, but not limited to, 100% grants to qualified applicants at power plants with a suffi-cient number of demonstration projects at commercial scale to yield economical use by the oil and gas industry.”
The resolution also called for tax incentives for capturing and using anthropogenic CO
2 to accelerate the deployment
of carbon capture technology, and to accelerate the produc-
1 trading partner and largest source of imported oil, Cana-da,” said American Petroleum Institute Executive Vice-Pres. Marty Durbin. A Canadian Economic Research Institute re-port estimates that Keystone XL will immediately generate 20,000 new US jobs, and that investing in Canadian oil will support 600,000 American jobs by 2035, he added.
Keystone XL’s construction will provide the US with a dependable energy supply from a close friend and ally, along with desperately needed jobs and a major economic boost, National Petrochemical & Refiners Association Pres. Charles T. Drevna observed on July 26. “If America turns its back on Canadian oil, China will eagerly buy this pre-cious resource, forcing our nation to turn to countries on the other side of the world for the energy needed to keep our economy running,” he warned. “The Senate should join the bipartisan majority in the House that voted today to approve this legislation.”
Karen A. Harbert, president of the US Chamber of Com-merce’s Institute for 21st Century Energy, said that the proj-ect would bring another 1.1 million b/d of oil into the coun-try as it created 20,000 US jobs almost immediately. “Given our current struggle to create jobs and reign in our debt, this project should be a no-brainer,” she said, adding, “It is disap-pointing that the administration continues to drag its feet on green-lighting this shovel-ready project, but I’m pleased the House acted to help move it along.”
Since 1968
110801ogj_37 37 7/28/11 12:02 PM
38 Oil & Gas Journal | Aug. 1, 2011
WATCHING GOVERNMENT
NICK SNOWWashington Editor | Blog at www.ogj.com
Keeping counties in the loop
tion of oil via CO2-EOR.
“NARUC strongly urges Congress and the administration to strongly and rapidly act on this resolution to increase the security of our nation so states are less dependent on foreign oil sources, and to create high-quality jobs,” it said.
NARUC members passed the reso-lution after North Dakota’s two US senators, Kent Conrad (D) and John Hoeven (R), launched a national EOR initiative on July 12 at a press confer-ence with oil industry executives, state officials, and technical experts.
They said the more than 30-mem-ber group will develop recommenda-tions for federal and state policymak-ers by early 2012.
US Sen. Richard G. Lugar (R-Ind.) welcomed Conrad and Hoeven’s ac-tion, noting that his own energy pro-posal would increase US oil produc-tion by 1.8 million b/d “by enabling a truly national infrastructure to con-nect oil resources with the CO
2 neces-
sary to harvest [them], including from sources in Indiana, and generate sub-stantial taxpayer returns.”
The US Department of Energy has an active carbon capture and storage research program in its Fossil Fuels Office.
Its web site notes that the US is the world’s EOR technology leader, using about 32 million tons/year of CO
2 for
this purpose.“From the perspective of the se-
questration program, [EOR] represents an opportunity to sequester carbon at low net cost, due to the revenues from recovered oil and gas,” it says, adding that this application is economically limited now to CO
2 emissions sources
near an oil or gas reservoir.NARUC members also passed a res-
olution commending the Task Force on Ensuring Stable Natural Gas Mar-kets for its report and urging state reg-ulators to serious consider the report’s recommendations.
The Bipartisan Policy Center and American Clean Skies Foundation is-sued the report in March.
Yellowstone County Commissioner Bill
Kennedy may not have been the most
alert person at a US Senate Environ-
ment and Public Works subcommittee
hearing on July 20, since he had just
flown some 2,000 miles to testify. He
nevertheless made a very strong point.
“We need to have a strategy
to keep local government officials
onboard and in decision-making
capacities,” he told the Transporta-
tion and Infrastructure Subcommittee
hearing on the ExxonMobil Pipeline
Co. (Empco) Silvertip crude oil pipeline
rupture and leak on July 1. “We have
five other pipelines in the vicinity un-
der the Yellowstone River. This was a
wake-up call for our county to become
involved.”
Duane Winslow, Yellowstone
County’s disaster and emergency ser-
vices director, opened an emergency
response center soon after the leak
was discovered, Kennedy indicated.
Members of the City of Laurel’s vol-
unteer fire department and county
deputy sheriffs evacuated about 125
people from their homes that night, he
continued. Empco employees worked
with county responders to quickly
close the pipeline’s valves.
Empco was involved from the start
as the US Environmental Protection
Agency and Montana Department of
Environmental Quality were en route,
he said. Soon after EPA took charge,
“it was very evident that the local
government was informed, but not in-
volved, in decisions involving the next
steps,” the county official said.
“We need to have a strategy to
keep local government officials on
board and in decision-making posi-
tions,” he maintained. “We know the
residents, the geography and the
companies in our community. This
spill opened our eyes to what a leak
can do and how our emergency plan-
ning works. We also know now that
we need to work on being included in
decisions on cleanup and future safety
planning.”
Positive outcomesAll parties seem to be working together
and there were positive outcomes, he
noted. They included the county’s be-
ing invited to participate in daily brief-
ings about the cleanup, local landown-
ers meeting face-to-face with Empco
and federal agencies, and Empco and
EPA holding public meetings. “The
people now know what to expect from
the public response system,” Kennedy
said.
He added, however, that when he
met with county officials from across
the country the previous week at
a National Association of Counties
meeting, commissioners from the Gulf
Coast particularly said that policies are
needed to strengthen the involvement
of counties in responses under the Oil
Pollution Act.
The situation has improved in Yel-
lowstone County, he told OGJ on July
26. “I met with representatives from
EPA and the state DEQ when I got
back, and we’ve been working with the
unified teams. They’re acknowledg-
ing our role and contributions, and it’s
working better,” Kennedy said.
110801ogj_38 38 7/28/11 12:02 PM
40 Oil & Gas Journal | Aug. 1, 2011
WATCHING THE WORLD
ERIC
WATKINSOil Diplomacy Editor | Blog at www.ogj.com
BP gains blocks off Trinidadand TobagoCurtis Williams
OGJ Correspondent
BP PLC unit BP Trinidad & Tobago (BPTT) reported it was awarded two deepwater exploration and production blocks by the Trinidad and Tobago government.
BPTT was awarded 100% interest in Blocks 23(a) and Block 14, both in deepwater frontier acreage off Trinidad and Tobago’s eastern coast, under pro-duction-sharing contracts.
BPTT was a sole bidder for Block 14; the firm beat out bids from Niko Resources and a consortium of BHP Billiton, Repsol-YPF SA, and Total SA for Block 23(a).
BPTT’s Trinidad and Tobago opera-tions account for more than half of the Caribbean twin-island nation’s natural gas output and 12% of BP’s global oil and gas production.
The awards double the acreage held by BP-controlled companies in Trini-dad and Tobago. BPTT holds explora-tion and production licenses covering 904,000 acres in areas off Trinidad and Tobago’s east coast.
Its total production averages 450,000 boe/d, comprised mainly by natural gas and natural gas liquids.
Bob Dudley, BP group chief execu-tive, said the awards mean that BP has gained access to 31 new upstream blocks across the world since July 2010, which is “a significant step-up in new access.”
Block 23(a), which lies 300 km northeast of BPTT’s Galeota Point op-erations base, covers 2,600 sq km in 2,000 m of water.
Block 14, which lies next to Block 23(a), covers a further 1,000 sq km also in 2,000 m of water.
Aug. 3 will be an eventful day for Iran’s
oil and gas industry, with the country’s
parliament scheduled to debate on
President Mahmoud Ahmadinejad’s
latest nominee for the position of oil
minister.
“I introduce Rostam Qasemi as the
oil minister nominee to the parlia-
ment,” Ahmadinejad last week said in
a letter to lawmakers, who will debate
a vote of confidence for Qasemi.
There will certainly be a lot for
them to debate about, too, as Qa-
semi is head of the Khatam Al-Anbia
construction firm, an engineering and
construction contractor controlled by
Iran’s elite Republican Guards.
The debate will turn partly on
Qasemi’s credentials for the position.
About all that can be said is that he
was a low-profile parliamentarian for
two terms in the late 1980s and 1990s
before heading to Khatam Al-Anbia in
2008.
International sanctionsThe state-run firm, which was created
after the 1980-88 Iraq-Iran War to
help the Republican Guards partici-
pate in the country’s reconstruction,
was originally involved in building
roads and infrastructure.
The organization has since become
involved in a number of projects in ad-
dition to the construction of dams and
roads, among them the development
of gas fields, petrochemical plants, as
well as oil and gas pipe lay.
Along the way, Khatam al-Anbiya
and its principal subsidiaries found
themselves on a list of Iranian institu-
tions subject to United Nations’ sanc-
tions, which were strengthened last
year by a strict embargo adopted by
Western powers.
In June, the UN Security Council
blacklisted 15 firms belonging to the
Republican Guards for their alleged
role in Iran’s nuclear activities, which
the US and its allies say is a cover to
build atomic bombs.
Qasem’s nuclear roleMore to the point, Qasemi is himself
named in sanctions by both the US
and European Union for his alleged
role in helping Iran’s controversial
nuclear program—a program that the
Iranians claim is for peaceful purposes
only.
Some parliamentarians oppose
Qasemi’s nomination because the EU
sanctions prevent him from traveling
to most parts of Europe, making it un-
likely for him to attend meetings of the
Organization of Petroleum Exporting
Countries in Vienna.
That should matter a lot as Iran
currently holds the OPEC presidency.
But some parliamentarians, such as
Mohammad Dehghan, think Iran could
try to have the sanctions on Qasemi
lifted “gradually.” Even if it does not
happen, Dehghan said, Qasemi “can
send his deputies.”
In the face of such wishful—if not
willful—thinking, one can only wonder
at the fate of the country’s oil and gas
industry. At the very least, it is being
turned into a political weapon.
Who will it harm most? That’s the
question.
Iran’s oil minister nominee
110801ogj_40 40 7/28/11 12:02 PM
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42 Oil & Gas Journal | Aug. 1, 2011
EXPLORATION & DEVELOPMENT
The investment climate in the mature UK North Sea will take a hit unless the government softens proposals in its 2011 budget. Photo
courtesy of Oil & Gas UK.
110801ogj_42 42 7/27/11 9:57 AM
Oil & Gas Journal | Aug. 1, 2011 43
Industry lobby group sees declining government revenue in UK tax hikeMike Tholen
Oil & Gas UK
London
The UK oil and gas industry supports hundreds of thou-sands of jobs across the UK, invests more than any other sector of British industry, and supplies the majority of the nation’s energy needs. Yet it has found its prospects marred by a surprise tax increase.
In the midst of a renaissance, earlier this year the UK Treasury announced a new top tax rate of 81% and a new lower limit of 62% on UK oil and gas production and capped companies’ ability to claim tax relief for decommissioning at the old tax rates.
These moves have damaged investor confidence and re-duced the attractiveness of the province as a destination for capital, jeopardizing new activity, job creation, and tax rev-enues over the long-term.
It is imperative that the industry and government work together to lessen the negative effects of the tax change and find a way to cure the chronic fiscal instability that the sec-tor faces.
Former renewed optimismOil & Gas UK forecast early in 2011 that its oil and gas com-pany members had a new and growing confidence in the stability of the UK regime and as a result were investing £8 billion this year and had plans to invest £40 billion or more over the next 5 years in order to develop more of the UK’s oil and gas reserves—despite the UK province being a mature
SPECIAL REPORT
110801ogj_43 43 7/27/11 9:57 AM
EXPLORATION & DEVELOPMENT
44 Oil & Gas Journal | Aug. 1, 2011
tion declines was likely to be 1.5%/year higher than had been anticipated.
The 25 marginalized projects account for more than 1 billion bbl of oil and gas equivalent, which equates to over a year’s domestic supply. To fill that gap, energy imports worth £50 billion would be required, increasing the cost of energy to the UK consumer, damaging the nation’s security of energy supply, and widening the trade gap.
The damage to projects’ economic viability is not con-fined to new fields, either. Worryingly, the survey found that the tax change may well shorten the lives of at least 20 pro-ducing fields by up to 5 years; the continued operation of these older fields, which are often located at infrastructure hubs, can be crucial as their removal can result in oil and gas nearby being left undeveloped.
Shoring up public financesWhile we fully appreciate the financial difficulties which the government faces, reserves left in the ground will not gener-ate any tax revenue and ironically, the public finances that needed boosting in the 2011 budget are likely to lose out in the long-term.
The newly marginalized projects could result in £15-20 billion of tax receipts being foregone.
The negative impacts on the wider economy mean it is vi-tal that the government and industry move ahead swiftly to find ways to rebuild investor confidence and to mitigate the effects of the unexpected tax change on future investment.
While the extension to the ring fence expenditure sup-plement announced in July is constructive and will help a limited number of new investors who are otherwise disad-vantaged compared to more established players, it will not redress the damage caused by the tax increase to the wider investor community.
In order to facilitate engagement with the Treasury on ways to reduce damage to investment and on the operation of the mechanism which triggers the higher tax rates, Oil & Gas UK has established a task group of senior industry ex-ecutives, reporting to the board of Oil & Gas UK.
The group is overseeing work to develop an evidence-based business case demonstrating marginalized invest-ment both in existing and new fields, the impact on gas, and the broader impact on our supply chain. The Treasury has actively signaled it wants to engage on these matters while working within the confines of the existing regime, and we are similarly committed to do so.
In addition, a task group on decommissioning has also been set up to produce proposals to resolve the current un-certainty on access to decommissioning tax relief and ad-dress the impact of the cap on decommissioning tax relief that was announced in the 2011 budget. The intention is to complete the bulk of this work before the summer recess and submit proposals thereafter for ministers’ consideration.
We believe it is imperative that the industry and govern-
and relatively costly place to operate.One impact of this sustained, higher investment was to
be a slowing of the production decline rate over the next 5 years. This was significant because at a time of uncertainty over energy supply and economic difficulty, higher UK oil and gas production would have meant less reliance on en-ergy imports and greater tax revenues for the government.
It was also important because the oil and gas sector’s role as the country’s biggest industrial investor, largest corporate taxpayer, and most significant source of energy security was seemingly assured. At a time of high and rising unemploy-ment, tens of thousands of new jobs were due to be created in an industry that was helping lead the UK out of recession.
Shattering the renaissanceHowever, just as the renaissance was gathering pace, in March the government shocked the industry by announcing a new top tax rate of 81% and a new lower limit of 62% on UK oil and gas production.
These higher rates of tax apply to oil and gas production for so long as the international price of oil is above $75/bbl. In fact almost half of the UK’s production is gas, which is currently fetching a price equivalent to $58/bbl and which has been trading within a range equivalent to $55-60/bbl for some time.
The government also announced that from 2012, compa-nies’ ability to claim tax relief for decommissioning would be capped at the old tax rates.
Investors are exposed to oil price volatility equally in all territories, but successive and unexpected negative changes in the UK tax regime reduce the attractiveness of the UK and put it at a competitive disadvantage relative to other prov-inces.
Coming so soon after assurances that the government un-derstood the industry’s need for a stable fiscal regime, this, the third major tax increase in 9 years, has severely shaken investor confidence. We now fear that this has fundamental-ly jeopardized the sustainable future of the UK continental shelf (UKCS).
Fallout from the changesCompanies are contractually and commercially commit-
ted to many projects and will continue with these.However, unless mitigating measures are soon put in
place, Oil & Gas UK’s recent survey shows that the budget had rendered marginal at least 25 projects with their associ-ated £12 billion investment and around 15,000 new jobs. In the next 10 years alone, the investment earmarked for proj-ects considered likely to go ahead had fallen by 30% to £23 billion from £33 billion.
Lower capital investment in developing oil and gas re-serves inevitably leads to lower production. Over the next 10 years, the survey showed that the rate at which produc-
110801ogj_44 44 7/27/11 9:57 AM
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EXPLORATION & DEVELOPMENT
ment now work together to achieve certainty on access to tax relief on decommissioning and find a way to cure the chronic fiscal instability with which the sector is faced.
Consultation before initiating any future changes to the fiscal regime must surely be in everyone’s interest. The UK is seen by the international en-ergy community to have a highly un-stable oil and gas tax regime and un-doubtedly pays a penalty in its ability to attract investment.
We are committed to engaging on the future of our industry and know the government wishes to do the same. The loss to the UK’s economy of not acting now is too great to consider.
The author
Mike Tholen (mtholen@
oilandgasuk.co.uk) is
economics director for
Oil & Gas UK. He seeks
to foster a business
environment that sustains
the competitiveness of
this mature oil and gas province. Prior
to joining Oil & Gas UK, Tholen worked
with Shell for 20 years, latterly holding a
variety of commercial positions includ-
ing economics and planning manager
for its upstream UK gas business and
offshore infrastructure manager in the
Netherlands.
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EXPLORATION & DEVELOPMENT
48 Oil & Gas Journal | Aug. 1, 2011
molecular breakdown of heavy oils.• Biofuels, the emerging fuels obtained from processing
corn and sugarcane.There are also small quantities of ‘other liquids’ from
nonhydrocarbons and coal derivatives.Crude oil is the mainstay of supply, accounting for 85%
of the total mix. It is also the only source of spare or backup capacity for any supply disruptions!
The oil supply scenario over the last 5 years (Table 1) un-derscores several factual trends: a) a total oil supply growth rate of 420,000 b/d/year, all on the back of NGL and biofu-els, in stark contrast to the expected demand growth rate of 650,000-900,000 b/d/year, b) crude oil supply is at a pla-teau, c) NGL and biofuels are the only ingredients showing growth, totaling 160,000-230,000 b/d/year, respectively.
The NGL 5-year growth rate of 160,000 b/d/year is slight-ly less than its long term (10-year and 15-year) trend.
IEA’s outlook through 2030 doubles this long term growth rate with the bulk coming from the OPEC countries.
Rafael Sandrea
IPC Petroleum Consultants Inc.
Broken Arrow, Okla.
The market for West Texas Intermedi-ate crude has been flirting with $100/bbl since February and the futures market is at $109 for June and July de-liveries. When crude oil prices go up it puts a burden on everyone, everything that’s delivered on a truck goes up—food, beer, and steel to name a few.
Transportation (land, water, and air) consumes more than two thirds of the oil produced, and heating and in-dustry account for the rest.
World oil demand peakingFollowing a recessional drop of 2 mil-lion b/d in 2009, the fourth quarter of 2010 saw the greatest spike in world demand since 2004 with a jump of 1.4 million b/d from the 2010 first quarter, subsequently reaching record highs.
All economic indicators show that the recession is behind us and the world economy is expected to grow at a strong 4.4% interannual rate through 2015.
Most oracles (ExxonMobil, Total, OPEC, the US Energy Information Administration, and the International Energy Agency, in that order) point towards a demand of 100-105 million b/d by 2030, up roughly 20% from the 2010 level of 87 million b/d. This increase symbolizes a growth rate of 650,000-900,000 b/d/year over the next 20 years.
Can global oil supply keep up with this vigorous de-mand? Imbalances in supply and demand critically shape the behavior of oil prices.
The oil supply pictureOil supply is a mix of four ingredients:
• Crude oil and condensate produced at the wellhead from 40,000+ oil fields in 90 countries.
• NGL or natural gas liquids extracted from the gas produced mainly from gas fields and from some of the gas produced with the oil; roughly half of all the gas produced around the world is processed in plants in 50 countries.
• Refinery gains or volume increases obtained from the
Have the stars aligned for higher oil prices?FIG. 1MONTHLY OIL PRICES SINCE 2000
West Texas Intermediate
Cru
de o
il p
rice, $
/bbl
160
140
120
100
80
60
40
20
0
1/1/
2000
6/1/
2000
11/1
/200
04/
1/20
019/
1/20
012/
1/20
027/
1/20
0212
/1/2
002
5/1/
2003
10/1
/200
33/
1/20
048/
1/20
041/
1/20
056/
1/20
0511
/1/2
005
4/1/
2006
9/1/
2006
2/1/
2007
7/1/
2007
12/1
/200
75/
1/20
0810
/1/2
008
3/1/
2009
8/1/
2009
1/1/
2010
6/1/
2010
11/1
/201
04/
1/20
11
110801ogj_48 48 7/27/11 9:57 AM
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EXPLORATION & DEVELOPMENT
50 Oil & Gas Journal | Aug. 1, 2011
OPEC’s NGL growth rate has been a soft 80,000 b/d/year the last 5 years.
Biofuels is the ‘new’ fuel. Its growth rate was just 36,000 b/d/year before 2005. Following an initial jump attributable to government directives and support, the growth rate sub-sequently decreased to 150,000 b/d/year in the last 2 years. This is attributable to unintended concerns such as land use changes, competition with food supply and fresh water re-sources, etc., making prognosis of future growth somewhat tenuous.
BP’s 2011 outlook uses a growth rate of 250,000 b/d/year through 2030, similar to the present 5-year average, and coming mostly from the US and Brazil.
Coincidently, the timeline covering the past 5 years pro-vides a unique insight into supply-demand trends before, during, and after a giant recession. For the first time in more than 100 years we have seen a continuous climb in oil prices over a prolonged period (2004-08) driven mostly by market forces (Fig. 1).
Previous price increases—there were three since the 1970s—were characterized by jumps mostly driven by geo-political events (embargoes, revolutions, and wars). In this same vein, the run-up in prices through mid-2008 provides a benchmark for crude oil supply at its maximum capac-ity—all producing countries were doing their utmost to take advantage of an unprecedented price bonanza.
Is the 5-year oil supply growth rate of 420,000 b/d/year representative of the future trend? The comparable 10-year (2000-10) growth rate is 890,000 b/d/year, but this dropped sharply to 420,000 b/d in the last 5 years following a zero growth rate of crude, the primary component of oil supply.
Crude oil output was at an all time high of 63 million b/d when the 1980 recession began and dropped a huge 10 million b/d by 1982 as world demand shrank. Recovery was slow, and it took 15 years for crude output to return to 63 million b/d, thereafter rising to 68 million b/d in 2000 and to 73.7 million b/d in 2005. From then on it has remained flat all through the sharp run-up in prices to 2008 and to the present day.
Output has increased just 10 million b/d over 30 years in spite of 400+ billion bbl of new oil discoveries during the
same period. The culprit of this nonlinear behavior is field decline dynamics, which unfortunately are not well under-stood by analysts.
It is important to note that the plateau trend of crude oil over the past 5 years also extends to all oil producing regions with the exception of Europe, which is in decline (Table 2). This would certainly indicate a worldwide state of limited if any spare capacity.
Previous studies1 show that this trend was predictable and that it may be sustained through 2015 with global pro-duction entering a slow decline thereafter. Crude oil produc-tion capacity is expected to return to 63 million b/d by 2030, a negative rate of 500,000 b/d/year.
OPEC’s supply pattern essentially mirrors the global print (Tables 1 and 2). At the start of the 1980 recession, OPEC was producing 30 million b/d of crude, then an all-time high, falling to a low of 14 million b/d by 1986 and fi-nally returning to the previous high 25 years later.
In concert with rising oil prices since 2004, OPEC’s out-put reached a new high of 32 million b/d in 2008, so overall the organization has been able to generate a net increase of merely 2 million b/d over 30 years. As a result, OPEC’s con-tribution to the expansion of global crude supply during this 30-year span was just 20%.
Closing remarksConsequently, any growth in supply to satisfy an increasing oil demand would have to come from NGL and biofuels as
WORLD OIL SUPPLY, 2005-10* Table 1
Growth, 1,000 2005 2008 2010 b/d/year
Crude oil 73.7 73.7 74.0 � atNGL 7.6 8.0 8.4 160Re� nery gains 2.1 2.1 2.2 � atBiofuels 0.7 1.5 1.8 230Other liquids 0.5 0.2 0.2 –– –––– –––– –––– –––– World 84.6 85.5 86.7 420OPEC 34.9 35.5 34.5 � at
*Crude oil including condensate accounts for 85% of total supply, NGL 10%, re� nery
gains 2.5%, biofuels 2.0%.
Sources: US Energy Information Administration, BP PLC, Organization of Petroleum
Exporting Countries, Oil & Gas Journal
REGIONAL CRUDE OIL SUPPLY, 2005-10* Table 2
2005 2008 2010 –––––––––– Million b/d –––––––––– Growth
Middle East 23.1 23.3 22.7 � at Iran 4.1 4.1 4.1 Saudi Arabia 9.5 9.3 8.9Eurasia 11.1 11.9 12.5 slight Kazakhstan 1.3 1.3 1.5 Russia 9.0 9.4 9.7N. America 10.9 10.3 10.8 � at Canada 2.4 2.6 2.7 Mexico 3.3 2.8 2.6 US 5.2 5.0 5.5Africa 9.6 10.0 10.0 � at Algeria 1.8 1.8 1.7 Angola 1.2 1.9 1.9 Libya 1.6 1.7 1.7 Nigeria 2.6 2.2 2.4 Asia-Oceania 7.4 7.5 7.7 � at China 3.6 3.8 4.0 Indonesia 1.0 0.9 0.9C. and S. America 6.3 6.3 6.4 � at Brazil 1.6 1.8 2.0 Venezuela 2.6 2.4 2.4Europe 5.2 4.3 3.7 declining Norway 2.7 2.2 1.9 UK 1.6 1.4 1.2 ––––– ––––– ––––– World 73.7 73.7 74.0 � atOPEC 31.9 32.5 32.1 � at
*Top 10 producers: Russia (9.7 million b/d), Saudi Arabia (8.9), US (5.5), China
(4.0), Iran (4.1), Canada (2.6), Nigeria (2.4), UAE (2.4), Iraq (2.4), and Venezuela
(2.4) account for 60% of current world crude oil (and condensate) output. OPEC was
producing 30.5 million b/d in 1979, dropped to 14.5 million b/d in 1986, and recover-
ing to 30.5 million b/d in 2004.
Sources: US Energy Information Administration, BP PLC, Organization of Petroleum
Exporting Countries
110801ogj_50 50 7/27/11 9:57 AM
Oil & Gas Journal | Aug. 1, 2011 51
EXPLORATION & DEVELOPMENT
has been the case in the last 5 years.A significant contraction in de-
mand from the transportation sector is almost mandatory in the short term. The irony is that high gas prices at the pump essentially act as a ‘direct’ tax on consumption.
Fortunately, vast reserves of natural gas that have been discovered in the US in the past 5 years can now become an important source of transportation fuel in the form of compressed natural gas (CNG). This would further open opportunities for other fuel concepts such as hydrogen/natural gas blends or HCNG, which have already been tested by the US DOE, and eventually for fuel cell vehicles.
Natural gas prices are currently one-fifth those of oil on an energy equivalent basis!
Reference1. Sandrea, R., “Oil, gas supply
trends point to tight spots, higher pric-es,” OGJ, Nov. 23, 2009, p. 37.
The author
Rafael Sandrea (san-
president of IPC Petro-
leum Consultants Inc., a
Tulsa international petro-
leum consulting firm. He
was formerly president
and chief executive of ITS, a Caracas
petroleum engineering firm he founded
and directed for 30 years. He has a PhD
in petroleum engineering from Penn
State University.
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110801ogj_51 51 7/27/11 9:57 AM
EXPLORATION & DEVELOPMENT
52 Oil & Gas Journal | Aug. 1, 2011
fication of Primary Vitrinite Working Group and is the result of an interna-tional partnership between members of ICCP, ASTM, the American Associa-tion of Petroleum Geologists, and The Society for Organic Petrology. The new consensus standard is available for purchase (http://www.astm.org/Stan-dards/D7708.htm) and is included in the 2011 Annual Book of ASTM Stan-dards, Vol. 05.06, Gaseous Fuels; Coal and Coke, which can be obtained as a free yearly benefit to ASTM members.
Development of the new test meth-od, ASTM D7708-11, began in 2008 with a survey of common practices used in laboratories that routinely measure the reflectance of dispersed vitrinite in shales. The test method writing committee was identified from among the survey respondents, and the existing ASTM coal vitrinite reflectance standard, ASTM D2798, was used as an outline for the new test method.
Significant changes from the coal standard include:
• Specialized terminology to in-clude recycled vitrinite, zooclasts, sol-id bitumens, and marine algae.
• Discussion of potential for vitrinite suppression and re-tardation in certain conditions.
• Inclusion of fluorescence observation and resulting changes to equipment description and procedure.
• Addition of reporting requirements, including type and quality of sample preparation, observation of fluores-cence, and consideration of supporting data and informa-tion.
The new standard was successfully balloted through the subcommittee and D05 main committee levels of the ASTM vetting process with no negative vote received. However, us-ers of the standard and other interested parties can bring comments and concerns to the attention of ASTM subcom-mittee D05.28, Petrography of Coal and Coke, which is re-sponsible for the maintenance and revision of this and other ASTM petrography standards.
OGJ readers who would like to contribute to consensus standards development within subcommittee D05.28 are encouraged to contact Paul Hackley, US Geological Survey ([email protected]), for more information.
A new American Society for Testing & Materials standard test method for measurement of the reflectance of vitrinite dispersed in sedimentary rocks has been developed by an international committee of technical experts from govern-ment agencies, academia, industry, and consultancies.
Anticipated users of the new D7708-11 standard include government, academic, and service laboratories. The stan-dard will be used as the prescribed method for the dispersed vitrinite reflectance accreditation program of the Interna-tional Committee for Coal and Organic Petrology (ICCP), which includes some 40 laboratories worldwide.
The test method is predicted to be most relevant for shale gas plays where precise information concerning thermal ma-turity is considered key to successful basin analysis. Antici-pated future improvements to the standard include the cre-ation of quantified reproducibility and repeatability values through interlaboratory round robin exercises and the de-velopment of a supplemental on line image atlas of dispersed organic matter in sedimentary rocks to aid in the identifica-tion of indigenous vitrinite.
This product grew from the efforts of the ICCP Identi-
Example of dispersed vitrinite in the Upper Cretaceous Eagle Ford shale, Maverick
basin, South Texas.
Reflectance standard adoptedfor dispersed vitrinite in sediment
110801ogj_52 52 7/27/11 9:57 AM
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EXPLORATION & DEVELOPMENT
54 Oil & Gas Journal | Aug. 1, 2011
“We are encouraged by the results of the extended well tests,” said Evans, who explained that the tests, “will help us as we now work towards declaration of commercialization by 2012-end.”
BP Oman had drilled eight wells and was drilling a ninth in mid-June, said Evans, who added that the stimulation and testing of the first three wells have been completed.
Development conceptTeams in London and Muscat are working with the govern-ment of Oman to agree on the development concept for the Khazzan project, which will form the first phase of develop-ment on Block 61.
“This includes designs for wells and surface facilities,” said Evans, who added that BP had begun producing 60 MMcfd of gas from the test wells. He said seven wells have been successfully tested, with BP Oman planning to add two more wells by yearend.
Under the terms of the exploration and production-shar-ing agreement signed in January 2007, BP is required to sub-mit a full-field development plan to the government. “We plan to do this early next year, and on the basis of that, we will then negotiate commercial terms,” Evans said.
The agreement covers a 2,800 sq km area in central Oman, including Makarem and Khazzan fields, which were discovered in 1993 and 2002, respectively, but had re-mained undeveloped due to what BP called “the complexity of their tight gas reservoirs.”
At the time, BP said it signed “a major production-sharing agreement that will give the company access to two Middle East fields and associated accumulations that could yield re-sources of some 20-30 tcf of natural gas.”
In November 2009, BP completed drilling five of eight appraisal wells as part of its development program for the reserves on Block 61.
“BP will drill eight appraisal wells in total by 2011,” ac-cording to Jonathan Evans, BP Oman general manager. “So far we’ve done five wells, which have provided a lot of useful information on the nature and the scale of the reservoirs” (OGJ Newsletter, June 7, 2010).
BP has a 100% stake in Block 61, but Oman’s government may take 20% equity in the project at the time of commer-ciality.
BP PLC is considering an investment of $15 billion over a 10-year period for full-field development of two low-perme-ability gas fields in Oman Block 61 in the Ghaba salt basin, said a senior executive of the firm.
The project would entail development of Khazzan and Makarem gas fields, said Jonathan Evans, vice-president of BP Oman.
“This will be a very large project…and will require ap-proximately $15 billion in capital investment from BP to make that happen,” Evans said. “About $10 billion of that will go into the drilling of wells and the rest will go for sur-face facilities.”
Khazzan and Makarem fieldsKhazzan is a combined structural-stratigraphic gas-conden-sate trap at 13,000-16,500 ft in the Barik sandstone member of latest Cambrian-earliest Ordovician age, Millson and oth-ers wrote in the AAPG Bulletin in 2008.
Khazzan and Makarem fields are near the producing Barik, Saih Rawl, and Saih Nihayda fields that contain 15 tcf of estimated ultimate gas-condensate recovery in conven-tional Barik structural traps.
For Khazzan and Makarem, Evans said, “We are propos-ing for the full-field development of a gas processing plant with a capacity to process 1.2 bcfd, which will need 330 wells, and about 600 km of gathering system to connect all those wells,” Evans said.
“We have not yet reached an agreement with the govern-ment,” he said, adding that, “We have to submit a field devel-opment plan to the government, which we plan to do early next year.”
Evans noted that on the basis of the field development plan, BP will negotiate commercial terms with the govern-ment. “The government has to agree for the scale of develop-ment that we are talking about,” he said.
If everything goes well, the first production of gas on commercial basis from the field is expected in late 2016 or early 2017. “We need 60 wells to start commercial produc-tion and thereafter, we will drill 20 wells every year for 10 years,” Evans said.
Evans’ remarks followed an announcement by BP of the successful completion of an extended well testing project, with the anticipated commercial gas production from its Khazzan and Makarem fields expected at about 1.2 bcfd.
BP mulls $15 billion investment in Omani tight gas fields
110801ogj_54 54 7/27/11 10:43 AM
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110801ogj_55 55 7/27/11 10:18 AM
EXPLORATION & DEVELOPMENT
56 Oil & Gas Journal | Aug. 1, 2011
The ultimate potential for marketable unconventional shale gas in the Horn River basin of Northeast British Columbia is 78 tcf, said a report by Canada’s National Energy Board and the BC Ministry of Energy and Mines.
The volume consists of 3 tcf of discovered resources and 75 tcf of undiscovered resources. The report is the first pub-licly released probability-based resource assessment of a Ca-nadian shale basin. Horn River is part of the Western Cana-da Sedimentary basin.
The 78 tcf volume is more than double a previous assess-ment of gas resources in the province.
By way of placing the Horn River figures in context, the NEB estimated that 197 tcf of conventional and unconven-tional natural gas remain in the WCSB, although this num-ber does not take into account known but as yet unassessed unconventional gas resources.
The estimate of total remaining conventional and uncon-ventional natural gas in Northeast BC available for future demand is 109 tcf. That includes 78 tcf of shale gas and 31 tcf of remaining natural gas resources identified in a joint as-sessment of conventional natural gas resources in Northeast BC. The NEB and the ministry released the conventional gas assessment in 2006.
The new report on unconventional gas resources puts forth the medium-case estimate of 78 tcf for Horn River shale gas as the most realistic scenario. However, the two
agencies estimated Horn River shale gas potential to be in a range from 61 tcf to 96 tcf.
In the same report the agencies estimated remaining con-ventional gas potential at 78 tcf in Alberta, 4 tcf in Saskatch-ewan, and 6 tcf in the southern territories. They did not esti-mate unconventional potential in those three areas.
Northeast BC now holds about 55% of the reported ul-timate remaining conventional and unconventional natural gas resources in the WCSB, and the remaining Horn River basin resources can support high drilling levels for many years in the province, the agencies said.
They noted that a number of other unconventional natural gas plays in BC and elsewhere in Canada, if developed, could substantially increase the resources available for Canadian use and export. The agencies intend to assess these BC plays as time, data, and resources allow. The NEB also intends to as-sess unconventional plays elsewhere in the country.
By further comparison, the Canadian agencies compared Horn River’s 78 tcf of marketable to 262 tcf for the Marcellus shale, 251 tcf for the Haynesville shale, 44 tcf for the Barnett shale, and 41.6 tcf for the Fayetteville shale. Figures for the US shales came from the US Department of Energy.
Horn River geologyDuring the Middle Devonian period, the agencies said, the Presqu’ile barrier reef extended from Alberta through BC and into the Yukon and Northwest Territories.
DEPICTION OF DEVONIAN PRESQU’ILE BARRIER REEF
Liard basin
Horn River
basin
Cordova
shale
basin
Redknife highland
Bovie structure
60°
59°
120°
58°
Source: National Energy Board after Alberta Geological Survey
P r es
qu
’i
le
B
ar
ri
er
YUKON
FIG. 1
Canada sees 78 tcf marketable in Horn River basin
110801ogj_56 56 7/27/11 12:02 PM
Oil & Gas Journal | Aug. 1, 2011 57
EXPLORATION & DEVELOPMENT
over 270 m in the southeast corner of the Horn River basin, where it consists of medium to dark grey calcareous shale with lower radioactivity and resistivity on well logs than the Evie and Muskwa shales. The Otter Park thins to the north and west and begins to include radioactive siliceous black shale beds, the agencies said.
The Muskwa consists of grey to black, radioactive, organ-ic-rich, pyritic, siliceous shales, and is characterized on well logs by high gamma ray readings and high resistivity. It has a gradational contact with the overlying silt-rich shales of the Fort Simpson formation.
In the Horn River basin, the Muskwa is 30 m thick adja-cent to the Presqu’ile barrier reef and thickens westward to over 60 m in the vicinity of the Bovie Lake structure on the western side of the basin. However, the Muskwa thins con-siderably where the Otter Park thickness reaches its maxi-mum in the southeast corner of the Horn River basin.
Unlike the underlying shales, the Muskwa is not re-stricted to the Horn River basin but thins and extends over the top of the barrier reef and is present through the rest of Northeast BC. It is also stratigraphically equivalent to the Duvernay shale, which extends over much of Alberta.
The agencies estimated 25 tcf of gas marketable from 132 tcf in place in the Muskwa and 24 tcf marketable from 159 tcf in place in Otter Park. They estimated 78 tcf of gas mar-ketable from 448 tcf in place in the overall Horn River basin.
The reef was an area of shallow, well-circulated sea wa-ter where fine calcite mud and the skeletons of reef growing organisms were deposited and converted to limestone and dolostone after they were buried. Clays, fine siliceous (silica-rich) muds, and organic matter from dead plankton were de-posited in the deeper, poorly oxygenated waters of the Horn River basin to the west and in the Cordova embayment to the east and were converted over time into shale deposits.
In both areas, the shales have been subdivided into, from the bottom up, the Evie, Otter Park, and Muskwa shales and contain enough organic material to have generated natural gas. Some of the gas migrated into the Presqu’ile barrier and was locally trapped in conventional oil and gas pools.
The Evie shale consists of dark grey to black, radioac-tive, organic-rich, pyritic, variably calcareous (calcite-rich), and siliceous shale. The unit is characterized on well logs by relatively high gamma ray readings and high resistivity. The uppermost part of the unit includes more silt and generally has lower radioactivity and resistivity.
In the Horn River basin, the Evie is over 75 m thick im-mediately west of the Presqu’ile barrier reef and thins west-ward to less than 40 m thick in the vicinity of the Bovie Lake structure (western margin of the basin). The Evie shale overlies limestones and dolostones of the Lower Keg River formation.
The Otter Park shale reaches a maximum thickness of
HORN RIVER BASIN STRATIGRAPHY
Liard basin Horn River basin Cordova embayment
Fort Simpson
(Mid Besa River)
Muskwa-Otter Park-Evie
(Lower Besa River)
Muskwa-Otter Park
Nahanni platform carbonates
Lower OP frac barrier
MDDC
Evie
Lower Keg River platform carbonates
Slave Point-Upper
Keg River reefal
carbonates
Muskwa-Otter Park
Lower Otter Park
Basinal Slave Point-SulphurPoint carbonates
Evie
Bovie structure
Source: AAPG Explorer
W E
Fort Simpson
FIG. 2
110801ogj_57 57 7/27/11 12:02 PM
EXPLORATION & DEVELOPMENT
58 Oil & Gas Journal | Aug. 1, 2011
much gas would be extracted as fuel gas to transport and process the raw gas. The amount of impurities in Horn River basin shale gas appears to vary by shale, with some wells as low as 8% and others as high as 19%, dominantly consisting of carbon dioxide. The impurities increase with depth.
Given the lack of long-term production from the Horn River basin, free gas recovery factors are highly uncertain. Recovery factors varied for each shale, but most likely values were 15-25%.
The agencies also considered the level of impurities to be removed to elevate the gas to pipeline quality and how
Indigo, formed in October 2006, through its relationship with the Martin companies owns the existing oil and gas leases and minerals of two of the largest private landowners in Louisiana, Roy O. Martin Lumber and Martin Timber Co.
Goodrich Petroleum Corp., Houston, said it has pur-chased 74,000 net acres of leases in Louisiana and Missis-sippi in the TMS trend. The company, which paid $13 mil-lion or $175/net acre, said it plans to begin development in the first quarter of 2012.
Amelia Resources LLC, private Woodlands, Tex., inde-pendent, has more than 100,000 acres. Among other an-nounced participants are Denbury Resources Inc., Plano, Tex., Anadarko Petroleum Corp., Houston, and Pryme En-ergy Ltd., Brisbane.
Indigo said the horizontal TMS play will “involve consid-
Source: After Pryme Energy Ltd.
TUSCALOOSA MARINE SHALE-AUSTIN CHALK TREND IN LOUISIANA
Anadarko
Lacour 43-1
Austin chalk �elds cumulative production
N. & S. Burr Ferry 3.3 MMBO + 18.2 bcf
Masters Creek 40.7 MMBO + 168 bcf
N. Bayou Jack 1.1 MMBO + 700 MMcf
Moncrief 1.3 MMBO + 2.5 bcf
W. Cheneyville 3.1 MMBO + 5.9 bcf
0 Miles 40
0 Km 64
Texas Louisiana
Turner Bayou 3D
Brookeland
Burr Ferry N.
Burr Ferry S.
Masters CreekMasters Creek
Cheneyville W.
N. Bayou Jack
MoncriefMoncrief
St. Landry
Avoyelles
Evangeline
Rapides
Allen
Beauregard
Vernon
Newton
Sabine
Shale-chalk trend
Shale-chalk trend
Swift Energy
GASRS 20-1
Anadarko
Dominique 27-1
Atinum
Briggs Alt.-1
Deshotels
13H-1
Pointe
Coupee
Louisiana, Mississippi marine shale oil play growsAlan Petzet
Chief Editor-Exploration
Several operators have amassed large land positions in Loui-siana and are preparing to target oil in the Cretaceous Tus-caloosa marine shale (TMS), stratigraphic equivalent of the South Texas Eagle Ford shale.
The operators will also get to look at the slightly shal-lower Austin chalk just above the TMS. Several wells were nearing objectives in July 2011.
Indigo II Louisiana Operating LLC, Houston, formed in 2006, has accumulated more than 240,000 net acres of lease-hold and mineral fee land in south-central Louisiana that it believes prospective in the TMS, a position nearly equal to that of Devon Energy Corp., which holds 250,000 acres.
110801ogj_58 58 7/27/11 12:02 PM
60 Oil & Gas Journal | Aug. 1, 2011
EXPLORATION & DEVELOPMENT
drill the TMS.Denbury in 2010 acquired Encore
Acquisition Co., Fort Worth, which had accumulated a gross 210,000 net acres along the Louisiana-Mississip-pi line and had drilled a total of four wells in both states to the highly over-pressured TMS (OGJ Online, Oct. 29, 2008). Denbury now holds a 15% in-terest in 105,000 acres with TMS po-tential and a larger interest in a further 45,000 acres in connection with its EOR projects.
Pryme Energy had drilled the De-shotels 13-H-1 well vertically to 15,000 ft in the Upper Austin chalk formation and set intermediate casing by mid-July at the 50,000-acre Turner Bayou 3D seismic project area in North Bayou Jack field in southeastern Avoyelles Par-ish (see map). The well targets Austin chalk at 15,300 ft and the Eagle Ford-TMS at 16,000 ft true vertical depth. Pryme has 40% working interest.
Deshotels 13H-1 was to continue horizontally with a 4,000-ft lateral in the chalk to a measured depth of 19,000 ft in August.
Pryme Energy’s Deshotels 20H-1 well intersected at least 12 oil and gas-bearing fracture zones in its horizontal leg, confirming the chalk’s prospectiv-ity in the project area. Earlier this year Pryme Energy said it had generated a development model that provides for the drilling of as many as 30 wells on the Turner Bayou project.
Pryme Energy noted that Anadarko is drilling the Dominique 27-1 well to the Austin chalk along trend west of the Turner Bayou area. That well is projected to 16,500 ft true vertical depth and 23,200 ft measured total depth. Anadarko has permitted several wells on trend with Turner Bayou.
Atinum E&P Inc., Houston, spud in late May a 21,254-ft test in Moncrief field in 20-3s-6e, St. Landry Parish.
Swift Energy Co., Houston, has an Austin chalk program of development and redevelopment wells in 2011-12 in Brookeland field in East Texas and Burr Ferry and Masters Creek fields in Louisiana.
erable time and capital to fully develop and it is Indigo’s intent to eventually secure a joint venture partner in order to establish oil production over the en-tirety of its leasehold.”
The formation could contain 7 billion bbl of recoverable oil, wrote Chacko J. John and coauthors in 1997 in describing a study conducted by the Basin Research Institute at Louisiana State University (see map, OGJ, Dec. 29, 1997, p. 91).
Drilling under wayMany operators will watch the results of early wells before jumping into the TMS play, which involves costly, tech-nology-heavy horizontal wells with multiple frac stages.
Indigo will horizontally drill the TMS at the Bentley Lumber 23H-1, in 23-5n-5w, Rapides Parish, La., near Flatwoods, La., 24 miles west-north-west of Alexandria. The well is per-mitted to 15,500 ft measured depth including a 4,000-ft lateral at 10,600 ft true vertical depth. The company plans 15 frac stages in the TMS.
The planned wellsite is 8 miles north of the vertical Bentley Lumber 32-1, in 4n-5w, Vernon Parish, which Indigo drilled and completed earlier this year. The company took full con-ventional cores through the TMS sec-tion, ran a suite of modern logs, and tested the objective section with two frac stages.
The 32-1 well went to 12,020 ft TD and established production of 42.2° gravity oil from the TMS in the center of Indigo’s acreage position.
Indigo noted that Devon described the TMS as being 200-400 ft thick at 11,000-14,000 ft across Devon’s acre-age position. Devon plans two hori-zontal wells this year, the first of which is projected to include a 5,280-ft later-al resulting in a measured total depth of more than 20,000 ft with as many as 15 frac stages.
Denbury, whose primary business is enhanced oil recovery and not ex-ploration, recently secured a joint ven-ture partner with plans to horizontally
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110801ogj_61 61 7/27/11 12:03 PM
62 Oil & Gas Journal | Aug. 1, 2011
DRILLING & PRODUCTION
Iraq’s Ahdab oil field developmentlimits contractor profitabilityMuhammed Abed Mazeel
RWE Dea
Hamburg, Germany
veloping the field in a joint venture with state-owned North Oil Co.-Middle Land Oil Co. under a technical service con-tract (TSC) concluded in 2008. The contract was the first contract awarded by Iraq’s oil ministry to a foreign company.
The equity in the service contract is held 75% by CNPC and 25% by North Oil Co.-Middle Land Oil Co.
The Ahdab development includes not only oil production but also an oil-fired power plant being built by Shanghai Heavy Industries. Plant construction started in 2008 and expectations are that it will be completed in 48 months.
The $940 million plant has a design capacity of 1,320 Mw. An estimate is that the plant at full capacity may need a supply of up to 50,000 b/d of Ahdab crude.
Using crude oil to produce electricity is an expensive al-ternative and not environmentally friendly. At $80/bbl, the plant would burn $400,000 of oil/day.
An economic analysis for the development of Ahdab field in Iraq under a technical service contract shows that the eco-nomic return to the contractor is modest in comparison with other types of contracts used in the oil industry.
But the field has potential for greater returns if uses for the associated gas can be found and oil does not have to be burned to generate electricity.
Ahdab oil fieldAhdab oil field is in a 303 sq km block in Iraq’s Wasit prov-ince, 180 km (about 112 miles) southeast of Baghdad. The field originally was delineated with 1970s vintage 2D seis-mic data.
The first well on the structure, Al Ahdab-1, discovered oil in the Zubair formation. This was followed by further appraisal drilling in the early 1980s. Iraq National Oil Co. (INOC) has drilled seven wells on the Ahdab structure.
Currently China National Petroleum Corp. (CNPC) is de-
AHAB FIELD TECHNICAL SERVICE CONTRACT CASH FLOW Government Cost Gross Oil Government net recovery 1,000 Production, revenue, price, Capex Opex revenue revenue fees Year b/d million bbl $ million $/bbl –––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––
2008 237 2009 385 2010 385 2011 392.7 2012 25 9.13 711.8 78.01 156.1 47.4 711.8 711.8 2013 30 10.95 793.1 72.43 159.2 57 396.55 396.55 396.5 2014 40 14.60 1,078.6 73.88 162.4 72.4 539.3 539.3 539.3 2015 50 18.25 1,375.2 75.35 165.6 88.4 687.6 687.6 687.6 2016 60 21.90 1,683.3 76.86 168.9 105.1 841.65 841.65 841.6 2017 70 25.55 2,003.1 78.40 172.3 122.3 1,001.55 1001.55 2018 80 29.20 2,335 79.97 175.8 140.4 1,842.8 1842.8 316.2 2019 90 32.85 2,679.4 81.56 179.3 159 2,157.14 2157.14 338.3 2020 100 36.50 3,036.7 83.20 182.9 178.2 2,471.2 2471.2 361.1 2021 110 40.15 3,407.1 84.86 124.3 195.7 2,862.3 2862.3 320 2022 120 43.80 3,791.2 86.56 63.4 212.6 3,270 3270 276 2023 120 43.80 3,867.1 88.29 64.7 216.8 3,340.3 3340.3 281.5 2024 120 43.80 3,944.4 90.05 66 221.1 3,412 3412 287.1 2025 120 43.80 4,023.3 91.86 67.3 225.6 3,485.1 3485.1 292.9 2026 120 43.80 4,103.7 93.69 68.6 230.1 3,559.8 3559.8 298.7 2027 120 43.80 3,504 80.00 70 234.7 3,635.9 3635.9 304.7 2028 120 43.80 4,269.5 97.48 71.4 239.4 3,713.5 3713.5 310.8 2029 120 43.80 4,354.9 99.43 72.8 244.2 3,792.7 3792.7 317 2030 120 43.80 4,442 101.42 74.3 249 3,899.7 3899.7 323.3 2031 100 36.50 3,775.7 103.44 223.1 3,370.1 3370.1 223.1 2032 –––––––– –––––––– –––––––– –––––––– ––––––––– ––––––––– –––––––– Total 669.78 59,179.1 3,665 3,462.5 48,990.99 48,990.99 6,715.7
110801ogj_62 62 7/27/11 12:03 PM
Oil & Gas Journal | Aug. 1, 2011 63
GeologyAhdab field is an elongate anticlinal structure, with two prominent domes oriented along a northwest-southeast axis. The gross structural closure measures 30 km by 5 km.
The proved oil resources are in the Late Cretaceous Kha-sib and Mishrif formations and the Hauterivian Zubair for-mation. The possible source for Mauddud formation oil is the Upper Jurassic strata.
The Zubair formation reservoir consists of interbedded quartzitic sands, shales, and siltstones that were deposited in a series of migrating and overlapping delta lobes. This has produced a complex, heterogeneous reservoir, with high-ly variable net reservoir thicknesses and reservoir quality across the structure.
The Zubair reservoir contains light 34° gravity oil.The Khasib formation is a chalky limestone. It has mod-
erate and occasionally a good reservoir quality with up to 120-md permeability. This reservoir contains moderately heavy 23° gravity oil.
The Mishrif formation is a limestone with shale of shal-low-marine origin. It has an average 14% porosity and up to a 50-md permeability.
The Mishrif formation seal is the Tanuma tight limestone reservoir. Mishrif contains a heavy 14° gravity oil. Sulfur content is 1.9-2.4%; reservoir depth is about 3,500 m.
Mauddud formation is grey colored dolomite and light grey limestone or dolomitic limestone. It has a 10-35% po-rosity and 10-110 md permeability as reported from various fields. The middle section of the Mauddud formation con-tains 28.5° gravity oil.
Because these formations produce different crudes, it will be necessary to develop technical scenarios for single and commingled production and for controlling gas coning or water influx as wells as for preventing sand and H2S problems.
To optimize reservoir management in this field, Iraq’s Ministry of Oil should decide on the maximum effi-ciency rate for the wells to ensure ef-ficient and stable production from the reservoirs.
Development planAhdab contains about 1 billion bbl of P50 oil reserves, but my estimate of the recoverable reserves is 670 million bbl based on the 115,000-120,000 b/d contract-term production target start-ing gradually in 2012 and maintaining a plateau for 20 years.
The 750 bscf of associated gas re-serves are considered technical resources because there are no announced plans for their commercial development, in which case the gas likely will be flared or reinjected.
Available gas cap and or associated gas could also fuel a small power plant or find local domestic or industrial uses.
CNPC started its appraisal program in 2009. It completed a 3D seismic survey and has started workover operations and is drilling vertical and horizontal wells.
The use of horizontal wells will reduce the surface impact of the proposed development. This is important because the field lies along the left bank of the Tigris River and is in Iraq’s main cereal growing Wasit province.
The Ahdab facilities are about 140 km from Iraq’s stra-tegic pipeline. Sources at the oil ministry indicate that the trunkline from the field will tie into Iraq’s 42-in strategic pipeline.
Production strategyThe reservoir development plan in the 1997 production shar-ing contract (PSC) with CNPC, which now has been voided by the Iraqi parliament, set several reservoir targets. These were 25,000 b/d on start-up, 50,000 b/d within 4 years, and peak production of 90,000 b/d within 6 years from the start of production.
If the new 2008 TSC is consistent with the original plan of development, production should be only from the Late Cretaceous Khasib, Mishrif, and Mauddud formations.
The production facilities under the 2008 contract are ex-pected to have a design capacity greater than 100,000 b/d and be built in two phases.
StateRemuneration Income State equity Company Total � eld
fee tax Bonus carry cash � ow cash � ow cash � ow–––––––––––– $ million –––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––
59.25 –237 –237 0.5 96.25 –385.5 –385.5 0.5 96.25 –385.5 –385.5 0.5 98.175 –393.2 –393.2 0.5 50.875 –204 –204 0.5 –45.075 179.8 179.8 0.5 –76.125 304 304 0.5 108.4 433.1 433.1 0.5 141.9 567.1 567.1
589.80 206.43 0.5 73.65 95.84 –7.57 88.27176 61.6 0.5 28.60 85.30 113.90
183.96 64.386 0.5 29.89 89.18 119.07204.4 71.54 0.5 33.22 99.15 132.36
224.84 78.694 0.5 36.54 109.11 145.65245.28 85.848 0.5 39.86 119.07 158.93245.28 85.848 0.5 39.86 119.07 158.93245.28 85.848 0.5 39.86 119.07 158.93245.28 85.848 0.5 39.86 119.07 158.93245.28 85.848 0.5 39.86 119.07 158.93245.28 85.848 0.5 39.86 119.07 158.93245.28 85.848 0.5 39.86 119.07 158.93245.28 85.848 0.5 39.86 119.07 158.93
219 76.65 0.5 35.59 106.26 141.85182.5 63.875 0.5 29.66 88.47 118.13
–––––––– ––––––––– –––––––– –––––––– –––––––– ––––––––3,742.74 1,309.959 11.5 608.20 1,401.29 2,009.48
Table 1
110801ogj_63 63 7/27/11 12:03 PM
DRILLING & PRODUCTION
64 Oil & Gas Journal | Aug. 1, 2011
CostsIn 1997, CNPC estimated a $660 mil-lion development cost, which includes $350 million for drilling and comple-tions and about $280 million for pro-cessing facilities, piping, and storage.
It also estimated a $280 million op-erating cost (opex) over the life of the project. This is equal to an average op-erating cost of $1.30/bbl.
The project costs (Table 1) have in-creased to a $3 billion capital invest-ment in 2009, which includes the pre-viously mentioned power station, and an additional $1.8 billion in 2010. The power station will be paid out of reve-nues generated from the sale of Ahdab crude oil.
Total estimated capital expendi-tures (capex) for developing 120,000 b/d of production is about $3.9 billion or $5.50/bbl. Opex will average about $5.2/bbl.
These values are greater than expect if the calculations were based on CERA international cost estimates.
Table 2 shows the cash flow calculations based on CERA
My economic analysis assumes a crude output peak of 120,000 b/d in 10 years from the start of production (Fig. 1).
FIG. 1AHDAB PRODUCTION
0
20
40
60
80
100
120
140
2009
2011
2013
2015
2017
2019
2021
2023
2025
2027
2029
2031
Oil p
roducti
on,
1,0
00
b/d
AHDAB FIELD COST ESTIMATES AFTER CERA Table 2
Oil pro- duction, Drilling- million workover Facilities Pipelines Capex OpexYear bbl ––––––––––––––––––––––– $ million ––––––––––––––––––––––––––
2008 2 50 235 287 2009 50 50 235 335 2010 60 50 235 345 2011 70 50 235 355 2012 8.67 80 50 10 140 34.42013 10.40 90 10 10 110 41.62014 13.87 10 10 10 30 55.482015 17.33 10 10 10 30 69.322016 20.80 30 30 83.22017 24.27 30 30 97.082018 27.74 30 30 110.962019 31.20 30 30 124.82020 34.67 30 30 138.682021 38.14 30 30 152.562022 41.61 30 30 166.442023 41.61 30 30 166.442024 41.61 30 30 166.442025 41.61 30 30 166.442026 41.61 25 25 166.442027 41.61 2028 41.61 2029 41.61 2030 41.61 2031 34.67 2032 34.67 ––––––– –––– –––– –––– –––––– –––––––– Total 670.92 697 280 980 1,957 1,740.28
110801ogj_64 64 7/27/11 12:03 PM
110801ogj_65 65 7/27/11 3:47 PM
DRILLING & PRODUCTION
66 Oil & Gas Journal | Aug. 1, 2011
model technical service contract (TSC) as illustrated in Table 1. The key remunerative element of the TSC is a service fee consisting of petroleum costs and remuneration fees.
Cost recovery is on a dollar-for-dollar basis, subject to a service fee cap equal to 50% of petroleum revenues. The re-muneration fee is payable to the contractor for the amount of oil produced, on a $/bbl basis.
The maximum remuneration fee decreases according to the ratio of cumulative revenues to cumulative costs (R-fac-tor). The remuneration fees are:
• $6/bbl for R-factor less than 1.• $5.40/bbl for R-factor of 1-1.5.• $4.90/bbl for R-factor of 1.5-2.• $3/bbl for R-factor greater than 2.The contractor is liable for a corporate income tax at a rate
of 35%. The calculation of net taxable profits is the annual aggregate of the remuneration fee actually received.
The calculation of the cash flow assumes the following:• Nominal 10% discount rate.• Discount date of Jan. 1, 2010.• 2% long-term inflation from January 2010.• An Ahdab crude price of Brent less 2.5%.• CERA Brent price of $81.28/bbl in 2011, $87.85/bbl in
2012, $91.69/bbl in 2013, $94.94/bbl in 2014, $98.86/bbl in 2015, $102.56/bbl in 2016, and $104.44/bbl in 2017.
• Wood Mackenzie Brent price of $77.63/bbl in 2010, $84.50/bbl in 2011, $80/bbl in 2012, $74.28/bbl in 2013, $75.77/bbl in 2014, $77.29/bbl in 2015, escalating at 2%/year thereafter. This equals a long-term assumed oil price of $70/bb in real terms (2010).
cost estimates. The estimates show an average capex at about $2.9/bbl and average opex at about $2.6/bbl. The addition of a conservative 15% for contingencies and a 10% escalation increases the cost estimate for capex to $3.60/bbl and opex to $3.25/bbl.
Economics My estimates of Ahdab field costs are based on Iraq’s 2009
FIG. 2AHDAB REVENUE SPLIT
–500
500
1,500
2,500
3,500
4,5002008
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
Gro
ss r
eve
nue,
$ m
illion
Company cash �ow
Government net revenue
Costs
AHDAB NET PRESENT VALUE Table 3
Field Company cash � ow NPV cash � ow NPVYear ––––––––––––––––––––––– $ million ––––––––––––––––––––
2008 –237 –237 2009 –386 –386 2010 –386 –290 –386 –2902011 –393 –269 –393 –2692012 –204 –127 –204 –1272013 180 101 180 1012014 304 156 304 1562015 433 202 433 2022016 567 241 567 2412017 500 193 404 1562018 114 40 85 302019 119 38 89 282020 132 38 99 292021 146 38 109 292022 159 38 119 292023 159 35 119 262024 159 31 119 242025 159 29 119 212026 159 26 119 192027 159 24 119 182028 159 21 119 162029 159 20 119 152030 142 16 106 122031 118 12 88 9 –––––– –––– –––––– –––– Total 2,421 614 1,813 475
110801ogj_66 66 7/27/11 12:03 PM
Oil & Gas Journal | Aug. 1, 2011 67
DRILLING & PRODUCTION
production will gradually increase as will the oil price, ca-pex will decrease, and opex will have a slight decrease or remain the same.
This results in a present value after tax of about $650 mil-lion-1,100 million for the project.
AcknowledgmentThis article presents the author’s views and is unrelated to his work at RWE Dea.
The internal rate of return (IRR) takes into account the timing of cash flows from Ahdab contract period. IRR is the discount rate at which the net present value of a project equals zero.
In 24 years, a compounded 10% annual interest rate will multiply an original investment by a factor of 10 and de-crease cash received by a factor of 10.
Table 3 shows the sum of Ahdab net present value (NPV) of the cash flow.
Profit oil is the net revenue/production after the deduc-tion of tax, bonus, etc. Profit oil is divided between the in-ternational oil company and host government.
The portion of the profit oil allocated to the company usually is negotiable and stipulated in the agreement. The basis of the split varies in different countries and may differ even within the same country, depending on prospects in an area, fiscal regime, and production level. The split could be at a flat rate or on a sliding scale.
Fig. 2 shows the split between CNPC, costs, and govern-ment.
The price sensitivity analysis for the remaining present value calculation after tax is between –20% and +20%. The
The authorM.A. Mazeel ([email protected]) is a senior reservoir engineer for RWE Dea, in Hamburg, Germany. He has worked many years in the oil and gas industry in several countries and for various companies. He previously served as director general of Iraqi Drilling Co. and director general for Oil Products Distribution Co. At the same time, he was the oil industry adviser to the Iraqi Prime Minister. Mazeel has a masters in engineering from the University of Belgrade and a PhD in pe-troleum engineering from the Technical University of Clausthal-Zellerfeld, Germany.
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110801ogj_67 67 7/27/11 12:03 PM
DRILLING & PRODUCTION
68 Oil & Gas Journal | Aug. 1, 2011
July 4, 2011, p. 72) explained the management system and the health, safety, and environment (HSE) concerns.
Integrated service providerThe drilling campaign used one service provider for the ma-jority of the service work such as wireline, drilling fluids, mud logging, cuttings and slop handling, coring, measure-ment-while-drilling (MWD), logging-while-drilling (LWD), directional drilling, bits, and cementing. The multiple ser-vice award to one service provider presented a variety of technical and commercial benefits such as:
• Alignment of quality and performance goals.• Dedicated project organization.• Prioritized service across the entire organization.• Engineering efforts focus on well target.• Ownership of project.The wireline work was subcontracted to a third-party
company through the main service contract.A project team led and organized the different drilling
services as an integrated package. Fig. 1 illustrates the proj-ect model.
Bjorn Thore Ribesen
Arild Saasen
Det norske oljeselskap ASA
Oslo
Kjell Arild Horvei
Halliburton
Stavanger
Tove Magnussen
Tormod Veiberg
AGR Petroleum Services AS
Oslo
A 3-year exploration drilling campaign run by a well man-agement company for five operating companies saw continu-ous improvement in operations off Norway.
This concluding part of a two-part series will discuss the integrated service provider, logistics, risk management, and technical performance of the campaign. The first part (OGJ,
Drilling campaign obtains continuous improvement
D R I L L I N G C O N S O R T I U M — 2 ( C o n c l u s i o n )
FIG. 1MAIN SERVICE PROVIDER’S STRUCTURE
Real-time
technical support
Account leader
Contract and
commercial
Project management
Wireline services
Subcontractor
HSEQ
Logistics
Drilling �uid
services
Drilling �uid
services
Cuttings
handling
Cementing services
Engineer
Personnel and
equipment
Drilling services
Directional drilling
MWD-LWD
Mud logging
Drilling and
coring services
Bit design
Coring
Completion tools
Liner hanger and
mechanical plugs
110801ogj_68 68 7/27/11 10:18 AM
Oil & Gas Journal | Aug. 1, 2011 69
DRILLING & PRODUCTION
A project manager led the integrated project team and was the main point of contact (focal point) for the different operators in the rig consortium and for the well management company and drilling contractor. This short communication and decision route allowed more effective operations. Key activities conducted included prejob engineering and plan-ning, risk mitigation, logistic coordination, service delivery, and third-party coordination.
The organization had a team of dedicated project person-nel with accompanying system and processes in addition to the standard service provider coordinators, such as project manager, assistant project manager, logistic coordinator, HSE coordinator, and product-line service coordinators.
LogisticsA project’s success requires the safe movement of equipment and materials to the right place at the right time and in a cost-effective manner. The drilling campaign used a desti-nation-driven approach for project management. The focus was to move all required goods to the location regardless of the number of internal departments involved. Key elements to the approach included organization, communication, re-sponsiveness, and functional competency.
The logistics function was an integrated part of the proj-ect organization. A dedicated logistics coordinator was in-volved directly from the tendering phase in the planning and execution of the project through to end.
The logistics coordinator participated in the twice-daily operational project meeting. Consequently, this allowed the transfer of essential information first hand and without de-lay, reducing the risk of misinterpretation and enabling ser-vice providers to be more responsive to the project. It also allowed the logistics coordinator to work with the various internal departments and consolidate freight movements.
To further provide timely services, project management ran 24-hr, 7-days-a-week logistics with personnel always on duty. The competence and skill of the logistics coordinator ensured success. The role requires knowledge of rules and regulations as well as the different operational scopes to en-sure safe handling of materials.
The logistical operation complexity is obvious because of the number of logistical operations within the drilling campaign. Fig. 2 illustrates the total amount of wells, bases, mobilizations, cargoes, weights, and demobilizations during the consortium’s operation.
CooperationThe collaborations among the service provider, operators, well management company, and drilling contractor were central to optimizing the integrated service performance. With no competing elements but a diversity of knowledge and experience, the team presented and used more optimal solutions.
This collaboration allowed the service provider to bal-
ance delivery more than through a discrete service contract. The service provider operated the equipment and products within its operational limits resulting in increased opera-tional time and efficiency and less unproductive time.
The consortium management model with short commu-nication lines was effective.
Each product line coordinator received a broader under-standing of the total operation and became more capable to recommend optimal solutions that did not conflict with oth-er products and services.
ProcessesEach product line or department within the main service provider’s organization has processes and procedures for all tasks in the initiation, planning, implementation, and close out of a project. The service company’s management system documented these processes and procedures.
A bridging document or work-flow process linked the service provider’s processes and procedures to the operator’s and well management company’s standardized system (Fig. 3). Use of the bridging document allowed the service pro-vider to be represented and involved throughout the differ-ent phases of the planning, and to have more influence on solutions.
Risk managementRisk management of the operation is part of the well estab-lished processes and procedures for an operation. As de-scribed in Part 1, the well management company handled the risk management for all wells drilled.
The service provider’s work flow adopted follow-up docu-ments and to-do lists that identified responsible persons and deadlines for each task or item. The service provider brought its experience on transfer and risk identification from internal systems into the well management risk system for each well.
FIG. 2MAIN SERVICE PROVIDER’S LOGISTICS
380
Demobilizations16 Wells
5 Mobilization
bases
360
Mobilizations
3,891
Cargo baskets,
13,295 tons
110801ogj_69 69 7/27/11 10:18 AM
DRILLING & PRODUCTION
70 Oil & Gas Journal | Aug. 1, 2011
It is common for one or more ser-vice deliveries to cause operational conflicts, resulting in unproductive time. The in-place cross product line systems for optimizing and balancing the different product lines reduced the chance of conflicts with the result of increased operational time and re-duced downtime for the service pro-vider.
Fig. 3 shows the operational time during the drilling campaign.
Shallow water flowAs in all drilling operations technical and operational incidents challenged the structure of the organization. An example showing how quickly the or-ganization could react to incidents is
the shallow water flow in Well 16/1-9, Draupne.Shallow water flow severely hindered drilling in the ex-
ploration well.1 The well had 20-in. casing set above a shal-low gas zone. After installation of the blowout preventers (BOPs), drilling of the 171⁄2-in. section started and continued for a few 100 m. A remotely operated vehicle was used rou-tinely to inspect the wellhead.
Optimizing across product linesThroughout the drilling campaign, the service provider sys-tematically, together with the operator, well management company, and rig owner focused on improvements.
The service provider internally had developed systems for all product-line representatives for optimizing their delivery without interrupting other deliveries.
FIG. 3BRIDGING DOCUMENT, WORK FLOW
HAZID - Hazard identi�cation studies
HAZOP - Hazard and operability analysis
EOWR - End of well report
Close outInitial design Planning step 2 Planning step 3 Implementation
Design criteria
Offset information
Knowledge
Experience
General risk
Base case scenario
Cost effective proposal
Service provider
proposals
Fluid discharge
Well design risk
assessment
HAZID
Follow-up document
Mitigating actions
Action list
Adjust proposals
������������������
���������
Engineering
Service provider
meetings
Optimize proposals
Cross product line
optimizing
More effective
solutions
Well speci�c risk
assessment
HAZOP
Follow-up document
Mitigating actions
Action list
Adjust proposals
������������������
���������
Engineering
Service provider
meetings
Optimize proposals
Cross product line
optimizing
More effective
solutions
Prespud meeting
Prejob documents
Prejob communication
Execution phase
Two daily operations
meetings
Weekly meeting
Weekly HMS meeting
Summarize data
Summarize
experience
Evaluation
Postwell meeting
Final EOWR
Experience transfer
Risk register
FIG. 4SERVICE PROVIDER’S OPERATION TIME
99.2%
Average
2010
2009
2008
2007
98.0 98.5 99.0 99.5 100.0
Time, %
99.2%
98.5%
99.5%
99.1%
110801ogj_70 70 7/27/11 10:18 AM
IMPORTANT INFORMATION FOR AVIVA POLICYHOLDERS and CLAIMANTS – SIMPLIFYING OUR LEGAL STRUCTURE
THE FOLLOWING INFORMATION WILL BE OF INTEREST TO YOU IF YOU ARE A POLICYHOLDER OF
OR ARE MAKING A CLAIM UNDER A NON-LIFE INSURANCE POLICY ISSUED BY AN AVIVA COMPANY.
Aviva has sold insurance under several brands and names – please read “Are you an Aviva policyholder or Claimant?” below. Notice of proposed Transfer Later this year, we’re proposing to consolidate our non-life insurance businesses into one main insurance company, Aviva Insurance Limited. At the same time we are also proposing to consolidate Aviva’s specialist London market business into one main company The Ocean Marine Insurance Company Limited. These changes will help to simplify our legal structure and help us work more effi ciently for our customers. Please be assured this won’t affect how we deal with your policy or claim or how you can contact us. The transfer of business will be carried out under two insurance business transfer schemes (“Schemes”) under Part VII of the Financial Services and Markets Act 2000 (“the Transfers”). We’ve made an application to the High Court in London for an order approving the Transfers so far as they relate to the transfer of the business of the companies listed in the section titled ‘Summary of the English Transfers’ (the “English Transfer”). The application for the English Transfer will be heard before a Judge at the Royal Courts of Justice, Strand, London WC2A 2LL, on Wednesday 5 October 2011. We’ve also made an application to the Court of Session in Scotland for an order approving the Transfers so far as they relate to the transfer of the business of the Scottish Boiler and General Insurance Company Limited or CGU Bonus Limited (the “Scottish Transfer”). The application for the Scottish Transfer will be heard before a Judge at the Court of Session at Parliament House, Parliament Square, Edinburgh EH1 1RQ on Thursday 6 October 2011. The Scottish Transfer will be in substantially the same terms as the English Transfer and conditional on the English Transfer. Subject to the approval of the High Court and the Court of Session (the “Courts”), the Transfers will take effect on 14 November 2011 and will automatically move across all of the rights, liabilities and obligations under all affected policies together with any claims, so there will be no need to reissue policies or sign any transfer document. Protecting customers’ interests We’ve taken great care to make sure that our customers’ interests are safeguarded, and that the security and benefi ts provided to Aviva’s policyholders will not be adversely affected by the Transfers. We’ve followed a strict legal and regulatory process that includes consulting with the Financial Services Authority and obtaining an assessment of the Transfers, carried out by an independent expert, Stuart Shepley FIA. The duty of the independent expert is to review the impact of the changes against the interests of all affected policyholders and claimants, and to write a report on his fi ndings for the Courts which will also be provided to the Financial Services Authority. Further Information Further information about the Transfers, including statements setting out the terms of each Scheme and containing a summary of the independent expert’s report and a copy of the full independent expert’s report, is available free of charge on our website, www.avivatransfer.co.uk or by writing to Aviva Transfer, PO Box 3062, Bristol BS2 8QY. Any further news about the Transfers will be posted on the website so you may wish to check for updates.You can also request free copies of any of these documents, or ask any questions you may have, by calling us on 0800 210 0035*. This number is for enquiries about the Transfers only, so if you have a general query about your policy or claim, please contact us on the numbers set out in your policy documents.Your rights We don’t anticipate that the Transfers will have any material effect on any policy or on any claim, and there’s nothing you need to do. If you have a policy or claim with any of the companies listed under the English Transfer and/or you are an existing policyholder or claimant of Aviva Insurance Limited and you believe the English Transfer may adversely affect you, you’re entitled to either make a written representation to the High Court or to be heard (either in person or by a legal representative) at the hearing on Wednesday, 5 October 2011. Any person who intends to appear at the High Court, or to make representations in writing, is requested to notify our solicitors in England as soon as possible, and by no later than 28 September 2011, to Ref CMS/EJXG/70-40495851 Clifford Chance LLP, 10 Upper Bank Street, London E14 5JJ. Aviva will ask the Court of Session in Scotland to approve the Scottish Transfer at a hearing to be held on Thursday, 6 October 2011. If you have a policy with, or a claim against, either the Scottish Boiler and General Insurance Company Limited or CGU Bonus Limited and/or you are an existing policyholder or claimant of Aviva Insurance Limited or you otherwise allege that you would be adversely affected by the Scottish Transfer, you are entitled to be heard by the Court of Session, as is the Financial Services Authority. If you wish to object to the Scottish Transfer you should lodge written answers (formal written objections) with the Court of Session at Parliament House, Parliament Square, Edinburgh EH1 1RQ by no later than 28 September 2011. While representations may be heard, if answers are not lodged in advance, anyone who does not lodge answers is strictly heard at the Court’s discretion.If you intend to come to the hearing at the Court of Session, please give not less than fi ve working days’ written notice of your intention to attend the hearing, and the reasons for any objection to the Scottish Transfer, to Aviva’s solicitors in Scotland, Dundas & Wilson CS LLP at Saltire Court, 20 Castle Terrace, Edinburgh EH1 2EN, quoting PM/AVI007.001. Summary of the English Transfer Under the English Transfer, the following companies will transfer their General Insurance and Health business to Aviva Insurance Limited: • Aviva Insurance UK Limited • Aviva International Insurance Limited • CGU Underwriting Limited • Hamilton Insurance Company Limited • London and Edinburgh Insurance Company Limited • The Ocean Marine Insurance Company Limited This covers most of Aviva’s non-life General Insurance and Health business. This includes, for example, car, home and travel insurance, private medical insurance and commercial all-risks insurance. The Scheme excludes a limited number of Global Aerospace policies written in Canada by Aviva International Insurance Limited.Also included as part of the English Transfer is a transfer to consolidate Aviva’s specialist London market business into one main company, The Ocean Marine Insurance Company Limited. “London market” business refers to business reinsured to National Indemnity Company and written on or before 31 December 2000 (including any contractual renewals of such business) (i) through the International Underwriting Association of London (“IUA”) or its predecessors (being the Institute of London Underwriters (“ILU”) and the London Insurance and Reinsurance Market Association (“LIRMA”)) ; and (ii) business identifi ed as ‘Global Risks’ which was written by the companies below and placed through the London market. The following companies will transfer their London market business to The Ocean Marine Insurance Company Limited: • Aviva Insurance Limited • Aviva International Insurance Limited • London and Edinburgh Insurance Company Limited • The World Auxiliary Insurance Company Limited Are you an Aviva policyholder or Claimant? You will be a policyholder of or claimant under an Aviva policy if your policy was issued by any of the companies listed above in relation to the English and/or Scottish Transfers. Please note that many policies issued by Aviva may carry branding of intermediaries such as banks, building societies, supermarkets and retailers, insurance brokers and affi nity groups. Your insurance documents should identify who the actual insurance company is. Please also note that Aviva’s insurance companies often have long histories and may have traded under other names in the past – you can check this on our website www.avivatransfer.co.uk * We’re open 8am to 8pm Monday to Friday and 9am to 5pm Saturday and 10am to 4pm Sunday. Calls may be recorded or monitored and will be free from a BT landline. Other operators may charge and mobiles will be considerably more. If calling from outside the UK please call +44 117 915 1983
110801ogj_71 71 7/27/11 12:03 PM
DRILLING & PRODUCTION
72 Oil & Gas Journal | Aug. 1, 2011
implementation of technological solutions. The technology provider presented the technology directly to the well man-agement company and operator at weekly cooperation meet-ing. The meetings recognized that these items would im-prove safety and thus were implemented.
In a similar manner, the project implemented the use of a riserless mud return system for ensuring safe drilling op-eration in future areas with potential shallow water flow. A benefit of these systems was the reduction of the affect of the operation on seabed fauna.3
Anchor handlingThe use of integrated services from a main service provider did not hinder the use of the intelligent application of other services. Anchor handling is an example because there was no competition to the technology delivered by the main ser-vice provider.
The combination of the well management company and the operator, however, did develop an operation based on combining anchor pick up, rig move, and presetting of an-chors at the next drilling location.4
Well abandonmentAn organizationally more difficult case was the use of alter-native methods to conventional plug cementing in abandon-ment operations.
The traditional plug and abandonment method of explo-ration wells in the North Sea sets a series of cement plugs to isolate the pressurized zones from each other and from sur-face. The service provider supplied the cementing services. To increase long-term well integrity and reduce rig costs, however, an alternative method used a Bingham-plastic un-consolidated plugging material with high solids concentra-tions in the reservoir section.5
As a result of the setup of the project organization, it was
After awhile, a tiny flow started around the wellhead. The flow increased in strength and later a large washout formed and further drilling was terminated. Most likely, the water flow came from a zone behind the 20-in. casing.
To stop the shallow water flow, it was decided to use grout cement on the outside of the casing. Regular well ce-ments were not desirable because their mineral composition retards curing. The cement selected was standard construc-tion industry cement with a very short curing time.
The BOP needed to be removed before grouting started, so that the well required other barriers for well control. Be-cause of the shallow gas zone beneath the 20-in. casing, the well needed two barriers. Two packers, one drillable and one retrievable, provided the barriers. After removal of the BOP, the grouting operation was successful.
No water flow or gas flow were observed while the ce-ment was setting. Drilling resumed in the 121⁄4-in. section after the cement cured and the packers were drilled out and retrieved.
The operator took an active part in selecting the best so-lution together with the drilling management team. During this period, the operator had close contact with the authori-ties and partners to ensure that all stakeholders agreed with the selected method.
The operator informed the authorities with the necessary information regarding handling of the operation in a safe matter, always with the main objective of keeping the well barriers intact. Communication with partners and industry ensured the review with the drilling management team of all previous experiences and best practices in similar incidents.
The project meetings for the following wells decided to continue using rapid hardening industry cement systems for the 30-in. casing.2 The next sections frequently included foam cement for improving well integrity.
The short decision routes in the consortium simplified
FIG. 5DRILLING PRODUCTIVITY COMPARISON
Orange columns are Det norske wells
Rate
, m
/dry
hole
days
Rate
, m
/dry
hole
days
P75
P25
P50
1 6 3 2 8 4 5 9 10 7
Well Well
1 2 3 4 5 6 7 8 9 10
110801ogj_72 72 7/27/11 10:18 AM
Oil & Gas Journal | Aug. 1, 2011 73
DRILLING & PRODUCTION
the cost for other operators, and 50% of the Det norske cam-paign wells have a lower cost than 75% of the comparable wells.
The right side of Fig. 6 shows that drilling costs fell dur-ing the drilling campaign. This cost reduction reflects the improved efficiency of the entire drilling operation.
AcknowledgmentsThe authors acknowledge Det norske oljeselskap ASA for providing the Rushmore benchmark data.
References1. Landbo, O., et al., “Curing Shallow Water Flow in a
North Sea Exploration Well Exposed to Shallow Gas,” Paper No. SPE 124607, SPE Offshore Europe Oil & Gas Confer-ence & Exhibition, Aberdeen, Sept. 8-11, 2009.
2. Landbo, O., et al., “Curing Shallow Water Flow in North Sea Exploration Wells,” Paper No. SPE 124608, SPE/IADC Middle East Drilling Technology Conference & Exhi-bition, Manama, Bahrain, Oct. 26-28, 2009.
3. Jodestol, K., and Furuholt, E., “Will drill cuttings and drill mud harm cold water corals?,” Paper No. SPE 126468. SPE International Conference on Health, Safety and Envi-ronment in Oil and Gas Exploration and Production, Rio de Janeiro, Apr. 12-14, 2010.
4. Saasen, A., et al., “Anchor Handling and Rig Move for Short Weather Windows During Exploration Drilling,” Pa-per No. SPE 128442, SPE/IADC Drilling Conference and Exhibition, New Orleans, Feb. 2-4, 2010.
5. Saasen, A., et al., “Permanent Abandonment of a North Sea Well Using Unconsolidated Well Plugging Material,” Pa-per No. SPE 133446, SPE Deepwater Drilling and Comple-tions Conference, Galveston, Tex., Oct. 5-6, 2010.
evident for the service provider’s single source of contact that the solution with the competing system was best for the well. Therefore, the service provider did not have a conflict for using this new option.
During the campaign, a decision was made to use a spe-cial contract between Det norske and a different service pro-vider for finalizing well abandonment. This involved the use of a separate vessel for cutting the casings just below the surface and removing the wellhead. In this way, the rig left the well after all barriers for permanent abandonment were in place and after the installation of a trawl protection cap.
The specialized vessel removed the wellheads in a sepa-rate campaign, making the removal of wellheads a cost ef-ficient operation without needing the rig. As a result of this separate contract, more rig time was allocated to drilling.
Technical performanceBenchmarking with other operations can verify the success of the drilling campaign. The campaign used Rushmore benchmarking for comparing efficiency trends with the rest of the industry in Norway. The comparison benchmarked the 10 Det norske wells drilled in the 16 well campaign with other exploration and appraisal wells drilled in the same pe-riod and area.
The comparison included only drilling of new wells be-tween 2005 and 2010 on the Norwegian continental shelf by semisubmersible drilling rigs. It did not include any side-tracked well sections.
Figs. 5 and 6 show the benchmarking results. The left side of Fig. 5 shows that 6 of the 10 wells drilled in the cam-paign had a drilling rate equal to or better than the industry average. The right side of Fig. 5 shows that the drilling rate on average doubled throughout the drilling campaign.
Fig. 6 shows a similar comparison for drilling costs. It shows that 8 out of 10 wells had lower drilling costs than
FIG. 6
Excludes all logging.
DRILLING COST COMPARISON
Orange columns are Det norske wells
Cost
, dry
hole
cost
/m
Cost
, dry
hole
cost
/m
P75
P25P50
5 10 7 4 2 8 9 1 6 3
Well Well
1 2 3 4 5 6 7 8 9 10
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74 Oil & Gas Journal | Aug. 1, 2011
PROCESSING
LNG figures heavily in Japan’spostdisaster energy demandTomoko Hosoe
East-West Center
Honolulu
Altogether, Tepco owns three nuclear power plants: 4.7-Gw Fukushima Daiichi, 4.4-Gw Fukushima Daini in Fu-kushima Prefecture, and 8.2-Gw Kashiwazaki-Kariwa in Niigata Prefecture. The Kashiwazaki-Kariwa plant was not affected by the disasters, while Fukushima Daiichi and Fu-kushima Daini completely stopped functioning.
Of the total 9.1-Gw capacities in Fukushima Prefecture, 6.4 Gw were in operation at the time of the earthquake and tsunami, while others (Fukushima Daiichi 4-6) were under maintenance. Tepco has officially decided that four units (Fukushima Daiichi 1-4) will be dismantled. It is also rea-sonable to believe that the remaining six units (Fukushima Daiichi 5-6 and Fukushima Daini 1-4) will be out of circula-tion indefinitely.
Tohoku Electric Power owns two nuclear power plants: 2.2-Gw Onagawa and 1.1-Gw Higashi-dori. Two units (total capacity 1.35 Gw) of the three at the Onagawa plant were in operation at the time of the Mar. 11 disasters, while the rest at Higashi-dori and Onagawa units were under mainte-nance. With the information at hand, we expect the Ona-gawa plant, in Miyagi Prefecture, to remain closed for a few
The 9.0 magnitude Great East Japan Earthquake followed by tsunamis on Mar. 11, 2011, in Tohoku affected not only Japan’s energy industries, including damage to basic infra-structure of nuclear power plants, but also long-term policy.The electric utilities directly affected by the disasters—To-kyo Electric Power Co., Tohoku Electric Power Co., and Ja-pan Atomic Power Co.—lost much of their base load nuclear power generation capacities, either permanently or tempo-rarily.
Other utilities that own nuclear power plants are also affected. Their nuclear plant utilization rates are falling, as they must conduct inspections on existing nuclear plants to ensure plant safety and emergency preparedness.
While the extent and duration of nuclear plant shut-downs remain unknown, it is certain that demand for other fuels, primarily LNG, will continue increasing, while power-saving efforts will escalate throughout Japan.
Nuclear plants’ statusTable 1 lists nuclear power plants owned by Tepco, Tohoku Electric Power, and Japan Atomic Power in the disaster ar-eas. None of the plants listed is operating as of today.
NUCLEAR PLANTS AFFECTED BY MAR. 11 DISASTERS Table 1
Operational status LocationElectric utility Plant name Unit number Capacity, Mw on Mar. 11, 2011 Current status (prefecture)
Tokyo Electric Power Fukushima Daiichi 1 460 Operating Halted Fukushima 2 784 Operating Halted Fukushima 3 784 Operating Halted Fukushima 4 784 Regular inspection Halted Fukushima 5 784 Regular inspection Halted Fukushima 6 1,100 Regular inspection Halted Fukushima Fukushima Daini 1 1,100 Operating Halted Fukushima 2 1,100 Operating Halted Fukushima 3 1,100 Operating Halted Fukushima 4 1,100 Operating Halted Fukushima Total capacity; still closed 9,096 Tohoku Electric Power Onagawa 1 524 Operating Halted Miyagi 2 825 Regular inspection Halted Miyagi 3 825 Operating Halted Miyagi Higashi-Dori 1 1,100 Regular inspection Halted Aomori Total capacity; still closed 3,274 Japan Atomic Power* Tokai Daini 1,100 Operating Halted Ibaraki Tsuruga 1 357 Regular inspection Regular inspection Fukui 2 1,160 Operating Halted Fukui Total capacity; still closed 2,617
*Hokkaido Electric 0.63%, Tohoku Electric 6.12%, Tokyo Electric 28.23%, Chubu Electric 15.12%, Hokuriku Electric 13.05%, Kansai Electric 18.54%, Chugoku Electric 1.25%, Shikoku
Electric 0.61%, Kyushu Electric 1.49%, Electric Power Development 5.37%, and 146 others 9.58%.
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Oil & Gas Journal | Aug. 1, 2011 75
years, and the Higashi-dori plant in Aomori Prefecture may be able to resume operation sooner.
Japan Atomic Power’s 1.1-Gw Tokai Daini nuclear plant in Ibaraki Prefecture and 1.2-Gw Tsuruga-2 in Fukui Pre-fecture have been offline since Mar. 11. (Tsuruga-1 had been under maintenance.)
Following the Fukushima crisis, at the request of Prime Minister Naoto Kan, Chubu Electric Power closed two units (4 and 5) of its Hamaoka nuclear power plant on May 13, 2011, while Unit 3—currently under maintenance—will re-main closed. Therefore, the 3.6-Gw Hamaoka plant will be completely closed until Chubu Electric completes a break-water and other tsunami- and quake-protection measures around the plant. It is expected to take 2-3 years for the completion.
The prime minister thought it necessary to ensure the safety of the Hamaoka plant because a government agen-cy (before the Fukushima disasters) had predicted an 87% chance of the large-scale earthquake occurring in the Tokai
region, where the Hamaoka plant is located, in the next 30 years.
Currently, various nuclear units are under maintenance, inspection, or both throughout Japan. In summary, only 19 of Japan’s total 54 nuclear units are operating, with Japan’s average nuclear plant utilization at 36%.
The average utilization rate will fall further unless the reactors (currently under maintenance or inspection) re-sume operation, especially as more units will be shut down for maintenance in the next few months. Nuclear reactors normally go through a 90-day maintenance cycle every 13 months. By early August, three units (a total capacity of 3.15 Gw) are to be shut down for maintenance followed by an ad-ditional four units (a total capacity of 3.4-Gw) to be closed by early September. The situation is expected to worsen to-ward summer as Prime Minister Naoto Kan on July 6 an-nounced new “stress tests” for nuclear reactors nationwide. The government believes stress tests, which are expected to use computer simulation to evaluate a reactor’s resilience to
STATUS OF THERMAL PLANTS Table 2
Operational statusElectric Plant Unit Capacity, on Mar. Current Locationutility name number Mw Fuel used 11, 2011 status (prefecture) Effect of the disasters
Tokyo Chiba Series 1 & 2 2,880 LNG Operating Operating Chiba Halted but has resumed operation Electric Goi Units 1-6 1,886 LNG, LNG, LNG Operating Operating Chiba Halted but has resumed operation Power Anezaki Units 1-6 3,600 LNG, fuel oil, Operating Operating Chiba Not affected by quake crude oil, LPG Sodegaura Units 1-4 3,600 LNG, LNG Operating Operating Chiba Not affected by quake Futtsu Series 1-4 4,534 LNG, LNG, LNG Operating Operating Chiba Not affected by quake Yokosuka Units 1-8 2,274 Fuel oil, crude oil, Operating Operating Kanagawa Not affected by quake gas oil, natural gas Kawasaki Series 1 1,500 LNG Operating Operating Kanagawa Not affected by quake Yokohama Units 5 & 6, Series 7 & 8 3,325 LNG, fuel oil, Operating Operating Kanagawa Not affected by quake crude oil Minami Yokohama Units 1-3 1,150 LNG Operating Operating Kanagawa Halted but has resumed operation Higashi Ohgishima Units 1 & 2 2,000 LNG Operating Operating Kanagawa Halted but has resumed operation Kashima Units 1-6 4,400 Fuel oil, crude oil Operating Operating Ibaraki Halted but has resumed operation Ooi Units 1-3 1,050 Crude oil Operating Operating Fukui Halted but has resumed operation Hirono Units 1-4 3,200 Fuel oil, crude oil Operating Halted Fukushima Remain halted Hirono Unit 5 600 Coal Operating Operating Fukushima Halted but has resumed operation Shinagawa Series 1 1,140 City gas Operating Operating Tokyo Not affected by quake Hitachinaka Unit 1 1,000 Coal Operating Operating Ibaraki Halted but has resumed operation Capacity still closed 3,200
Tohoku Hachinohe 3 250 Heavy oil, crude oil Operating Operating Aomori Halted but has resumed operation Electric Noshiro 1 600 Coal Operating Operating Akita Halted but has resumed operation Power Noshiro 2 600 Coal Operating Operating Akita Halted but has resumed operation Akita 2 350 Fuel oil, crude oil Operating Operating Akita Halted but has resumed operation Akita 3 350 Fuel oil, crude oil Operating Operating Akita Halted but has resumed operation Akita 4 600 Fuel, crude oil Operating Operating Akita Halted but has resumed operation Sendai 4 446 Natural gas Operating Halted Miyagi Remain halted Shin Sendai 1 350 Fuel Operating Halted Miyagi Remain halted Shin Sendai 2 600 Natural gas, fuel oil, Operating Halted Miyagi Remain halted crude oil Haramachi 1 1,000 Coal Operating Halted Fukushima Remain halted Haramachi 2 1,000 Coal Operating Halted Fukushima Remain halted Higashi Niigata 1 600 Fuel oil, crude oil, Operating Operating Niigata Not affected by quake natural gas, LNG Higashi Niigata 2 600 Fuel oil, crude oil, Operating Operating Niigata Not affected by quake natural gas, LNG Higashi Niigata Series 3 1,090 LNG Operating Operating Niigata Not affected by quake Higashi Niigata Series 4 1,610 LNG Operating Operating Niigata Not affected by quake Higashi Niigata Port 1 350 Fuel oil, LNG Not operating Operating Niigata Not affected by quake Higashi Niigata Port 2 350 Fuel oil, LNG Operating Operating Niigata Not affected by quake Niigata 4 250 Fuel oil, natural Operating Operating Niigata Not affected by quake gas, LNG Niigata 5 109 Natural gas Operating Operating Niigata Not affected by quake Capacity still closed 3,396
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76 Oil & Gas Journal | Aug. 1, 2011
Thermal power plants’ statusTable 2 lists thermal power plants owned by Tepco and Tohoku Elec-tric Power. As shown, some of Tepco’s power plants halted operation on Mar. 11; however, all of them (except for the Hirono plant) have resumed opera-tion. Hirono has five units, of which four (total capacity 3.2 Gw) consume fuel oil, crude oil, or both, and one 600-Mw unit consumes coal. Tepco brought back the coal-fired unit in June and planned to bring back the remaining units in full operation be-fore the summer peak season this year. With Hirono’s restart, Tepco will have brought back all its thermal power plants.
As for Tohoku Electric, five units (total capacity of 3.4 Gw) listed in the table remain closed. The duration of the plant shutdowns remains un-known, given that the plants are in the disaster areas.
Fig. 1 illustrates geological loca-tions of nuclear and thermal power plants owned by Tepco and Tohoku in the disaster areas. It is important to note that all of Tepco’s coal and fuel oil and oil-fired plants lie outside Tokyo.
Effects on regionalpower demandPower sales in Tokyo and Tohoku fell significantly due to supply disruptions after the disasters. Tepco’s power sales volume declined by 6% year-over-year
(y-o-y) in March and by 14% y-o-y in April, while Tohoku’s sales fell by 14% y-o-y and 20% y-o-y in March and April, respectively (Table 3).
Sales volumes to industrial users in Tokyo fell by 18% y-o-y in March and by 12% y-o-y in April. In Tohoku, sales volumes fell by 14% y-o-y in March and by 20% y-o-y in April. The April decline resulted not only from supply dis-
ruptions but also from energy conser-vation, particularly in Tokyo. Some plants and manufacturers had to in-crease plant operations in other re-gions, such as Kansai and Kyushu, to make up the loss of manufacturing bases in the disaster areas.
Table 4 summarizes fuel consump-tion in March by Tepco and Tohoku Electric. As previously discussed, both
different disasters beyond its current design capacity, could give the general public a better sense of nuclear plant safety. Yet it remained unclear how long such tests will take and how local authorities and community would judge the test results.
It remains in question as to how soon nuclear units can resume normal operations; Japan has never before experi-enced nuclear power problems on this scale. In other words, the country has no way of assessing how soon utilities could receive permission from local authorities and local communities to resume nuclear plant operations as the general public’s trust in nuclear power and the government has been lost.
FIG. 1POWER PLANTS IN TOHOKU AREA
Kashima (oil; Tepco)
Halted but hasresumed operation
Remain halted
Not affected
Noshiro (coal; Tohoku)
Akita (oil; Tohoku)
Higashi Niigata
(oil & LNG; Tohoku)
Niigata (oil & LNG;
Tohoku)
Higashi-dori (nuclear; Tohoku)
Hachinohe (oil; Tohoku)
Onagawa (nuclear; Tohoku)
Sendai (LNG; Tohoku)
Shin Sendai (LNG; Tohoku)
Haramachi (coal; Tohoku)
Hirono (oil & coal; Tepco)
Fukushima Daiichi (nuclear; Tepco)
Fukushima Daini (nuclear; Tepco)
Tokai Daini (nuclear; Japco)
Hitachinaka (coal; Tepco)
POWER SALES: 2011 Table 3
Year-over-year Mw-hr change, %
TepcoMarch 22,320 –6April 20,960 –14
TohokuMarch 6,227 –14April 5,568 –20
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Oil & Gas Journal | Aug. 1, 2011 77
PROCESSING
y to 296 Tw-hr; furthermore, generation by coal, oil, and hydro increased by 6%, 1%, and 13.6%, respectively, from 2009. Nuclear power generation (the key baseload power generation) increased by 7% y-o-y to 278 Tw-hr. The aver-age nuclear operating rate in 2010 was 68.4% vs. 64.7% in 2009—the highest level since 2007 when Tepco shut down the 8.2-Gw Kashiwazaki-Kariwa nuclear power plant in Ni-igata Prefecture after the Chuetsu offshore earthquake.
Fig. 4 shows the share of natural gas in total power gen-eration in 2010 (1,038 Tw-hr).
Japan’s total power generation in 2011 will likely decline by at least 5% y-o-y, as a result of a supply shortage and na-tionwide power-conservation efforts.
Tepco and Tohoku lost a significant amount of coal-fired generation ca-pacities in March and increased LNG consumption to make up those losses.
As Fig. 2 illustrates, all of Tepco’s LNG-fired plants and LNG terminals are on Tokyo Bay, away from the disas-ter center and were not affected. How-ever, there is a physical limit to Tep-co’s LNG import capability, as the port authority will not allow an unlimited number of LNG tankers within the already congested bay. Furthermore, considering Tokyo’s strict monitor-ing and management of photochemi-cal smog issues, Tepco’s LNG imports should be limited at around 24 million tonnes/year unless special arrange-ments are made.
Primary energy demand outlookIn the long run, Japan’s primary en-ergy consumption (PEC) mix will change significantly from 2010, while the total PEC will likely fall in light of Japan’s looming fundamental struc-tural changes: the country’s shrinking population, strict energy-conservation policies, and greater efficiency regulations. Japan’s existing energy policy, which focused on expanding nuclear power’s share, will be revised.
While specific details of revisions to be made remain un-known, Prime Minister Kan wants the new energy policy to consist of four pillars—energy conservation, fossil fuels, renewables, and nuclear power. While the Kan administra-tion remains committed to nuclear power, existing govern-ment targets of 50% of Japan’s electricity from nuclear power by 2030 will have to be revised downward. Under such a scenario, 12-14 nuclear units would need to be built and the utilization ratios of the operating nuclear units would need to increase to 85-90%. Currently, the utilization rate is 36%.
We forecast that the share of natural gas in Japan’s PEC will reach 24% in 2020 (from 18% in 2010), based on the assumption that no new nuclear reactor will be built for the forecast period (Fig. 3). The 2020 shares of oil will be 38% (44% in 2010), coal 22% (21% in 2010), nuclear 9% (12% in 2010), and hydro and others 7% (5% in 2010).
Power-generation outlookJapan’s improved industrial activities and extremely hot and prolonged 2010 summer, which raised air conditioning de-mand significantly for July-September, contributed to a 6.6% increase in total power generation last year.
Power generation by natural gas increased by 8.6% y-o-
MARCH 2011 FUEL CONSUMPTION Table 4
2010 2011 Change, %
TepcoLNG, 1,000 tonnes 1,640 1,765 8Coal, 1,000 tonnes 317 90 –72Fuel oil, 1,000 b/d 37 25 –32Oil,* 1,000 b/d 17 26 53
TohokuLNG, 1,000 tonnes 308 391 27Coal, 1,000 tonnes 524 364 –31Fuel oil, 1,000 b/d 8 13 63Oil,* 1,000 b/d 3 14 367
*Direct burning.
FIG. 2TEPCO LNG-FIRED PLANTS
1 Futtsu LNG receiving terminal
2 Higashi Ohgishima LNG receiving terminal
3 Sodegaura LNG receiving terminal*
4 Yokohama Negishi LNG receiving terminal*
Shinagawa
KawasakiHigashi Ohgishima
Yokohama
Minami Yokohama
Yokosuka
ChibaGoi
Anezaki
Sodegaura
Futtsu1
3
2
4
Kanagawa
Prefecture
Chiba
Prefecture
Tokyo
Tokyo Bay
*Joint ownership with Tokyo Gas.
LNG thermal power plants
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78 Oil & Gas Journal | Aug. 1, 2011
For mid-March to May, Tepco (Ja-pan’s largest electric utility supplying electricity to the Kanto region, which includes the Tokyo metropolitan area) had a program of rolling power black-outs (2-3 hr/day) in its supply areas. For the summer peak season (July-September), the government is in-structing consumers to cut electric-ity consumption in order to reduce the peak demand. Tepco planned to supply 55 Gw by the end of July and 56 Gw by the end of August; a typi-cal summer peak demand is around 55 Gw, and an unusually hot summer (such as that experienced in 2010) re-quires 60 Gw.
Energy-conservation efforts will be adopted not only in Tokyo but also in other major consumption areas such as Nagoya, Osaka, and Kyushu. With the Hamaoka closure and other nu-clear-related issues, Chubu Electric, Kansai Electric, and Kyushu Electric will have limited surplus generation capacities for this summer. Already, many factories are cutting back the need for power during peak hours by moving to night shifts, adopting sum-mer hours, and giving employees long summer vacations. We believe that the electricity savings efforts will become a long-term feature of the country’s energy industry, especially as the Kan administration plans to include energy conservation as one of the four key ele-ments of the revised energy policy.
By 2020, we forecast the share of natural gas will increase to 41%; the anticipated increase will come at the expense of nuclear, as the share of nu-clear in the power generation mix will likely fall to 19% by 2020 (Fig. 5).
In order to avoid such issues as those Tepco is facing in Fukushima, Japanese electric utilities will increase their earthquake and tsunami-protec-tion measures. This will require tem-porary plant closures and extended plant maintenance cycles. With strict-er maintenance regulations after the Fukushima disasters, utilities would be unable to bring them back on, fol-lowing a 90-day maintenance cycle,
FIG. 3PEC OUTLOOK FOR 2020: 503 MILLION TONNES*
*In oil equivalency.
Natural gas 24%
Nuclear 9%
Hydro 3%Others 4%
Coal 22%
Oil 38%
FIG. 4POWER GENERATION IN 2010: 1,038 Tw-hr
Natural gas 28%
Nuclear 27%
Hydro 6%Others 1%
Coal 24%
Oil 14%
FIG. 5POWER GENERATION OUTLOOK FOR 2020: 967 Tw-hr
Natural gas 41%
Nuclear 19%
Hydro 7%Others 4%
Coal 24%
Oil 5%
110801ogj_78 78 7/27/11 10:18 AM
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80 Oil & Gas Journal | Aug. 1, 2011
Until recently, it was generally un-derstood that reactors could operate for 60 years if being properly main-tained. Following the Fukushima disasters, however, there is already strong opposition to continuing to op-erate older nuclear units. All those is-sues will contribute to the reduced nu-clear share in total power generation.
Gas demand outlookThe power sector accounted for 61.9% of Japan’s total natural gas demand in 2010 (9 bcfd), a slight increase from 2009, and the city’s gas sector (i.e., in-dustrial, residential-commercial, and others) made up the balance. Under the city’s gas sector, industrial demand accounted for 19.3% (18% in 2009),
residential-commercial demand had a 15.3% share (18% in 2009), and others made up the balance (Fig. 6). Industrial demand notably improved in 2010 from 2009 when demand was hard hit by the economic recession and fell by 13% y-o-y.
Based on current information, we forecast Japan’s nat-ural gas consumption in 2011 will increase by 12.8%, to 10.3 bscfd, due to a significant demand increase in the power sector. The power sector’s demand will increase by 23.9%, to 7 bcfd, in order to make up for lost nuclear
until plant safety is approved by local authorities and the community. Even if units may be brought back in opera-tion, maintenance will take longer than 90 days, thus Japan’s nuclear utilization will decline further.
Furthermore, the life span of the existing nuclear reactors will likely be shorter, considering some units in Japan are already 40 years old (Table 5). Every 10 years, utilities obtain permission from the Nuclear and Industrial Safety Agency to operate their reactors another 10 years. The life span is not specifically regulated but must be approved by the agency.
STATUS OF JAPANESE NUCLEAR PLANTS Table 5
Built and Capacity, operationalCompany Plant Unit no. Mw since
Japan Tokaidaini 1,100* Nov. 1978Atomic Power Tsuruga 1 357 Mar. 1970
2 1,160 Feb. 1987Hokkaido Tomari 1 579 June 1989 2 579 Apr. 1991 3 912 Dec. 2009Tohoku Onagawa 1 524 June 1984
2 825 July 1995 3 825 Jan. 2002
Higashi-dori 1 1,100 Dec. 2005 Tokyo (Tepco) Fukushima 1 460 Mar. 1971 Daiichi 2 784 July 1974
3 784 Mar. 1976 4 784 Oct. 19785 784 Spr. 1978 6 1,100 Oct. 1979
Fukushima 1 1,100 Apr. 1982 Daini 2 1,100 Feb. 1984
3 1,100 June 19854 1,100 Aug. 1987
Kashiwazaki- 1 1,100 Sept. 1985 Kariwa 2 1,100 Sept. 1990
3 1,100 Aug. 1993 4 1,100 Aug. 1994
5 1,100 Apr. 1990 6 1,356 Nov. 1996 7 1,356 July 1997 Chubu Hamaoka 3 1,100 Aug. 1987
4 1,137 Sept. 1993 5 1,380 Jan. 2005
Built and Capacity, operationalCompany Plant Unit no. Mw since
Hokuriku Shika 1 540 July 19932 1,206 Mar. 2006
Kansai Mihama 1 340 Nov. 1970 2 500 July 1972
3 826 Dec. 1976 Takahama 1 826 Nov. 1974 2 826 Nov. 1975 3 870 Jan. 1985 4 870 June 1985 Oi 1 1,175 Mar. 1979 2 1,175 Dec. 1979
3 1,180 Dec. 1991 4 1,180 Feb. 1993Chugoku Shimane 1 460 Mar. 1974 2 820 Feb. 1989Shikoku Ikata 1 566 Sept. 1977 2 566 Mar. 1982
3 890 Dec. 1994Kyushu Genkai 1 559 Oct. 1975
2 559 Mar. 19813 1,180 Mar. 1994
4 1,180 July 1997 Sendai 1 890 July 1984 2 890 Nov. 1985 ––––––– ––––––– Total capacity 54 units 48,960
Total capacity operating 19 units 17,580
*Red numbers signify not operating.
FIG. 6SECTORAL GAS DEMAND FOR 2020
Power
Industry
Residential-commercial
Others
2010 2011 2020
Dem
and,
bcfd
8
7
6
5
4
3
2
1
0
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Oil & Gas Journal | Aug. 1, 2011 81
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efforts will continue to be adopted nationwide and will re-main a long-term feature.
The power sector’s future gas demand is inextricably linked with Japan’s future energy policy. The Kan admin-istration has pledged to start from a blank slate in rethink-ing the energy policy following the Fukushima crisis. Local residents and authorities call for higher nuclear safety stan-dards and a better procedure for emergency management, while opposition to building more nuclear power reactors has grown.
On the other hand, for many villages and cities, a com-bination of employment and government subsidies relat-ing to the nuclear industry plays an important role in their economic activities. Local economies are already being ad-versely affected, as the plant shutdowns have left many out of work, placing additional pressure on local authorities. In-deed, the nuclear issue is a social as well as an energy secu-rity, economic, and political issue. Ultimately, the shape of Japan’s postcrisis energy policies will be determined in large by the degree to which local communities accept further nu-clear power generation in their vicinities.
There is a dire need for an integrated energy policy grounded in a new post-Fukushima reality. Such an energy policy will require a reassessment of all kinds of renewable energy, including nuclear power, and a review of future en-ergy use. The timing, pace, and scale of any nuclear devel-opment, however, will be adversely affected by the Fuku-shima crisis; thus impacts on the global market, specifically for LNG, will be profoundly felt over the coming years.
power capacity including Tepco’s Fukushima Daiichi and Fukushima Daini, Tohoku Electric’s Onagawa, and Chubu Electric’s Hamaoka. Furthermore, utilities will not be able to bring back some reactors, currently under maintenance, until plant safety is approved by local authorities following the stress tests.
We forecast that the power sector’s demand will peak in 2013, assuming the bulk of nuclear reactors remain closed. After that, gas demand will fluctuate as some of the nuclear units, currently under maintenance or inspection, will even-tually return to operation. Our base assumption is, however, that no new nuclear reactors will be built in the next decade.
The share of the power sector in gas demand will increase to 64.9% in 2020 and will start declining thereafter.
The industrial sector’s demand will likely fall off this year but increase to higher than the 2010 level in 2013. The fol-lowing factors will retard city gas sector’s demand:
1. Tepco’s reduced power supply capacity will affect in-dustrial activities, as well as consumer spending.
2. Damaged infrastructure such as roads, sewage sys-tems, hospitals, and other public offices are slowing the dis-tribution of goods and services.
3. Japanese consumers will restrict spending in sympa-thy for suffering residents in temporary shelters.
Overall, the industrial sector’s demand will grow at an average of 1.2%/year for 2010-15 and at 3.2% for 2015-20. Fig. 6 shows the power sector’s overall gas demand will in-crease at an average of 3.5%/year for 2010-15 and then at 1.7%/year for 2015-20.
In terms of LNG imports, Japan will remain as the world’s largest LNG importer by far. All of Japan’s natural gas im-ports are in the form of LNG for the foreseeable future.
In 2010, LNG imports increased by 5.5 million tonnes to 70.0 million tonnes as demand from the power and city gas sectors increased y-o-y.
Consumption by sector, in terms of LNG, is as follows:1. Power sector at 43.1 million tonnes (+9.4% y-o-y).2. Industrial sector at 13.1 million tonnes (+11%).3. Residential/commercial sector at 10.7 million tonnes
(+1.9%).Under our base-case scenario, Japan’s LNG imports in
2011 and 2020 will be 78.8 million tonnes and 85.4 million tonnes, respectively.
Energy policy uncertaintyThe disaster and its effect on the power sector have changed the Japanese life-style in the most dramatic way and will have profound implications on the global LNG market. It is important to understand, however, that there is a limit as to how much Tokyo will be able to import, considering re-gional logistics and environmental issues.
On the demand side, energy-saving initiatives by the gov-ernment and Japanese consumers should be taken very seri-ously. We certainly believe that Japan’s energy-conservation
The authorTomoko Hosoe ([email protected]) is a project specialist at the East-West Center, Hono-lulu. An energy expert on Japan, she is familiar with energy policies, demand, supply, and trade with a special focus on downstream oil and natural gas and LNG. Her research focus also includes a comparative analysis of corporate efficiency of national oil companies vs. interna-tional oil companies. Hosoe holds a master’s in public affairs from the School of Public and Environmental Af-fairs—Public Management at Indiana University and a doctorate in international relations (management) from Graduate School of International Relations at Nihon University.
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82 Oil & Gas Journal | Aug. 1, 2011
inspection, if the test occurs during turnaround.For ESDs, if we are able to test them on line, we will do
them annually. Otherwise, off-line inspection will be per-formed during turnarounds.
Each SIS, the third class, will have its individual safety re-quirement specification for that shutdown device. The speci-fication contains detailed testing procedures for each of the shutdown valves. If it is a Class VI for a heater, then it is test-
ed in bubbles per minute when down. If there is a way to bypass that valve and do it on line with a full test, then it is done every 5 years; otherwise, it is off-line during turnaround.
When I saw this question, I did not know exactly what the person wanted to know. So, if it was whether we do full or partial, then my response is that we no longer do partial testing of shutdown valves. They are all done full test, and we will not do one if it jeop-ardizes the unit running. That is why we do them only during shutdowns or turnarounds.
Tracy: ConocoPhillips has developed guidelines for emergency shutdown valve testing. The target frequency for testing is one turnaround cycle. That
testing frequency is increased, however, based on individual application or to achieve the safety integrity level required by layers-of-protection analysis.
For shutdown valves that do require testing between turnarounds, we put in bypass valves. Our testing includes leak-testing the plug and seat in the as-found condition, dis-assembly inspection repair of the valve and actuator, and then reassembly, including a final leak-test of the plug and seat for final verification.
Johnson: The appropriate required testing of emergency shutdown valves is included in each Marathon refinery’s me-chanical integrity (MI) program and complies with the Pro-
This second of three articles that presents selections from the 2010 National Petrochemical and Refiners Association Q&A and Technology Forum (Oct. 10-13, Baltimore) con-tinues a discussion of safety and also covers coking and cor-rosion.
The first installment based on edited transcripts from the 2010 event (OGJ, July 4, 2011, p. 80) deals with safety and process operations. The final installment (OGJ, Sept. 5, 2011) will highlight gasoline pro-cesses, especially dealing with safety, alkylation, and naphtha hydrotreating.
The session employed five panel-ists (see accompanying box). The only disclaimer for the panelists was that they discuss their own experiences, their own views, and the views of their companies. What has worked for them in their plants or refineries might not be applicable to every situation, but it can provide sound guidelines for what would work to address specific issues.
Safety
What testing procedures do you use for emergency shutdown valves? What are the parameters you measure and the accept-able values?
Johnson: Each Marathon refinery has its own mechani-cal integrity program containing detailed inspection, test-ing, and preventive maintenance tasks for each of the three equipment classes of shutdown devices. Those are emer-gency isolation valves (EIVs), emergency shutdown devices (ESDs), and SIS (safety instrumented systems); each has dif-ferent requirements.
For EIVs, we only test them off-line, a full test of the driv-er. These tests are done biennially if they can be done on the run; otherwise, only in turnaround. We do a full stroke test. We verify the DCS [distributed control system] alarms, po-sition indication, and valve closure and do an internal valve
Discussion expands to include coking, corrosion
N P R A Q & A — 2
The panel…
• Jim Johnson, hydropro-
cessing and crude/vacuum tech-
nologist, Marathon Petroleum
Co. LLC
• Frank Tracy, advising engi-
neer, ConocoPhillips Co.
• Ralph Goodrich, princi-
pal consultant, KBC Advanced
Technologies Inc.
• Doug Meyne, business de-
velopment manager, Champion
Technologies Inc.
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Oil & Gas Journal | Aug. 1, 2011 83
PROCESSING
cess Safety Management regulation of the US Occupational Health and Safety Administration and the US Environmen-tal Protection Agency’s Risk Management Plan regulation.
Inspection, testing, and preventive maintenance (ITPM) plans are detailed for each equipment class, which includes emergency isolation valves, emergency shutdown valves as-sociated with emergency shutdown devices pre-ANSI/ISA S84.00.01, and Safety Instrumented Systems as defined by ANSI/ISA S84.00.01.
The minimum ITPM tasks for EIVs includes a full stroke test, verification of DCS/HMI [human-machine interface] alarms, position indication, valve closure, and internal valve inspection. The testing will only be off-line and include a full test of the driver. If the EIV is where it can be isolated on the run, then the valve will be tested biennially except for the internal valve inspection, which is only done during turnarounds.
If the valve cannot be isolated on the run, then all testing will be completed during turnarounds. Limit switches must be satisfied that the valve travels fully open and closed. The internal valve inspections are to be conducted by a qualified inspector; if internal damage is observed, an appropriate re-pair plan will be developed, which may include leak-testing after repairs.
Emergency shutdown valves associated with ESDs are to undergo a full-function test annually if the ESD was designed for on line testing or will be tested during turnarounds, if not designed for on line testing.
Valves associated with SISs undergo testing detailed in the individual safety requirement specification (SRS). An ex-ample of a notable additional requirement for SISs is that
heater shutdown valves (Class 6) are leak-tested with the leak rate measured in bubbles per minute that must pass the leak-test tolerance in accordance with ANSI B16.104-1976. These valves are leak-tested on either a 5-year interval, if available on line, or the turnaround interval if not available on line.
We no longer perform partial-function tests on shutdown valves, only full tests.
Coking
In your experience, what are the implications on coker heater run length and coke drum operations with the following feed-stock quality: contaminants (Na, Ca), low saturates or high as-phaltenes, crude compatibility, solvent deasphalt (SDA) pitch, low asphaltenes, and high saturates?
Tracy: I am going to speak first to the heater run-length por-tion of the question, and then I will follow with some discus-sion of drum operations.
There are at least three main mechanisms by which heat-er tubes become fouled in cokers. The first one is inorganic material deposition or precipitation, the second is rapid as-phaltene precipitation, and the third is coke formation. All of these may contribute to chronic heater fouling. However, we have identified the first two in conjunction with specific episodes of rapid fouling.
I am going to talk first about inorganic fouling mecha-nisms. Inorganic fouling typically occurs in the top of the radiant section or even in the lower part of the convection section of the heater. Suspended solids in the oil are often a source for these inorganic materials. These materials may be inherent in the crude, or they may be introduced into the oil as part of upstream processing, transportation, or produc-
Valero Energy Corp., since it acquired the Texas City Refinery in 1997, has invested more than $750 million in expansions and upgrades. Most recently, said the company, the plant completed a major expansion consisting of a new delayed coker and a gasoline desulfur-ization unit. The company said the new units allow the crude units to run lower-value, heavier-gravity crude feedstocks to produce a large slate of low-sulfur, clean fuels. Photo from Valero Energy.
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84 Oil & Gas Journal | Aug. 1, 2011
benefit from desalter operation changes and in managing caustic injection for chloride control in the crude unit. You may also be able to get some relief from crude suppliers.
At the end of the day, however, it becomes an economic decision as you deal with certain crudes and recognize that crude selection affects heater-run length. You have to value that crude appropriately, based on that impact because you are often just stuck with what comes in the crude. In ad-dition, refinery slop and possibly FCC [fluid catalytic con-verter] slurry oil have inorganics that might contribute to fouling.
The second area is asphaltene precipitation. We have ex-perienced episodes in which we have seen asphaltene pre-cipitation occur rapidly. It tends to occur in the upper radi-ant and lower convection sections. Sometimes this has links to highly paraffinic materials or low asphaltene stability ma-terials such as a resid hydrocracker bottom stream.
Within ConocoPhillips, we use asphaltene stability test-ing and coking propensity testing to identify feeds that are problematic and have feed-compatibility issues. Distillate recycle technology, which recycles either a coker distillate stream or a coker gas oil stream through the heater and coke drums, will help with asphaltene stability.
The final area of concern is coke formation: the tradition-al coker fouling mechanism. The heaviest coke formation tends to be in the lower radiant section of the heater, and turbulence and velocity can be used to help minimize the amount of time that a molecule is at that hot tube wall. Ve-locity steam is used for this purpose, as is distillate recycle, which also provides a yield benefit.
As to the drum operations portion of the question, the inorganic materials do not generally create any drum opera-tion problems. If you operate an anode coker, however, then the coke quality issues can be significant with certain crudes and some of those contaminants. Feedstock, of course, im-pacts drum operations. The top of the coke bed has had the least amount of time to complete the coking reactions.
So, if you have a less reactive feedstock such as a resid hydrocracker bottom stream, then that material may be less converted to coke, particularly in the top of the bed. When the drum is finished, therefore, that material may be a little bit more like tar than a vacuum resid feed would be. And, as a consequence, it tends to plug off some of the channels in the upper part of the coke drum and lead to more hotspots and blowouts.
In fact, we have seen that situation in two of our cokers that fed some amount of resid hydrocracker bottoms mate-rial. In addition to adjusting temperature, we have limited the amount of that feedstock to those cokers to help with the hot spots and blowouts.
Goodrich: I essentially agree with everything that Frank has commented on so far. I just want to emphasize a few of
tion before their arrival at the coker.Desalters are generally effective at removing the crystal-
line salts from the oil—think of sodium chloride—but not generally as effective in removing some of these other inor-ganic solids. The sodium and calcium noted in the question are certainly common problems in cokers: 15-20 ppm so-dium is a common industry rule of thumb as a maximum for sodium in feed to the coker. Of course, we would like to see numbers below that. Crude-unit caustic injection for chlo-ride control will lower sodium loading in the vacuum resid.
Because we have seen large quantities of calcium in some of the scale removed from some heaters as well, we know that calcium is another inorganic material that causes prob-lems in certain cases.
Silicon is an inorganic that has also caused major prob-lems in at least three of our cokers. It has also been identified with certain crudes, and the source is most often silicates or silica (quartz) in the crude oil. In additional, silicon-based antifoam has been identified as a possible foulant in one of our units.
Iron is another inorganic material we have seen in heater-tube fouling, and the common sources are iron sulfides and other iron compounds that, again, make it through the de-salter and end up in the feed to the coker.
There are other inorganics associated with fouling. Alu-minum and magnesium are often associated with some of the silicates, as well as barium, although these are less com-mon than the four I have mentioned. Well workover chemi-cals add to the amount of inorganic material in the crude supply.
As you know, the inorganic materials don’t lend them-selves well to on line spalling or steam-air decoking and of-ten require pigging to be properly removed from the heater tubes.
Ideally, these inorganic materials will be handled up-stream of the coker and you might be able to achieve some
Champion Technology’s standard corrosion-control program package includes installation of corrosion rate data loggers, similar to the one shown here (Fig. 1).
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86 Oil & Gas Journal | Aug. 1, 2011
er as similar as possible. Do not mix, for example, highly asphaltenic feeds with highly paraffinic feeds.
Corrosion
Please discuss advanced methods you use to monitor corro-sion in operating units. Are any of these used in conjunction with the DCS for continuous on line monitoring?
Johnson: To answer this, I had to ignore the comment of advanced methods because most of our methods are not re-ally advanced.
We utilize three methods for corrosion monitoring. The most advanced would be the multipoint resistance mea-surements for naphthenic acid. Two of our refineries utilize those. Then, basically, we have ER [electrical resistance] probes and corrosion coupons.
Two refineries utilize the multipoint resistance measure-ments. One uses [iiccor Ltd.], the field signature method; the other refinery uses the GE Betz RCM [resistance corrosion monitoring] system. Neither of these RCM systems is moni-tored continuously. The vendors take periodic readings, in-terpret the corrosion data, and send memos to the refinery, but this monitoring is not done continuously.
ER probes, likewise: nothing continuous. But one of our refineries uses data loggers for relatively real-time. It is not
the areas, one being the caustic injection.This injection rate is something we target when we feel
some refiners may be pushing that a little bit too hard. You really want to monitor the amount of caustic that you use. In fact, when we do a grassroots design of a crude unit, we will provide injection facilities. We would rather not pipe it up but prefer to have it available only if it is actually needed.
Also, the high asphaltenes content in the feed can sig-nificantly increase your furnace fouling rate. It can also in-crease the tendency to produce shot coke and cause coke drum cooling problems and high thermal stresses, which can result in coke drum cracks.
Another point, particularly in some locations in Canada, is that there could be a high solids content in the feed, as high as 2%. This content can cause fouling in the coker fur-nace in the same locations that Frank mentioned and in the coke drum’s overhead line and the main fractionator’s wash section.
Finally, there are definitely crude compatibility issues to be aware of. Dissimilar crude and resulting coker feeds can result in difficulties in drum cooling and hot spots. Foam-ing can be a problem as well. Some of these problems with dissimilar coker feeds can be addressed with procedural changes; but at some point, limiting the offending crude is the only economic choice.
In general, to avoid these problems, keep the feeds to cok-
BENEFITS OF DATA LOGGERS
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Oil & Gas Journal | Aug. 1, 2011 87
PROCESSING
gers and getting more than just the traditional one-corro-sion-rate reading per week. If the only corrosion rate data you had on the system was that represented by the “yellow dot” trend, you would have missed all of the corrosion spikes and, in this case, the issues with the slop-handling practices that were leading to increased corrosion in the overhead sys-tem.
Mike Nugent (Northern Engineering Consultants Inc.):
Continuous UT [ultrasonic thickness] transducers now exist that can be mounted on high-temperature operations.
We have had some on transfer line service at 650º F. for 5 years now. They are ultrasonic thickness measurements to give pipe thickness readings. They provide real thick-ness monitoring as opposed to the correlations from cor-rosion probes. The big problem has been having a sensor that would last for 5 years or more. So, there are now ultra-sonic thickness capabilities for continuous high-temperature monitoring.
The question of tying it into the DCS again becomes less a technology question and more an information question. Your computer folks have to go with wireless transmission, which either is a benefit or is banned in certain refineries, and also the logistics of tying it in.
Sometimes it is easier to put a data logger at a remote sta-tion to acquire corrosion data, but I know no one who has gone to a real-time monitoring of corrosion, as far as setting crude rate. The capability does exist, and the ability to tie it into the DCS becomes more an IT issue than a technology issue because there is wireless technology and hard cable. Usually, though, most people find it easier to leave the data logger there, as you have for the corrosion probes, and re-cord them on a batch basis.
Johnson: Marathon utilizes three methods of corrosion monitoring in crude and vacuum units: multipoint resis-tance measurement (iicorr, FSM, GE Betz RCM) systems for naphthenic acid corrosion, ER probes, and corrosion cou-pons. While use of coupons may not be considered an “ad-vanced method” for monitoring corrosion, we continue to use them in our refining system.
Two of our refineries have installed multipoint resistance measurement technology in areas that previously experi-enced naphthenic acid corrosion. One refinery uses iicorr’s field signature method system, while the other location utilizes GE Betz’s RCM system. Neither of these systems is monitored continuously. Rather, spot readings taken rou-tinely with the calculated corrosion rate are reported to the refinery.
A mix of ER probes and coupons is used in our refiner-ies. Either is used, depending on the corrosion history of the particular circuit and how frequent corrosion data are required. One of our refineries utilizes a data logger on the ER probe signal to capture data on a near-continuous ba-
continuous and is not brought back to any DCS.And lastly, the most nonadvanced are corrosion coupons.
We are still using these heavily in our systems, and we use them for metallurgy selection, not just corrosion.
Meyne: To build on what Jim said, part of Champion’s stan-dard corrosion-control program package is installation of corrosion-rate data loggers in the critical areas of the system. This [Fig. 1] is a picture of the data logger and an example of a wireless bus. I have not seen any of these recently that have been tied directly into the DCS due to the significant cost associated with making this connection.
We typically see these data loggers hooked up to stan-dard ER probes. You can set them to take as many corrosion rates per day or week as you would like. To retrieve the data, you take a hand held device to the logger, plug it in as you normally would to an ER probe, download all the data, and then enter it into your software to get your rates. The more corrosion rates per day you set the data logger to read, the more frequently you will have to download the data to the hand-held device.
This slide [Fig. 2] is an example of why we use data log-gers as part of our standard corrosion-control programs. Normally, ER probes are only read once or twice a week, thus generating minimal corrosion-rate information. Corro-sion is very episodic. Obtaining only one or two corrosion rates per week does not allow you to see these “corrosion episodes.”
We are not nearly as concerned with seeing weekly aver-age corrosion rates of 5 mils/year (mpy) as we are with see-ing the 2 or 3-hr windows of time during the week when the corrosion rates may spike to 80 mpy or 100 mpy.
[Fig. 2] shows the output of a data logger that was set to take six readings a day. As you review the data, you can see obvious spikes in corrosion rate. For the most part, these spikes are occurring roughly every Friday evening or Friday night. Tracing it back, we found that there were some abnor-malities in the tank farm with respect to slop dumps back to crude. The tank farm was essentially transferring all the weekly slop from the refinery to the crude tanks all at once on Friday evening instead of daily as their procedure stated.
Once this issue was identified, we were able to get the slop-handling practices changed. The leveling of the corro-sion rates seen on the far right side of the graph represents the time period after the handling practices were changed and the corrosion spikes were eliminated.
For comparison purposes, if you were just going out there every Wednesday afternoon to take a normal one-corrosion-rate reading on an ER probe, then the results are represented by the big yellow circles [Fig. 2].
This comparison shows the importance of the data log-
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88 Oil & Gas Journal | Aug. 1, 2011
to be episodic and can be attributed to many changes in operating conditions. Under normal conditions, a system may see 1-5 mpy corrosion rates; how-ever, the rates can spike up to hundreds of mpy during one of these corrosion episodes. It is critical to identify these corrosion spikes when they occur so that changes in operations or chemical additions can be made immediately to resolve the issue. By reducing the time of these spikes, the overall corrosion rate is minimized.
In order to “see” these corrosion spikes and overcome the limited da-ta-acquiring capabilities of traditional coupons and ER probes, Champion utilizes data loggers to obtain multiple corrosion rates per day. Standard ER probes are hooked up to the data log-gers that have the ability to store sev-eral days of corrosion rates.
Typically, the rates are uploaded to a hand-held unit out in the field and then downloaded to a PC. The data loggers can also be tied directly into a DCS via cables or wireless buses to yield true “real time” corrosion rates. These data loggers are part of our stan-dard corrosion monitoring package and can be set to read corrosion rates on any given time interval.
Eberhard Lucke (Commonwealth
Engineering & Construction LLC): I have not seen any operation yet that would show corrosion monitoring in the DCS. The most advanced I have seen (and I may be outdated on that) was installed corrosion probes with easy connections to a data logger (hand held, [personal digital assistant] PDA-like device). A dedicated maintenance person would walk the unit in certain intervals and collect all the data from the corrosion probes via data logger.
The data would then be transferred electronically into spread sheets and used in an off-line unit monitoring system. I assume that with new wire-less technologies and internet connec-tions, automatic data transfer into da-tabases, and even into the DCS, should be no problem, if required.
sis, whereas at all other locations the probes are typically monitored weekly.
We have no examples in which data are sent to the DCS.
Corrosion coupons are still wide-ly used, mainly for general corrosion monitoring. At one refinery designed for high TAN [total acid number] crudes, corrosion coupons of various less-corrosion-resistant metallurgies are placed in select circuits to provide data on the relative corrosivity of cer-tain crudes and cuts. These data will be used in an effort to better optimize
metallurgy requirements in the future and provide pertinent corrosion data if a common crude is processed at an-other location.
Meyne: Traditionally, standard cor-rosion coupons and ER probes are used to monitor corrosion in operat-ing units. The main limitation of these types of corrosion monitoring devic-es is the limited amount of data they generate, usually one to two corrosion rates a week if not fewer.
Corrosion in operating units tends
NELSON-FARRAR COST INDEXES
Re nery construction (1946 basis)(Explained in OGJ, Dec. 30, 1985, p. 145, and at www.pennenergy.com/index/research-and_data/oil-and_gas/Statistic-De nitions.html; click “Nelson-Farrar Cost Indices”)
Apr. Mar. Apr. 1962 1980 2008 2009 2010 2010 2011 2011
Pumps, compressors, etc.222.5 777.3 1,949.8 2,011.4 2,030.7 2,027.9 2,088.4 2,101.6
Electrical machinery189.5 394.7 515.6 515.5 513.9 514.1 514.1 514.1
Internal-comb. engines183.4 512.6 990.9 1,023.0 1,027.8 1,033.2 1,030.0 1,030.6
Instruments214.8 587.3 1,342.1 1,394.8 1,435.1 1,424.4 1,470.7 1,470.7
Heat exchangers183.6 618.7 1,354.6 1,253.8 1,116.0 1,103.5 1,103.5 1,103.5
Misc. equip. average198.8 578.1 1,230.6 1,239.7 1,224.7 1,220.6 1,241.3 1,244.1
Materials component205.9 629.2 1,572.0 1,324.8 1,480.1 1,515.6 1,605.9 1,620.7
Labor component258.8 951.9 2,704.3 2,813.0 2,909.3 2,875.0 2,964.2 2,966.6
Re� nery (In� ation) Index237.6 822.8 2,251.4 2,217.7 2,337.6 2,331.3 2,420.9 2,428.2
Re nery operating (1956 basis)(Explained in OGJ, Dec. 30, 1985, p. 145, and at www.pennenergy.com/index/research-and_data/oil-and_gas/Statistic-De nitions.html; click “Nelson-Farrar Cost Indices”)
Apr. Mar. Apr. 1962 1980 2008 2009 2010 2010 2011 2011
Fuel cost100.9 810.5 1,951.3 978.5 1,184.9 1,117.3 1,171.2 1,240.1
Labor cost93.9 200.5 237.9 264.5 281.7 278.1 276.4 293.3
Wages123.9 439.9 1,092.2 1,177.1 1,279.4 1,290.0 1,266.6 1,323.6
Productivity131.8 226.3 460.8 445.2 454.5 463.9 458.3 451.3
Invest., maint., etc.121.7 324.8 830.8 812.4 850 847.7 880.3 883.0
Chemical costs96.7 229.2 472.5 406.2 449.8 456.6 520.2 535.1
Operating indexes Re� nery
103.7 312.7 674.1 582.6 628.2 620.3 644.6 659.7Process units*
103.6 457.5 1,045.1 706.1 796.8 771.2 801.0 831.1
*Add separate index(es) for chemicals, if any are used. See current Quarterly Costimating in rst issues for January, April, July, and October. These indexes are published in the rst of each month. They are compiled by Gary Farrar, OGJ Contributing Editor. Indexes of selected individual items of equipment and materials are also published on the Costimating page in rst issues for January, April, July, and October.
110801ogj_88 88 7/27/11 10:18 AM
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90 Oil & Gas Journal | Aug. 1, 2011
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Study opens pathto optimized MIC assays
copy and energy dispersive x-ray spectroscopy (ESEM-EDS).Results of these analyses provided necessary background
information for further implementation of MMM for MIC risk assessment in the Aramco crude oil pipeline system.
BackgroundCorrosion resulting from the attachment and activities of microorganisms on metal surfaces is microbiologically in-fluenced corrosion (MIC). It occurs in diverse environments and is not limited to aqueous submerged conditions, but also takes place in humid atmospheres. It is an electrochemical process in which the participation of microorganisms is able to initiate, facilitate, or accelerate the corrosion reaction
without changing its electrochemical nature.1 MIC stems from interactions that are often syn-
ergistic among the metal surface, abiotic corrosion products, and microbial cells and their metabolites. The latter includes organic and inorganic acids and volatile compounds, such as ammonia and hydro-gen sulfide. Microbiologically mediated reactions do not result in a unique type of corrosion, but they can induce localized corrosion, change the rate of corrosion, and also inhibit corrosion.2
Most MIC studies have focused on bacterial in-volvement. Under aerobic conditions, however,
other single-celled organisms, such as fungi, yeast, and dia-toms, can influence corrosion.3 The predominant types of bacteria associated with MIC are sulfate-reducing bacteria (SRB), sulfur-oxidizing bacteria, iron-oxidizing-reducing bacteria, manganese-oxidizing bacteria, and bacteria secret-ing organic acids and slime.4 These organisms coexist within a biofilm matrix on metal surfaces, functioning as a consor-tium, in a complex and coordinated manner.
The various mechanisms of biocorrosion reflect the vari-ety of physiological activities carried out by these different types of microorganisms when they coexist in biofilms. De-cades of study on MIC have so far failed to determine how many species of microorganisms contribute to corrosion, and researchers continue to report on the formation of bio-films by an ever-widening range of microbial species.
The high diversity of microorganisms and mechanisms
Mazen Al-Saleh
Peter Sanders
Tawfiq Al-Ibrahim
Saudi Aramco
Dhahran
Susanne Juhler
Ketil Sorensen
Thomas Lundgaard
Danish Technological Institute
Aarhus, Denmark
Genetic characterization of microbes present in crude oil samples makes possible the design of optimized assays for surveillance and troubleshooting of mi-crobially influenced corrosion (MIC).
Chemical and microbiological analyses of wa-ter condensates during the first phase of applying molecular microbiology methods (MMM) to risk assessment of microbially influenced corrosion of Saudi Aramco’s crude pipelines showed microor-ganisms, many with the potential to cause MIC, present in numbers comparable to other systems with documented incidences of MIC.
This article discusses research conducted in Saudi Aramco Research and Development Center to devel-op MIC assessment protocols introducing MMM to confirm MIC as the cause of corrosion in a specific case and proce-dures to conduct reliable field monitoring of MIC.
Initial stages of the project collected several water and solid samples from different sites along a single crude oil pipeline. Analysis sought to:
• Determine how many and what types of microorgan-isms are present in the samples through MMM.
• Determine the chemical nature of the water in the sys-tem through geochemical analysis.
• Investigate the presence of bacteria in solid and filter samples through environmental scanning electron micros-
SPECIAL REPORT
Based on presentation to NACE Corrosion 2011 Conference, Houston, Mar. 13-17, 2011.
110801ogj_90 90 7/27/11 10:18 AM
Oil & Gas Journal | Aug. 1, 2011 91
potentially involved in MIC has made it hard to predict and assess the process before substantial damage has already oc-curred. Recent technological advances in the field of molec-ular microbiology have now made it possible to detect and enumerate specific MIC-promoting microorganisms with a much better precision than previously. Given proper proce-dures for sampling and analyzing field material, it has now become possible to perform a reliable screening of industrial systems for potentially harmful microorganisms and to use this information in a MIC risk analysis.
Saudi Aramco in collaboration with the Danish Technological Institute launched a joint research project in early 2010 to introduce molecular mi-crobiology methods (MMM) as a tool for failure analysis and MIC risk as-sessment in Aramco’s crude oil pipe-line system. This article presents the initial findings of the project and outlines future steps.
Researchers collected sets of water and solid samples (after scraping) from across the targeted crude oil pipeline system and analyzed and evaluated them with respect to microbiological and chemical composition. A general micro-biological population study using several molecular micro-biology methods determined how many and what types of microorganisms were present in the system.
This microbiological characterization will provide the basis for development of customized laboratory kits and protocols for the detection and enumeration of MIC-related microorganisms in the Aramco crude oil pipeline system. Knowledge of the chemical composition of the water phase in the pipeline will be valuable for developing procedures to extract microorganisms and DNA from crude oil.
Experimental procedureWater samples collected from a vertical outlet in the crude oil pipeline system determined the basic water chemistry and microbiology in the system (Table 1). Table 2 provides a general description of the studied pipeline.
Filtering of samples SA-1, SA-3 and SA-4 occurred imme-diately after sampling, and the filters were stored in a fixa-tion buffer for later microbiological analysis. Samples SA-2, SA-5 and SA-6 served for chemical analysis of the water. An evacuated container containing a 20% zinc-acetate solution
to preserve any reduced sulfur in the water collected sample SA-6.
Researchers gathered and immedi-ately preserved a solid (debris) sample (SA-7) from the scraper trap receiver area during scraping operations. Sub-jecting this sample to laboratory test-ing with ESEM/EDS investigated the
presence of bacteria and the chemical composition, includ-ing corrosion products, of the solid samples.
Chemical analysisCharacterization of the water samples from the identified crude oil pipelines took place according to its organic matter content, salinity, H
2S concentration, and inorganic elemen-
tal composition. Filtrating part of each sample determined the amount of total suspended solids (TSS). Drying the sec-ond part determined its organic content by loss of ignition (at 550° C.). Drying and homogenization preceded analysis of the inorganic elemental solids with wavelength dispersive x-ray fluorescence (WDXRF) spectroscopy. Spectrometry determined the concentration of dissolved hydrogen sulfide in the water.
SAMPLES, PERFORMED ANALYSES Table 1
Sample Sample Chemical Microbiological MicroscopicID type analyses analyses analysis
SA-1 50 ml water, � lter � xed –– qPCR,1 cloning-seq2 ––SA-2 200 ml water, un� xed Salinity, TSS,3 XRF4 –– ––SA-3 200 ml water, � lter � xed –– qPCR,1 cloning-seq2 ––SA-4 200 ml water, � lter � xed –– qPCR,1 cloning-seq2 ––SA-5 200 ml water, un� xed Organic fraction, salinity, XRF4 –– ––SA-6 5 ml water, � xed with 1 ml zinc acetate H
2S –– ––
SA-7 Solids –– –– ESEM-EDS
1Quantitative polymerase chain reaction. 2Cloning and sequencing. 3Total suspended solids. 4X-ray � uorescence.
PIPELINE Table 2
Length 99 kmOD 46 in.Basic sediment and water 0.2 vol %, normalTemp. pro� le 150° F. inlet; 80° F. outletVelocity 4.8-8.3 fpsCrude type Wet, sweet crudePipe grade Carbon steel, X52
WATER SAMPLES Table 3
Salinity, H2S TSS
% ––––––––– mg/l. –––––––––
14.5 5.4 120
DISSOLVED INORGANIC IONS,ELEMENTAL COMPOSITION*
Table 4
S Ca Fe Na Mg Cl
3.7 9.5 13 0.6 1.6 27
*Precipitate % of dry weight precipitate after water evaporation.
SUSPENDED INORGANIC SOLIDS,ELEMENTAL COMPOSITION*
Table 5
OrganicSi S Ca Fe Sr Ba material
0.8 5.6 0.2 3.6 1.6 8.8 43
*Filtrate % dry weight after drying of � lter.
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92 Oil & Gas Journal | Aug. 1, 2011
ble-sided carbon tape mounted the samples on the ESEM sample holder.
Results Tables 3-5 list results of the chemical measurements. The sa-linity in the water measured 14.5%, and the main salts were CaCl
2 and MgCl
2. A small amount of sulfide was detected
(5.4 mg/l.). Total suspended solids (TSS) amounted to 120 mg/l. and consisted mainly of BaSO
4, SrSO
4, organic mate-
rial, and Fe-containing corrosion products.
Quantification Triplicate samples determined the total number of microor-ganisms in water from the crude oil pipeline bypass, indicat-
ing both archaeal and bacterial num-bers in the range 105-106 cells/ml–1
(Table 6). The study could not deter-mine how the number of microorgan-isms in these water samples related to the number of microorganisms in the crude flowing in the pipelines. This determination will happen once the procedures for extracting cell materi-al and DNA from crude samples have been developed.
Table 6 shows the size of the to-tal microbial populations and thereby gives an idea about the overall microbiological status of the system. Knowing the number of specific MIC-causing microorganisms rather than total cell numbers would allow a much better MIC risk analysis.
qPCR may quantify MIC-causing microorganisms, such as sulfate reducers and methane producers, in a manner similar to the total bacterial and archaeal populations in Table 6. But doing this reliably requires determining which microorganisms are present in the system and optimizing
Population studies Analyzing the water samples for total microbiological cell numbers allowed characterization with respect to microbio-logical community composition. Quantitative polymerase chain reaction (qPCR) analysis of the 16S rRNA gene content in the sample determined total microbiological cell num-bers. This method amplifies genetic material extracted from samples as a basis for qualifying microorganisms.
Results given as number of genes (genetic units or GU) per ml sample correspond to the number of microorgan-isms within a factor of 2-3. (Some groups of microorganisms have more than one 16S rRNA gene copy, and therefore the number of genes is usually a bit higher than the number of microorganisms.) The total number of bacteria and archaea were quantified separately, with the sum providing information on total prokaryotic numbers.
Cloning, sequencing, and phyloge-netic analysis of specific target genes determined the microbiological com-munity composition. Characterizing the bacteria and archaea present in the water samples required amplifying the 16S rRNA genes with bacteria and archaea-specific primers, respectively. Studying the sulfate-reducers required amplifying and characterizing genes for the A and B sub-units of dissimilatory sulfite reductase (dsrAB).
ESEM-EDSA high resolution ESEM integrated with EDS analyzed the solid samples. The ESEM operated at 15 kV, 0.23-0.7 torr water vapor pressure and working distance of about 8 mm. ESEM acquired backscattered electron images together with EDS x-ray spectra from different parts of the samples. A dou-
PROKARYOTIC CELLSIN WATER SAMPLES*
Table 6
Sample Bacteria ArchaeaID ––––––––– cells/ml–1 ––––––––
SA-1 6.5 × 105 1.15 × 106
SA-3 4.4 × 104 3.0 × 105
SA-4 1.6 × 106 7.0 × 105
*Determined by quantitative polymerase chain
reaction.
BACTERIA PHYLOTYPES FOUND IN WATER SAMPLES Table 7
Taxonomic group Frequency Physiological characteristics, based on closely related cultures in sequence database
Deferribacteres 1/110 Thermo- or mesophilic, probably NO3
– or Fe3+ -reducer or fermenting organic material.
Synergistes 1/110 Thermophilic or mesophilic, fermenting organic material.
Firmicutes 25/110 Thermophilic, SO4
2– -reducing or fermenting organic material.
Thermotoga 6/110 Thermophilic, fermenting organic material.Actinomycetes 1/110
Chloro� exi 1/110 Thermo- or mesophilic, degrading aromatic or chlorinated compounds.
Unknown Bacterial Cluster I 3/110 No similar DNA sequences in the database. This group of microorganisms has apparently never been found before. Function of group in environment therefore unknown.
Unknown Bacterial Cluster II 1/110 Similar DNA sequences found before in thermophilic environments, but the microorganisms have never been cultured. Group is widespread in hot environments, but its function is unknown.
Unknown Bacterial Cluster III 71/110 Most abundant group of microorganisms in the clone library. As was the case with UC II, no closely related microorganisms have been cultured, but similar DNA sequences have been found in several studies of thermo- philic environments. Group therefore consists of thermophilic microorganisms whose metabolism and function is unknown.
110801ogj_92 92 7/27/11 10:18 AM
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110801ogj_93 93 7/27/11 10:19 AM
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94 Oil & Gas Journal | Aug. 1, 2011
clone library was related to methane-producing microorgan-isms (109 of 166 sequences, or 66%). One of the methano-gen clusters detected was related to the genus Methanother-mococcus, which has often been found in scale material close to corrosion points in production pipeline systems.1
This organism has also shown a propensity to accelerate cor-rosion of metal test coupons in laboratory studies.6 Several lines of evidence therefore show Methanothermococcus’ in-volvement in MIC.
The other two clusters of methanogens detected in the water sample carry out the same processes as Methanother-mococcus, but their involvement in corrosive processes is less well documented. Biocides employed by the oil and gas industry have in general not been tested for their efficacy in mitigating methanogens or other archaea. This article’s findings suggest future biocide test programs should include methanogens.
Testing sequenced the dsrAB genes in the samples to characterize the sulfate-reducing microorganisms in more detail. This analysis showed four different types of SRB as present (Table 9). The detected SRB are all known from other systems, and together they use a diverse selection of organic substrates as well as hydrogen for the production of sulfide. No sulfate-reducing archaea (SRA) were found. The presence of SRB in the system correlated well with the detection of sulfide in the water samples, and confirmed that SRB are growing and active in the system.
the qPCR assay on that basis.5 Tables 7-9 further character-ize the microorganisms in the system.
IdentificationTesting detected nine different types of bacteria (Table 7). Some of these clusters were similar to cultured and well-characterized microorganisms, including several types of thermo- and mesophilic bacteria that have been shown to live from SO
42–, NO
3– or Fe3+ reduction or by fermentation of
organic material. Other clusters (Unknown Bacterial Cluster I, II, and III in Table 7) represented completely unknown groups of bacteria never before cultured or characterized.
Some of these clusters show similarity to DNA sequences found in thermophilic environments, but their function is completely unknown. These unknown clusters made up a large fraction of the clone library (75 out of 110 analyzed sequences, or 68%). It remains unknown whether these bac-teria are growing and active in the pipeline system or repre-sent dormant organisms originating from the oil reservoir, but their function may be highly relevant and potentially related to MIC in the system.
Testing detected a total of seven different types of archaea (Table 8). Three of these clusters (Unknown Archaeal Clus-ter I, II and III) showed no similarity to previously charac-terized organisms. These three exotic archaeal groups com-prised 51 of 166 sequences, or 31%. As with the unknown bacterial clusters, the function of the unknown archaea re-mains enigmatic.
A large fraction of the remaining sequences in the archaeal
ARCHAEAL PHYLOTYPES FOUND IN WATER SAMPLES Table 8
Taxonomic group Frequency Physiological characteristics based on closely related cultures in sequence database
Methanosaeta 73/166 Meso- or thermophilic, with growth at temperatures up to 70° C. Methanogen, produces methane from acetate.
Methermicoccus 34/166 Thermophilic, growth at temperatures up to about 70° C. Methylotrophic methanogen, produces methane from methanol and methylamines.
Thermococcus 6/166 Hyperthermophilic, growth at temperatures up to 100° C. Grows by fermentation of complex organic material, such as hydrocarbons, polymers, peptides.
Methanothermococcus 2/166 Thermo- or hyperthermophilic, growth between 17° and 90° C. Produces methane from CO2 and hydrogen. Globally
widespread in oil production systems. May promote MIC.
Unknown Archaeal Cluster I 2/166 No close relatives of this group in culture or database. Group has apparently never been found before. Function in the environment therefore unknown.
Unknown Archaeal Cluster II 25/166 No close relatives in culture, but similar DNA sequences retrieved from subsurface marine sediments and hydrocar- bon-rich deep-sea locations. Function of group in environment unknown.
Unknown Archaeal Cluster III 24/166 No close relatives in culture, but similar sequences found in oil-contaminated soils and hydrocarbon-rich marine sediments. Function of group in environment unknown.
SULFATE-REDUCING MICROORGANISMS FOUND IN WATER SAMPLES Table 9
Taxonomic group Frequency Physiological characteristics based on closely related cultures in sequence database
Desulfomicrobium thermophilum 49/58 Thermophilic, uses sulfate, H2, ethanol, lactate, etc., to generate acetate and sul� de.
Desulfoglaeba alkanexedens 1/58 Mesophilic, degrades n-alkane and other complex organic substrates.
Desulfoglaeba sp. 4/58 Degrades complex organic molecules.
Thermodesulforhabdus sp. 4/58 Thermophilic, uses fatty acids to generate sul� de and CO2.
110801ogj_94 94 7/27/11 10:18 AM
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110801ogj_95 95 7/27/11 3:47 PM
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96 Oil & Gas Journal | Aug. 1, 2011
• Optimizing analytical protocols. No universal assay exists for specific enumeration of troublesome microorganisms, such as sulfate-reducers or methane-producers, from oil sys-tems. It is, however, possible, based on the information pre-sented in this article, to design customized qPCR assays for both these groups in Saudi Aramco’s crude pipeline systems.
• Understanding the link between cell numbers and MIC risk. The final critical step in MMM-based MIC risk assessment is translation of cell numbers into a reliable risk factor. Based on experience from produced water from other systems, to-tal prokaryotes detected in sample SA-1 and SA-4 are rela-tively high, while the number in sample SA-3 is not. The cell numbers from oil systems in other regions, therefore, may not be comparable to those in the Aramco’s system. More detailed MIC risk analysis will become possible as a more comprehensive dataset is collected from Aramco’s crude oil pipeline system.
ESEM-EDS investigationESEM-EDS results identified the main elements in the sam-ples as carbon, oxygen, iron, and sulfur with small amounts of silicon, calcium, chlorine, potassium, and sodium (Fig. 1). Results also clearly showed microorganisms present, suggesting the presence of bacteria as contributing, as also shown by iron’s presence.
MMM-based enumeration of MIC-causing microorgan-isms can provide a sensitive tool for early warning of MIC events, for general system surveillance, and for failure analy-sis in Aramco’s crude oil pipeline system, but still requires:
• Development of protocols for handling of crude samples. Analysis of crude oil presents unique problems as compared to analysis of water. Extraction of microbial cells from the oil matrix is not, for example, trivial and various oil compo-nents may be detrimental to downstream analysis if samples are not properly purified.
0.70 1.40 2.10 2.80 3.50 4.20 4.90 5.60 6.30 7.00
Kiloelectron volts
Spot analysis
CN
O
FeSi
P
S
Cl
KCa
Fe
ESEM IMAGES,* EDS X-RAY SPOT ANALYSIS FIG. 1
*At 2 microns magni�cation.
110801ogj_96 96 7/27/11 10:18 AM
Oil & Gas Journal | Aug. 1, 2011 97
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References1. Videla, H.A., “Manual of Biocor-
rosion,” Boca Raton, Fla.: CRC Lewis Publishers, 1996.
2. Videla, H.A., “Corrosion Inhibi-tion in the Presence of Microbial Cor-rosion,” NACE Corrosion 1996, Den-ver, Mar. 25-28, 1996.
3. Prasad, R., “Assessment and Control of MIC in the Oil Industry in the 20th Century,” NACE Corrosion 2000, Orlando, Mar. 26-31, 2000.
4. Beech, I.B., and Gaylarde, C.C., “Recent Advances in the Study of Bio-corrosion—An Overview,” Review of Microbiology, Vol. 30, No. 3, pp. 177-190, March 1999.
5. Skovhus, T.L., Sorensen, K.B., Larsen, J., Rasmussen, K., and Jensen, M., “Rapid Determination of MIC in Oil Production Facilities with a DNA-based Diagnostic Kit,” SPE Interna-tional Conference on Oilfield Corro-sion, Aberdeen, May 24-25, 2010.
6. Daniels, L., Belay, N., Rajagopal, B.S., and Weimer, P.J., “Bacterial Meth-anogenesis and Growth from CO
2 with
Elemental Iron as the Sole Source of Electrons,” Science, Vol. 237, pp. 509-511, July 3, 1987.
7. Larsen, J., Sorensen, K., Hojris, B., and Skovhus, T.L., “Significance of Troublesome Sulfate-reducing Pro-karyotes (SRP) in Oil Field Systems,” NACE Corrosion 2009, Atlanta, Mar. 22-26, 2009.
The authorsMazen Al-Saleh ([email protected]) is a laboratory scientist at Research & Development Center, Saudi Aramco, Dhahran. He has also served as a chemist at the National Methanol Co. (IBN SINA). He holds a BS (1996) in chemistry from Toledo University, Toledo, Ohio. He is a member of the American Chemical Society.
Peter Sanders ([email protected]) is a research science consultant at R&D Center, Saudi Aramco, Dhahran. He has previously worked at Aberdeen University, Micran Ltd., and Oil Plus Ltd. in senior technical capacities. He holds a PhD (1978) in microbiology from Exeter University, UK. He is a member of the Society for General Microbiology.
Tawfiq Al-Ibrahim ([email protected]) is a science specialist at R&D Center, Saudi Aramco. He holds a BS (1990) in chemistry from the Univer-sity of Alabama. He is a member of the American Chemical Society.
Susanne Juhler ([email protected]) is a consultant microbiologist at Danish Tech-nological Institute, Aarhus. She holds a PhD (2009) from Aarhus University, Aarhus, Denmark.
Ketil Sorensen ([email protected]) is a microbiologist at Danish Technological Institute, Aarhus. He also has 5 years of postdoctoral experience from in the US and Europe. He holds a PhD (2002) from Aarhus University and is a member of the American Society of Microbiology.
Thomas Lundgaard ([email protected]) is center manager at Danish Technologi-cal Institute, Aarhus. He holds an MS (2005) in environmental engineering from Aalborg University. He is a member of the Society of Petroleum Engineers.
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110801ogj_97 97 7/27/11 10:19 AM
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98 Oil & Gas Journal | Aug. 1, 2011
Pipeline schedulingScheduling multiproduct pipelines involves two major ac-tivities, input and delivery.
The sequence of batch injections, entering products, batch sizes, pump rates, and input terminal define the input step. Finding the optimal product input sequence and lot size aims to reduce interface costs due to product mixing or pipeline cleaning. Pipeline systems do not use separation devices and must prohibit certain sequences due to potential product contamination.
The delivery schedule specifies product batches leaving the pipeline and the amounts diverted to assigned destinations during every pumping run. This stage provides times at which pumps should be turned on-off to meet the delivery plan. Reduc-ing the number of pipeline stoppages and pump switchings reduces energy costs and pump main-tenance costs. A discrete-event simulator of mul-tiproduct pipeline operations is a computer-aided tool for quickly generating more efficient, realistic, and robust schedules. It allows easy generation of
alternative detailed schedules by changing operational cri-teria.
Approaches to study pipeline scheduling problems in-clude rigorous optimization models, knowledge-based techniques, discrete-event simulation, and decomposi-tion frameworks.1-7 Rigorous optimization methods gener-ally consist of a single mixed-integer linear programming (MILP) or mixed-integer nonlinear programming (MINLP) mathematical formulation and are usually grouped into two classes—discrete and continuous—depending on handling of route and time domains.
Discrete formulations divide the pipeline volume into a number of single-product packs and the planning horizon into several time intervals.8-11 Most formulations generally use uniform time and volume division. Rejowski and Pinto, however, assume each pipeline segment consists of packs with equal or different prespecified volumes to account for reductions in the pipeline diameter, and the horizon length consists of time intervals of adjustable duration to allow changes in the pump injection rate.10
Vanina Cafaro
Diego C. Cafaro
Carlos A. Mendez
Jaime Cerda
INTEC (UNL-CONICET)
Sante Fe, Argentina
A discrete-event simulation technique, combined with op-timization tools, permits easy management of real-world pipelines operations with low computational effort.
Modeling to develop the technique used a non-traditional multi-server queuing system with a number of synchronized servers at every pipe-end and priority rules to decide which server should dispatch the entity waiting for service to the associ-ated depot. Each priority rule can lead to a different delivery schedule, evaluated using several criteria.
Part 1 of this series discusses a novel discrete event simulation system developed on “Arena” for the detailed scheduling of a multiproduct pipeline consisting of a sequence of pipes connecting a sin-gle input station to several receiving terminals. Part 2 will conclude this discussion and apply its findings to manage-ment of a real-world multiproducts pipeline.
BackgroundRefined products pipelines transport a variety of oil deriva-tives end-to-end in successive batches. Multiproduct pipe-lines operate in either segregated or fungible mode. Segre-gated products are branded or blend-stock materials whose identity is maintained throughout transportation, and the same batch received for shipment is delivered at the destina-tion. Fungible batches consist of generic products that meet published specifications. Shippers will receive an equivalent product matching the same product specifications, but it may not be the original lot shipped at the specified input terminal.
Discrete-event simulation guides pipeline logistics
SPECIAL REPORT
M U L T I P R O D U C T O P E R A T I O N S — 1
Based on presentation to IEEE’s 2010 Winter Simulation Confer-
ence, Baltimore, Dec. 5-8, 2010.
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Oil & Gas Journal | Aug. 1, 2011 99
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Neves et al. presented a decomposition approach for the planning of pipeline operations over a monthly horizon.5 The decomposition relied on a heuristic preprocessing block that accounts for demand requirements, production plan-ning, and typical lot sizes to determine a candidate set of product sequences. The heuristic block also provides time windows for pump and delivery operations at every termi-nal. A continuous MILP formulation later uses the prepro-cessed information to determine exact start-finish times of batch input and reception.
The model includes binary variables to account for sea-sonal energy costs and avoid pumping operations during high-cost periods. Boschetto et al. reformulated Neves’s hy-brid approach with a different decomposition strategy in-volving three blocks:6
• Resource-allocation block determining candidate se-quences of batch injections.
• Preanalysis block specifying precise volumes to be ei-ther pumped from source nodes or received in destination nodes and providing the earliest start-finish times for strip-ping operations at every destination node.
• Continuous-time MILP model determining the exact timing of pump and delivery operations at each node.
Most of the computational burden in multiproduct pipe-line scheduling comes from three tasks:
1. Pump sequencing.2. Batch sizing.3. Batch allocation to receiving terminals.Heuristically choosing them allows the remaining opera-
tional decisions to be taken in a short CPU time. The previ-ously made heuristic-based decisions, however, greatly in-fluence the final pipeline schedule.6
MILP-continuous optimization tools for pipeline sched-uling, by contrast, do not require any decomposition and can find the optimal input schedule from a single refinery
by minimizing the sum of pumping, interface, and inven-tory costs.12-13 Cafaro and Cerda also developed a continuous formulation for managing pipeline networks with multiple inlet points.14
Even these tools, however, just provide the set of ag-gregate batch stripping operations to be done during every pumping run without specifying the detailed sequence of in-dividual cuts performed by the pipeline operator. The many ways to distribute input batches among the assigned desti-nations requires generating an efficient delivery schedule to accomplish optimal pipeline operation.
SimulationMori et al. developed a simulation model for the scheduling of injection and stripping operations in a real-world pipeline network.2 The network consists of a series of single pipes that connect multiple refineries, harbors, and distribution centers, and transport many oil derivatives. Garcia-Sanchez et al. presented a hybrid methodology combining “tabu search” and a discrete-event simulation model for address-ing a real-world multiproduct pipeline scheduling problem.3 The tabu-search technique improved unsatisfactory sched-ules easily tested by the simulation model. Product batches divided into equally sized discrete units moved to a destina-tion predefined when they were injected into the pipeline network.
This article introduces a discrete event simulation model for a trunk pipeline transporting refined products from a single origin to multiple distribution terminals in segregated or fungible mode. The trunk consists of a sequence of pipes, each connecting either an input to an output terminal or a pair of distribution terminals to each other.
Discrete simulation regards the pipeline as a coordinated nontraditional multiserver queuing system. The servers per-form their tasks in a synchronized manner, with each one
FIG. 1TYPICAL MULTIPRODUCT PIPELINE OPERATION
B1(P4)
B2(P3)
B3(P1)
B4(P2)
B5(P4)new
D1
0
0
0
100
0
D2
0
0
100
0
0
D3
0
100
0
0
0
D4
50
0
0
0
0
D5
50
0
0
0
0
Re�nery
Input station
Distribution centers
Start End
0.00 8.00
D1 D2 D3 D4 D5
10
0
10
0
10
0
50
50
P1 P2 P3 P4
400B5400 B4300 B3300 B2250 B1250
B4400 B3400 B2350 B1350
110801ogj_99 99 7/27/11 10:19 AM
TRANSPORTATION
100 Oil & Gas Journal | Aug. 1, 2011
could be done in two or more non-consecutive steps, requir-ing further work before fully developing the pipeline deliv-ery schedule.
Since a pumping run is divided into a sequence of events, and batches flowing through the line are discrete entities, the matrix Q
ko(i,j) can easily derive the possible destinations
for each entity and occurrence of each event. When a new input event occurs, therefore, each pipe server knows if the first entity on its queue is eligible for being transferred to the associated terminal. The entity should otherwise move to the next pipe.
If two or more servers can dispatch the leading entry to their output terminals to meet unsatisfied demand, the sim-ulation model should decide, based on priority rules, which one is chosen. Simulating the pipeline schedule provided by the optimization package requires delivering the specified stripping volumes for every run, k, and satisfying terminal demands, q
ko(i,j).
The simulation model should update unsatisfied de-mands, q
k(i,j), at every terminal—initially equal to q
ko(i,j)—
for each time event. If qk(i,j) drops to zero, such a termi-
nal, j, can no longer receive an entity from batch i. Reaching null for all unsatisfied demands q
k(i,j), generates the output
schedule for run k. Previous work assumed the destination for each entity
was already given by the optimization package.2-3 This ar-ticle’s approach provides some capabilities to the proposed simulation model for selecting the route to be followed by every entity based on three key elements:
• The assignment matrix, Qk
o(i,j), for every run, k.• The batch to which each entity belongs.• A set of priority rules selecting both the leaving entity
and the receiving terminal (if several cut operations are eli-gible for execution).
Changing the priority rules can generate different pipe-line output schedules. The simulation model can also con-sider operational details like loading and unloading indi-vidual tanks at input and distribution terminals, instead of handling them in aggregate. These abilities allow the simu-lation model both to track the evolution of inventory in ev-ery individual tank over time and address pipeline stoppages due to high-cost peak periods.
Problem statementEffectively stating the problem to be overcome in product scheduling requires defining:
• A multiproduct pipeline connecting an oil refinery to several distribution terminals.
• Number, type of products to be transported through the pipeline.
• Set of product batches to be pumped (input schedule).• Associated set of stripping volumes to be transferred
during each batch injection (terminal-batch assignment ma-trix, Q
ko(i,j)).
having its own queue of fixed-sized batch elements (enti-ties). There is a server at the end of each pipe and its queue consists of the sequence of batch elements in that pipe. The length of any server queue remains fixed throughout the time horizon since every pipe should be permanently full of liquid and has a constant volume.
Solving a rigorous optimization model provides the sim-ulator injection schedule. The simulation model considers multiple scenarios and heuristic rules to evaluate scheduling efficiency and generate alternative detailed output schedules
ExampleFig. 1 represents a typical multiproduct pipeline transport system. It consists of a single refinery where oil products are injected and five distribution terminals at different sites along the pipeline.
The first line in Fig. 1 depicts the location of every batch inside the pipeline (linefill) at the start of the time horizon, four batches (B4(P2)-B3(P1)-B2(P3)-B1(P4)) with 400, 400, 350, and 350 volumetric units of product, respectively. The next line in Fig. 1 shows the pipeline contents after complet-ing the first injection. It consists of 400 units of product P4, pumped from 0.00 hr to 8.00 hr (represented by a right ar-row) into the new batch B5(P4)
new. A series of up arrows also
shows associated product deliveries to every terminal. Due to liquid incompressibility, the volume of product
injected in the pipeline origin equals the sum of product deliveries to receiving depots, i.e., 400 = 100 + 100 + 100 + 50 + 50. The optimization model proposed by Cafaro and Cerda not only generates an efficient input schedule but also provides the set of stripping volumes to be transferred dur-ing every batch injection.12-13
Hierarchical solution Solving the scheduling problem hierarchically requires two stages, the first one generating the input schedule through the optimization module and the second developing a de-tailed delivery schedule based on the information provided by optimization. An efficient discrete event simulation sys-tem developed on Arena both validates the pipeline sched-ule provided by the optimization module and generates the detailed output schedule.15 The model allows visualizing pipeline operations through an animation interface showing pipeline system dynamics over time.
The simulator uses the set of batches to be stripped and the related number of entities to be delivered to the distri-bution terminals while performing a pumping run as in-put data, the so-called terminal-batch assignment matrix (Q
ko(i,j)) whose element q
ko(i,j) represents the product de-
mand at terminal j covered by batch i during pumping run k. The terminal-batch assignment matrix Q
k appears at the
right side of Fig. 1.The simulator, however, must determine the detailed or-
der of execution of stripping operations. Some operations
110801ogj_100 100 7/27/11 10:19 AM
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TRANSPORTATION
102 Oil & Gas Journal | Aug. 1, 2011
Major assumptionsDeveloping a pragmatic representation of the real-world problem requires next considering assumptions in the dis-crete-event simulation model:
• A unidirectional pipeline connecting a single refinery to multiple distribution terminals is considered. The model, however, can be extended to manage network topologies.
• The pipeline is always full of liquid products and op-erates either in segregated or fungible mode. In the latter mode, a single batch can have many destinations.
• Batches of products are injected into the pipe one after the other, with no physical barrier between them.
• Interface, contamination loss between a particular pair of refined products is a known constant.
• Liquid incompressibility requires every time an el-ement of a batch is injected that one and only one entity already in the line be simultaneously transferred from the pipeline to a single receiving terminal.
• Every batch portion is pumped at a fixed flow rate.• Distribution centers are tank farms with dedicated
storage units of known capacity for each product.• One terminal tank, at most, is connected to the pipe-
line at any time event and the setup time for switching from one tank to another is negligible.
• Refinery production schedules are developed in adva-ce. Scheduled start-end times and rates of incoming product
• Scheduled production runs to be loaded into the tanks of the input station.
• Initial pipeline conditions (sequence of batches inside the line at t = 0 and their sizes).
• Initial inventory level of every product in terminal tanks.
• Hourly product demand profile at the distribution cen-ters.
• Constant product pumping rate.• Time-horizon length.Generating the detailed delivery schedule requires ex-
plicitly defining:• Sequence of batch portions to be pumped into the
pipeline.• Size of every portion and starting-end times of related
injections.• Amount, type of product delivered to a storage tank
from a batch arriving at an output terminal for each injec-tion.
• Time at which a batch portion has been completely loaded in the terminal tank.
• Product inventory management at the delivery termi-nals based on hourly discharged product lots and client de-mands.
FIG. 2DISCRETE-EVENT SIMULATION MODEL COMPONENTS
Input schedule
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��'�������
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Market demands
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+ � ��
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$� �
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110801ogj_102 102 7/27/11 10:19 AM
Oil & Gas Journal | Aug. 1, 2011 103
TRANSPORTATION
quires expressing their volumes as a number of small, equal-size batch elements called entities. Entity attributes come from the batch to which it belongs. Linefill similarly consists of a sequence of entities defining the queue of the pipe serv-er. Each event represents the pumping of a single entity into the line. The state of the pipeline system, therefore, changes only when an event is accomplished.
Each time an elementary pumping operation occurs at the input station (i.e., at the inlet of the first pipe) a new enti-ty enters the first-server queue, and another entity at the exit of one of the pipes should be dispatched to the correspond-ing receiving terminal. The set of servers should jointly de-cide which one will dispatch the first entity on its queue to the associated distribution terminal (dispatching server). The servers will also determine which servers should trans-fer the entity in transit to the next pipe (servers upstream of the dispatching server) and which will remain idle because there are no new arrivals (servers downstream of the dis-patching server).
A pipe server, in other words, can take three different ac-tions whenever an event is accomplished:
• Remain idle, because there is no product arrival to its queue.
• Transfer the first entity waiting for service to the next pipe.
• Deliver the first entity on the queue to its receiving ter-minal.
A new entity arrival to the server queue triggers the sec-ond two actions, so only a single distribution terminal will be active on every pumping event.
Entity volume (a user choice) and the pumping rate for the current injection determine the service time of an enti-ty. After the servers perform their jobs, the simulation clock advances to the next event time. Delays can arise if the se-lected distribution terminal lacks sufficient storage capacity to receive the departure entity, leading to disrupted pipeline operations.
Simulation blocksThe model structure involves three blocks, each represent-ing a main component of the pipeline system: the input sta-tion, the receiving terminals, and the pipes. Fig. 2 shows the model blocks together with key simulation elements, such as entities (batch elements), and resources.
References1. Sasikumar, M., Prakash, P.R., Patil, S.M., and Ramani,
S., “Pipes: A heuristic search model for pipeline schedule generation,” Knowledge-Based Systems, Vol. 10, pp. 169-75, 1997.
2. Mori, F.M., Luders, R., Arruda, L.V.R., Yamamoto, L., Bonacin, M.V., Polli, H.L., Aires, M.C., and Bernardo, L.F.J., “Simulating the operational scheduling of a real-world pipe-line network,” Computer Aided Chemical Engineering, Vol.
flows to storage tanks at the input station are problem data.• Daily client demands are expressed as deterministic
data on an hourly basis.
Objective functionThe sequence in which product deliveries to distribution terminals are accomplished greatly affects operational costs. Pipeline stoppages are particularly expensive and should be avoided.4 A pipe stoppage occurs whenever a delivery at a terminal is interrupted forcing a different stripping opera-tion to start at an upstream point. Stoppages cause inter-ruption of the flow in the pipeline segment connecting the activated and the deactivated output nodes, and consequent shutdown of several pump stations.
The main cost of stoppage comes from the lost energy of fluid momentum, since the stopped flow itself will move again to resupply downstream destinations. Maintenance costs also increase with the number of stoppages, with the time between pump repairs strongly dependent on the num-ber of shutdowns.
Measuring the quality of the resulting output schedule requires defining the so-called accumulated idle volume. Adding the product volumes in idle pipes across the com-plete horizon computes this variable. The accumulated idle volume together with the total number of cut operations re-quired to meet the specified terminal demands are the two performance measures used to compare alternative pipeline output schedules.
Model structureA refined products pipeline network consists of an input station, a set of receiving terminals, and pipes connecting the tank storage facilities. Oil products arriving at the input station from neighboring refineries remain in tanks tempo-rarily until injection runs transfer material from the input station tanks to the pipeline system. Specifying the type of product injected, the batch size, and the expected pumping rate also takes place at this point, each injection run creat-ing a new batch to be pumped into the line from the input station.
Injection run sequence determines input schedule. In-troducing a new product batch forces preceding batches forward, and another product batch already in transit is si-multaneously transferred from the pipeline to a receiving terminal.
A list of time events, each one representing the injection time of a single element into the system, provides the basis for simulation of pipeline operations. The simulation model scheduler block generates the event list, accounting for the input schedule. The optimization approach permits generat-ing the input schedule for the following month, showing the sequence of batches to be injected and the batch attributes (product, volume, pump rate, and start pumping time).12-13
Handling product batches in a discretized manner re-
110801ogj_103 103 7/27/11 10:19 AM
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104 Oil & Gas Journal | Aug. 1, 2011
trial & Engineering Chemistry Research, Vol. 48, pp. 6,675-89, 2009.
15. Kelton, W.D., Sadowski, R.P., and Sturrock, D.T., Simulation with ARENA, Fourth Ed., New York: McGraw-Hill, 2007.
24, pp. 691-96, 2007.3. Garcia-Sanchez, A., Arreche, L.M., and Ortega-Mier,
M., “Combining simulation and tabu search for oil-deriva-tives pipeline scheduling,” Studies in Computational Intel-ligence, Vol. 128, pp. 301-25, 2008.
4. Hane, C.A., and Ratliff, H.D., “Sequencing inputs to multi-commodity pipelines,” Annals of Operations Re-search, Vol. 57, pp. 73-101, 1995.
5. Neves Jr., F., Magatao, L., Stebel, S.L., Boschetto, S.N., Felizari, L.C., Czaikowski, D.I., Rocha, R., and Ribas, P.C., “An Efficient Approach to the Operational Scheduling of a Real-World Pipeline Network,” Computer Aided Chemical Engineering, Vol. 24, pp. 697-702, 2007.
6. Boschetto, S.N., Felizari, L.C., Yamamoto, L., Magatao, L., Stebel, S.L., Neves Jr., F., Arruda, L.V.R., Luders, R., Ri-bas, P.C., and Bernardo, L.F.J., “An Integrated Framework for Operational Scheduling of a Real-World Pipeline Network,” Computer Aided Chemical Engineering, Vol. 25, pp. 259-64, 2008.
7. Moura, A.V., de Souza, C.C., Cire, A.A., and Lopez, T.M., “Planning and Scheduling the Operation of a Very Large Oil Pipeline Network,” Principles and Practice of Con-straint Programming, Lecture Notes in Computer Science, Vol. 5202, pp. 36-51. DOI: 10.1007/978-3-540-85958-1, 2008.
8. Magatao, L., Arruda, L.V.R., and Neves Jr., F., “Mixed integer programming approach for scheduling commodities in a pipeline,” Computers & Chemical Engineering, Vol. 28, pp. 171-85, 2004.
9. Zyngier, D., and Kelly, J.D., “Multi-product inventory logistics modeling in the process industries,” in Chaovalit-wongse, W., Furman, K.C., and Pardalos, P.M. (Eds.), Opti-mization and logistics challenges in the enterprise. Spring-er optimization and its applications, pp. 61-95, New York: Springer, 2009.
10 Rejowski, R., and Pinto, J.M., “A novel continuous time representation for the scheduling of pipeline systems with pumping yield rate constraints,” Computers and Chem-ical Engineering, Vol. 32, pp. 1,042-66, 2008.
11. Herran, A., de la Cruz, J.M., and de Andres, B., 2010, “A mathematical model for planning transportation of mul-tiple petroleum products in a multi-pipeline system,” Com-puters and Chemical Engineering, Vol. 34, pp. 401-13, 2010.
12. Cafaro, D.C., and Cerda, J., “Optimal scheduling of mulitiproduc pipeline system using a non-discrete MILP for-mulation,” Computers and Chemical Engineering, Vol. 28, pp. 2,053-68, 2004.
13. Cafaro, D.C., and Cerda, J., “Dynamic scheduling of multiproduct pipelines with multiple delivery due dates,” Computers and Chemical Engineering, Vol. 32, pp. 728-53, 2008.
14. Cafaro, D.C., and Cerda, J., “Optimal Scheduling of Refined Products Pipelines with Multiple Sources,” Indus-
The authorsVanina G. Cafaro ([email protected]) is a PhD student in the Center for Advanced Process Systems Engineering (CAPSE) at the INTEC research institute, Santa Fe, Argentina. She earned her BS in industrial engineering from UNL in Argentina. Her research interests include production planning and scheduling of pipe-lines networks, optimization, and discrete-event simulation.
Diego C. Cafaro ([email protected]) is a professor of industrial engineering at Universi-dad Nacional del Litoral (UNL), Santa Fe, Argen-tina, and assistant researcher at the Argentine National Scientific and Technical Research Council (CONICET). He received his PhD (2008) in chemical technology from UNL and his BS (2003) in industrial engineering from Univer-
sidad Nacional del Litoral. He has done extensive research in oil pipeline planning and scheduling and teaches courses on modeling and optimization in process system engineering.
Carlos A. Mendez ([email protected]) is professor of industrial engineering at UNL and associate researcher at CONICET in process systems engineering. He earned his BS in information systems engineering from Univer-sidad Tecnológica Nacional (UTN), Santa Fe, Argentina, and his PhD in industrial engineering from UNL.
Jaime Cerda ([email protected]) is a professor of chemical and industrial engineering at UNL and superior researcher at CONICET. He received his PhD (1980) in chemical engineer-ing from Carnegie-Mellon University, Pittsburgh, his MS (1979) in chemical engineering from Carnegie-Mellon, and his BS (1968) in chemical engineering from UNL in 1968. He is a former
industrial engineering department head of the school of chemi-cal engineering at UNL. His research contributions have been in planning and scheduling batch and continuous processes, energy integration, process synthesis, supply chain operational management, oil pipeline planning, and scheduling, dynamic vehicle routing, and pickup-delivery problems.
110801ogj_104 104 7/27/11 10:19 AM
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110801ogj_105 105 7/27/11 10:19 AM
TRANSPORTATION
106 Oil & Gas Journal | Aug. 1, 2011
liquid flowing through a pipeline. The sampler consists of several parts including a programmer to enable a represen-
tative sample to be obtained. The sam-pling result plays an important role in financial calculations. The most typi-cal samplers in the oil industry are in-line, fast loop, and jet mix, listed in or-der of measurement certainty.
Iran’s Khark crude terminal in-stalled its current sampler system in 1993 on the downstream header of an oil metering station, with piping ele-ments as the mixing system. This arti-cle describes a proving test conducted on the sampler system by injecting a known amount of water over a finite period of time into a measured volume of crude oil during tanker loading.
The article compares top (C1) and bottom (C2) water concentrations with API/ISO Standard limits. The mixing ratio on the loading rate of more than 6,000 cu m/hr is near 0.9, with heavy crude showing better results than light crude at this rate.
The C1/C2 curves and proving test results show that at a fluid veloc-ity at the sampling point of more than
Mohammad Zahedi
Azad University of Research & Science
Tehran
Kourosh Tahmasbi Nowtarki
Pars Drill Fluid Co.
Tehran
Research at Iran’s Khark crude termi-nal shows the water-injection proving test to be the best evaluation method for determining the accuracy of crude and condensate sampling systems and suggests its inclusion in site-accep-tance testing.
An autosampler extracts a representative sample from the
Water-injection testing improves terminal operationsMIXER COMPARISON
Jet mix Static mix Power mix
Installation
Maintenance
Pressure loss
Hot tap
External
Immeasurable
Cut, �ange
Minimal, nonremovable
n/a
Cut, �ange “T”
Dif�cult; depressurize, draw
Low
FIG. 1
EQUATIONSGross volume = (Raw pulse/K.F)* M.F (1)K.F = Pulse/unit volume (2)GSV = Gross vol* CTL *CPL (3)NSV = GSV – (BS&W vol) (4)Where:CTL = temperature compensation, CPL = pressure compensation, BS&W = bottom sediments and water content by % volume, GSV = gross standard volume, and NSV = net standard volume.
C1/C2 = exp (–W/ε/D) (5)
W = 855(ρd – ρ) E–0.8/νρ2.2 (6)
∆p = kpν2/2 (7)
ε/D = 6.313 × 10–3 V0.875 D–0.125 ν0.125 (8)
E = KV3/2∆X or E = ∆PV/∆Xρ (9)
DEV = (Wtest
– Wbl)*W
inj (10)
Where:DEV = deviation, vol %W
test = water in test sample, vol %
Winj
= water injected into barrels during test, vol %W
avg = average measured baseline water, vol %
Wavg
= (Wbl
1 + Wbl
2)/2 (11)
Wbl = W
avg. * (TOV–V)/TOV (12)
Where:TOV = total observed volume (test oil, injected water) passing the sampler, bblV = volume of injected water, bbl
Winj
= (V/TOV) * 100 (13)
110801ogj_106 106 7/27/11 10:19 AM
Oil & Gas Journal | Aug. 1, 2011 107
TRANSPORTATION
2 m/sec (achieved during most cargo loadings), the sampler’s performance is acceptable 90% of the time. At the start and end of each loading and at low loading rates, however, the mix-ing ratio for the piping element is not enough, and poor sampling occurs.
To improve homogeneity and solve poor sampling, the article recom-mends installing a suitable static or dynamic mixer before the in-line sam-pler where the worst conditions exist. Modifications are also recommended based on API/ISO Standards.
Khark systemAutosampling takes a portion of crude oil from the pipe during transfer to ei-ther the refinery or tankers and uses it for analysis to determine if it meets quality parameters set by the customer. A representative sample comes from a pro-portional flow in a homogenous area of the stream. Proper sampling is extremely important to indicate both quantity and quality of crude being transferred and permit accurate collection of revenues on that basis.
Laboratory results directly affect fiscal calculations be-cause the API gravity applied to the mathematical formula is subject to correction factors to compensate for tempera-ture and pressure. Bottom sediments and water content are deducted from gross standard volume and net standard vol-ume.
The Khark terminal sampling system contains a horizon-tal probe, motor driver, sample divider and controller, pulse combinatory for flow proportional sampling (time propor-tional for backup), and a 0.375-in. diameter flexible hose
with an 18-l. standard receiver can. The sampling systems contain the piping elements as natural mixers installed be-fore stream conditioning and the automatic samplers.
Comparisons occurred between shore-tank sampling and the Cojetix autosampler at Assaluyeh terminal and at Neka terminal between ship-tank sampling and Cojetix.
Autosamplers should be checked periodically to both en-sure customer satisfaction and maximize producer revenue. This project injected metered seawater at the Khark terminal autosamplers during tanker loading in low flow conditions for both light and heavy crude and then evaluated perfor-mance and deviation from standard conditions. The project also performed short-term grab performance tests and cal-culated the C1/C2 mixing ratio for heavy and light crude oil for all samplers.
MIXER PIPING ELEMENT BEFORE SAMPLER
Reduced asrequired
Flow straightener,tube bundle
Proving connection
Strainer
Meter run
Prover valve
10 pipe diameters
or 20-25
pipe diameters
5
pipe
diameters
Low
Block valveTurbine meter
Flow controlvalve
Doubleblock-bleed
valve
Upstreamstraightening
section
Upstreamstraightening
section
FIG. 2
IN-LINE AUTOSAMPLER WITH JET MIXING
Sample probe
Jet mixFlow
Can
cabinet
Can weigh
Power pump
FIG. 3
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108 Oil & Gas Journal | Aug. 1, 2011
Competition in marketing and trading crude oil is very high, placing a premium on quality control. Proper sampling also plays a great role in fi-nal price of oil sold. Reducing sam-ple error requires increasing both the sample volume and homogeneity and maintaining the proper relationship between all sampling system elements. Sampling error cannot be eliminated, but it can be reduced by improving sampling techniques.
Sampling determines such physi-cal parameters of a crude oil as spe-cific gravity, vapor pressure, sediment and water content, sulfur, salt content, H
2S, and viscosity. The typical pur-
poses of sampling include customer satisfaction regarding composition, water content, and contaminant con-tent, the completing and fiscal reports, and resolution of commercial or insur-ance claims.
Automatic sampling at Khark nor-mally gathers 10-15 l. Some of the sample is subject to laboratory analy-sis. A 1-1. sealed sample is delivered to the captain. Another 1-1. sample is sealed and placed in cold, dark stor-age for at least 3 months. The main fac-tors affecting the quality of sampling include the sampling location, hard-ware, and handling and analysis of the sample.
Manual sampling is an alternative but is problematic in its own ways. The quantity of free water in storage tanks
must be determined. Extra care is required in handling, mixing, and storing the samples. The uniformity of sample fill rates and volumes must be maintained by the operator. Errors in determining the level and sampling point in the stream must also be avoided. And a relatively large amount of time elapses en route between the sampling point and the laboratory.
Proper extraction and representative sampling requires an autosampling system to ensure:
• Proper positioning of the autosampler with regards to the custody transfer point.
• Line-content homogeneity.• Flow-proportional sampling. • Proper sample handling and laboratory mixing. • Accurate laboratory analysis.• Occasional performance testing.In all conditions stream profiling should be 1.1>C1/C2
ResearchKhark terminal is on the Persian Gulf and is one of the big-gest loading terminals in the world. National Iranian Oil Co. exports much of its crude through Khark.
Equations 1-4 show the standard API formulas related to crude sampling.
IN-LINE SAMPLER WITH STATIC MIXER
Sample controller
Samplereceiver
Sample probe
Steel, rubber hose, 0.375-in.
Solenoid valves
Static mixer
FIG. 4
KHARK AUTOSAMPLER SCHEMATIC
Flow
line
Sample probe
Motor drive Sample controllerFlow signal
Flexible hose, 0.375-in.
Sample receiver
FIG. 5
JET VS. STATIC MIXERS Table 1
Comparison criteria Jet mix system Static mixer
Mixing ability Meets ISO 3171, API 8.2 n/aMixing, turndown ratio In� nite 5:1 maximumWater droplet size 0.1-0.3 μm 100-2,000 μmWater dropout rate 1.8 × 10–3 m/sec n/aVelocity dependency Independent DependentPressure drop Negligible 0.1-0.5 bar at 5:1 turndownCapital cost High LowerInstallation cost Low HighInstallation In-service possible Requires drainingHigh � ow rate shutdown Can be shut down Not possible
110801ogj_108 108 7/27/11 10:19 AM
Oil & Gas Journal | Aug. 1, 2011 109
TRANSPORTATION
Static mixers use vanes to create additional flow turbu-lence. The flow passing through the vanes creates pressure drop across the mixer.
Fig. 4 shows the static mixer in an in-line sampling sys-tem.
The most prevalent auto-samplers in the crude industry are:
• Jet mix autosampler (Cojetix).• Fast loop sampler.• Shipboard sampler.• In-line sampler (as used at Khark terminal).Cojetix uses the standard dynamic mixing method but
pulls from the center of the flow to create a mixing area, homogeny, and a mixed phase between water and crude. To minimize cross contamination the sloped steel tube between the sampler and the receiver is short. At the end of sampling dead volume is negligible.
The fast loop autosampler creates suction and discharge via pump at the same point on the annulus, making one tapped connection on the pipeline enough. Systems some-times use a combination of Cojetix and fast loop sampling.
Portable shipboard autosamplers are used during ship-to-ship operation. Individual samplers should be installed for each manifold. Proper sampling requires adjusting the load-ing rate of each manifold to near equal. With proportional sampling the variation of flow rate should be less than ±10%.
>0.9. The sampling system should be designed such that these parameters are met even in worst-case conditions.
Conditions for representative sampling include:• Taking the sample from the middle of the flow line.• Homogeny and good mixing.• Flow-proportional sampling. • Low alteration of physical properties of fluid in sample
such as pressure, viscosity, and density. • Sample volume of 10-15 l. and grabs of 1-1.5 cc.Table 1 explains the influence of sampling and mixing
systems on loading rate and of fluid velocity and piping ori-entation on sampling point.
Sampling systemDifferences in density between crude oil and water, partic-ularly at low velocities, cause water flow movement in the bottom of the pipeline to take a stratified shape. At low flow rates homogeneity is weak. Preventing phase separation and improving the mixing ratio and homogeneity in sample points required installing an additional mixer.
Figs. 1-2 show the mixing system and piping elements. Dynamic (jet) mixers run a branching pipe from the bot-
tom of the line, pressurize the liquids extracted, and re-in-ject them upstream against the general flow.
Fig. 3 shows typical positioning of a jet mixer.
KHARK C1/C2, IRANIAN LIGHT VS. HEAVY CRUDES
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0.0
C1
/C2
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0.0
C1
/C2
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0.0
C1
/C2
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0.0
C1
/C2
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000
Flow rate, cu m/hr Flow rate, cu m/hr
Flow rate, cu m/hr
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000
0 2,000 4,000 6,000 8,000 10,000
Flow rate, cu m/hr
0 2,000 4,000 6,000 8,000 10,000
Heavy crude, T. jetty autosampler, 12 cts, 29.8° Heavy crude, Azarpad autosampler, 12 cts, 29.8°
Light crude, T. jetty autosampler, 8 cts, 33.8° Light crude, Azarpad autosampler, 8 cts, 33.8°
FIG. 6
110801ogj_109 109 7/27/11 10:19 AM
TRANSPORTATION
110 Oil & Gas Journal | Aug. 1, 2011
tra mixer. Instead of adding another piping element Khark used a rim rotor-type turbine meter and pipe straightener.
The sampler proving test injected pressurized seawater into the Azarpad during light and heavy crude loading to tanker at minimum possible crude flow rates. The test ap-paratuses contain a water meter, a 1-in. quick action valve, elbow, check valve, fitting, and hose pipe.
The test procedure injected a set amount of water in a finite time before the sample position and performed labo-ratory analysis of water content at the sample receiver. Data from multiple test helped compute a standard deviation (Equations 10-13) and results were compared with the API standard table.
Tests lasted about 2.5 hr and were repeated two times. Water entered the system at rate of 67 gpm injected on top of a strainer about 20D before the sampling point. Table 3 shows data and test results. Allowable deviation for a single sampler is ±0.09 for total water content of 0.5%, One of the samplers was within these parameters on light crude but not on heavy crude.
A test of short-term performance factors used the ex-pected sample for a user configurable grab count vs. actual sample for that grab count. Table 4 shows the results of the
Khark terminal uses Cliff Mock Model C in-line auto-samplers with a 2-in. probe. The samplers are mounted horizontally in the center of the pipe-line downstream of the oil metering station. They use the isokinetic sam-pling system to take representative samples from crude oil during the tanker loading, transferring them to 18-l. receivers via a 0.375-in. diameter hose.
Khark’s in-line samplers use pip-ing elements as a mixing system. Fig. 5 shows a schematic of Khark terminal’s crude oil samplers. Fig. 2 shows the mixer piping element installed before the autosamplers.
TestingResearch calculated and drew the graphs for C1/C2 ratio vs. flow rate for the entire autosampling system at Khark. The C1/C2 ratio measures the concentration of water at the top of the pipeline vs. against that found at the bottom (Table 2).
Equations 5-9 (API standard formulas) generate Fig. 6, showing flow rates of both heavy and light crudes and the C1/C2 ratio.
Khark’s autosampler functions better for heavy crude than for light. When the flow rate is more than 6,000 cu m/hr, C1/C2 remains within tolerance. T jetty autosamplers exposed to the same flow rate as samplers at Azarpad yield a better C1/C2 because of differences in the meter-run size of the piping element mixer.
For the same flow rate the C1/C2 ratio decreases from heavy to light crude oil, mixing energy and dissipation being greater for light crude. Treating this problem in low flow rate sampling required modifying the system by installing an ex-
KHARK TERMINAL SAMPLER TEST RESULTS Table 3
––––––––––––––––––– Sampler location ––––––––––––––––––––Parameter Azarpad H#03 Azarpad H#04
Vessel name NABI NABITime, date 18:30-21:00, Mar. 16, 2009 19:30-22:00, Mar. 17, 2009Flow rate, bbl/hr 23,000 23,000Pipeline OD, in. 48 48Oil � owmeter type, size Turbine, 20-in.Water injection point, size Strainer top, 2-in.Water meter type, size Barton turbine meter, 1-in.Product type Light crude Heavy crudeAPI gravity 33.8° 29.6°Mixing type Piping element Piping elementSeawater injected, bbl 186.2 178.2Water injection rate, gpm 67 67Meter factor of water meter 0.9951 0.9951Sampler point � uid velocity 0.87 0.87Water injection � uid velocity, m/sec 9.3 9.3Water baseline 1, vol % 0.1 0.15Water baseline 2, vol % 0.1 0.2Water test content avg., vol % 0.1 0.175Total volume, oil + water, bbl 46,352 42,480Water injected during test, vol % 0.402 0.419Water in sample, volume, vol % 0.45 0.45Water baseline, vol % 0.1 0.174Analysis method Distillation DistillationDeviation with standard –0.052 –0.143Final result Accepted Rejected
KHARK TERMINAL AUTOSAMPLER,SHORT-TERM GRAB TEST RESULTS
Table 4
Date: Mar. 17-18, 2009 ––– Grab size: 1.5 cc –––– Location Azarpad Azarpad Equations header 03 header 04 (see box)
Grab number 100 100 (1)Ideal grab volume, cc 150 150 (2) = (1)*1.5Actual grab volume, cc 120 117 (3)Grab performance factor 0.8 0.78 (4) = (3)/(2)Standard grab performance: 0.9-1.1
RECOVERY COMPARISON,SHORE TANK SAMPLING VS. COJETIX
Table 5
Cargoes 9Average API gravity 59.3°Crude type Gas condensateTotal cargo volume, bbl 3,131,914Shore tank sample results, bbl water 544Cojetix autosampler results, bbl water 706Water content variance, % 0.005API gravity difference 0.20°
C1/C2 VS. SAMPLINGCONDITION
Table 2
Param- Homogeneityeter Range condition
C1/C2 0.9-1.1 Good <0.7 Not predictable <0.4 Poor, strati¤ ed
110801ogj_110 110 7/27/11 10:19 AM
Oil & Gas Journal | Aug. 1, 2011 111
TRANSPORTATION
short-term grab performance test for Azarpad autosamplers, a few of which fall within an allowable limit of 0.9-1.1.
Table 5 compares shore tank sampling and the Cojetix autosampler. The results show higher uncertainty in the shore tank sampling.
ResultsComparing Khark’s in-line single autosamplers with mixing piping element test results with the latest version of standard C1/C2 curves shows acceptable homogeneity at loading rates >6,000 cu m/hr, but found that at low loading rates enough mixing was not occurring within sampling, requiring ad-dition of an extra mixing element. Figs. 3-4 show recom-mended modification systems. Equation 9 also shows mix-ing energy varying with flow rate, the increase in loading rates creating additional mixing energy.
Cargo loading rates at Khark exceed 6,000 cu m/hr more than 90% of the time, so it has acceptable performance in normal operations. To decrease cross contamination, the length of the 0.375-in. diameter hosepipe between the sam-ple extractor outlet and container should be minimized. The connection hose should have sufficient downward slope to-wards the receiver can to minimize collection error. A scale can help evaluating sampling performance.
The distance between the probes and custody transfer at Azarpad jetty complicates taking a representative sample. Two approaches may resolve the line fill issue: sample the line fill in a separate receiver or ignore the problem.
Existing dead sample volume on the Azarpad sampling system can compensate for ignored line fill samples. The in-line sampler with piping element works best using the near-est meter to run samples at the start and completion of load-ing, and any other generally low loading rate, decreasing the mixing ratio and homogeneity.
Using this sampling system for 100,000 b/d of crude transfer can save about $1.7-3.5 million/year, with $300,000/year realized when handling condensate. Maximizing these savings, however, requires periodic testing of the sampling system, with water injection being the best available testing mechanism. Maintaining the accuracy of sampling will also increase customer satisfaction.
Table 3’s results show one sampler operating at near 1 m/sec velocity accepted and the other rejected, confirming the unpredictability of mixing in slow flow rate conditions. Comparing Table 3 with Fig. 6 also shows the C1/C2 ratio as not adequate for checking the sampling system, making the water injection proving test mandatory.
The authorsMohammad Zahedi ([email protected]) is deputy operation manager of Assaluyeh terminal at Iranian Oil Terminals Co., Assaluyeh Port. He has also served as oil control and mea-surement supervisor, Khark terminal, IOTC. He earned and MS in petroleum engineering (2009) at Azad Science & Research University, Tehran.
Kourosh Tahmasbi Nowtarki ([email protected]) is director manager of Pars Drill Fluid Co., Tehran. He earned a PhD in chemical engi-neering (1997) from Imperial College, University of London, and is a member of the dual-degree program committee, at Petroleum University of Technology, Tehran (2003-Present).
Manuscripts welcome
Oil & Gas Journal welcomes for publication con-sideration manuscripts about exploration and devel-opment, drilling, production, pipelines, LNG, and processing (refining, petrochemicals, and gas pro-cessing). These may be highly technical in nature and appeal or they may be more analytical by way of examining oil and natural gas supply, demand, and markets. OGJ accepts exclusive articles as well as manuscripts adapted from oral and poster pre-sentations. An Author Guide is available at www.ogj.com, click “Submit an article.” Or, contact the Chief Technology Editor ([email protected]; 713/963-6230; or, fax 713/963-6282), Oil & Gas Journal, 1455 West Loop South, Suite 400, Houston TX 77027 USA.
110801ogj_111 111 7/27/11 10:19 AM
112 Oil & Gas Journal | Aug. 1, 2011
EQUIPMENT | SOFTWARE | LITERATURE
to offering 335° rotation can pivot down
25° for 8 ft of extra digging and access
to hard-to-reach areas.
For digging performance, it offers
water pressures as high as 18 gpm at
3,000 psi in combination with its 8-in.
positive displacement vacuum system
that provides airflow of 5,800 cfm/28 Hg
to help ensure cleanup of debris. An on
board boiler with 714,000 btu/hr capac-
ity heats up the high-pressure water to
break up frozen, stubborn material and
flush out tight spaces. Winter recircula-
tion, antifreeze, and air purge systems
help ensure that the unit performs
optimally in harsh climates. Its heated
aluminum cabinet offers easy access
and increased storage capacity.
Source: Super Products LLC, 17000 W. Cleve-
land Ave., New Berlin, WI 53151.
UPDATED ALARM,NOTIFICATION SOFTWARETopView software suite has been en-
hanced with the release of TopView 6.10
with alarm RSS capability.
This capability allows upstream and
downstream oil field users to subscribe
to one or more TopView alarm feeds from
a variety of desktop and mobile devices.
As with other RSS feeds, the TopView
alarm RSS feed can contain multiple
feed items (alarms), item headlines
(alarm message), item description (alarm
details), and links.
Users can view TopView alarms,
alarm details, and open customized links
per alarm event using a desktop, mobile,
or tablet RSS reader.
Source: Exele Information Systems Inc.,
445 W. Commercial St., East Rochester, NY
14445.
NEW LUBE, SEALANTS BROCHUREA new brochure describes how Molykote
brand specialty lubricants and Dow
Corning brand severe-duty sealants help
with oil field operations.
The brochure says its specialty
lubricants and severe-duty sealants are
designed to help solve problems that
occur during exploration and extraction,
transport, storage, and processing.
Molykote brand Smart Lubrication so-
lutions include severe-duty greases, an-
tiseize pastes, antifriction coatings, and
silicone oils and greases. The firm says
these advanced formulations can help
control friction and wear, reduce fretting
corrosion and galling, extend lubrication
intervals, and improve reliability.
Severe-duty silicone sealants, includ-
ing pastes, coatings, form-in place gas-
keting materials, and hot-melt assembly
adhesives, are suited for equipment
assembly, maintenance shop repairs,
and in-field service.
Source: Dow Corning Corp., Corporate Center,
Box 994, Midland, MI 48686-0994.
NEW VERSION OF WELLBORESOFTWARE PLATFORMNewly released Techlog 2011 software is
the latest version of this firm’s wellbore
software platform.
It enables customization at several
levels of granularity—from the corporate
perspective, within a project, and for the
petrophysicist, geoscientist, or engineer,
the company notes.
The new pore pressure prediction
module incorporates industry standard
methods to compute the pore pressure
and fracture gradients and establish the
safe mud weight window to ensure safe
drilling operations. The 2011 release
also sees the full implementation of
GeoFrame ELAN functionality in Techlog,
augmenting the existing mineral solver
capabilities with the proved algorithms
from this application.
The 2011 release delivers a com-
plete modernization of the application
interface. The new ribbon interface
combines intuitive icons with complete
customization capability—to bring clarity
and knowledge sharing directly into the
application. The convenient dashboard
mode supports automatic window tiling
to maximize the work space and reduce
mouse movements. Furthermore, an
intelligent right-mouse-click in context
brings frequently used tools and actions
directly to the users’ fingertips.
The work flow interface enables users
to create comprehensive cross-domain
analysis work flows that are applicable
across single or multiple wells with equal
ease. Work flows can be saved and
shared as templates, edited, and re-
applied to new data facilitating consis-
tency, ease of use, and efficient sharing
of expertise across asset teams, the firm
points out.
Source: Schlumberger Ltd., 5599 San Felipe,
Suite 100, Houston, TX 77056.
NEW ULTRASONICLIQUID LEVEL DETECTORSA new line of products detects and mi-
cromeasures ultrapure chemical fluids.
The SL 900 Series of ultrasonic liquid
level detectors has no moving parts that
can induce impurities in the liquid caus-
ing false readings, downtime for mainte-
nance, and a complete loss of product.
The additional feature of a thermocouple
sensor to monitor temperature avoids
the costs of welding a thermocouple
well in the ampoule, the company notes.
The product line is applicable to a range
of applications in the semiconductor
chemical vapor deposition process.
Features include no particle contami-
nation, as many as eight alarm points,
functioning independent of a liquid’s
density and viscosity, and measuring
accuracy.
Source: Cosense Inc., 155 Ricefield Lane,
Hauppauge, NY 11788.
NEW OIL FIELD HYDROEXCAVATORThe new Mud Dog 1600 promises to
meet demanding hydroexcavation chal-
lenges in oil field uses.
The unit features a 16 cu yd debris
body, standard 1,500 gal water capacity,
and rear-mounted boom that in addition
110801ogj_112 112 7/27/11 10:19 AM
Oil & Gas Journal | Aug. 1, 2011 113
SERVICES | SUPPLIERS
GE OIL & GAS,Florence, Italy, has
named Dan Heintzelman
CEO, succeeding Claudi
Santiago, who is retiring.
Heintzelman previously
served as CEO of GE
Energy Services.
GE Oil & Gas is a
world leader in advanced technology
equipment and services for all segments
of the oil and gas indus-
try, from drilling and pro-
duction, LNG, pipelines,
and storage to industrial
power generation, refin-
ing, and petrochemicals.
GE Oil & Gas also pro-
vides pipeline integrity
solutions. It is part of GE
Energy, which in turn is
part of GE, a diversified infrastructure,
finance, and media company.
SWIRE OILFIELD SERVICES, Aberdeen, has launched a new global
division, Swire Modular Systems, headed
by Arild Sivertsen. The company recently
announced a £50 million investment
in additional fleet units and formed the
new division to offer modular systems
worldwide. A new, six-person team led
by Reinhardt Schoeman, product line
manager, Modular Systems UK, has
been formed in Aberdeen to serve the
UK sector.
Swire Oilfield Services, part of the
Swire Group, is the world’s largest sup-
plier of specialist offshore cargo carrying
units to the global energy industry and is
a leading supplier of modular units (both
pressurized and nonpressurized), pump
and filtration equipment, helicopter fuel
systems, chemical handling services,
and frac water transfer.
AMEC PLC,London, has named Andy Sallis presi-
dent of AMEC Oil & Gas Americas. He is
responsible for Houston-based project
operations, including supervision of joint
ventures AMEC Black & McDonald in
Canada and Paragon Angola in West
Africa. Previously, Sallis served as senior
vice-president, business
capture and delivery, for
AMEC Paragon, the oil
and gas business unit of
AMEC Natural Resources
Americas. Sallis has been
with AMEC for 23 years,
responsible for multiple
project and corporate roles in the UK,
South Africa, Angola, China, and US. He
is a chartered engineer, a member of the
Institute of Civil Engineering, and a mem-
ber of the Project Management Institute.
Sallis has a BS in civil engineering from
the University of Manchester Institute of
Science and Technology.
AMEC provides consultancy, en-
gineering, and project management
services to its customers in the oil and
gas, minerals and metals, clean energy,
environment, and infrastructure markets.
JDR CABLES SYSTEMS LTD.,Edinburgh, has begun loadout at Hartle-
pool, England, of more than 200 km of
cables the firm is manufacturing for one
of the world’s largest offshore wind farm
projects and located in the Thames River
estuary. JDR recently commissioned its
new vertical laying up machine, which
significantly increases its capability to
manufacture longer-length, medium-
and high-voltage alternating current
export cable for the offshore wind energy
market.
JDR is a leading provider of custom-
designed and manufactured static and
dynamic subsea power cables and
umbilical systems for a broad range of
applications throughout the oil and gas
sector and offshore renewable energy
industry.
LEE C. MOORE (LCM),Tulsa, has appointed Melissa Herring
vice-president, production and procure-
ment. She has spent more than 30 years
in the onshore and offshore contract
drilling industry, with roles in procure-
ment, quality, and software implementa-
tions. Herring served in procurement
management roles and on the executive
teams for Atwood Oceanics Inc., Premier
Drilling Inc., and Parker Drilling Co. She
is a graduate of the Uni-
versity of Oklahoma.
LCM, a Woolslayer
company, provides drill-
ing rig structures and
components and servic-
es, including engineering
design and analysis, drill-
ing rig inspection and repairs, inspecting
training, feasibility studies, and project
planning.
POLAR STAR CONSULTANTS LLC,Houston, has appointed Stephanie D.
Garner marketing director. She has 10
years experience in various positions
in sales and marketing. Most recently
she served as the marketing commu-
nications specialist for Nalco’s oil field
chemicals division. Prior to that, she
worked at NACE International as a mar-
keting coordinator and later marketing
manager.
Polar Star is a group of marketing and
engineering professionals who provide
business strategy consultation, engineer-
ing and technical services, product and
services marketing, brand management,
and sales promotion for small and medi-
um-size oil field manufacturing, supply,
service, and production companies.
HARRIS CORP.,Melbourne, Fla., has named Tom Eaton
president of the company’s global
communications services business,
Harris CapRock Com-
munications. Eaton
most recently served as
Harris CapRock’s global
operations officer and
formerly led the govern-
ment division. Previously,
Eaton was president of
G2 Satellite Solutions, a
wholly owned subsidiary
of PanAmSat, where he also served as
executive vice-president of global sales
and marketing. Prior to that, Eaton led
Intelsat’s global sales and customer
support organization and also served as
cofounder and vice-president of sales
and marketing for Integrated Network
Services Inc. Andrew Lucas will fill Ea-
Heintzelman
Santiago
Sallis Herring
Eaton
110801ogj_rev_113 113 7/27/11 2:13 PM
114 Oil & Gas Journal | Aug. 1, 2011
SERVICES | SUPPLIERS
ton’s previous role overseeing the opera-
tion and deployment of the company’s
global network and service delivery
infrastructure.
Harris CapRock Communications is
a global provider of managed satellite
and terrestrial communications solutions
specifically for remote and harsh envi-
ronments, including the energy, govern-
ment, and maritime markets.
SCHLUMBERGER LTD.,Paris, has inaugurated the WesternGeco
Penang Product Centre (WPPC) at
Penang, Malaysia, dedicated to the
manufacture and support of state-of-the-
art marine and land seismic equipment.
WPPC will play a central role in the
continuing development and deployment
of WesternGeco’s Q-Technology and will
support the rollout of Q-Marine Solid
streamer technology and deliver UniQ
integrated point-receiver seismic acquisi-
tion systems. By the end of 2012, WPPC
will employ about 300 people.
Schlumberger is the world’s largest
supplier of technology, integrated project
management, and information solutions
to the oil and gas industry.
WESTERNGECO,London, has begun the Revolution II
multiclient survey as a follow-up to the
Revolution I survey in the western Gulf of
Mexico—the first dual coil shooting, mul-
tivessel, full-azimuth (FAZ) acquisition in
the industry—that was concluded in late
2010. The latest survey is in the highly
prospective Green Canyon area of the
central Gulf of Mexico, where long off-
sets and FAZ imaging solutions support
clients’ future production and appraisal
drilling plans. The Revolution II multicli-
ent survey will provide FAZ coverage on
more than 3,200 sq km, or 140 Outer
Continental Shelf blocks.
WesternGeco, part of Schlumberger,
provides a full range of geophysical ser-
vices to the oil and gas industry.
SUPERIOR ENERGY SERVICES,New Orleans, has named Kerric Peyton
vice-president, corporate health, safety,
and environmental (HSE). Based in
Houston, Peyton will
lead the execution of
all technical, functional,
auditing, compliance,
and training responsi-
bilities related to the HSE
function across the entire
organization. Previously
a drilling superintendent and manager
of worldwide HSE activities at a leading
offshore drilling contractor, he has more
than 12 years of industry experience. He
is also a veteran of the US Navy, where
he served 6 years in the nuclear power
program. Peyton has a BS in human
resource management from New School
University and has completed post-
graduate work in business administration
from Regis University.
Superior provides specialized oil field
services and equipment focusing on
production, intervention, workover, well
services, and rental tools worldwide.
RAIN FOR RENT,Bakersfield, Calif., has opened a new
location in Kenedy, Tex. From this new
location the company will provide water
transfer pumps, pipelines, and filtration
to exploration and production companies
in the Eagle Ford shale.
Rain for Rent provides solutions for
water-handling, irrigation, and temporary
liquid storage needs to oil and gas E&P,
refining, construction, municipal, and
environmental sectors. Those solutions
include steel and polyethylene tanks,
pumps, spill containment and filtration
equipment, aluminum and HDPE pipe,
and associated fittings.
HELMERICH & PAYNE INC.,Tulsa, has signed agreements to build
and operate 12 additional FlexRigs under
multi-year term contracts with eight E&P
companies. The rigs are scheduled to
be completed and start work during the
company’s fiscal 2012. The order brings
H&P’s newbuilds roster to 57 announced
since March 2010, a jump of 30% in
the company’s FlexRigs fleet. Including
the latest announcement, H&P has 26
FlexRigs under construction and expects
them to be completed at the rate of
about three per month.
H&P is primarily a contract driller with
business segments in the U.S. onshore,
offshore, and international sectors.
DEVIN INTERNATIONAL INC.,Lafayette, La., has promoted Craig Latch
to deepwater projects coordinator, Gulf
of Mexico. He will coordinate equipment
orders for customers’ projects from
Devin’s Lafayette office.
Latch previously served
as international projects
coordinator for the com-
pany. He has bachelor’s
and master’s degrees in
communications/market-
ing from the University
of Louisiana at Lafayette.
He is a member of Young Profession-
als in Energy and the Intervention and
Coiled Tubing Association.
A unit of Greene’s Energy Group LLC,
Devin is a leading provider of specialty
support equipment for coil tubing drill-
ing and snubbing operations and offers
equipment rental tools such as lift
frames, elevator bails, crossover subs,
and safety valves. Devin is also a primary
rental source for tools with premium
thread connections and offers patented
surface test trees and motion compensa-
tion equipment.
KVAERNER ASA,Oslo, has been launched as a new
company with its first listing on the Oslo
stock exchange on July 8. The original
Kvaerner merged with Aker ASA as Aker
Kvaerner in 2005, and the Kvaerner
name disappeared with the name
change to Aker Solutions. Kvaerner
reemerged in May 2011 when the engi-
neering, procurement, and construction
(EPC) part of Aker Solutions was spun
off as Kvaerner ASA. Jan Arve Haugan
has been appointed Kvaerner president
and CEO. Haugan started his profession-
al career in the Norwegian construction
company F. Selmer (now part of Skan-
ska), and in 1991 he joined the Norwe-
gian industrial group Norsk Hydro as
chief engineer with lead roles in many of
Hydro’s oil and gas projects and opera-
Peyton
Latch
110801ogj_114 114 7/27/11 10:19 AM
Oil & Gas Journal | Aug. 1, 2011 115
SERVICES | SUPPLIERS
tions. Following the demerger of Hydro’s
oil and gas operations, he joined the
company’s aluminum business as head
of technology and global smelter opera-
tions. In 2009, Haugan became CEO
of Qatar Aluminum Ltd., a joint venture
of Qatar Petroleum and Hydro Alumi-
num. Meanwhile, Eiliv Gjesdal has been
appointed Kverner CFO. Gjesdal joined
Aker Solutions in 2002 and has exten-
sive experience from finance functions in
Aker Solutions as well as a background
as a state-authorized public accountant.
Gjesdal started his career as an auditor
with Arthur Andersen & Co. working with
large Norwegian companies.
Kvaerner provides EPC services for
offshore platforms and onshore plants to
the global oil and gas industry.
Aker Solutions is a leading global
oil services company that provides
engineering and construction services,
technologies, products, and field-life
solutions for the oil and gas industry.
CORTLAND CO.,Cortland, NY, has named Oystein Larsen
general manager of its Bergen, Norway,
Selantic engineering and design center.
Larsen began his career
with the Norwegian
Navy before becom-
ing a research scientist
with Christian Michelsen
Research. Prior to joining
Cortland, Larsen was
president and CEO of
GexCon Corp., Bergen,
since 2006.
He has MBAs in process safety tech-
nology and strategic management.
In addition, Cortland has hired Rob
Arends as European rope sales manager.
He will be based in the
Netherlands. Arends has
many years of interna-
tional experience in high
modulus polyethylene
(HMPE) heavy lift slings
and grommets, mooring
assemblies, and syn-
thetic ropes. Previously
he was sales manager for Endenburg BV
in Gouda, the Netherlands. Prior to that,
Arends spent 4 years with ABUS Kraan-
systemen BV in various sales manage-
ment roles.
Cortland, part of Actuant Corp.,
provides lightweight rope, slings, cables,
and umbilicals to the oil and gas, heavy
marine, subsea, ROV, seismic, defense,
and medical markets.
COOPER POWER TOOLS GMBH & CO. OHG,Westhausen, Germany, has changed its
name to Apex Tool Group GMBH & Co.
OHG. Apex was formed with the joint
venture of tool manufacturers Danaher
Tool Group and Cooper Industries PLC in
July 2010. Since then the company has
been the German branch of Apex Tool
Group LLC, Sparks, Md.
Apex Tool is one of the biggest manu-
facturers of industrial hand and electric
tools, tool magazines, drill sockets,
chains, and electric soldering products
to the energy/electric, aerospace, auto-
motive, and appliance industries.
KNIGHT OIL TOOLS,Lafayette, La., has named Kenny Ben-
nett corporate account representative.
Bennett has held sales positions with
Integrated Production
Services, Smith Ser-
vices, Cudd Pressure
Control, and American
Pipe & Steel. His most
recent position was in
US executive sales with
Scomi Oil Tools. Based in
Oklahoma City, Bennett
will be responsible for
oil and gas customers in the company’s
Midcontinent region.
Knight is the largest privately held
rental and fishing tools business in the
oil and gas industry.
AXENS, Rueil-Malmaison, France, and General
Technology & Systems Company Ltd.
(Gentas) have signed a letter of intent
to build a world-scale hydroprocessing
catalyst plant in Saudi Arabia. The new
plant will serve the local market but also
support Axens’ global supply chain for
hydroprocessing catalysts.
Gentas is a member of the Shoaibi
Group undertaking joint ventures with
partner Saudi Trading & Research Co.
to pursue opportunities in the oil and
gas and petrochemicals products and
services sectors in Saudi Arabia.
Axens provides advanced technolo-
gies, catalysts, adsorbents, and services
worldwide with a focus on the conversion
of oil, coal, natural gas, and biomass to
clean fuels as well as production and
purification of major petrochemical
intermediates. Axens is a wholly owned
subsidiary of IFP New Energy, formerly
Institut Francaise du Petrole. IFP is
a public-sector research and training
center aimed at developing the technolo-
gies and materials of the future in the
fields of energy, transportation, and the
environment.
X DRILLING TOOLS, Gillman, Australia, has appointed Cliff
Brannan regional business develop-
ment manager for the UK, Europe, and
Africa. Cliff Brannan has
a background in line
hanger completions,
casing, and cement-
ing. With more than 30
years’ experience in the
oil and gas sector, Bran-
nan started his career as
an offshore turbodrilling
service engineer with the
French company Neyrfor. He worked
in PDC drill bit technology and then
became an offshore liner completions
technician before moving into a sales
engineering and management role that
saw him spend the last 6 years working
in West and South Africa, Dubai, Libya,
and Oman.
XDT, part of Reservoir Group, pro-
vides downhole drilling products, notably
downhole roller-reamers and ancillary
tools.
Reservoir Group is an international oil
field services firm specializing in down-
hole drilling, completion, and production
and physical and digital data manage-
ment.
Brannan
Larsen
Bennett
Arends
110801ogj_115 115 7/27/11 10:19 AM
STATISTICS
116 Oil & Gas Journal | Aug. 1, 2011
Additional analysis of market trends is available through OGJ Online, Oil & Gas Journal’s electronic information source, at http://www.ogj.com.
OGJ CRACK SPREAD 7-22-11* 7-23-10* Change Change, ———–—$/bbl ——–—— %
SPOT PRICES Product value 128.43 84.57 43.87 51.9 Brent crude 118.36 77.39 40.97 52.9 Crack spread 10.07 7.17 2.89 40.4
FUTURES MARKET PRICESOne month Product value 130.72 86.87 43.85 50.5 Light sweet crude 98.11 77.76 20.35 26.2 Crack spread 32.61 9.11 23.50 257.9 Six month Product value 126.12 86.62 39.50 45.6 Light sweet crude 100.08 79.88 20.20 25.3 Crack spread 26.04 6.74 19.30 286.4
*Average for week ending.Source: Oil & Gas JournalData available at PennEnergy Research Center.
PURVIN & GERTZ LNG NETBACKS—JULY 22, 2011 –––––––––––––––––––––––––––– Liquefaction plant ––––––––––––––––––––––––––––––––Receiving Algeria Malaysia Nigeria Austr. NW Shelf Qatar Trinidadterminal –––––––––––––––––––––––––––––––– $/MMbtu ––––––––––––––––––––––––––––––––––––
Barcelona 10.35 7.70 9.27 7.58 8.46 9.17Everett 3.47 0.98 3.02 1.05 1.64 3.81Isle of Grain 7.19 4.53 6.37 4.43 5.25 6.41Lake Charles 1.50 -0.79 1.21 -0.56 -0.27 2.24Sodegaura 8.32 11.14 8.53 10.75 9.79 6.97Zeebrugge 9.70 7.64 9.07 7.53 8.21 9.13
De� nitions, see OGJ Apr. 9, 2007, p. 57.Source: Purvin & Gertz Inc.Data available at PennEnergy Research Center.
CRUDE AND PRODUCT STOCKS —–– Motor gasoline —–– Blending Jet fuel, ————— Fuel oils ————— Propane- Crude oil Total comp.1 kerosine Distillate Residual propyleneDistrict ———————————————————————————— 1,000 bbl —————————————————————————
PADD 1 ..................................... 11,944 55,800 48,025 12,503 53,450 11,444 4,333PADD 2 ..................................... 99,858 49,137 26,834 6,566 27,808 1,329 19,309PADD 3 ..................................... 172,815 71,652 55,133 14,263 46,958 19,235 19,208PADD 4 ..................................... 14,827 6,456 2,148 654 3,601 175 11,204PADD 5 ..................................... 56,011 28,655 25,136 10,430 13,210 5,802 —
July 15, 2011 ........................... 355,455 211,700 157,276 44,416 145,027 37,985 44,054July 8, 2011 .............................. 358,579 212,539 155,784 43,333 142,061 37,805 41,508July 16, 20102 ........................... 353,096 221,036 142,368 47,769 162,639 41,343 51,619
1Includes PADD 5. 2Revised. Source: US Energy Information AdministrationData available at PennEnergy Research Center.
REFINERY REPORT—JULY 15, 2011
REFINERY –––––––––––––––––––––––––––– REFINERY OUTPUT ––––––––––––––––––––––––––– –––––– OPERATIONS –––––– Total Gross Crude oil motor Jet fuel, ––––––– Fuel oils –––––––– Propane- inputs inputs gasoline kerosine Distillate Residual propyleneDistrict ––––––– 1,000 b/d –––––––– –––––––––––––––––––––––––––––––– 1,000 b/d –––––––––––––––––––––––––––––––
PADD 1 .............................................. 1,308 1,295 2,943 97 375 63 48PADD 2 .............................................. 3,272 3,261 2,216 223 971 58 265PADD 3 .............................................. 7,776 7,573 2,134 750 2,369 324 756PADD 4 .............................................. 540 537 263 38 181 10 169PADD 5 .............................................. 2,711 2,552 1,555 443 597 128 —
July 15, 2011 ...................................... 15,607 15,218 9,111 1,551 4,493 583 1,138July 8, 2011 ........................................ 15,635 15,315 9,532 1,500 4,446 566 1,079July 16, 20102 ..................................... 15,919 15,468 9,455 1,521 4,459 444 1,085
17,736 Operable capacity 88.0% utilization rate
1Includes PADD 5. 2Revised.Source: US Energy Information AdministrationData available at PennEnergy Research Center.
IMPORTS OF CRUDE AND PRODUCTS
— Districts 1-4 — — District 5 — ———— Total US ———— 7-15 7-8 7-15 7-8 7-15 7-8 7-16* 2011 2011 2011 2011 2011 2011 2010 ––––––––––––––––––––––––— 1,000 b/d ––––––––––––––––––––––––—
Total motor gasoline ............. 749 660 4 39 753 699 922 Mo. gas. blending comp. ..... 704 571 4 39 708 610 852 Distillate ............................... 108 123 0 0 108 123 147 Residual .............................. 212 390 24 0 236 390 282 Jet fuel-kerosine .................. 51 24 23 29 74 53 58 Propane-propylene .............. 42 37 30 21 72 58 50 Other ................................... 428 248 24 (58) 452 190 36
Total products ...................... 2,294 2,053 109 70 2,403 2,123 2,347
Total crude ........................... 7,652 8,639 1,348 1,216 9,000 9,855 9,280
Total imports ........................ 9,946 10,692 1,457 1,286 11,403 11,978 11,627
*Revised. Source: US Energy Information AdministrationData available at PennEnergy Research Center.
110801ogj_116 116 7/27/11 2:19 PM
STATISTICS
Oil & Gas Journal | Aug. 1, 2011 117
OGJ GASOLINE PRICES
Price Pump Pump ex tax price* price 7-20-11 7-20-11 7-21-10 ————— ¢/gal —————
(Approx. prices for self-service unleaded gasoline)
Atlanta .......................... 333.1 372.3 260.1
Baltimore ...................... 330.0 371.9 266.1
Boston ........................... 328.4 370.3 261.1
Buffalo .......................... 304.3 367.5 273.1
Miami ............................ 320.3 372.7 278.2
Newark .......................... 324.2 357.1 266.1
New York........................ 318.2 381.4 281.1
Norfolk........................... 318.9 356.8 256.1
Philadelphia .................. 319.9 370.6 267.1
Pittsburgh ..................... 313.7 364.4 270.1
Wash., DC ...................... 338.9 380.8 277.1
PAD I avg .................. 322.7 369.6 268.7
Chicago ......................... 384.3 442.3 301.2
Cleveland ...................... 300.1 346.5 262.3
Des Moines .................... 314.1 354.5 263.5
Detroit ........................... 333.1 387.3 273.5
Indianapolis .................. 310.2 363.3 274.8
Kansas City ................... 328.5 364.2 256.9
Louisville ....................... 340.3 381.2 267.9
Memphis ....................... 319.3 359.1 266.2
Milwaukee ..................... 331.1 382.4 275.8
Minn.-St. Paul ............... 324.7 370.3 274.8
Oklahoma City ............... 312.0 347.4 243.9
Omaha .......................... 311.9 358.3 262.8
St. Louis ........................ 328.7 364.4 258.9
Tulsa ............................. 316.2 351.6 248.8
Wichita .......................... 316.0 359.4 263.9
PAD II avg ................. 324.7 368.8 266.3
Albuquerque .................. 309.1 346.3 259.3
Birmingham .................. 311.7 351.0 263.3
Dallas-Fort Worth .......... 323.1 361.5 265.3
Houston ......................... 318.0 356.4 262.3
Little Rock ..................... 311.5 351.7 257.8
New Orleans .................. 319.4 357.8 260.8
San Antonio ................... 326.4 364.8 258.3
PAD III avg ................ 317.0 355.7 261.0
Cheyenne....................... 315.9 348.3 270.9
Denver ........................... 310.2 350.6 279.4
Salt Lake City ................ 308.4 351.3 282.9
PAD IV avg ................ 311.5 350.1 277.7
Los Angeles ................... 313.7 381.1 304.6
Phoenix.......................... 298.6 336.0 282.6
Portland ........................ 337.6 381.0 292.8
San Diego ...................... 306.7 374.1 315.6
San Francisco................ 325.8 393.2 317.7
Seattle........................... 325.2 381.1 310.8
PAD V avg ................. 317.9 374.4 304.0
Week’s avg. .................. 321.0 366.3 272.3June avg........................ 322.8 368.1 271.1May avg. ....................... 347.0 392.3 285.82011 to date ................. 307.7 353.0 —2010 to date ................. 230.0 274.8 —
*Includes state and federal motor fuel taxes and state
sales tax. Local governments may impose additional taxes.
Source: Oil & Gas Journal.
Data available at PennEnergy Research Center.
BAKER HUGHES RIG COUNT
7-22-11 7-23-10
Alabama............................................ 8 8
Alaska ............................................... 4 5
Arkansas ........................................... 34 38
California .......................................... 46 38
Land................................................ 46 38
Offshore .......................................... 0 0
Colorado ............................................ 70 62
Florida ............................................... 1 1
Illinois ............................................... 2 2
Indiana.............................................. 1 7
Kansas .............................................. 31 15
Kentucky............................................ 5 4
Louisiana .......................................... 174 184
N. Land ........................................... 91 142
S. Inland waters .............................. 18 14
S. Land............................................ 30 15
Offshore .......................................... 35 13
Maryland ........................................... 0 0
Michigan ........................................... 4 0
Mississippi ........................................ 7 10
Montana ............................................ 11 5
Nebraska ........................................... 1 0
New Mexico........................................ 82 71
New York............................................ 0 1
North Dakota ..................................... 158 126
Ohio................................................... 12 6
Oklahoma .......................................... 177 132
Pennsylvania ..................................... 116 88
South Dakota..................................... 2 1
Texas ................................................. 864 674
Offshore .......................................... 2 1
Inland waters .................................. 0 0
Dist. 1 ............................................. 104 51
Dist. 2 ............................................. 73 32
Dist. 3 ............................................. 46 45
Dist. 4 ............................................. 44 44
Dist. 5 ............................................. 54 77
Dist. 6 ............................................. 50 71
Dist. 7B ........................................... 10 11
Dist. 7C ........................................... 74 56
Dist. 8 ............................................. 257 158
Dist. 8A ........................................... 34 26
Dist. 9 ............................................. 41 35
Dist. 10 ........................................... 75 67
Utah .................................................. 29 27
West Virginia ..................................... 21 27
Wyoming............................................ 51 41
Others—NV-3; OR-1; VA-1 ................ 5 12
Total US ........................................ 1,916 1,585 Total Canada ................................ 376 349
Grand total ................................... 2,292 1,934US Oil rigs ......................................... 1,021 591
US Gas rigs ....................................... 889 982
Total US offshore ............................... 37 14
Total US cum. avg. YTD ..................... 1,791 1,439
Rotary rigs from spudding in to total depth.
De£ nitions, see OGJ Sept. 18, 2006, p. 42.
Source: Baker Hughes Inc.
Data available at PennEnergy Research Center.
US CRUDE PRICES7-22-11
$/bbl*
Alaska-North Slope 27° ......................................... 108.33
South Louisiana Sweet .......................................... 116.50
California-Midway Sunset 13° .............................. 104.75
Lost Hills 30° ........................................................ 114.85
Wyoming Sweet ..................................................... 91.37
East Texas Sweet ................................................... 85.75
West Texas Sour 34° .............................................. 91.25
West Texas Intermediate ........................................ 96.25
Oklahoma Sweet.................................................... 96.25
Texas Upper Gulf Coast ......................................... 89.25
Michigan Sour ....................................................... 88.25
Kansas Common ................................................... 95.25
North Dakota Sweet ............................................... 93.00
*Current major re£ ner’s posted prices except North Slope lags
2 months. 40° gravity crude unless differing gravity is shown.
Source: Oil & Gas Journal.
Data available at PennEnergy Research Center.
SMITH RIG COUNT
7-22-11 7-23-10Proposed depth, Rig Percent Rig Percent ft count footage* count footage*
0-2,500 208 1.4 157 5.0
2,501-5,000 82 59.7 67 65.6
5,001-7,500 114 23.6 154 23.3
7,501-10,000 307 2.9 275 3.2
10,001-12,500 435 8.0 295 10.1
12,501-15,000 288 0.6 242 2.0
15,001-17,500 175 0.5 184 —
17,501-20,000 123 — 120 —
20,001-over 65 — 33 —
Total 1,797 7.0 1,527 8.6
INLAND 22
10LAND 1,750 1,500
OFFSHORE 25 17
*Rigs employed under footage contracts.
De£ nitions, see OGJ Sept. 18, 2006, p. 42.
Source: Smith International Inc.
Data available at PennEnergy Research Center.
US NATURAL GAS STORAGE1 7-15-11 7-8-11 7-15-10 Change, –——––—— bcf —––——– %
Producing region ................ 995 1,001 991 0.4
Consuming region east ...... 1,298 1,248 1,419 -8.5
Consuming region west ...... 378 362 473 -20.1
Total US ............................. 2,671 2,611 2,883 -7.4 Change, Apr. 11 Apr. 10 %
Total US2 ............................ 1,789 2,012 -11.1
1Working gas. 2At end of period.Source: Energy Information Administration
Data available at PennEnergy Research Center.
WORLD CRUDE PRICES
$/bbl1 7-15-11
United Kingdom-Brent 38° ..................................... 117.95
Russia-Urals 32° ................................................... 115.92
Saudi Light 34° ...................................................... 115.09
Dubai Fateh 32° ..................................................... 110.60
Algeria Saharan 44°............................................... 117.23
Nigeria-Bonny Light 37° ........................................ 118.48
Indonesia-Minas 34°.............................................. 121.53
Venezuela-Tia Juana Light 31° ............................... 108.39
Mexico-Isthmus 33° ............................................... 108.28 -
OPEC basket........................................................... 113.96 -
Total OPEC2 ............................................................ 114.23
Total non-OPEC2 ..................................................... 112.46
Total world2 ............................................................ 113.51
US imports3 105.49
1Estimated contract prices. 2Average price (FOB) weighted by
estimated export volume. 3Average price (FOB) weighted by
estimated import volume.
Source: DOE Weekly Petroleum Status Report.
Data available at PennEnergy Research Center.
OGJ PRODUCTION REPORT
17-22-11 27-23-10 –—— 1,000 b/d —–—
(Crude oil and lease condensate)
Alabama ................................. 17 19
Alaska .................................... 604 541
California ............................... 619 621
Colorado ................................. 66 60
Florida .................................... 4 5
Illinois .................................... 26 25
Kansas ................................... 108 108
Louisiana ............................... 1,555 1,452
Michigan ................................ 16 17
Mississippi ............................. 61 65
Montana ................................. 71 67
New Mexico ............................. 192 176
North Dakota .......................... 349 320
Oklahoma ............................... 185 191
Texas ...................................... 1,463 1,458
Utah ....................................... 62 69
Wyoming ................................. 140 145
All others ................................ 65 74
Total .................................. 5,603 5,4131OGJ estimate. 2Revised.
Source: Oil & Gas Journal.
Data available at PennEnergy Research Center.
REFINED PRODUCT PRICES
7-8-11 7-8-11 ¢/gal ¢/gal Spot market product prices
Motor gasoline
(Conventional-regular)
New York Harbor ......... 307.50
Gulf Coast .................. 301.30
Motor gasoline
(RBOB-regular)
New York Harbor ......... 313.50
No. 2 heating oil New York Harbor ......... 311.90
No. 2 Distillate
Low sulfur diesel fuel
New York Harbor ......... 322.90
Gulf Coast .................. 316.90
Los Angeles ................ 314.40
Kerosine jet fuel
Gulf Coast .................. 316.90
Propane
Mt. Belvieu ................. 153.10
Source: DOE Weekly Petroleum Status Report.
Data available at PennEnergy Research Center.
110801ogj_117 117 7/27/11 2:19 PM
STATISTICS
118 Oil & Gas Journal | Aug. 1, 2011
PACE REFINING MARGINS May June July July 2011 2011 2011 2010 Change Change, ——––—––––— $/bbl –––––––––—— %
US Gulf Coast West Texas Sour ............................... 23.85 24.45 27.94 6.71 21.23 316.4 Composite US Gulf Refi nery.............. 21.61 19.62 23.53 8.39 15.14 180.5 Mars (Cracking) ............................... 6.71 6.26 7.88 2.73 5.15 188.5 Bonny Light ...................................... 5.50 4.07 7.05 3.30 3.75 –113.4US PADD II Chicago (WTI)................................... 30.07 25.90 28.93 7.41 21.53 290.7US East Coast Brass River ...................................... 9.46 5.76 9.36 4.85 4.51 93.1 East Coast Comp ............................. 13.09 9.24 12.24 5.67 6.57 115.7US West Coast Los Angeles (ANS) ............................ 17.27 14.16 14.17 18.25 –4.08 –22.3NW Europe Rotterdam (Brent) ............................ 1.44 0.29 1.21 1.06 0.15 13.9Mediterranean Italy (Urals) ...................................... 0.18 –1.83 –0.84 –0.15 –0.69 470.4Far East Singapore (Dubai) ............................ 5.90 4.54 5.37 2.95 2.42 81.9
Source: Jacobs Consultancy Inc. Data available at PennEnergy Research Center.
US NATURAL GAS BALANCEDEMAND/SUPPLY SCOREBOARD
Apr. Total YTD Apr. Mar. Mar. 2011-2010 ––– YTD ––– 2011-2010 2011 2011 2010 change 2011 2010 change ——————————— bcf ———————————
DEMAND Consumption ................... 1,807 2,224 1,695 112 9,359 9,202 157 Addition to storage .......... 320 172 425 –105 629 481 –– Exports ............................ 127 144 76 51 531 357 174 Canada ......................... 76 98 50 26 342 256 86 Mexico .......................... 43 41 22 21 156 88 68 LNG ............................... 8 5 4 4 33 13 20 Total demand .................. 2,254 2,540 2,196 58 10,519 10,040 331
SUPPLY Production (dry gas) ........ 1,886 1,928 1,766 120 7,381 6,979 402 Supplemental gas............ 5 6 5 0 23 23 0 Storage withdrawal.......... 108 317 70 38 1,945 2,094 –149 Imports ............................ 279 316 298 –19 1,277 1,325 –48 Canada.......................... 246 277 251 –5 1,132 1,131 1 Mexico ........................... 0 0 5 –5 1 13 –12 LNG................................ 33 39 42 –9 144 181 –37 Total supply ..................... 2,278 2,567 2,139 139 10,626 10,421 205
NATURAL GAS IN UNDERGROUND STORAGE Apr. Mar. Feb. Apr. 2011 2011 2011 2010 Change —————————— bcf ——————————
Base gas 4,306 4,306 4,304 4,281 25Working gas 2,308 1,724 1,581 2,012 296 Total gas 6,614 6,030 5,885 6,293 321
Source: DOE Monthly Energy Review. Data available at PennEnergy Research Center.
US HEATING DEGREE-DAYS 2011 % change Total degree-days % change May May from ———–– July 1 through May 31 ––——— from 2011 2010 Normal normal 2011 2010 Normal normal
New England ................................................................ 281 200 243 15.6 6,545 6,026 6,478 1.0 Middle Atlantic ............................................................. 217 148 158 37.3 5,872 5,370 5,756 2.0 East North Central........................................................ 238 183 230 3.5 6,447 6,133 6,509 –1.0 West North Central ....................................................... 208 223 250 –16.8 6,701 6,701 6,831 –1.9 South Atlantic .............................................................. 61 33 49 24.5 2,846 2,987 2,930 –2.9 East South Central ....................................................... 76 36 97 –21.6 3,597 3,855 3,618 –0.6 West South Central ....................................................... 17 15 43 –60.5 2,286 2,650 2,212 3.3 Mountain ...................................................................... 233 283 286 –18.5 5,127 5,204 4,896 4.7 Pacifi c .......................................................................... 182 240 249 –26.9 3,152 3,166 3,260 –3.3
US average*............................................................ 159 142 166 –4.2 4,485 4,427 4,494 –0.2
*Excludes Alaska and Hawaii.Source: DOE Monthly Energy Review.
Data available at PennEnergy Research Center.
OXYGENATES Apr. Mar. YTD YTD 2011 2011 Change 2011 2010 Change ———————––—––– 1,000 bbl –––—————————
Fuel ethanol
Production .................. 26,194 28,194 –2,000 108,312 99,926 8,386
Stocks ......................... 20,807 21,440 –633 20,807 19,682 1,125
MTBE
Production .................. 1,391 1,452 –61 4,910 3,209 1,701
Stocks ......................... 889 534 355 889 1,024 –135
Source: DOE Petroleum Supply Monthly.
Data available at PennEnergy Research Center.NOTE: No new data available at press time.
WORLDWIDE NGL PRODUCTION 4 month Change vs. average previous Apr. Mar. –– production –– –––— year —– 2011 2011 2011 2010 Volume ————–—–––— 1,000 b/d ———––———— %
Brazil ................................... 89 83 88 80 8 9.9Canada ................................ 598 653 646 640 7 1.0Mexico ................................. 396 392 393 380 12 3.2United States ...................... 2,015 2,168 2,031 1,968 63 3.2Venezuela ............................ 214 214 214 211 3 1.5Other Western Hemisphere ..................... 232 233 239 244 –5 –2.2 Western Hemisphere .................. 3,545 3,744 3,611 3,522 88 2.5
Norway ................................. 233 209 248 285 –38 –13.2United Kingdom ................... 87 89 90 129 –40 –30.6Other Western Europe ............................. 9 10 10 10 — –1.5
Western Europe ............. 330 308 347 425 –77 –18.2
Russia ................................. 444 441 442 437 6 1.3Other FSU ............................ 127 128 128 130 –2 –1.3Other Eastern Europe ............................. 15 15 15 16 –1 –6.3 Eastern Europe .............. 586 584 585 582 3 0.5
Algeria ................................. 350 350 350 350 — —Egypt ................................... 143 143 144 145 –2 –1.0Libya .................................... 0 0 69 140 –71 –50.9Other Africa ......................... 183 182 181 174 8 4.4 Africa .............................. 676 675 744 809 –65 –8.0
Saudi Arabia ........................ 1,655 1,620 1,629 1,500 129 8.6United Arab Emirates .......... 400 400 399 384 15 3.9Other Middle East ................ 1,500 1,515 1,514 1,550 –36 –2.3
Middle East ..................... 3,555 3,535 3,541 3,434 108 3.1
Australia .............................. 59 56 63 68 –5 –7.4China ................................... 650 650 650 650 — —India .................................... — — — — — —Other Asia-Pacifi c ................ 173 173 173 174 — –0.2 Asia-Pacifi c .................... 882 879 886 891 –5 –0.6
TOTAL WORLD ................. 9,574 9,725 9,714 9,663 51 0.5
Totals may not add due to rounding.Source: Oil & Gas Journal.Data available at PennEnergy Research Center.
110801ogj_rev_118 118 8/1/11 9:52 AM
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EMPLOYMENT
119 Oil & Gas Journal | Aug. 1, 2011
Director-Accounting, KMGP Services Co.,
Inc., Houston, TX Direct & coordinate � -
nan. reporting & accnt’ng for oil & gas co.
incl. coord./directing prep. of annual budget
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SENIOR RESEARCH GEOPHYSICISTS Scientific Professionals - ExxonMobil, a global leader in the petroleum and petrochemicals industry, is seeking Senior Research Geophysicists for their Upstream Business Line located in Houston, TX. Job duties include: Conduct geophysical research pertaining to Full Wavefield Inversion. Develop seismic modeling and inversion software applications and workflows that can be applied to recorded field data. Test prototype seismic modeling and inversion modules under development on real data. Conduct research on coupling between wavefield parameters and sensitivity analysis in multiparameter Full Wavefield Inversion. Write scientific articles and reports. Develop Intellectual Property including filing of patents on inventions and present results at industrial conferences. Job requires a PhD degree in Geophysics and 2 years of experience in the following: seismic Full Wavefield Inversion research, finite difference based visco-elastic seismic wavefield modeling and inversion, and implementation of geophysical processing and inversion concepts to develop computer programs for massively parallel, high performance computing. Experience must include visco-elastic seismic wave propagation and software development in one or more of the following programming languages: FORTRAN, Python, C, or C++ programming languages. Please submit your cover letter and resume to our web site: www.exxonmobil.com/ex. Please apply to Senior Research Geophysicist – 12503BR and reference requisition number 12503BR in both letter and resume. ExxonMobil is an Equal Opportunity Employer.
110801ogj_119 119 7/27/11 2:19 PM
120 Oil & Gas Journal | Aug. 1, 2011
MARKETPLACE
EDUCATION
Introduction to Petroleum Refi ning, Technology and Economics:
Colorado School of Mines. Sept. 21-23, 2011. Overview of the integrated fuels
refi nery of today, from the crude oil feed to the fi nished products. Emphasis is placed on transportation fuels production and the
refi nery process used.Introduction to Economics of
Petroleum Refi ning:Sept. 28-30, 2011. Overview of petroleum refi ning technology and economics with a
focus on transportation fuels refi neries. Contact: 303/279-5563,fax: 303/277-8683, email:
[email protected], www.mines.edu/Educational_Outreach
EMPLOYMENT
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Chevron seeks Machinery Engineer in Houston, TX. Masterís in Mechanical Engineering & 2 yrs exp; Reqd skills: Data Signal Processing; Condition Monitoring Applications drawing on analysis of process signal related to the machinery; Intellectual Property evaluation; Reliability analysis, including Signal Processing, Wavelet de-noising & Wavelet transformation; Isolation, Logistic regression, SOM & LVQ; Prognostics, Recurrent Neural networks, Evolutionary Algorithms & PSO. Mail resume: Chevron, 1500 Louisiana St., Houston, TX 77002, Attn E. Lopez, Ref job 157.
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� Supervise I&E Techs, give daily directions and instruction � Lead projects, schedule, organize, and manage plant and field growth � Use SCADA, Programming and updating WW host on hardware
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organized � Train on Automation, Electrical, and Computer systems � Keep plant PSM and DOT data in compliance with Whiting standards � Troubleshoot automation issues, when Technicians cannot resolve � Manage RL SCADA Network, manage segregated automation network
Qualifications: � 5 years of relevant work experience � Certifications in XP-Pro � Hands-on hardware, XP-Pro, and MS Office troubleshooting
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SENIOR COMPLETIONS SUPERVISOR
Position Summary: Responsible for supervising, direction and coordinating daily activities of field employees or third-party contractors engaged in various areas of work over/completions activities. Job Duties: � Supervises and coordinates contract well servicing crews, as well as
other contractors that perform work including: perforating, acidizing, fracturing, cased hole drilling, fishing, squeeze cementing, down hole equipment installation and repair, swabbing, etc.
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Qualifications: � High School diploma or equivalent � Minimum of 5 - 10 years of supervisory and industry experience. � Basic computer skills, good verbal and written communication skills
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a company vehicle
Petrophysicist SpecialistDesign and coordinate LWD and/or wireline logging programs for reservoir monitoring, spe-cial core measurements, formation testers (pressure and sampling), production logging and evaluating new logging technology. Provide interpretation of log data including nuclear mag-netic resonance, elemental capture spectroscopy, dielectric and sonic platforms. Use TCL/TK, Python, Loglan, QT and VBA to extend petrophysical sub-routines while characterizing reservoir properties in multiple fi elds. Assess and/or integrate reservoir engineering analyses including well test analysis, petrophysical log analysis, residual oil saturation techniques, special core analysis, decline curve analysis and/or material balance to evaluate development plans, reserves analysis and economic evaluation. Assess and specify reservoir stimulation practices such as fracturing, gravel pack and acidizing techniques. Requirements: bachelor’s degree in science or engineering and 5 years of experience as an oil and gas petrophysicist which included log interpretation. Salary is commensurate with background. Send resumes to: Quantum Reservoir Impact 909 Fannin, Suite 2200, Houston, Texas 77010, Attn: Sy Salerian Job Code # P002 or by email to [email protected], job code # P002. See our website at www.qrigroup.com. Quantum Reservoir Impact LLC is an equal opportunity employer.
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MARKETPLACE
Oil & Gas Journal | Aug. 1, 2011 121
CONSULTANTS
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EDUCATION
Introduction to Petroleum Re� ning, Technology and Economics:
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Petroleum Re� ning:Sept. 28-30, 2011. Overview of petroleum re� ning technology and economics with a
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110801ogj_121 121 7/27/11 2:19 PM
MARKETPLACE
PUBLIC TENDER
State of IsraelMinistry of National Infrastructures
The Ministry of National Infrastructures is issuing a public tender for technical monitoring and auditing services related to oil andgas E&P in Israel
This tender will be published in the English language and willbe available online from July 13, 2011 at the Ministry website:http://www.mni.gov.il/mni/en-US/NaturalResources/Tenders/RDTenders29_11.htm
Bids, as set forth in the tender, must be submitted, no later than13.09.2011 at 13:00 p.m. (Israel time).
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110801ogj_122 122 7/27/11 2:19 PM
COMPANY NAME PAGE
ADVERTISERS INDEXADVERTISING SALES
COMPANY NAME PAGE
This index is provided as a service. The publisher does not assume any liability for errors or omission.
Mogas Industries Inc 59 www.mogas.com
Nachurs Alpine Solutions Industrial 11 www.nasindustrial.com
NuTech Energy Alliance 33 www.nutechenergy.com
OMK United Metallurgical Company 65 www.omk.ru/en/
Offshore Asia 2012 51 www.offshoreasiaevent.com
Offshore India 79 www.offshoreoilindia.com
Offshore Middle East 2013 105 www.offshoremiddleeast.com
PennEnergy Equipment 89 www.pennenergyequipment.com
PennEnergy Research 60 www.PennEnergyResearch.com
Phoenix Project Engineering 13 www.pec.us.com
Piezo Technologies 67 www.piezotechnologies.com
Polyguard 93 www.polyguardproducts.com
RACOR 46 www.parker.com/racor
Sandvik Materials Technology 45 www.offshore-europe.co.uk
Shawcor, LTD. 15 www.shawcor.com
Siemens AG 19 www.siemens.com
SoundPLAN 67 www.soundplan.com
Topsides 2012 122 www.topsidesevent.com
Veolia 25 www.veoliawater.com
Wago Kontakttechnik GmbH 53 www.wago.com
Weatherford 4, 5 www.weatherford.com
Ariel Corp 55 www.arielcorp.com
Aviva 71 www.aviva.com
Baker Hughes 21 www.bakerhughes.com
BASF SE C4 www.basf.com/
Bodycote AD&E 47 www.bodycote.com
Bredero Shaw 49 www.brederoshaw.com
CHEVRON 9 www.chevron.com
Deepwater Operations 2011 97 www.deepwateroperations.com
DOT 2011 101 www.deepoffshoretechnology.com
Dow Oil and Gas C3 oilandgas.dow.com
Drilformance 31 www.drilformance.com
Emerson Process Management, Fisher 2 www2.emersonprocess.com
Flir Systems, Inc. 27 www.flir.com
FMC Technologies, Inc. 41 www.fmctechnologies.com
GE C2 www.ge.com
Halliburton 7 www.halliburton.com
Hytorc 35, 37, 39 www.hytorc.com
Industrial Rubber 17 www.iri-oiltool.com
Inmarsat 29 www.inmarsat.com
Lagcoe 95 www.lagcoe.com
Layne Christensen 85 www.laynechristensen.com
Mears Integrity Solutions 26 www.mears.net
Milliken 61 www.milliken.com
Oil & Gas Journal | Aug. 1, 2011 123
US SalesMarlene Breedlove, Tel: (713) 963-6293,E-mail: [email protected]. Roy Markum, Tel: (713) 963-6220, E-mail: [email protected]. Mike Moss, Tel: (713) 963-6221, E-mail: [email protected]. Stan Terry, Tel: (713) 963-6208, E-mail: [email protected].
PennWell1455 West Loop South, Houston, TX 77027Fax: (713) 963-9228
CanadaStan Terry, Tel: (713) 963-6208, E-mail: [email protected]
Nigeria / West AfricaDele Olaoye, Flat 8, 3rd Floor, Oluwatobi House, Ikeja Lagos, Nigeria; Tel: +234 805 687 2630; Tel: +234 802 223 2864; E-mail: [email protected]
United Kingdom / Scandinavia / Denmark /
The NetherlandsRoger Kingswell, 9 Tarragon Road, Maidstone,ME16 0UR, United Kingdom; Tel: 44.1622.721.222;Fax: 44.1622.721.333; Email: [email protected]
France / Belgium / Spain / Portugal /
Southern Switzerland / MonacoDaniel Bernard, 8 allee des Herons, 78400 Chatou, France; Tel: 33(0)1.3071.1119, Fax: 33(0)1.3071.1119; E-mail: [email protected]
Germany / Austria / Northern Switzerland /
Eastern Europe / Russia / Former Soviet UnionSicking Industrial Marketing, Kurt-Schumacher-Str. 16, 59872, Freienohl, Germany. Tel: 49(0)2903.3385.70, Fax: 49(0)2903.3385.82; E-mail: [email protected]; www.sicking.de <http://www.sicking.de> Andreas Sicking
Japane.x.press sales division, ICS Convention Design Inc. 6F, Chiyoda Bldg., 1-5-18 Sarugakucho, Chiyoda-ku, Tokyo 101-8449, Japan, Tel: +81.3.3219.3641, Fax: 81.3.3219.3628; Kimie Takemura, Email: [email protected]; Masaki Mori, E-mail: [email protected]
BrazilGrupo Expetro/Smartpetro, Att: Jean-Paul Prates and Bernardo Grunewald, Directors, Ave. Erasmo Braga 22710th and 11th floors Rio de Janeiro RJ 20024-900 Brazil; Tel: 55.21.3084.5384, Fax: 55.21.2533.4593; E-mail: [email protected] and [email protected]
Singapore / Australia / Asia-PacificMichael Yee, 19 Tanglin Road #05-20, Tanglin Shopping Center, Singapore 247909, Republic of Singapore; Tel: 65 9616.8080, Fax: 65.6734.0655; E-mail: [email protected]
IndiaRajan Sharma, Interads Limited, 2, Padmini Enclave, Hauz Khas, New Delhi-110 016, India; Tel: +91.11. 6283018/19, Fax: +91.11.6228 928; E-mail: [email protected]
ItalyFerruccio Silvera, Viale Monza, 24 20127 MILANO Italy; Tel:+02.28.46 716; E-mail: [email protected]
COMPANY NAME PAGE COMPANY NAME PAGE
110801ogj_123 123 7/27/11 3:47 PM
124 Oil & Gas Journal | Aug. 1, 2011
Latin America is growth marketfor US refinersby Sam Fletcher, Senior Writer
Latin American refinery expansions planned this decade will not be enough to stem the region’s growing dependence on imported US fuels, said analysts at Deutsche Bank AG (DB). Structural growth in US-Latin American trade for gasoline and gas oil will continue, with an increasing role for these exports in the US oil balance and US margins, they said.
While oil markets have focused on expanding Asian demand—particularly China—Latin American demand growth is shaping not only the oil balance for the Americas but also global fundamental dynamics, said Soozhana Choi, head of Asia commodities research at DB. Latin America’s oil demand growth averaged 3.8% during 2006-08. But in 2010, the region’s demand growth averaged 4% year-over-year, “a sharp recov-ery from 2009 when the region’s oil demand fell 0.7%,” she said.
Latin America’s demand growth is expected to average 3% in 2011 and 2012, moderating from the 2010 recovery but still above the 10-year average. DB officials ex-pect Latin American economic growth to “normalize” in 2011-12. Choi said, “Healthy economic growth in the years just prior to 2009 and now post-2009 has in good part been driven by structurally higher prices for raw materials, of which the region is a major global producer and exporter, including many key energy, metals, and agricul-tural commodities.”
In Brazil, the largest Latin American economy, commodities represent 65% of the country’s total exports. “Income growth in Latin America, aided by fuel subsidy re-gimes in one form or another, has in turn translated into brisk rising domestic oil demand. This is clearly evidenced in robust car sales,” she said.
Demand exceeds refining capacityDB said 1.5 million b/d of refinery capacity (distillation basis) is scheduled for con-struction in 2012-17, including 1 million b/d capacity to be built in Brazil. However, state-owned Petroleo Brasileiro SA (Petrobras) may allocate less funding to down-stream in favor of boosting upstream investment. Choi said even if all refinery projects proceed as planned, the region will grow increasingly short of gas oil and gasoline.
“Gasoline demand, which represents 30% of the region’s total oil demand, has been growing consistently in the past several years, even in 2009,” she said. “Year-to-date, Latin America’s gasoline demand is up 5.4% year-over-year, certainly strong relative that of the US, where demand growth year-to-date is down more than 1% year-over-year.” Demand for gas oil, representing one third of total Latin American oil demand, is up 4.4% year-to-date, while US demand for distillates is flat.
Because of weaker demand growth in their home market, US refiners have surplus refinery capacity and production available for export markets with Latin America being the destination for half of all US oil exports. “Mexico is the destination for 20% of total US exports, and 10% is sent to Brazil, Argentina, and Chile combined,” Choi reported, adding, “The growing importance of exports to the US refined products balance is reflected in that exports now represent 15% of total US refinery production, up from 6% in 2002.”
She said, “Since 2007, we have seen a threefold increase in combined gas oil and gasoline exports to Latin America. Brazil’s diesel imports have been trending higher in the past several years and have more than doubled in 2010 to 155,000 b/d since 2006. Brazil’s growing diesel demand prompted the country to add biodiesel to their transportation fuel mix with soybean as the main feedstock. Brazil’s mandate is ex-pected to rise from a 2% blend in 2008 to a 5% blend in the next few years,” she said.
Brazil became a net gasoline importer in first-half 2010 due to ethanol supply con-straints that led to pricing imbalances; ethanol prices are not controlled, while gasoline prices are regulated. “A similar situation looks to be developing this year given expec-tations for declining sugar production, which may prompt the government to reduce the ethanol blend into the gasoline supply pool from 25% to as low as 18%,” Choi said.
ONLINE JULY 25, 2011 | [email protected]
MARKET JOURNAL THE EDITOR’S PERSPECTIVE
From the Subscribers Only area of
www.ogj.com
US oil productiongains change theenergy landscapeby Bob Tippee, Editor
The Independent Petroleum Association of America has called attention to a stealthy trend changing the energy landscape: US production of crude oil and gas liquids is increasing.
Not many years ago, US production was thought to have entered a period of perpetual decline. Even fewer years ago, the assumption was that the only producing region able to yield increases was the Outer Continental Shelf.
Events have scuttled those expectations.IPAA points out that between the first quar-
ter of 2008 and first quarter of 2011, US out-put of crude oil and gas-plant liquids increased by slightly more than 500,000 b/d.
Last year, total average crude and liquids production was 7.5 million b/d. While that’s still well below historic highs of the 1970s, the gain looks much different from the pessimistic projections of yesteryear. Combined with a sag in demand, it helped lower oil imports between 2008 and 2010 by 1.7 million b/d.
Geography of the production increase also contrasts sharply with former expectations.
Onshore Lower 48 crude production rose by 340,000 b/d between the first quarter of 2008 and same quarter this year. Its trend is upward. Offshore Lower 48 output rose by 260,000 b/d over the period, but the trend is slightly downward.
Onshore production has received new life from shale plays. Offshore production has been slowed by regulatory and permitting brakes applied after the Macondo blowout and spill last year.
Also between first-quarter 2008 and 2011, production of gas-plant liquids increased by 200,000 b/d to more than 2 million b/d.
Further gains are likely—or at least pos-sible—from all three sources as shale plays expand, gas production rises to supply new and expanding markets, and offshore work recovers.
Oil production has entered a new era in the US.
A large question now is whether a hostile political climate, with its persistent threat of preferential taxation of producers and restric-tions on essential well-completion methods, will keep the country from enjoying the ben-efits.
ONLINE JULY 22, 2011 | [email protected]
110801ogj_124 124 7/27/11 10:19 AM
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