GENERAL INTEREST — Quick Takes
Fitch: US firms' FD&A costs up moderately
Despite sharply rising drilling and service costs, the costs per barrel of finding, developing, and acquiring (FD&A) oil and natural gas increased moderately in 2011 and remain below levels of 2008, says Fitch Ratings.
The median FD&A cost among 19 of the largest US exploration and production companies rose to $18.51/boe in 2011 from $14.89/boe in 2010, according to the credit-rating firm.
The 2008 median was $20.31/boe.
Average FD&A costs for the sample were $20.57/boe in 2011, $18.23/boe in 2010, and $26.59/boe in 2008.
"A key factor limiting the scope of FD&A increases is technology improvements (expanded horizontal drilling, higher frac stages per well, and other efficiency gains), which have helped offset rising costs on a dollar/boe basis," Fitch says.
The median reserves addition across the firm's sample was 4.8% in 2011.
BHP Billiton ponders writedown of shale gas assets
BHP Billiton Petroleum is considering whether to write down its US shale gas assets by the end of the quarter, as it already plans to cut the number of shale gas wells it drills in the coming months, the company's chief executive officer told the Australian Petroleum Production & Exploration Association conference in Adelaide.
Michael Yeager said BHP Billiton plans to spend slightly less than the $4 billion that it originally budgeted for onshore US operations. BHP Billiton acquired Petrohawk Energy Corp., Houston, for $12.1 billion, giving the Australian firm operated positions in the US Eagle Ford, Haynesville shale resource plays, and the Permian basin (OGJ Online, July 25, 2011).
"We hope everybody knows that we'll take another accounting snapshot in the future and whenever those circumstances are changed, that whatever action we take now, may get reversed later on," Yeager said.
EPA seeks more time to issue NAAQS PM rules
The US Environmental Protection Agency will need at least until Aug. 15, 2013, to finalize new national ambient air quality standards on particle matter, it told a federal court on May 4.
EPA anticipates it would require at least a year to complete its rulemaking and would not be able to take final action by October as plaintiffs in a 2009 court mandate have requested, Regina McCarthy, assistant administrator for EPA's Air and Radiation Office, said in the motion filed in US District Court for the District of Columbia. The volume of new scientific information which has emerged makes a full-year public comment period essential, she said.
Howard Feldman, regulatory and scientific affairs director at the American Petroleum Institute, said that API recognizes the difficulty EPA faces in completing a NAAQS review under a 5-year statutory requirement.
"API believes that the science does not support a tightening of the current [particle matter] standards, especially given the significant impact these standards have on other EPA programs and the economy," Feldman said. "By virtually all metrics, US air quality continues to improve under the current standards."
Marathon becoming Vilje oil field operator
Statoil is transferring operatorship of Vilje oil field offshore Norway to Marathon Oil Norge, effective Sept. 1 if approved by the Norwegian Ministry of Petroleum and Energy.
The field, in 120 m of water, produces from two subsea wells into a production vessel on Alvheim field, operated by Marathon, 20 km southwest.
Statoil, with 28.85% interest in the PL 036D license, expects Vilje to produce 21,000 b/d of oil this year. Statoil holds a 46.9% interest, and Total E&P Norge, 24.24%.
Exploration & Development — Quick Takes
Anadarko adds 7 to 20+ tcf at Golfinho off Mozambique
The Anadarko Petroleum Corp. group has added 7 to 20+ tcf of recoverable gas to its discovered trove offshore Mozambique at an exploratory success nearly 20 miles northwest of its Prosperidade complex.
The Golfinho well, drilled to 14,885 ft in 3,370 ft of water 10 miles offshore, encountered more than 193 net ft of natural gas pay in two high-quality Oligocene fan systems that are age-equivalent to but geologically distinct from the prior discoveries at Prosperidade (see map, OGJ, Apr. 2, 2012).
Anadarko estimated the Golfinho area to have 13 to 45 tcf of gas in place entirely contained in the Offshore Area 1 block. Its proximity to shore implies cost advantages for development options.
The company said Golfinho has a "significant areal extent" and noted that more prospects remain to be tested on the block in the Rovuma basin.
Once operations are complete at Golfinho, the partnership plans to move the Belford Dolphin drillship to drill the Atum-1 exploration well south of Golfinho and west of Prosperidade.
The partnership also drillstem tested the Upper Oligocene at the Barquentine-1 well in the Prosperidade complex. It flowed at a facility-constrained rate of 100 MMcfd of gas.
Anadarko is operator of Offshore Area 1 with a 36.5% working interest. Mitsui E&P Mozambique Area 1 Ltd. has 20%, BPRL Ventures Mozambique BV 10%, Videocon Mozambique Rovuma 1 Ltd. 10%, and Cove Energy Mozambique Rovuma Offshore Ltd. 8.5%. Empresa Nacional de Hidrocarbonetos EP's 15% interest is carried through the exploration phase.
Eni adds 7-10 tcf at Coral find offshore Mozambique
An Eni SPA-led group said a gas find off northern Mozambique has opened a new play in Eocene sand and hiked the overall potential of the Mamba complex to 47-52 tcf of gas in place.
The Coral-1 well went to 4,869 m in 2,261 m of water. The wellsite is 65 km off Capo Delgado in the southern part of Area 4 and 26 km southeast of the group's Mamba South-1 find.
The well, which found 75 m of gas pay in a single, high-quality Eocene sand, is to be production-tested. The Coral prospect holds 7-10 tcf in place, Eni said, and the resource exclusively located in Area 4 is 15-20 tcf in place. Eni will drill at least five more wells to fully establish Area 4's upside potential.
Area 4 operator Eni holds 70% participating interest. Galp Energia and Korea Gas Corp. have 10% each, and Mozambique's state ENH has 10% carried through the exploration phase.
Two firms connect to pursue Indonesia CBM
CBM Asia Development Corp., Vancouver, BC, and Continental Energy Corp., Jakarta, formed a joint study and bid group to investigate coalbed methane opportunities in Indonesia.
The two firms will jointly and exclusively study selected areas in Indonesia to identify geologically favorable areas to be jointly pursued for direct acquisition of CBM production sharing contracts offered by the Indonesian government. Acquisitions would be by public tender or direct proposal tender conducted under joint study arrangements.
Acquired assets would be shared 75% by CBM Asia as operator and 25% by Continental. CBM Asia would pay 100% of general and administrative costs, while all PSC acquisition costs and other joint exploration and drilling costs would be shared proportionally. The Indonesian government has signed 39 CBM PSCs since 2008.
BG has Cretaceous gas find off southern Tanzania
BG Group is preparing to spud its sixth wildcat offshore southern Tanzania after reporting a fifth gas discovery at the Mzia-1 exploratory well on Block 1.
Mzia-1 is the group's first discovery in the deeper Cretaceous section and opens an extensive new play fairway in the group's offshore acreage in Blocks 1, 3, and 4 to complement the proven Tertiary fairway.
BG Group did not provide a resource estimate for Mzia-1 but said its four previous discoveries found a combined recoverable resource of nearly 7 tcf of gas.
Logs indicate that Mzia-1 encountered 55 m of natural gas pay in good quality sands. BG Group ran extensive logs and acquired pressure data and gas samples.
The company said the well has derisked a number of adjacent Cretaceous prospects that it said could form part of a future Mzia hub. The prospects are expected to be tested in a future appraisal program to be defined after the company integrates data from Mzia-1 and 3D seismic.
Mzia-1 is in 1,639 m of water 45 km off southern Tanzania and 23 km from the Jodari-1 discovery. It is part of the 2012 three-to-four well exploration program.
After finishing operations at Mzia, the Deepsea Metro-1 will relocate to Block 3 to drill the Papa-1 exploratory prospect.
BG Group is operator with 60% interest in the three blocks, and Ophir Energy PLC has 40%.
Drilling & Production — Quick Takes
Total believes kill operation has stopped Elgin leak
Total UK Ltd. reported a well intervention operation stopped the G4 well natural gas leak on the Elgin complex in the UK North Sea within 12 hr of when workers started pumping heavy mud into the well.
The G4 well had leaked since Mar. 25, prompting an evacuation of 238 people from Elgin and an adjacent drilling rig, the Rowan Viking. From an estimated initial gas flow rate of around 2 kg/sec, the leak progressively decreased to 0.5 kg/sec, Total UK said.
Experts from Total and specialist contractors will closely monitor the G4 well in coming days to confirm the complete success of the intervention, Total UK said.
Yves-Louis Darricarrere, Total's president of exploration and production, said the company's priority was to stop the gas leak safely and as quickly as possible.
"We have been working closely with the authorities and we have communicated transparently and will continue to do so," he said. "We shall now fully complete the ongoing task and take into account the lessons learned from this incident."
No details were immediately available yet on whether Total will continue drilling the relief well that already is under way.
Laricina: Carbonate SAGD test 'encouraging'
Laricina Energy Ltd., Calgary, reported "encouraging" production test results at its Saleski pilot in the Athabasca region of Alberta, the first steam-assisted gravity drainage project in the Upper Devonian Grosmont carbonate.
A test begun on Mar. 5 in a well pair in the Grosmont C zone achieved peak production of 807 b/d of bitumen and average output of 445 b/d over 52 days. Flow exceeded 500 b/d for 21 days during the test cycle.
During a 27-day test of the zone in November and December 2011, production peaked at 812 b/d, averaged 511 b/d, and exceeded 500 b/d for 17 days, Laricina said in its first-quarter 2012 financial reports.
During the first quarter, in an effort to bring drilling costs in line with horizontal wells in clastic formations and improve well performance, Laricina drilled a well pair to test a balanced-pressure mud system and open-hole completion "to enhance early thermal start-up and steam-chamber development, which we expect to use in the 10,700-b/d Phase 1 commercial expansion," Laricina said. The company applied for permits for the first commercial phase in December 2010.
Also during the quarter, the company completed a 4D seismic program at Saleski, which it said "confirmed observation-well pressure and temperature measurements, indicating good near-wellbore conformance, as expected in this early period of horizontal thermal operations."
The company expects during the next 12-18 months to secure approval of an amendment to its permit application to increase production to 12,500 b/d. It also expects to begin steam injection into the C2 well pair, complete its 4D seismic evaluation on steam chamber development, and transition to its proprietary solvent-cyclic (SC) SAGD production method.
At its Germain commercial demonstration project west of Saleski, meanwhile, Laricina remains on schedule for start-up in the second quarter of 2013 of production of 5,000 b/d of bitumen from Lower Cretaceous Grand Rapids sandstone via SAGD and SC-SAGD.
Laricina has applied to expand Germain production to 155,000 b/d in a 30,000 b/d second project phase followed by two phases of 60,000 b/d each (OGJ Online, Mar. 12, 2012).
Petrobank to boost cold heavy oil output
Petrobank Energy & Resources Ltd., Calgary, has adjusted its 2012 development plans for heavy oil projects in Canada toward cold production, in one case to prepare the reservoir for its proprietary toe-to-heal air injection (THAI) process.
The company recently reported production increases at its Kerrobert THAI project starting up in southwestern Saskatchewan (OGJ Online, Apr. 23, 2012). There, it said in its first-quarter financial report, "our operating philosophy remains unchanged with a focus on gradually increasing production, reducing pump and surface downtime, and reducing per-barrel operating costs."
At its Dawson THAI project in northwestern Alberta, Petrobank deferred completion in late 2011 to save on costs of a winter start-up and will produce cold heavy oil from existing horizontal wells (OGJ Online, Nov. 30, 2010).
"We have determined that the Dawson reservoir would benefit from being preconditioned" by the cold production, the company said.
"We expect to begin the two-well THAI demonstration project in 2013, and the full-field THAI development application is expected to be filed after the THAI demonstration project is on production."
Petrobank also will use some of its existing wells in Saskatchewan for cold heavy oil production.
"While Petrobank's primary focus is THAI production, we will take advantage of existing opportunities on our lands to increase production," it said. "Success with these completions and reactivations may lead to additional conventional drilling opportunities."
Statoil hires rig for drilling off Newfoundland
Statoil ASA has reached an agreement to use Seadrill's West Aquarius harsh-environment semisubmersible on its 2012-13 exploratory drilling offshore Newfoundland.
The rig, capable of drilling in as much as 3,000 m of water, will drill two exploratory wells in the Flemish Pass basin and one in the Jeanne d'Arc basin. The rig has been taken on under an assignment from ExxonMobil Deepwater Rig Ltd.
PROCESSING — Quick Takes
Copano to take South Texas gas plant to 1 bcfd
Copano Energy LLC, Houston, will add 400 MMcfd of cryogenic processing capacity at its Houston Central complex, in Colorado County, Tex., west of Houston, the company reported. It said the decision responds to "continuing producer demand" in the liquids-rich Eagle Ford shale.
At the same time, Copano reported a new long-term fee-based gathering and processing agreement with a major Eagle Ford producer-which neither the announcement nor a Copano spokesperson identified. Combined with previously announced producer commitments, the agreement will support the expansion.
This recently announced expansion will bring total cryogenic processing capacity at Houston Central to 1 bcfd. Copano estimates anticipated capital spending for the expansion and associated facilities to reach about $190 million, with expected in-service of mid-2014.
An initial 400 MMcfd cryogenic processing expansion at Houston Central, announced in 2011, is to start up in first-quarter 2013 (OGJ Online, Apr. 19, 2011).
East Texas ethylene plant to add cracking capacity
Eastman Chemical Co., Kingsport, Tenn., is adding a furnace to one of its three olefin crackers at its plant in Longview, Tex.
Shaw Group Inc., Baton Rouge, has received a contract to provide its technology and engineering services for a new Ultra Selective Conversion furnace. It will also procure the equipment for the furnace.
A spokeswoman for Eastman told OGJ "this additional furnace will increase our capacity, but we are not disclosing the amount of additional capacity or which cracking unit at this time."
In December 2010, Eastman Chemical announced the restart of a previously idled cracking unit at Longview. That increased Eastman's olefin capacity by about 215,000 tonnes and brought to three the company's number of active cracking units.
Eastman's cracking units, said the announcement at the time, produce propylene and ethylene used to make olefin derivatives. That announcement similarly did not disclose the plant's total cracking capacity.
RIL taps Fluor for petcoke, petrochem work
Reliance Industries Ltd., Mumbai, has let a contract to Fluor Corp. covering project management services for a new petcoke gasification plant and expansion of petrochemical facilities at its complex at Jamnagar, Gujarat, India, where it has 1.24 million b/d of refining capacity.
The company said the petcoke gasification facility would be "among the largest such projects ever built" but did not specify capacity. It recently reported cost of the project as $4 billion. The unit, for which Fluor also will provide engineering and procurement services, will supply synthesis gas for use as a plant fuel and source of hydrogen.
Fluor's contract also covers expansion of the refinery's off-gas cracker and downstream petrochemical plants, a captive power plant, and related facilities.
In a recent financial presentation, RIL reported that the refinery off-gas cracker expansion would increase capacities as follows: ethylene to 3.248 million tonnes/year (tpy) from 1.883 million tpy; propylene to 913,000 tpy from 759,000 tpy; monoethylene glycol to 1.466 million tpy from 733,000 tpy; low-density polyethylene to 590,000 tpy from 190,000 tpy; HDPE and LLDPE to 1.478 million tpy from 928,000 tpy; and paraxylene to 3.656 million tpy from 1.856 million tpy.
TRANSPORTATION — Quick Takes
Partners detail British Columbia LNG export project
Partners in one of British Columbia's planned LNG export projects have announced details of the project. Shell, Korea Gas Corp., Mitsubishi Corp., and PetroChina Co. Ltd. said they are developing the proposed LNG export plant near Kitimat, BC.
Shell holds a 40% interest in the LNG Canada project, with Kogas, Mitsubishi, and PetroChina each holding 20%. The proposed project includes design, construction, and operation of a natural gas liquefaction plant, storage, and export of LNG, including marine off-loading and shipping.
LNG Canada will initially have two LNG processing trains, each with capacity to produce 6 million tonnes/year, with an option to expand.
The announcement said the partners will decide whether to move ahead with the project's development after conducting engineering work and environmental assessments, as well as consultations with local communities and other stakeholders.
Start-up could come around the end of the decade.
GOM site chosen for first US floating LNG plant
Excelerate Energy LP, Houston, will develop the first US floating natural gas liquefaction plant for Port Lavaca, between Galveston and Corpus Christi, Tex. The Lavaca Bay LNG project will be designed to export LNG by 2017.
The company said it selected Port Lavaca because of its direct access to the "highly liquid South Texas natural gas market, access to the Atlantic Basin through the Gulf of Mexico, and potential access to the Pacific Basin with the widening of the Panama Canal."
Excelerate's floating liquefaction storage offloading (FLSO) vessel will be able to produce 3 million tonnes/year (tpy), store 250,000 cu m of LNG, and support a "fully integrated" gas processing plant, according to the company's announcement.
The gas processing capability will allow the vessel to "accommodate a wide range of gas compositions at its inlet." When gas processing is not required, when existing processing is available or pipeline-quality gas is the feedstock, the processing equipment can be removed and liquefaction capacity increased to 4 million tpy.
The FLSO will measure 338 m long with a breadth of 62 m.
Front-end engineering and design is in an advanced phase, said Excelerate, which is beginning discussions with "potential off takers and natural gas suppliers as well as investors and potential sources of finance to take the project forward."
Excelerate expects the FEED to last until yearend and, following its completion and successful permitting, project delivery will take about 44 months from final investment decision.
Initially, Lavaca Bay LNG will consist of one permanently moored FLSO with multiple connections to the onshore natural gas grid in South Texas. The project will be designed with the potential for expansion and the addition of a second FLSO for a total production capacity of up to 8 million tpy.
TransCanada to proceed with terminal project
TransCanada Corp. received binding long-term commitments in excess of 500,000 b/d during the open season for its Keystone Hardisty terminal project (OGJ Online, Mar. 1, 2012), allowing it to expand the proposed 2 million bbl of oil batch accumulation tankage and pipeline infrastructure to 2.6 million bbl. Subject to regulatory approvals, TransCanada expects the project to enter service by late-2014.
The terminal project will cost about $275 million.
The 2,154-mile Keystone Pipeline delivers more than 500,000 b/d of oil to the US Midwest and Cushing, Okla.
On May 4, TransCanada applied to the US Department of State for a Presidential Permit for the Keystone XL Pipeline from the US-Canada border in Montana to Steele City, Neb (OGJ Online, May 4, 2012). TransCanada expects to receive the permit and begin construction of Keystone XL in first-quarter 2013, with completion slated for late 2014 or early 2015.
More Oil & Gas Journal Current Issue Articles
More Oil & Gas Journal Archives Issue Articles
View Oil and Gas Articles on PennEnergy.com