General Interest — Quick Takes
API, NPRA legally challenge new EPA RFS2
The American Petroleum Institute and the National Petrochemical & Refiners Association filed separate legal challenges of the US Environmental Protection Agency's final rule for the second stage of the Renewable Fuel Standard program (RFS2), which EPA published on Mar. 26.
The rule, which missed by a year the deadline established under the 2007 Energy Independence and Security Act (EISA), combines the 2009 and 2010 biomass-based diesel volumes and makes the entire rule retroactive to Jan. 1, API said in a statement. The two associations filed their petitions for a review of the regulation with the federal appeals court for the District of Columbia.
"The petition NPRA filed today does not challenge the overall RFS2 program and does not call into question the import role renewable fuels play in our nation's transportation mix," NPRA Pres. Charles T. Drevna said on Mar. 29. "Rather, our concern is with the unreasonable retroactive application of certain provisions of the rule and fundamental fairness in the implementation of policy."
Drevna said EISA required EPA to promulgate and finalize certain standards under the RFS2 program by specific 2008 and 2009 dates. "The agency, however, failed to meet those statutory deadlines. Instead, in its recently published RFS2 final rule, EPA retroactively and unlawfully imposed RFS2 compliance burdens on obligated parties, many of whom are NPRA members," he said.
API, meanwhile, said it considers the regulation unlawful and unfair. "While the US oil and natural gas industry recognizes and appreciates the role of ethanol and other biofuels in the fuel marketplace, we are deeply concerned that [EPA's] final RFS2 rule could result in higher consumer costs," its statement continued. "By setting retroactive requirements, refiners, and ultimately consumers, will be penalized for EPA's inability to get this rule out on time as directed by Congress."
"Simply put, the fact that EPA failed to meet its statutory obligations under current energy law does not give the agency license to impose retroactively additional compliance burdens on obligated parties," said Drevna. "At the least, such action calls into serious question the fundamental fairness of EPA's RFS2 rule-making process."
Statoil, Chesapeake adding Marcellus acreage
Statoil ASA has signed an agreement with Chesapeake Energy Corp., Oklahoma City, that will add 59,000 net acres to Statoil's current 600,000 net acre positions in the Marcellus shale in the Appalachian basin.
Statoil put the transaction cost at $253 million, or $4,325/acre.
As part of Statoil's 2008 joint venture agreement with Chesapeake, Statoil has the right to periodically acquire its share of leasehold that Chesapeake continues to acquire in the Marcellus shale. Statoil has now exercised such acquisition rights on a series of Chesapeake Marcellus shale acquisitions.
Statoil has seen encouraging production performance since the entry into the Marcellus play in late 2008. This new acreage is expected to strengthen Statoil's position and its cooperation with Chesapeake as the largest lease holders in one of the most prospective US shale gas plays. The acquisition will enable the partnership to optimize its development activity and secure additional developments in the play. Statoil expects to continue to grow its Marcellus position together with Chesapeake (OGJ, Feb. 1, 2010, p. 34).
Andy Winkle, vice-president for the Marcellus Asset, said, "We were an early mover into the Marcellus and we will continue to build a long term position in what we expect will become a legacy asset and reach our goal of 50,000 b/d of oil equivalent production by 2012."
Magellan buys into Evans Shoal field
Magellan Petroleum Australia Ltd., Brisbane, has acquired the 40% share in undeveloped Evans Shoal natural gas field in the Timor Sea from Santos Ltd., Adelaide. Evans Shoal lies on permit NT/P48. Magellan will pay Santos $100 million (Aus.) cash over several tranches with final payment due in this year's second half. Magellan also will pay $50 million (Aus.) on any final investment decision to develop Evans Shoal and another $50 million (Aus.) upon first gas production from NT/P48.
Magellan made the acquisition after being awarded the adjacent NT 09-1 exploration permit in the 2009 acreage release.
The company has an agreement with an unnamed methanol producer for construction and operation of a possible onshore methanol plant near Darwin.
Evans Shoal was originally found by BHP Petroleum in 1988 and confirmed by Timor Sea Petroleum in the 1990s.
The field, although large with an estimated 6.6 tcf of gas, has a high carbon dioxide content similar to other nearby fields in this part of the Timor-Arafura Sea north of Darwin, which has been a stumbling block to development.
However, high CO2 is a plus for methanol production and at one stage the MEO Australia Ltd. group tried to make a deal with the Evans Shoal group to feed into its proposed Tassie Shoals offshore artificial island methanol and LNG development proposal.
A similar outlet for the CO2 appears to be a part of Magellan's plans. The company says Evans Shoal is unique in its fit with Magellan's strategies. It hopes to work with the other members of the field joint venture (Petronas Carigal 25%, Shell Australia 25%, and Osaka Gas 10%) to come up with a development plan.
The sale is part of Santos' move to dispose of noncore assets. Santos recently sold a 60% stake in the Petrel, Term, and Frigate fields in the Bonaparte Gulf to GDF Suez for $220 million (Aus.).
Exploration & Development — Quick Takes
Apache tests Egypt Faghur basin oil, gas find
Apache Corp., Houston, has gauged a field discovery in Egypt's Faghur basin at the rate of 4,554 b/d of oil and 10.1 MMcfd of natural gas.
Flow came from 105 ft of net pay in Jurassic Safa at the West Kalabsha I-1X well, 10 miles southwest of the company's Phiops field in the Western Desert.
As the result of a string of discoveries in the area, Apache is expanding processing and transportation that will enable production capacity to climb to 40,000 b/d in late 2010 from 8,100 b/d. Apache also sees shortened duration to production from concept.
The most recent discovery elevates the Safa to primary objective status in the basin. The company established Safa production at West Kalabsha-C and Phiops.
The I-1X well, on a 3D seismic prospect, cut pay in more than 200 ft of total sand, demonstrating the potential size of Safa accumulations in the basin. The company has finished two 3D seismic surveys in the basin and is about to start shooting its largest survey of the year to the west, along the trend established by recent discoveries, in an area void of 3D but where regional 2D data indicate promising geological features.
Apache owns a 100% contractor interest in the West Kalabsha concession and plans to drill four more exploratory wells targeting the Alam el Bueib and Safa formations in the Faghur basin in 2010. Apache will drill an appraisal well 2 miles southwest of the latest discovery before it formulates full development plans.
Alange exploring Cubiro block in Llanos basin
Alange Energy Corp., Toronto, has spud the Cubiro Este-1 and Copa-1 exploration wells on the Cubiro block in the eastern Llanos basin of Colombia.
The wells, projected to Carbonera at 6,185 ft and 5,985 ft, respectively, follow the company's February 2010 Barranquero-1 discovery that is producing 700 b/d of 28° gravity oil, natural, with 3% basic sediment and water. A 250-sq-km 3D seismic survey and structural mapping confirmed a number of high-prospectivity well locations.
Alange plans to spud the Criollo-1 exploration well on Apr. 15 to 6,210 ft in Carbonera. Then it will drill a Barranquero appraisal well. The company' $24 million 2010 capital plan includes drilling the aforementioned four exploration wells plus seven appraisal wells. It also includes two well workovers and $2.1 million for the acquisition of 68.7 sq km of 3D seismic currently being shot, and would target a combined resource of 7.3 million bbl of oil in the Turpial, Azulejo, and Careto Sur prospects.
The company has announced exploration-appraisal success at four wells in the Cubiro block in the last 4 months, namely Careto-5, Careto-6, Careto-8, and Barranquero. Alange has working interests in 12 properties in four basins in Colombia.
ExxonMobil to take stake from Statoil Tanzania
ExxonMobil Exploration & Production Tanzania Ltd. agreed to take a 35% interest in deepwater Block 2 off Tanzania from operator Statoil Tanzania AS.
The Tanzania government approved the transaction earlier this month. Statoil now holds 65% interest in the 11,099-sq-km block for which it signed a production-sharing agreement in 2007.
A 3D seismic survey was completed in February.
Drilling & Production — Quick Takes
Shell begins production at Perdido
Royal Dutch Shell PLC began production through the Perdido spar facility, which lies in about 8,000 ft of water on Alaminos Canyon Block 857 in the Gulf of Mexico about 200 miles south of Freeport, Tex., and 8 miles north of the international maritime border with Mexico.
Shell said the facility set a water depth record for a drilling and production facility.
The facility will handle production from Great White, Silvertip, and Tobago fields. Designed capacity of the facility is 100,000 bo/d and 200 MMscfd of gas.
Shell said that production from Great White is the first from the gulf's Lower Tertiary section. So far the company has drilled six development wells in Great White of which five are producing wells and one is an injection well. Shell notes that it may need as many as 35 wells to develop the three fields.
Perdido is the first spar with direct vertical access wells, Shell said. Besides these wells, the development will also require remote subsea completed wells.
Because of the low pressure and temperature of the fields, Shell has installed an innovative subsea separation and boosting system that can lower back pressure on the wells by about 2,000 psi.
Shell acquired its first leases in the area in 1996 and discovered Great White in 2002. It moored the spar on location in late 2008 and installed the topsides in early 2009.
Shell said Great White represents about 80% of Perdido's total estimated production.
Besides the Lower Tertiary sands, Shell said the area also has prospective shallow Frio sands, which it has tested with two horizontal wells. The sands lie about 3,000 ft below the mudline.
Shell operates the facility and has a 35% interest in the development. The other interest owners are Chevron USA Inc. 37.5% and BP Exploration & Production Inc. 27.5%.
ATP starts oil production from Telemark Hub
ATP Oil & Gas Corp. has begun producing its deepwater Atwater Valley Block 63 No. 4 well of the Telemark Hub in about 4,000 ft of water in the Gulf of Mexico. The well is produced to ATP's Titan deep-draft floating drilling, and production platform.
ATP started production from the Telemark hub in about 4,000 ft of water in the Gulf of Mexico.
T. Paul Bulmahn, ATP's chairman and chief executive officer, said, "Although ATP slowed development and capital expenditures during 2008-09, this billion-dollar deepwater project is now on production within 46 months from acquisition of the first Telemark Hub property. That is only 3.8 years from acquisition by ATP to first production in 4,000 ft of water."
Bulmahn said, "Offshore data shows that the average for deepwater developments utilizing tension-leg platforms is 94.3 months or just under 8 years and spar installations averaged 55.6 months or just under 5 years from discovery to first production."
ATP said the next Telemark Hub well scheduled to produce is Mississippi Canyon 941 No. 3. The well was drilled to 20,043 ft and encountered 266 ft of net pay sands, about triple the 87 ft of net pay sands found in the original discovery well, ATP said.
ATP drilled the third well, MC 941 No. 4, and the fourth well at MC 942 No. 2 to 12,000 feet and this year plans to finish drilling and completing the wells to TD.
ATP owns a 100% working interest and is the operator Telemark Hub.
CNOOC starts production from oil fields
CNOOC Ltd. has started oil production from WeiZhou 11-1 east field (WZ 11-1E) in western South China Sea and from BoZhong (BZ) 3-2 field in Bohai Bay.
WZ 11-1E oil field lies in 40 m of water in the Beibu Gulf basin. The field's development and production operation will rely mainly on the facilities of the adjacent field, WZ 11-1. CNOOC expects WZ 11-1E, currently with 3 wells on line, to reach a 3,000 bo/d peak production within the year.
BZ 3-2 lies in 25 m of water in the central part of Bohai Bay about 20 km southeast of producing field Qinhuangdao 32-6. The development uses a self-elevating producing platform to reduce costs.
Seven wells currently are on line and CNOOC expects production to reach a peak 4,800 bo/d this year.
CNOOC Ltd. is the operator and holds 100% interest in the fields.
Processing — Quick Takes
Marathon starts expanded Garyville refinery
Marathon Oil Corp. has integrated and started up the 180,000-b/d expansion of its Garyville, La., refinery, bringing total crude capacity to 436,000 b/d. Both trains are on stream (OGJ Online, Mar. 11, 2010).
Marathon completed construction of the expansion facility late last year. While starting up the new equipment early this year, the company conducted an extensive turnaround of the existing plant, which was shut down.
New processing units include a 44,000-b/d coker, a 65,000-b/d reformer, a 70,000-b/d hydrocracker, a 74,000-b/d kerosine hydrotreater, and sulfur and hydrogen plants.
The project boosted output capacities at Garyville to 290,000 b/d from 190,000 b/d of gasoline and to 175,000 b/d from 95,000 b/d of diesel.
HPCL upgrading its refineries in India
Hindustan Petroleum Corp. Ltd. (HPCL) is upgrading its two refineries in India to meet Euro 4 emissions standards for high-speed diesel and gasoline.
HPCL recently let two engineering, procurement, construction, and commissioning contracts to Technip for diesel desulfurization at its 164,000-b/cd Visakh refinery in Andhra Pradesh on India's east coast. Under one contract, Technip will provide a 2.2-million tonne/year diesel hydrotreater. The other contract is for a 36,000 tpy hydrogen generation unit.
Among other work at Visakh, HPCL is adding a single-point mooring unit able to handle very large crude carriers, which can't now reach the refinery because of draft restrictions. It also has reported plans for a delayed coking unit.
At its 132,000-b/cd Mumbai refinery, HPCL is installing a 2.2-million tpy diesel hydrotreater and a 20,000-tpy hydrogen generation unit as well as a 1.4-million tpy FCCU, which will join a 1-million tpy FCCU in place.
Also at the Mumbai refinery, HPCL is studying feasibility of adding a solvent deasphalting unit.
Shell to exit New Zealand downstream
Royal Dutch Shell PLC, after announcing plans to trim its refining and marketing operations, has reported an agreement to sell its downstream businesses in New Zealand.
Shell will sell its 17.1% interest in the 104,000-b/d refinery at Marsden Point and its network of more than 220 retail outlets to Aotea Energy Ltd., a consortium of Infratil Ltd. and the Guardians of New Zealand Superannuation. The consortium will manage the interest through its operating company, Greenstone Energy Ltd.
Shell is to receive a cash payment of $696.5 million (NZ) with a working capital adjustment.
Earlier this month, Shell executives disclosed plans to cut worldwide refining capacity by 15% and retail operations by 35% (OGJ Online, Mar. 22, 2009). Marsden Point, owned by New Zealand Refining Co., is the country's only refinery. Other major shareholders in New Zealand Refining are BP PLC, Chevron Corp., ExxonMobil Corp., and Emerald Capital.
Pemex refineries due desulfurization units
Pemex Refining let a $622 million engineering, procurement, and construction contract to ICA Fluor for gasoline desulfurization trains at two refineries.
The contractor will install, test, and start up catalytic desulfurization units with 25,000 b/d capacities each, associated amine regeneration units, and related facilities at the 185,000-b/cd Minatitlan and 330,000-b/cd Salina Cruz refineries.
The work is to be complete in mid-2013.
ICA Fluor is a joint venture of Empresas ICA SAB de CV and Fluor Corp.
Transportation —Quick Takes
Sinopec launches Sichuan-Shanghai gas line
China Petroleum & Chemical Corp. (Sinopec) said it has started transporting natural gas through the recently completed $9.4 billion Sichuan-Shanghai pipeline.
According to Sinopec Chairman Su Shulin, the 1,655-km trunk line can transport 12 billion cu m (bcm)/year of gas from Puguang gas field in Sichuan province to Shanghai and eight other provinces or municipalities along the way.
In addition to the main line, Su said development of the project also involved exploration and development of Puguang field, construction of acidic gas treatment facilities, and five branch lines.
To secure ample supplies of gas, Su said Sinopec has been exploring areas adjacent to Puguang, and has confirmed 451.8 bcm of gas reserves. Sinopec also has discovered 464.8 bcm of probable gas resources and 575 bcm of possible gas reserves.
Earlier this month, Zhou Yuan, Sinopec senior consultant, said the state firm plans to produce 4 bcm of gas from Puguang field and transport it to eastern China via the new line this year.
Zhou said Puguang output alone will increase Sinopec's overall gas production by 50% in 2010, as well as create a major revenue stream for the company amid growing gas demand.
Puguang is Sinopec's largest gas field, according to Zhou, who added that the proved reserves of the field and nearby areas come to 489 bcm.
According to Zhou, Sinopec has completed well-drilling and construction at 16 gas-collecting substations, one main gas collecting station, and gas desulfurization unit with a 12 bcm/year capacity.
In October, Sinopec said production from Puguang in 2010 would reach 4 bcm, rising to 8 bcm in 2011. Puguang has a production capacity of 10.5 bcm, which Sinopec said will allow the field to maintain a stable output for at least 20 years.
TransCanada gets OK for Alaska open season
TransCanada Alaska Co. LLC received approval with modification Mar. 31 from the US Federal Energy Regulatory Commission for its detailed plan for conducting an open season to make binding commitments for initial capacity on its natural gas Alaska Pipeline Project.
FERC said while TransCanada's plan generally complies with its open season regulations, the commission will require the company to make two modifications. First, TransCanada must immediately open its data room to allow prospective bidders sufficient time to review needed information. The company also must make certain revisions to its plan to comply with the commission's standards of conduct.
TransCanada plans to issue its open season notice no later than Apr. 30, and expects to close it 90 days later on July 30.
Two options will be submitted for shipper assessment in the open season. The first option is a 1,700-mile line from Alaska's North Slope to Alberta, from where the gas could be delivered on existing pipeline systems to the US. The second option would transport gas 800 miles from ANS to Valdez, Alas., where it would be converted to LNG in a facility to be built by others and then delivered by ship to North American and other international markets.
Both options would allow offtake by Alaskan customers. Both also would include a gas treatment plant and a 58-mile pipeline from Point Thomson fields to the plant and main transmission line (OGJ Online, Jan. 29, 2010).
French court upholds Total liability in Erika spill
A judgment handed down Mar. 31 by the Paris Court of Appeal confirmed that Total SA "had been imprudent" in implementing its vessel-vetting process for the Erika tanker, which spilled oil in December 2009 that damaged 400 km of Brittany's coast. The court ordered Total to pay a €375,000 fine.
The court decided, however, that Total could not be held responsible on civil grounds for deliberately taking the risk of chartering the vessel and was found not liable under international conventions.
In what was considered a first, the court also confirmed and broadened the meaning of "ecological damage"—a notion hailed by Energy and Ecological Minister Jean-Louis Borloo and many environmentalist organizations. Following the Erika spill, the European Union imposed new marine safety rules including the enforced use of double-hulled tankers.
Total pointed out that following the Paris Criminal Court's Jan. 16, 2008, decision, it had (without admitting liability) paid €171.5 million in full as final settlement to the civil plaintiffs. It also spent more than €200 million to clean up the coast, pump the cargo remaining in the Erika wreck, and treat the remaining waste.
The group is now considering whether or not to take the case to the Cour de Cassation, the French Supreme Court of Appeal.
Enbridge plans Marcellus-Chicago NGL pipeline
Enbridge Inc. announced Mar. 22 plans to develop an NGL pipeline from the Marcellus shale in southern Pennsylvania and northern West Virginia to the US Midwest. The proposed line would deliver into an existing NGL system in the Chicago area, including the Aux Sable facility, which processes gas from Alliance pipeline, fractionates NGLs from various supply sources, and has spare fractionation capacity.
Enbridge says other NGL markets, including Ontario, Can., could also be accessed from Chicago utilizing the existing system.
Enbridge will develop, construct, own, and operate the planned NGL line. The company is evaluating various routing and market alternatives and anticipates moving forward with an open season in this year's second quarter.
Buckeye Partners LP and Nova Chemicals Corp. last month signed a memorandum of understanding regarding evaluation and development of a mixed NGL pipeline extending 400 miles from the Marcellus basin in Pennsylvania to the refining and petrochemical complex in the Sarnia-Lambton area of Ontario (OGJ Online
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