OGJ Newsletter

April 12, 2010

General InterestQuick Takes

Shell reviews downstream assets in Africa

Royal Dutch Shell PLC is reviewing its downstream businesses in 21 African countries, saying it hopes to sell them as going concerns.

It has excluded from the review its fuels, lubricants, and refining operations in South Africa as well as its African exploration and production and LNG interests and most of its trading activities in the continent.

Under review are retail, commercial fuels, lubricants (excluding Egypt), LPG, bitumen, aviation, and marine businesses in Morocco, Algeria, Tunisia, Egypt, Ivory Coast, Burkina Faso, Ghana, Togo, Senegal, Mali, Guinea, Cape Verde, Kenya, Uganda, Tanzania, Botswana, Namibia, Madagascar, Mauritius, and La Reunion.

Shell last month said it would cut worldwide refining capacity by 15% and retail operations by 35% and has announced plans to sell its downstream businesses in New Zealand (OGJ Online, Mar. 29, 2010).

Eurogas to buy Talisman's Ontario/Erie assets

Eurogas Corp., Toronto, plans to acquire Ontario oil and gas assets from an undisclosed seller for $131 million. Closing is set for May 27.

Eurogas described the assets—which appear to be those of Talisman Energy Inc.—as "the largest accumulation of oil and natural gas assets in Ontario." Talisman separately announced agreements to sell $1.9 billion (Can.) in assets in Canada to multiple buyers, including the Ontario properties.

The assets, onshore and offshore oil and gas properties in and around Lake Erie, will provide operating cash flow of at least $2 million/month at current low natural gas price levels. The assets include growth potential from numerous development drilling locations, recompletions, and optimizing existing infrastructure.

Eurogas will operate 100% of the acquired production with an average 95% working interest in 65,000 acres onshore and 65% in 902,000 acres offshore.

The properties produce 790 b/d of 42° gravity oil and condensate and 11.1 MMcfd of gas, and reserves are estimated at 2 million bbl of oil and 66 bcf of gas.

Eurogas will also acquire 65% ownership in a fleet of offshore drilling and completion vessels, 65% ownership in three gas processing plants and three compressor stations, all located onshore, 100% ownership in four oil tank batteries onshore, ownership of 13,400 line-km of 2D seismic and 317 sq km of 3D seismic, and potential for underground gas storage field development.

Eurogas, as part of the transaction, is obligated to extend an offer under the same terms and conditions to the holder of the remaining 35% interest in the offshore assets. There is no assurance the holder would agree to sell.

Quantum to buy former Encore assets

Quantum Resources Management LLC plans to buy certain oil and gas assets from Denbury Resources Inc. for $900 million.

Denbury acquired the assets in its $3.2 billion takeover of Encore Acquisition Co. (OGJ, Nov. 9, 2009, p. 26).

The properties being sold are in the Permian basin, the Anadarko basin, and the East Texas basin. Closing is expected in May.

Production of these assets is estimated at 13,000 boe/d. As of Dec. 31, 2009, estimated proved reserves were 54 million boe, of which 64% was natural gas.

The agreement does not include Haynesville shale assets although Denbury executives said they still plan to sell those assets.

Pacific Asia to acquire stake in Oyo oil field

Pacific Asia Petroleum Inc. shareholders have approved the company's pending acquisition of all interest in Oyo oil field off Nigeria held by Camac Energy Holdings Ltd. and its affiliates.

The company expects closing the transaction on Apr. 7. Camac currently owns 60% interest in Oyo field. Field operator Nigerian Agip Exploration Ltd., an affiliate of Italy's Eni SPA, owns the remainder.

Oyo field started production in December 2009 from two subsea wells in 400 m of water about 75 km offshore (OGJ, Dec. 21, 2009, Newsletter).

The field produces through the Armada Perdana floating production, storage, and offloading vessel.

In November 2009, Camac agreed to sell its Oyo interest to Pacific Asia in exchange for 62.74% of the common shares of Pacific Asia and $38.84 million cash.

Pacific Asia of Hartsdale, NY, controls rights to gas acreage in China and is a partner in several Chinese oil fields. Camac International of Houston is a privately-held independent having interests in West Africa and South America.

Exploration & DevelopmentQuick Takes

Eni makes two deepwater oil finds off Angola

A group led by Eni's Angolan unit has reported two deepwater oil discoveries in Block 15/06 about 350 km northwest of Luanda, Angola.

Nzanza-1 and Cinguvu-1 found Lower Miocene oil pay with good reservoir characteristics in 1,400 m of water. Total depths are 3,008 m and 3,023 m, respectively.

Nzanza-1 made more than 1,600 b/d of 18° gravity oil on production tests. Analysis of the results indicates potential for future production wells in excess of 5,000 b/d/well on artificial lift.

Capacity of surface facilities limited Cinguvu-1's production test rate to 6,400 b/d of 23° gravity oil.

Nzanza and Cinguvu follow the group's Sangos-1 and N'Goma-1 discoveries in 2008 and Cabaca Norte-1 in 2009 in confirm the block's potential.

Angola's state Sonangol EP is the concessionaire for Block 15/06. Block interests are Eni 35%, SSI Fifteen Ltd. 20%, Sonangol Pesquisa e Producao SA 15%, Falcon Oil Holding Angola SA 5%, Petrobras International (Braspetro) BV 5%, and Statoil Angola Block 15/06 AS 5%.

Anadarko tests 7,500 b/d rate on Wahoo DST

The first of two planned drillstem tests in the presalt Wahoo field in the Campos basin off Brazil confirmed the world-class nature and productivity of the reservoirs, said Anadarko Petroleum Corp.

The company believes the Wahoo-1 well on the BM-C-30 block to be capable of producing at a rate well in excess of 15,000 b/d of oil after it sustained 7,500 b/d of 31° gravity oil and 4 MMcfd of associated gas limited by equipment and facilities.

Anadarko plans to move the equipment to the Wahoo-2 well 5 miles north for another DST. Test data will help the partnership draft a development plan for the field, which has an estimated gross resource potential of more than 300 million bbl of oil.

After the second DST, Anadarko will move the drillship 5 miles south of the Wahoo discovery well to drill the Wahoo South exploration well on Block BM-C-30.

An Anadarko subsidiary has a 30% working interest and is operator of BM-C-30. Devon Energy Corp. holds a 25%, IBV Brasil Petroleo Ltda., a subsidiary of Bharat PetroResources Ltd. and Videocon Industries, holds 25%, and SK Energy Co. Ltd. has 20%.

Alberta Colorado shales joint venture forms

Stealth Ventures Ltd., Calgary, signed a joint venture with MOI Resources Ltd., a private Saskatchewan operator, to develop gas in the Cretaceous Colorado Group shales resource play in western Canada. Terms are not disclosed.

The Cretaceous Colorado Group in the Western Canadian Sedimentary Basin is represented almost continuously in a 1,000-km east-west profile. Of the more than 250,000 wellbores that penetrate the Colorado, most were drilled to target deeper horizons.

Meanwhile, following Stealth's initial downspacing approval by the Alberta Energy Resources Conservation Board to proceed with eight wells per square mile on two sections of land in the Wildmere, Alta., area, Stealth has added 17 more sections.

Consulting engineers completed extensive rate transient analysis on location 15-10-50-06 w4m, which had over 2 years of production data, and showed that ultimate well density will approach 18 wells per section (36-acre spacing) to ultimately drain the resource before interference occurs.

A further 11 sections are awaiting a board decision, and the remaining Stealth acreage totaling 80+ sections (gross) are in process with Fekete. With full spacing approval, Stealth will have hundreds of locations available for development.

EOG pursues Denver basin fractured Niobrara

EOG Resources Inc. has built a position of 400,000 net acres in a horizontal play for oil and gas in Cretaceous Niobrara fractured shale in the Denver-Julesburg basin.

The company is running two rigs and plans to drill several exploratory wells in 2010. The targets lie in Wyoming north of Silo field, developed in Laramie County in the 1990s, and in Wyoming and Colorado south of Silo.

The leased acreage contains several areas with Niobrara potential, and other geologic objectives provide further upside, said EOG, which is still acquiring acreage.

The EOG Jake 2-01H, in 1-11n-63w, Weld County, Colo., about 20 miles south of the east edge of Silo field, produced 50,000 bbl of oil in its first 90 days on production in the third quarter of 2009, EOG said. Its maximum initial rate was 1,558 b/d of oil and 350 Mcfd of gas from a stimulated lateral in Niobrara.

EOG has drilled four other wells in the immediate area. Elmer 8-31H had a maximum stimulated rate of 730 b/d, and Red Poll 10-16H made 1,100 b/d unstimulated. Critter Creek 2-03H and 4-09H await completion.

Flow rates haven't stabilized, and it is too early to estimate reserves, EOG said. It called the initial rates encouraging and said long-term performance is needed to understand the economics of the play.

The company estimated the cost of a completed well at $3.4 million and said it is testing several completion techniques.

Industry Scoreboard

Drilling & ProductionQuick Takes

Bakken well yields oil, gas at record rate

A long horizontal well completed in the Bakken formation has produced oil and gas at an early 24-hr peak flow back rate, said Brigham Exploration Co., Austin.

Rate was 4,335 b/d of oil and 4.79 MMcfd of gas at the Sorenson 29-32 1H, for a combined rate of 5,133 boe/d. That rate represents an apparent record production level for the more than 2,700 horizontal wells in the Williston basin based on publicly reported data, the company said.

Brigham has a 95% working interest in the well, which was completed with 27 frac stages, perf and plug, and ceramic proppant. The well is in the Ross area of Mountrail County.

Based on this updated production performance, Brigham has completed five long-lateral high-frac stage wells in Ross with an average early 24-hr peak flow back rate of about 2,980 boe/d.

Italian flow starts from Annamaria gas field

Gas production has begun from the Italian side of Annamaria field straddling the border with Croatia in the northern Adriatic Sea.

Eni SPA, operator, said the Annamaria B platform was flowing about 800,000 cu m/day and will produce 1.2 million cu m/day when fully on stream.

Gas flows through a pipeline to a treatment plant at Fano, Italy, about 70 km away.

Production started last November from six wells of the Annamaria A platform on the Croatian side. Production there is about 800,000 cu m/day.

Annamaria field, with reserves of 10 billion cu m, lies in 60 m of water about 30 km south of the southern end of Ivana field in Croatian waters.

In the Annamaria B platform, Eni holds a 90% interest, and Ligestra, Rome, holds 10%.

Eni operates the Annamaria A platform through a 50% interest in INAgip, a joint operating company with INA of Croatia.

The platforms were built by a consortium of Rosetti Marino, Saipem Energy Services, and Intermare Sarde in Italian yards and Marina di Ravenna, Arbatax, and the Rijeka yard in Croatia.

Shell awards Perdido Stage 2 contract

Royal Dutch Shell PLC has awarded a contract to FMC Technologies Inc. for the supply of subsea and topsides equipment and controls for the Perdido Stage 2 development.

Production through the Perdido spar on Gulf of Mexico's Alaminos Canyon Block 857 in 8,000 ft of water began late last month (OGJ Online, Mar. 31, 2010).

The contract includes the supply of five subsea production trees and three subsea water injection trees, each rated at 10,000 psi. FMC will also manufacture and provide subsea and topsides controls, manifold, tie-in equipment, and other systems and services.

FMC said deliveries will commence in the third quarter.

Total orders equipment for Laggan-Tormore

Total Exploration & Production UK Ltd. placed a $210 million order with FMC Technologies Inc. for subsea production equipment for the Laggan-Tormore field development west of Shetlands. Laggan-Tormore fields lie offshore in about 1,950 ft of water (OGJ Online, Mar. 24, 2010).

FMC will supply and manufacture nine subsea trees, eight wellheads, and two six-slot manifolds. FMC will also provide 12 multiphase meters, 10 subsea control modules, and associated control systems.

The company will manufacture and assemble the equipment at its facilities in Dunfermline, Scotland, and Kongsberg, Norway, and at its Multi Phase Meters AS operation in Stavanger.

It has scheduled deliveries starting in first-quarter 2011.

Dong Energy (20%) is Total's partner in developing Laggan-Tormore.

Processing — Quick Takes

New BC gas plant obtains NEB approval

Canada's National Energy Board has approved a new gas plant to serve increased shale gas production from the Horn River basin in British Columbia.

Spectra Energy Corp.'s BC Field Services subsidiary will build the 250-MMcfd Fort Nelson North gas processing plant on about 200 acres 75 km northeast of Fort Nelson, BC.

The new plant will expand the company's processing services to basin producers, adding to capacity at the older 1-bcfd Fort Nelson gas plant, which OGJ gas processing data show has been operating at less than 500 MMcfd. The new plant is north and west of the existing plant.

A company spokesperson said gas to the new plant will be very dry. A single train at the plant will separate carbon dioxide and dehydrate and sweeten the inlet stream. Residue gas, she said, will then flow by pipeline to an interconnection with the existing 30-in. Fort Nelson main line taking gas to eastern and southern markets.

A year ago, Spectra Energy announced it had received firm commitments of 760 MMcfd from seven producers operating in the Horn River basin for gathering and processing capacity. Those commitments have since been turned into firm contracts.

They are in support of Spectra's activities to expand gathering and processing in the Fort Nelson area to accommodate as much as 830 MMcfd of incremental gas from Horn River producers.

Spectra Energy President Greg Ebel said last year the company's plan involved staged expansions of existing Fort Nelson area infrastructure.

The expansion program began last year and will run into 2012. It includes reactivating 500 MMcfd of existing capacity at the Fort Nelson gas plant, looping and reconfiguration of area gathering and compression, and construction of the Fort Nelson North plant at Spectra Energy's existing Cabin Lake compressor station—the subject of the NEB's recent ruling.

The existing Fort Nelson plant is the largest sour-gas processing plant in North America, says Spectra, and the only one processing Horn River gas.

On completion in 2012, said the Spectra Energy spokesperson, the company will have more than 1.2 bcfd of raw gas processing capacity and associated gathering pipelines in the area, including the 250 MMcfd new Fort Nelson North plant.

Sunoco completes sale of PP business

Sunoco Inc. has completed the previously announced sale of the stock of its subsidiary Sunoco Chemicals Inc., comprised of its polypropylene (PP) business, to Braskem SA for about $350 million (OGJ Online, Feb. 1, 2010).

Included in the sale were manufacturing facilities in Marcus Hook, Pa.; La Porte, Tex.; and Neal, W.Va., which have the combined capacity to produce about 2.1 billion lb/year of PP. The sale also included a research and technology center located in Pittsburgh.

Petroplus eyes options for French refinery

Petroplus Holdings AG, Zug, Switzerland, is considering the sale of its 84,800-b/d refinery at Reichstett, France.

Citing "required future capital investments at the site," the company said it will "evaluate strategic alternatives, including the potential sale of the refinery."

It said it plans to operate the refinery and "make the necessary investments required for compliance with environmental, health, and safety standards" while conducting its review.

Petroplus bought the Reichstett refinery and the 161,800-b/d Petit Couronne refinery in France from Royal Dutch Shell PLC in 2008. According to Oil & Gas Journal's Worldwide Refining Survey, the Reichstett refinery's processing capacities include 17,750 b/cd of thermal cracking, 13,420 b/cd of fluid catalytic cracking, 12,900 b/d of semiregenerative cat reforming, and 20,200 b/cd of cat hydrotreating for reformer feed (OGJ, Dec. 21, 2009, p. 46).

Qatar's condensate refinery at capacity

The 146,000-b/d condensate refinery at Ras Laffan, Qatar, is operating at full capacity, officials of Qatargas, the operator, said at an inauguration ceremony.

The facility, first of its kind in Qatar and one of the world's largest, started up last September after a series of delays (OGJ, Apr. 20, 2009, Newsletter).

It has distillation units, naphtha and kerosine hydrotreaters, a hydrogen unit, and a saturated gas plant.

Production capacities are 63,000 b/sd of naphtha, 52,000 b/sd of kerosine jet fuel, 24,000 b/sd of gas oil, and 8,000 b/sd of LPG.

The Laffan Refinery processes field condensate produced by Qatargas and RasGas.

Project interests are Qatar Petroleum 51%; ExxonMobil Corp., Total SA, Itemitsu, and Cosmo 10% each; and Mitsui and Marubeni 4.5% each.

Transportation — Quick Takes

Yemen starts up second LNG train

Yemen LNG has started up its second LNG train. Combined with the first train, the Balhaf plant's nameplate capacity has now reached 6.7 million tonnes/year.

Feed gas for the plant flows nearly 200 miles to the LNG plant on Yemen's southern coast from Block 18 in central Yemen's Marib.

A press statement from partner Total SA (39.62%) said initial investment in the venture was about $4.5 billion. Other partners are state-owned Yemen Gas Co. (16.73%), Hunt Oil Co. (17.22%), SK Energy (9.55%), Korea Gas Corp. (6%), Hyundai Corp. (5.88%), and Yemen's General Authority for Social Security and Pensions (GASSP, 5%).

Since start-up of Train 1, said the statement, 18 cargoes of LNG have moved to South Korea, the US, China, Spain, and Mexico.

South Hook LNG terminal completes final phase

The South Hook LNG terminal at Milford Haven, South West Wales, has completed commissioning its second and final phase.

The event brings the terminal to full processing capacity of 15.6 million tonnes/year and full sendout capacity into the UK National Transmission System of 21 billion cu m/year (about 2 bcfd). The terminal received its first cargo in March 2009 (OGJ Online, Mar. 23, 2009).

Operator South Hook LNG Terminal Co. Ltd. calls the terminal Europe's largest. It is a part of the supply chain of the Qatargas 2 integrated value chain, which begins with liquefaction at Ras Laffan Industrial City, Qatar, fed by 30 wells and three platforms in Qatar's North field. Gas is liquefied in Trains 4 and 5 at Ras Laffan, loaded onto specially built LNG carriers, and shipped to the South Hook terminal.

South Hook LNG is jointly owned by Qatar Petroleum LNG Services Ltd. (67.5%), ExxonMobil Corp. (24.15%), and Total SA (8.35%).

Also at Milford Haven is the 4.4 million cu m/day Dragon LNG terminal jointly owned by BG Group (50%), Petronas (30%), and 4Gas (20%), Rotterdam. It started up in second-half 2009 (OGJ Online, Sept. 2, 2009) with sendout capacity of 1.2 million cu m/hr (about 1 bcfd).

El Paso granted FERC approval for Ruby pipeline

El Paso Corp. announced Apr. 5 it had received US Federal Energy Regulatory Commission approval for its Ruby Pipeline project. Ruby is a 675-mile, 42-in. OD interstate natural gas pipeline that will ship Rockies supplies to consuming markets in California, Nevada, and the Pacific Northwest.

Ruby will use four compressor stations totaling 160,500 to transport natural gas from an existing supply hub at Opal, Wyo., to interconnections near Malin, Ore., at an initial design capacity of up to 1.5 bcfd. Pending receipt of rights-of-way from the US Bureau of Land Management, construction of the $3 billion project is scheduled to begin in late spring 2010 to meet a March 2011 in-service date.

El Paso also said it has entered into agreements with Global Infrastructure Partners, whereby GIP will invest up to $700 million in the Ruby project and upon satisfaction of various closing conditions acquire a 50% equity interest in the project.

FERC issued its final environmental impact statement on Ruby Jan. 8, 2010, saying any potential impacts could be mitigated with use of appropriate measures (OGJ Online, Jan. 11, 2010).

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, Mar. 11, 2010).

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