GENERAL INTEREST — Quick Takes
Linn Energy to buy Jonah, Pinedale gas assets from BP
Linn Energy LLC agreed to buy BP America Production Co.'s holdings in Jonah and Pinedale natural gas fields for $1 billion in a cash transaction expected to close by July 31.
"This acquisition provides Linn with a significant operated position in the Green River basin of Wyoming," said Mark E. Ellis, Linn chairman, president, and CEO. The properties are expected to provide 145 MMcfd equivalent of liquids-rich gas production, Ellis added.
BP CEO Bob Dudley said, "This sale will allow us to realize the value of the mature Jonah assets and reinvest in higher growth opportunities in BP's North America gas business and elsewhere." Since January 2010, BP has divested $24 billion. BP expects the total will reach $38 billion by yearend 2013.
Lynn is buying BP's operations center in Sublette County, Wyo., and all of BP's working interest in 260 operated wells with net BP production of 80 MMscfd of gas equivalent and nonoperated wells with net BP production of 66 MMscfd.
BP said its production operations in Moxa and Wamsutter, Wyo., are unaffected by the sale.
Mitsui to buy BP's stake in UK North Sea fields
Mitsui & Co. Ltd. plans to buy BP PLC's interests in the Alba and Britannia fields in the UK North Sea for $280 million, subject to regulatory and other licensee approvals.
BP holds 13.3% interest in Alba and 8.97% interest in Britannia. Closing is expected by the end of the third quarter. Net BP production from the two fields averages 7,000 boe/d compared with BP's total 200,000 boe/d of North Sea production.
Trevor Garlick, BP North Sea regional president, said the divestments are part of BP's strategy to develop a more focused business in the UK and Norway. BP expects to invest $10 billion over 5 years in the North Sea, including major projects in the UK and in Norway.
Rosneft, Statoil, Eni advance joint ventures
Rosneft has signed contracts advancing its strategic cooperation agreement with Statoil SA to cover projects in Russia and setting up joint ventures under a similar agreement with Eni SPA (OGJ Online, May 7, Apr. 25, 2012).
The new contracts between Rosneft and Statoil provide for the formation of JVs between Rosneft JV Projects SA and Statoil Petroleum AS to seek licenses in the Barents Sea offshore Norway in the country's 22nd bidding round. Rosneft will form a Norwegian subsidiary, which will apply for 33.33% interests in licenses blocks.
Rosneft and Statoil also signed an agreement to jointly evaluate high-viscosity oil beneath the gas cap in Sever-Komsomolsk field in the Yamalo-Nenets Autonomous District of Western Siberia and oil shale deposits in the Khadumsky formation in Stavropol Territory. If development proceeds, the companies will set up an operating company held 66.67% by Rosneft and 33.33% by Statoil. Statoil will pay for desktop study and pilot-phase work including seismic surveys, drilling, testing, pilot production research, and modeling.
The Rosneft-Statoil strategic cooperation agreement, signed on May 5, also covers exploration of blocks in the Russian Barents Sea and Sea of Okhotsk. The companies are still working on structure of that cooperation.
Eni and Rosneft signed their initial agreement, covering joint development of specific licenses in the Black and Barents seas offshore Russia, on Apr. 25.
The new contracts provide for creation of the joint ventures envisioned by the original agreement, with Rosneft holding 66.67% interests and Eni 33.33%. Eni will pay costs of geological exploration required by license terms and pay its share of license acquisition costs. The Italian company also will reimburse much of the historical exploration expenses on a Black Sea block, Western Chernomorsky.
Rosneft also has formed an upstream partnership with ExxonMobil covering exploration of the Kara and Black Seas and providing the Russian interests or options to acquire interests in West Texas, the Gulf of Mexico, and western Alberta (OGJ Online, Apr. 17, 2012).
Pertamina to buy Harvest's Venezuelan assets
HNR Energia BV, a wholly owned subsidiary of Harvest Natural Resources Inc., has signed a definitive agreement to sell its interests in Venezuela to state-owned PT Pertamina (Persero) of Indonesia for $725 million (OGJ Online, Mar. 6, 2012).
After costs and taxes, net proceeds from the all-cash sale will be about $525 million.
Pertamina will acquire Harvest's 32% interest in Petrodelta SA by buying HNR Energia's 80% interest in Harvest-Vinccler Dutch Holding BV.
The deal is subject to approval by the governments of Venezuela and Indonesia and Harvest shareholders.
Petrodelta produced an average 32,700 b/d of oil in the first 3 months of 2012. It holds 274,113 gross acres in eastern Venezuela, 90% undeveloped, on which it operates Uracoa, Bombal, Tucupita, El Salto, El Inseno, and Temblador fields. Proved and probable reserves are estimated at 486 million boe.
Exploration & Development — Quick Takes
Japex Indonesia Buton oil find may be commercial
A group led by a unit of Japan Petroleum Exploration Co. Ltd. will plug and abandon a potentially commercial oil discovery in the frontier Buton basin off southeastern Sulawesi, Indonesia.
The group drilled the Benteng-1 exploratory well to 12,424 ft and encountered good oil shows in a 111-ft interval from a depth of 2,375 ft. Initial log analysis indicates a 15-ft oil-bearing Tertiary limestone reservoir.
Benteng-1 is the first well to discover hydrocarbons in the frontier Buton basin, where it has established the existence of a working petroleum system. It was drilled to test two play types, a shallow anticline and a deeper fault dependent trap. The hydrocarbons were discovered in the shallow play type.
The well results will be integrated into the existing database to determine the viability of the discovery and the follow on potential in the shallow play type across the Buton block.
Interests in the Buton block are Japex Buton Ltd. operator with 40%, and Premier Oil PLC and Kuwait Foreign Petroleum Exploration Co., 30% each.
Devonian objective of Arizona Pedregosa leasing
Arizona Oil & Gas Inc., private Bisbee operator, said its affiliates have acquired more than 150,000 acres of oil and gas leases in Cochise County where geologic work and remote sensing indicate a complex of major reef structures.
The firm said it plans a drilling program to test the Devonian in late 2012 or early 2013. The Devonian section in the Pedregosa basin includes the Morenci, Portal, and Percha formations with the Percha shale possibly serving as a source rock.
Exploration is sparse in the basin, which has not produced commercial hydrocarbons in Arizona or New Mexico. The basin extends into northern Mexico.
The former Phillips Petroleum Co. drilled three stratigraphic tests in Cochise County in 1981-82 to total depths of 7,058 ft, 8,513 ft, and 10,561 ft in exploring a possible extension of the Rocky Mountain Overthrust Belt. All bottomed in Cretaceous as dry holes.
Wintershall OMV to appraise Abu Dhabi field
Wintershall Holding GmbH and OMV AG will shoot a 3D seismic survey and drill as many as three wells to appraise a sour gas and condensate field in Shuwaihat in western Abu Dhabi under a technical evaluation agreement with Abu Dhabi National Oil Co.
The European companies will be equal partners during the appraisal phase with Wintershall as operator. If appraisal is successful, ADNOC will participate in development and production. The field is 25 km west of Ruwais.
Drilling & Production — Quick Takes
Redevelopment proceeds of pioneer UK field
EnQuest Britain Ltd. has let a contract to Technip for subsea equipment and services in its revitalization of a North Sea oil field once known as Argyll, the first field to produce oil at commercial rates offshore the UK.
EnQuest is drilling in the field, now known as Alma, and will begin drilling in nearby Galia field later this year.
It plans to drill six production wells in Alma and one in Galia as well as two water injection and disposal wells. Production wells will be completed with variable speed drive electric submersible pumps.
Produced fluids will flow to a floating production, storage, and offloading vessel undergoing modification in Hamburg, Germany, to be renamed EnQuest Producer. The FPSO will be able to handle production streams with water cuts as high as 95%. Subject to final approvals, EnQuest expects production to start in the fourth quarter of 2013 and to peak above 20,000 boed in 2013.
The fields are in 80 m of water 310 km southeast of Aberdeen, Scotland. EnQuest estimates proved plus probable reserves at 20.8 million boe at Alma and 8.6 million boe at Galia.
Argyll production started in 1975 and ceased in 1992 with a water cut of about 70%. With nearby Duncan and Innes fields, Argyll produced a total of 97 million bbl of oil.
Argyll had been developed with the world's first floating production system, a converted semisubmersible drilling rig (OGJ, Dec. 14, 1992, p. 26).
Alma is on Blocks 30/24c and 25c, License P1765. Galia is on Block 30/24b, P1825.
Tuscan Energy North Sea Ltd. redeveloped the field and renamed it Ardmore, which produced during 2003-05 until Tuscan entered receivership with oil output at 6,000 b/d. Acorn Oil & Gas Ltd., a 35% partner, completed the removal of three subsea wellheads and a subsea manifold 2 years later.
Technip's contract in the new revitalization project is for installation of production and water flowlines, risers, umbilicals, and power cables; procurement, fabrication, and installation of a 175-ton manifold structure; and associated trenching, tie-ins, testing, and commissioning.
EnQuest holds a 65% interest in the Alma-Galia development after recently farming out a 35% interest to Kuwait Foreign Petroleum Exploration Co. for a $500 million investment covering a pro rata share of past expenditures and future contributions.
Nexen notes progress in oil sands project
Nexen Inc. has begun production from the 12th pad at its Long Lake oil sands project and steaming of the 13th pad, saying it is adjusting work to quality of the complex resource in the southern Athabasca region of Alberta (OGJ Online, Apr. 16, 2012).
The company is using steam-assisted gravity drainage to produce bitumen for an integrated upgrader that gasifies asphaltenes in the bitumen into synthesis gas for use as a fuel and source of hydrogen for a hydrocracker.
It expects to achieve production of 30,000-44,000 b/d from the first 11 pads this year or next and of 11,000-17,000 from the 12th and 13th pads in 2014-15.
The project is designed eventually to produce 72,000 b/d of bitumen, from which the upgrader will yield 60,000 b/d of syncrude. The upgrader began operation in 2009 and has achieved as much as 60% overall capacity utilization during tests.
Actual project production, recently reported at 34,500 b/d, is slightly more than half original expectations.
In a new report, Nexen says it is adapting to the presence of lean zones of mobile water that draw large amounts of steam early and reduce production and increase steam-oil ratios (SORs). Once mobile water heats, performance improves. Nexen says high fluid rates reduce time to improvement.
In response to multiple channeling events in the Long Lake resource, the firm has increased the frequency of core-hole drilling. Well performance from the first 10 pads showed discontinuous shales act as barriers to steam-chamber growth when enough of them exist. Nexen drilled more than 200 core holes last winter and plans similar programs in the next 3 years.
It says one of several lessons from Long Lake is the "need for resource calibration−understanding [the] relationship between clean sand, shales, lean zones, and their impact on rate and SOR."
E-T to reapply for novel oil sands project
E-T Energy Ltd., Calgary, indicated it will refile an application for commercial-scale production of bitumen in Alberta based on a proprietary electrical heating system.
The provincial Energy Resources Conservation Board returned an application filed in July 2009 saying the firm hadn't demonstrated that the system, ET-DSP (for electrothermal dynamic stripping process), can obtain or sustain commercial bitumen production rates. ERCB cited a lack of production data.
E-T said the application didn't include results of a crucial field test that remains in progress. It said the test, which it calls Step 3, won't establish the recovery factor and energy-oil ratio required to produce bitumen until later in 2012 or early-2013.
The returned application was for a 10,000 b/d project. E-T said, "In light of the recent decision by the ERCB, the timing of the Step 3 results, and weak capital markets, management will be considering other alternatives, including a smaller project building upon the existing Step 3 field test surface assets."
The firm holds acreage in the Athabasca oil sands region adjacent to Fort McMurray. The ET-DSP system, based on a grid of production and electrode wells, has been used by the environmental industry for remediation of contaminated sites.
E-T wants to apply the technology to recovery of bitumen from Lower Cretaceous McMurray formation zones too deep to be mined, more than 75 m, and too shallow to be produced by steam-assisted gravity drainage, less than 150 m.
PROCESSING — Quick Takes
Enterprise to build PDH unit on Texas Gulf Coast
Enterprise Products Partners LP, Houston, will build a 35,000-b/d propane dehydrogenation (PDH) unit on the Texas Gulf Coast to take advantage of low-cost propane derived from increased NGL production out of nearby shale gas development.
A company spokesman told OGJ the "precise location is still being determined," and he did not disclose the estimated cost. Enterprise operates extensive fractionation at Mont Belvieu and several pipelines connecting operations there with local markets and export terminals.
The PDH unit will be able to produce up to 1.65 billion lb/year (about 750,000 tonnes/year) of polymer-grade propylene (PGP), a prime feedstock for plastics manufacturers.
According to the announcement, the unit will be "one of the world's largest." Enterprise Products expects it to begin operating in third-quarter 2015.
For feedstock supply, the PDH will be supported by Enterprise's Gulf Coast NGL fractionation and storage. With previously announced expansions, the company by 2015 will have 708,000 b/d of NGL fractionation capacity, which would provide up to 177,000 b/d of propane (OGJ, May 7, 2012, p. 88).
In addition, the new PDH unit will be supported by Enterprise Products' 100 million bbl of NGL and petrochemical storage along the Texas Gulf Coast.
Also in 2015, the PDH unit will be complemented by Enterprise's 5.3 billion lb/year (2.4 million tpy) propylene fractionation capacity, which fractionates refinery-grade propylene to produce PGP.
Enterprise also has PGP storage and a 102-mile pipeline capable of delivering PGP to 18 downstream customers and to international markets through the partnership's propylene export terminal in Seabrook, Tex.
Contract let for Uzbekistan ethylene plant
Uz-Kor Gas Chemical LLC, a joint venture of Uzbekneftegaz of Uzbekistan and a group of South Korean firms, let a contract to KBR for technology and services for a 400,000-tonne/year ethylene plant in the Ustyurt region.
KBR will license its proprietary ethylene technology and provide engineering, procurement, and construction support.
Uz-Kor Gas Chemical, based in Nukus in Uzbekistan's Karakalpakstan autonomous region, plans to build a petrochemical complex at Surgil gas and condensate field, a Ustyurt basin field it is developing.
The Ustyurt complex, at the Akchalak settlement in Karakalpakstan's Kungrad region, is to process 4.5 billion cu m/year of gas and condensate from Surgil, East Berdakh, and North Berdakh fields, according to Uz-Kor Gas Chemical (OGJ Online, Mar. 31, 2006).
The complex is to produce 400,000 tpy of high-density polyethylene, 100,000 tpy of propylene, pyrolysis gasoline and oil, and sales gas. Completion of the complex is planned for yearend 2014.
FEED pact let for Tatarstan ethylene plant
Nizhnekamskneftekhim OAO has let a contract valued at more than $40 million to CB&I for front-end engineering and design of a 1 million tonne/year ethylene plant at its refinery-petrochemical complex at Nizhnekam, Tatarstan, Russia.
Completion of work under the contract is expected in 2013. The project also includes a butadiene extraction unit and a pyrotol unit, including offsites and utilities.
TRANSPORTATION — Quick Takes
Nova gets NEB nod for Alberta gas pipeline
Nova Gas Transmission Ltd. (NGTL), a wholly owned subsidiary of TransCanada Corp., received approval from Canada's National Energy Board for its 972-MMcfd Leismer-to-Kettle River Crossover application. The project, about 90 km south of Fort McMurray, Alta., will consist of 77 km of pipeline and related facilities. About 29 km will follow existing right-of-way.
Approval depends on NGTL demonstrating it has met all 22 NEB-imposed conditions, which include mitigation requirements for the protection of the environment and additional requirements specifically for the protection of caribou. NGTL must conduct a comprehensive survey of species at risk before beginning construction and must demonstrate how these species are being monitored during and after construction.
NGTL also must develop and implement a caribou habitat restoration plan addressing caribou issues during both construction and operation of the pipeline. NEB also mandated monthly reports on NGTL's consultation activities with aboriginal groups potentially affected by the pipeline.
NGTL expects the pipeline to enter service April 2013. The company earlier this year received NEB approval to expand its Peace River natural gas pipeline by adding three loops (OGJ Online, Mar. 1, 2012).
Access applies to expand bitumen blend shipments
Access Pipeline Inc. applied with Alberta's Energy Resources Conservation Board for approval to build and operate a 295-km, 42-in. OD expansion to its existing system. The Access Northeast Expansion pipeline would transport low vapor pressure bitumen blend with no hydrogen sulfide from a pump station near Conklin, Alta., to Access' existing Sturgeon terminal near Redwater, Alta., roughly paralleling the existing line.
The current Access Pipeline includes a 345-km, 16-in. OD diluent line running south-to-north and 345 km of 24-in. and 30-in. OD line shipping blended bitumen south to Sturgeon. Terminals operated by Provident and Enbridge supply diluent for the northbound line. Enbridge stores the southbound blend in tankage at Edmonton.
Access is jointly owned by MEG Energy and Devon ARL Corp. ERCB is accepting comments on the project through July 6. Devon received approval for a third Jackfish steam-assisted gravity drainage oil sands project 15 km southeast of Conklin late last year (OGJ Online, Dec. 6, 2011). MEG moved ahead with its Christina Lake Phase 2B SAGD, also near Conklin, earlier in 2011 (OGJ Online, June 20, 2011).
Permian Express line to transport West Texas crude
Sunoco Logistics Partners LP's newly announced Permian Express pipeline will transport West Texas crude oil to Gulf Coast markets. Phase I of the project will move about 150,000 b/d from Wichita Falls, Tex., to Nederland-Beaumont, Tex. Sunoco will reverse its Wortham-to-Wichita Falls pipeline to create continuous pipeline service from Wichita Falls to Nederland, including using excess capacity on the southern leg of its West Texas Gulf pipeline system.
Sunoco Logistics expects Phase I to be operational within 6-9 months at an initial capacity of 90,000 b/d, with 150,000 b/d expected within 12-18 months.
Permian Express Phase II would boost capacity by at least 200,000 b/d and extend shipments as far east as St. James, La., using a combination of new and existing pipelines. Sunoco could twin 300-miles of pipeline, parallel to the existing West Texas Gulf pipeline from Colorado City, Tex., to Wortham, Tex., for Phase II. From Wortham it would connect to existing excess capacity of the southern leg of the West Texas Gulf pipeline system. Sunoco expects Phase II to be operational by second-half 2014.
Sunoco Logistics described Permian Express as separate from, but complementary to, previously announced plans to expand oil flow on the West Texas Gulf pipeline by at least 100,000 b/d (OGJ Online, Apr. 12, 2012). Sunoco says currently announced projects will increase crude takeaway capacity from West Texas by a total of at least 450,000 b/d.
ClarificationTwo recent articles in Oil & Gas Journal contained material from reports by Wood Mackenzie for which attribution was insufficient. The article "Iraq's Ahdab oil field development limits contractor profitability" (OGJ, Aug. 1, 2011, p. 62) contained material from Wood Mackenzie's Ahdab Asset Analysis published by Wood Mackenzie Upstream Service in April 2010. The article "Hydrocarbon reservoir potential estimated for Iraq bid round blocks" (OGJ, Mar. 5, 2012, p. 42) contained material from Wood Mackenzie's Iraq Country Overview published by Wood Mackenzie Upstream Service in December 2010. |
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