OGJ Newsletter

Aug. 6, 2012
International news for oil and gas professionals


Sumitomo eyes $1.4 billion stake in Permian plays

Sumitomo Corp. will invest $1.4 billion in exchange for 30% of Devon Energy Corp.'s interest in 650,000 net acres in the Cline shale and Midland-Wolfcamp shale in the Permian basin.

Sumitomo will invest $340 million in cash at closing and a further $1.025 billion in the form of a drilling carry. The drilling carry will fund 70% of Devon's capital requirements, resulting in Sumitomo paying 79% of overall drilling and completion costs during the carry period.

The partnership expects to drill 40 gross wells in 2012. Based on the current work plan, Devon expects the entire $1.025 billion carry to be realized by mid-2014.

Devon will serve as operator and is responsible for commercially marketing all production from the plays into the North American market. Closing is expected to occur in the third quarter of 2012 retroactive to Jan. 1, 2012. Devon said it has had a strong working relationship with Sumitomo for a long time.

Devon said its Permian basin oil production in the quarter ended June 30 was 24% higher than in the second quarter of 2011. Output was nearly 59,000 b/d of oil equivalent, nearly 60% oil.

The Cline shale lies between the Wolfcamp and Strawn formations (OGJ Online, Aug. 29, 2011).

US Chamber launches shale energy campaign

The US Chamber of Commerce launched an advocacy campaign called Shale Works for US to show the general public how shale development can provide economic benefits to states, counties, and communities.

Karen A. Harbert, president of the US Chamber's Institute for 21st Century Energy, said the benefits are widespread.

"Shale energy is in 20 states," Harbert said. "It potentially could provide economic benefits for another 100 years."

The campaign was launched during July in Ohio, Pennsylvania, West Virginia, and New York, with more states to follow, she said.

During a July 26 event at chamber headquarters, Samuel Denisco, vice-president of government affairs at the Pennsylvania Chamber of Business and Industry, said shale plays generate revenue for towns decimated when manufacturing declined during the 1960s and 1970s.

Harbert expects the Shale Works for US will be a long-term campaign to showcase economic benefits, job creation, and energy security.

"We'd like a debate. We're ready to take the critics on," she said. "But it has to be based on facts and well-done analysis. We can't give way to fear-mongering."

Denisco agreed, saying, "Facts, not rhetoric, should make the difference."

Talks start on sale of BP's TNK-BP stake

BP PLC entered a 90-day period of negotiations with Alfa Access Renova (AAR), its 50-50 partner in TNK-BP, about the sale of part or all of its interest in the Russian company.

BP in June said it was interested in such a sale and disclosed unsolicited expressions of interest (OGJ Online, June 1, 2012). AAR responded by saying parity ownership of the Russian company had become "inoperable." It earlier indicated interest in acquiring half the BP stake.

AAR has exercised its option under the TNK-BP shareholders' agreement to negotiate a purchase.

BP said it "is also able to and will enter into negotiations with other interested parties in parallel for the sale of its share in TNK-BP."

In a statement, AAR said a sale would "not affect BP's potential liability to AAR and TNK-BP for breach of the shareholders' agreement in connection with BP's attempted strategic alliance with Rosneft."

AAR blocked a BP-Rosneft deal announced in January 2011 for joint exploration of the Russian Arctic and other collaboration, including a share swap (OGJ Online, Mar. 25, 2011).

Exploration & DevelopmentQuick Takes

Llanos field well confirms Mirador oil

Participants in the Los Ocarros block in Colombia's Llanos basin have drilled a well in Las Maracas field that confirmed the Mirador formation regular oil pay and recovered light oil from deeper pay in the Gacheta formation.

Las Maracas-3 went to a total depth of 12,580 ft measured depth and flowed at the rate of 1,491 b/d of 30° gravity oil from 14 ft of perforations in the Gacheta. The well encountered new oil pay of 59 ft true vertical depth, of which 30 ft are in Mirador and 29 ft are in Gacheta.

Gacheta averages 24% porosity and 72% oil saturation over the net pay interval. The Mirador formation has properties similar to those in the Las Maracas-2 sidetrack discovery well.

Additionally, as a possible upside, potential thin-bed pay is identified in the Une, Gacheta, and Carbonera C7 formations, and good oil and gas shows were encountered drilling through the Une reservoir. This upside potential will be evaluated in future wells, said Petroamerica Oil Corp., Calgary, which has a 50% interest in the block.

The participants decided to run an electric submersible pump and complete the well, producing the Gacheta at rates as high as 2,000 b/d through the Las Maracas long-term test facility during the first week of August 2012. The Mirador interval will be produced later using the same wellbore.

The rig will now be skidded to drill the Las Maracas-4 well from the same surface location.

Las Maracas-2 has been producing from the Mirador formation on long-term test since Apr. 23 and as of July 29 had produced more than 102,000 bbl of oil. It is choked at a stable 1,080 b/d with less than 2% water-cut.

Block operator Cepcolsa, has transferred its 50% participating interest to Parex Resources Colombia Ltd. Sucursal pending approval by Colombia's ANH.

Meanwhile, Petroamerica will divest its 33.3% working interest in Lower Magdalena Block 5 to the operator of the block in return for a $3 million letter of credit.

Mississippi lime play sprawls into Nebraska

Horizontal wells in the US Midcontinent Mississippi lime oil play aren't as productive as those in the Williston basin Bakken, but shallower depths and cheaper drilling costs are driving increased interest in the Mississippi lime, said IHS Inc.

The land play has expanded to more than 17 million acres in northern Oklahoma, western Kansas, and southern Nebraska, said Paul O'Donnell, author of the IHS Herold Mississippian Oil Play Regional Play Assessment.

"The Mississippian's highly variable drilling results to-date, combined with increasing entry costs, might deter new entrants, but recent drilling reports suggest results could improve as knowledge of the play and technical adjustments increase.

"This is a shallow carbonate play, with depths ranging from 3,000 ft to 6,000 ft, and since it's shallower than other US unconventional plays, operators can employ less expensive, lower horsepower rigs to drill it."

The reservoir averages 300-500 ft thick with the Woodford shale as its source rock (OGJ Online, Aug. 29, 2011). Using rigs of about 1,000 hp, drilling costs are estimated at $2.9-3.5 million/well, compared with $8-11 million in the Bakken.

IHS said SandRidge Energy has an early mover advantage and is most leveraged to the Mississippian, as measured by acreage in the play per million dollars of company enterprise value. SandRidge is driving the play's development and recently reported completion at 2,200 b/d of oil equivalent well as the first 30-day average that could make Alfalfa County, Okla., one of the best spots in the play.

Coincidentally, Devon Energy Corp. said Wednesday that it has increased its exposure to 545,000 net acres in the emerging Mississippi lime light-oil resource play in Oklahoma.

O'Donnell said, the Mississippi lime "will be a good ancillary asset for most companies, rather than a 'company-changer.'"

India proposes terms for shale oil, gas

The government of India has invited public comment on draft fiscal terms for development of oil and gas resources in shale (OGJ Online, Mar. 13, 2012).

The US Geological Survey has estimated India's technically recoverable shale gas resource at 6.1 tcf in three of the country's 26 basins and said oil potential in shale also exists.

The Ministry of Petroleum and Natural Gas envisions a contract different from the agreement in place for conventional resources. It already uses a special contract for coalbed methane.

Non-Indian operators would be able to bid for shale contracts.

Basic terms in the draft contract are ad valorem production-level payments, royalty, and license fees.

Contract duration would be 32 years in two phases: 7 years for exploration and 25 years for production if development proceeds.

Prospective contractors would bid on the basis of minimum work program, production-linked payments, technical ability, and net worth.

Drilling & ProductionQuick Takes

Chevron to further develop Bangladesh's Bibiyana

A Chevron Corp. unit will invest $500 million to expand production capacity at giant Bibiyana gas-condensate field in the Habiganj district of northeastern Bangladesh.

Chevron placed Bibiyana field on production in 2007 (OGJ Online, Mar. 21, 2007). The field is the country's largest gas producing area (OGJ, Apr. 22 and 29, 2002).

The expansion, to come on line in 2014, is expected to boost the company's total gas production capacity in Bangladesh by more than 300 MMcfd, to 1.4 bcfd, and 4,000 b/d of natural gas liquids.

Chevron will drill more development wells, expand the gas processing plant, and install an enhanced gas liquids recovery unit.

Devon's Jackfish projects flow 51,000 b/d of bitumen

Devon Energy Corp., Oklahoma City, said production from its Jackfish 1 and 2 thermal projects in the southern Athabasca oil sands region of Alberta reached 51,000 b/d of bitumen in the second quarter, 63% above the year-earlier average (OGJ Online, Dec. 6, 2011).

The company said construction is about 40% at the Jackfish 3 project, where production is expected to begin late in 2014. Devon's 100%-held Jackfish projects, 10 miles southeast of Conklin, Alta., use steam-assisted gravity drainage with saline water. Each phase is designed to produce 35,000 b/d.

Devon in June filed applications for the first phase of its Pike SAGD project on land adjacent to the Jackfish acreage. Targeted production is 105,000 b/d. Devon and BP Canada Energy hold 50% interests in Pike.

UK forum issues offshore safety guidelines

The Well Life Cycle Practices Forum (WLCPF), set up in the UK after the Macondo tragedy in the Gulf of Mexico in 2010, has published four new sets of guidelines for offshore operational safety.

The new guidelines cover operation of subsea blowout preventer systems, well integrity throughout the well lifecycle, well suspension and abandonment, and qualification of materials used for suspension and well abandonment.

WLCPF is a permanent function created by the Oil Spill Prevention & Response Advisory Group (OSPRAG) and managed by Oil & Gas UK. OSPRAG completed its work last year (OGJ Online, Sept. 23, 2011).

The forum has published nine sets of guidelines.


Caltex to shut Kurnell refinery near Sydney

Caltex has decided to close its Kurnell refinery on Botany Bay, just south of Sydney, and convert the facility into a fuel import terminal at a cost of $680 million (Aus.).

The move, which will come into effect during second-half 2014, comes close on the heels of Shell Australia's move to close its Clyde refinery in Sydney next year and also convert it to an import terminal.

Kurnell handles 125,000 b/d of crude and Clyde, 80,000 b/d. The two refineries together represent 27% of Australia's current refining capacity.

However, they have both been under increasingly stiff competition from imported product produced in the mega-refineries in Asia. The combination of cheap labor and more efficiency in Asia has become too hard for the Sydney facilities to match.

Caltex says it will buy refined oil from Singapore, South Korea, and India for sale in its Australian retail outlets.

The company adds that Kurnell lost $208 million (Aus.) last year and another $60 million (Aus.) during the first 3 months of 2012—a state of affairs that has forced its hand on the closure decision.

The closure will mean the loss of 330 in-house jobs and the loss of an unspecified number of jobs from the 300 contractors who also work at Kurnell.

The Clyde closure will cause the loss of 220 jobs.

The Caltex move means that there will be no refineries in New South Wales. Queensland still has two refineries in Brisbane, but Caltex has refused to rule out a similar closure of its Lytton refinery there. Its closure would leave BP's facility at Bulwer Island the only one in that state except the small topping plant at Eromanga in the southwest of the state supplied by Cooper-Eromanga basin fields.

Victoria still has two refineries—Shell's in Geelong and ExxonMobil's Altona facility. The only other refinery in the country is BP's Kwinana plant near Perth in Western Australia.

Valero mulls separation of retail business

Valero Energy Corp. is considering a separation of its retail business from refining and other operations, according to Chairman and Chief Executive Officer Bill Klesse.

"We believe a separation of our retail business from the remainder of Valero by way of a tax-efficient distribution will create operational flexibility within the businesses and unlock value for our shareholders," Klesse said in an announcement of the company's second-quarter financial results.

Valero operates 16 refineries, all in the US except for one in Canada and one in the UK, with total throughput capacity of 3 million b/d. Its average refinery size is 187,000 b/d. It also owns 10 corn ethanol plants in the US with combined capacity of 72,000 b/d.

Valero's retail business includes about 6,800 branded marketing sites in the US and Canada, including nearly 1,300 sites operated by the company.

"As independent companies, both retail and the remaining business will be better-positioned to focus on their industry-specific strategies," Klesse said. He said Valero is considering several separation transactions, including a distribution of the retail business to Valero shareholders.

Valero reported net income attributed to shareholders from continuing operations of $831 million in the second quarter of 2012, compared with $745 million in the same quarter last year.

PDVSA lets contract for El Palito refinery expansion

PDVSA Petroleo SA has let a contract to a unit of Foster Wheeler's global engineering and construction group for the engineering, procurement, and construction management for the expansion of PDVSA's El Palito refinery near Pto. Cabello, Carabobo state.

Foster Wheeler will execute the project in a consortium with Japan's Toyo Engineering Corp. and Venezuela's Y&V Ingeniería y Construccion. The contract's value was not announced.

The project is to be completed in 2016. Previously, the consortium has conducted front-end engineering design for the project.

The expansion will double the refinery's capacity to 280,000 b/sd, processing heavy and extra-heavy crudes from the Orinoco belt, and increasing production of clean fuels, said the Foster Wheeler announcement.

Included in the expansion are several new units:

• A 140,000-b/sd crude vacuum distillation unit.

• A 24,500-b/sd naphtha hydrotreater and continuous catalytic reformer.

• A 58,000-b/sd vacuum gas oil hydrotreater.

• A 45,000-b/sd diesel hydrotreater.

• An 80-MMscfd hydrogen production unit.

• A 250-tonne/day sulfur recovery and tail-gas treatment unit.

Also included are a new flare system, amine regeneration and sour water stripper, and relevant utilities, including marine facilities, and a product tank farm.


Alaska project announces nonbinding open season

The Alaska Pipeline Project (APP), a joint effort between affiliates of TransCanada Corp. and ExxonMobil Corp., will hold a nonbinding open season to solicit interest in shipping on the potential natural gas pipeline system to move Alaska North Slope gas to market. The solicitation will identify parties interested in making future capacity commitments on a pipeline system from the ANS to either an LNG terminal at a tidewater location in south-central Alaska or to an interconnection point near the border of British Columbia and Alberta.

The open season will occur under the Alaska Gasline Inducement Act, which requires TransCanada, as AGIA licensee, to assess market interest every 2 years after its first open season. Either APP routing will provide a minimum of five delivery points for local natural gas connections in Alaska.

Alaska Gov. Sean Parnell announced in March that the state had resolved long-running litigation with ExxonMobil and other Point Thompson field lease holders allowing development of its gas resources to proceed. He also received a letter from BP PLC, ConocoPhillips, and ExxonMobil's chief executives declaring their willingness to work with APP on a pipeline to move gas from the ANS to an LNG export terminal (OGJ Online, Mar. 30, 2012).

The open season will run from Aug. 31 through Sept. 14.

Fort Hills selects Northern Courier pipeline builder

Fort Hills Energy LP has selected TransCanada Corp. to design, build, own, and operate the proposed Northern Courier Pipeline project. Northern Courier is a 90-km pipeline system to transport bitumen and diluent between the Fort Hills mine site and the Voyageur upgrader north of Fort McMurray, Alta.

Northern Courier is fully subscribed under long-term contract to service the Fort Hills Mine, which is jointly owned by Suncor Energy Inc., Total E&P Canada Ltd., and Teck Resources Ltd. and operated by Suncor Energy Operating Inc.

TransCanada expects to file its initial regulatory application later this year at which time it will provide a more-detailed project schedule. Pipeline routing is still being determined.

The $660 million Northern Courier project is conditional on the Fort Hills project receiving sanction by its co-owners and obtaining regulatory approval. The project will be operated by Northern Courier Pipeline GP Ltd., a wholly owned TransCanada subsidiary.

Total and Suncor formed a strategic oil sands alliance in late 2010 encompassing Fort Hills, the Total-operated Joslyn mining project, and the Suncor-operated Voyageur upgrader. Suncor and Total agreed to develop Fort Hills and Voyageur in parallel so that both come on stream in early 2016 (OGJ Online, Dec. 20, 2010).

Enbridge gets nod for Line 9 pipeline reversal

Enbridge Pipelines Inc. received permission from Canada's National Energy Board to reverse the flow on a segment of its Line 9 crude oil pipeline, subject to 15 conditions, mainly related to pipeline integrity. On Aug. 8, 2011, Enbridge applied to reverse about 194 km of Line 9 between the Sarnia terminal (at Sarnia, Ont.) and the North Westover pump station (near Hamilton, Ont.) to flow in an eastward direction.

Enbridge said a 50,000-b/d expansion of its 490,000-b/d Line 5 and reversal of Line 9 would increase access for light crude produced in western Canada and the US to refineries in the upper Midwest and Ontario (OGJ Online, Nov. 11, 2011). Line 5 runs from Superior, Wis., to Sarnia. Enbridge expects its expansion to be in service first-quarter 2013, with the Line 9 reversal following in late 2013. Line 9 has a 240,000 b/d capacity in its current direction.

During the public hearing process regarding the Line 9 application, the NEB heard concerns regarding the integrity of the pipeline and impacts resulting from any possible accidents or malfunctions.

The $16.9 million (Can.) project involves infrastructure additions and modifications at four existing sites along the pipeline.

Colonial Pipeline completes 75,000 b/d expansion

Colonial Pipeline Co. completed the final phase of a 75,000 b/d increase to the capacity of its primary distillate pipeline, extending from Houston to Greensboro, NC. The 15-month expansion enhanced pumps, motors, and existing operations at 17 Colonial sites but did not require laying additional pipe.

The distillate line extends parallel to Colonial's main gasoline pipeline from Houston to Greensboro and carries diesel fuel (including ultralow-sulfur diesel), jet fuel for commercial aviation, military fuels, and heating oil, as well as other refined products. The line supplies Colonial's tank farm in Greensboro, from which additional Colonial pipelines transport the products further into the US Northeast.

The Houston-to-Greensboro distillate pipeline's overall capacity is now 1.15 million b/d. Colonial is also building two additional mainline capacity expansions, a 100,000-b/d increase on Colonial's main gasoline line from Houston to Greensboro (OGJ Online, Dec. 22, 2011), and a 60,000-b/d expansion on the line serving the Northeast. Each of these expansions is under way and scheduled to be operational by mid-2013.