OGJ Newsletter

June 18, 2012
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

EPA urged to retain certain PM air-quality standards

The US Environmental Protection Agency should consider retaining certain existing particulate matter air-quality standards, an American Petroleum Institute spokesman said June 12.

Howard Feldman, API director of regulatory and scientific affairs, said the existing PM 2.5 standard should be among standards EPA considers for its proposed particulate standard rule. EPA last revised its PM standards in 2006.

Fine particles are 2.5 µm or less in diameter and can contribute to reduced visibility. Some research has linked exposure to PM 2.5 levels with increased health risks. API said EPA's analysis shows the 2.5 standard is more protective than previously believed.

"Air quality progress under the current standards, control programs, and industrial initiatives has been substantial," Feldman said. "According to EPA, between 2000 and 2010, concentrations of PM 2.5 fell by 27%. As a result, more than three fourths of Americans today live in areas where air quality meets today's standards."

He warned that more stringent standards could bring additional costs to refineries, manufacturers, and utilities.

Representatives of API, the American Chemistry Council, and the National Association of Manufacturers were among groups that met with the Office of Management and Budget to discuss PM standards, Feldman told reporters during a June 12 conference call from his Washington, DC, office.

Previously, EPA said it needed until August 2013 to update standards but some groups are pushing for an accelerated deadline to December.

Chesapeake to sell midstream assets

Chesapeake Energy Corp., Oklahoma City, plans to sell midstream assets to two companies in three transactions for a total of more than $4 billion.

Global Infrastructure Partners is to buy all of Chesapeake's limited partner units and general partner interest in Chesapeake Midstream Partners LP for $2 billion. Closing is expected by June 29.

Also, Global Infrastructure is to buy Chesapeake Midstream Development LP, and Chesapeake Midstream Partners LP is to buy certain Midcontinent midstream assets from Chesapeake. Those two deals are expected to yield a total of $2 billion.

The three midstream divestitures are expected to enable Chesapeake to reduce previously budgeted capital expenditures by $3 billion over the next 3 years.

Aubrey K. McClendon, Chesapeake's chief executive officer, said proceeds of these transactions are an important part of the company's program to sell assets for a total of $11.5-14 billion.

Chesapeake has announced asset sales so far this year of $6.6 billion, including the midstream transactions.

ZaZa, Hess to end plans for Eagle Ford, Paris basin

ZaZa Energy Corp. reported plans to terminate its exploration and development agreements with Hess Corp. in the Eagle Ford shale in South Texas and the Paris basin in France.

ZaZa was paid $15 million with an additional $70 million to be paid to the Houston independent upon closing. The parties expect to sign definitive agreements by June 29 with closing expected before Aug. 15.

ZaZa said its Eagle Ford net acreage will increase from 11,500 acres to 72,000 acres. In France, ZaZa will transfer its 50% working interest in the Paris basin exploration licenses and retain a 5% overriding royalty interest.

Exploration & DevelopmentQuick Takes

Petrobras finds good quality oil in Guara Sul presalt

Petroleo Brasileiro SA said it has discovered good quality oil in the third well drilled in the Sul de Guara region of the Santos basin presalt cluster offshore Brazil.

The 1-BRSA-1045-SPS (1-SPS-96) discovery well detected 27° gravity oil in carbonate reservoirs below salt on wireline tests. The drillsite is in 2,202 m of water 320 km off Sao Paulo state in the southern part of Sapinhoa field.

The well is being deepened to 5,058 m to determine the lower limit of the reservoir. After drilling is completed, a formation test will be conducted to evaluate the productivity of the oil reservoirs, in line with the activities and investments set out in the mandatory exploration program annexed to the Rights Transfer Contract.

According to the Rights Transfer contract, Petrobras is entitled to produce as much as 319 million bbl of oil equivalent in this area.

Clontarf sees Ucayali oil development potential

Clontarf Energy PLC, Dublin, has completed a detailed work program for reentry of a 1999 indicated discovery well on Block 188 in the Ucayali basin in Peru and is discussing the project with potential industry partners.

Clontarf is in detailed strategic partnership talks that relate to the rest of Block 188 and also to Block 183. Block 188 covers 595,809 ha 100 km northeast of the Camisea gas-condensate fields, and Block 183 covers 396,826 ha in the north central Peruvian jungle.

Repsol and Petrobras have made recent discoveries nearby, and the Camisea fields have gained several extensions. As a result, Clontarf noted, access and infrastructure have steadily improved.

The former Phillips Petroleum Co. drilled the Panaguana structure on Block 188 in 1999. Five horizons had hydrocarbons shows, but only one was tested in which 37° gravity oil was found in the Carboniferous Green sandstones.

Before drilling Panaguana, Clontarf said, Phillips had decided to relinquish the block because of the then low $16 oil price, challenging fiscal terms, and postponed development of Camisea given Shell's withdrawal in 1996-97. Camisea had been seen as a necessary anchor tenant for further, incremental exploration and development in what was then a remote area.

An appraisal well will have to be drilled to verify the result from the original well. Clontarf said the Phillips on-site staff believed that Panaguana's Green sandstones held 31 million bbl of quality oil estimated at mid-range and that the well had potential in other horizons.

Kuwait Energy group awarded Iraq Block 9

Iraq has awarded a group led by Kuwait Energy an exploration, development, and production contract for Block 9 in the country's fourth bid round.

Kuwait Energy will operate Block 9 in Basrah Province with a 40% contractor share. Dragon Oil PLC and Turkish Petroleum Corp. will have 30% each.

If the block is found to be commercial during the 5-year exploration period, the group may apply to the Iraqi government to develop the block over a 20-year development period.

The consortium's bid was awarded on the basis of a remuneration fee of $6.24/bbl of oil equivalent. Compared with the previous bid rounds in Iraq, there was no stipulated plateau production target for blocks awarded in this bid round.

Amerisur tests strong Putumayo development well

Amerisur Resources PLC is to spud the second well in a six-well program in Platanillo field in the Putumayo basin in Colombia after the Platanillo-3 well flowed for 30.4° gravity oil for 24 hr at the rate of 2,340 b/d, natural, on choke with 44 psi wellhead pressure.

The well encountered 52 ft of net pay in an 85-ft gross interval in U sands of the Villeta formation. Amerisur perforated the upper 26 ft of indicated net pay and used a drillstem test assembly. Two other Villeta zones may contain potential pay and are under evaluation.

Platanillo field has two producing wells, Alea-1R and Platanillo-2, on the 14,341-ha block.

The next well is to be drilled from the same Platform 9 location and will be deviated to an offset of 600 m south of Platanillo-3.

The well was shut in for pressure build-up. The company will install a permanent completion string and commence commercial production. Given the well's high rate, Amerisur is evaluating completion options to maximize efficiency, including the installation of an electric submersible pump.

Drilling & ProductionQuick Takes

BP starts up Galapagos project in the deepwater gulf

BP PLC reported that initial start-up of the Galapagos development in the deepwater Gulf of Mexico began on June 3. The project marks the "first major infrastructure development" in the gulf since the Macondo well blowout and oil spill, according to a BP spokeswoman. BP brought Thunderhorse field on production earlier this year.

Last year, Noble Energy Inc., one of BP's partners in Galapagos, added a third field discovery to the project with Santiago (OGJ Online, June 1, 2011).

A BP spokeswoman told OGJ that over the next 4 weeks, the three wells in the Galapagos development will be brought online, "one at a time to ensure the proper operation of the new equipment and to gather production data." She said this step will be followed by full ramp-up of the wells, which is expected in 4-6 weeks. Gross production from Galapagos is expected to peak at about 60,000 boe/d, she said.

Galapagos is one of a series of major upstream developments that the company expects to bring into production this year, BP said. "The start-up of this project in the Gulf of Mexico is one of BP's key operational milestones for 2012, one of six high-margin projects we expect to come on stream this year," said Bob Dudley, BP group chief executive officer.

The Galapagos development includes three deepwater fields—Isabela, Santiago, and Santa Cruz—and increases the capability of a key offshore production hub for BP. The three fields are being produced using subsea equipment. A new production flowline loop has been added to carry output to the nearby Na Kika host facility, a BP-operated platform 140 miles southeast of New Orleans in 6,500 ft of water.

The Na Kika facility, with a production capacity of 130,000 boe/d, has been modified to handle output from the three fields. Full ramp-up of the project is expected at the end of June.

BP's overall interest in the three-block area that includes the fields comprising the Galapagos project is 56%. Partners are Noble Energy Inc., Red Willow Offshore LLC, and Houston Energy LP. BP is the operator of Isabela field, while Noble Energy operates Santiago and Santa Cruz fields.

Canadian oil output seen doubling by 2030

Production of crude oil will more than double to 6.2 million b/d by 2030, largely from oil sands, according to the Canadian Association of Petroleum Producers.

Production last year was 3 million b/d, of which 1.1 million b/d came from conventional resources in Western Canada, 1.6 million b/d from oil sands, and 300,000 b/d from Eastern Canada, CAPP says in a new report.

The trade group expects conventional production in Western Canada to rise to 1.3 million b/d in 2015 and 2020 before slipping to 1.2 million b/d in 2025 and back to 1.1 million b/d in 2030.

Production from the oil sands region climbs steadily in the CAPP projection: to 2.3 million b/d in 2015, 3.1 million b/d in 2020, 4.2 million b/d in 2025, and 5 million b/d in 2030.

Conventional production from Eastern Canada, CAPP says, will slip to 200,000 b/d in 2015 and stay at that level through 2025 before falling to 100,000 b/d in 2030.

ExxonMobil invests in Ignite Energy's CSG venture

An affiliate of ExxonMobil Australia Pty. Ltd. agreed to obtain an initial 10% interest in an onshore Exploration License 4416 in the Gippsland basin of southeast Victoria, Australia, from Ignite Energy Resources Ltd.

The ExxonMobil affiliate is Esso Ventures LLC. During the next 12-18 months Esso Ventures and IER will jointly evaluate and assess the natural gas potential in the license's coal seams to determine whether it can be commercially produced.

IER plans to operate the preliminary assessment phase. EL4416 covers more than 3,800 sq km. Financial terms of the agreement were not disclosed.

IER has offices in Melbourne and Sydney with an onshore resource portfolio and a lignite and biomass upgrading technology being demonstrated at its Somersby facility near Sydney.

Esso Australia Resources has operated the Bass Strait Joint Venture for more than 40 years.

Statoil acquires Peregrino FPSO from Maersk

Statoil and its partner Sinochem have agreed to purchase the Peregrino floating production, storage, and offloading vessel from Maersk. The FPSO has been in use at Statoil-operated Peregrino field in Brazil since production start-up in 2011 (OGJ Online, Apr. 11, 2011).

BW Offshore, the FPSO's contractor, will take over the vessel's operation after a 6-month transition period.

The Peregrino FPSO project was initiated in 2007. The conversion from a very large crude carrier to an offshore oil production installation required more than 15 million labor hr and an investment of more than $1 billion.

At present the vessel is operating in the Campos basin 85 km off Rio de Janeiro. The unit has a storage capacity of 1.6 million bbl of oil and has produced well over 15 million bbl during its first year of operation.

Thore E Kristiansen, senior vice-president for development and production international, South America and sub-Saharan Africa, said, "Brazil plays an important part in Statoil's international growth strategy specializing in deep water and heavy oil. We've been present in Brazil since 2001 and this was the right time for us to invest further. Our operatorship at Peregrino proves that the company's strategy in pursuing complex projects is paying dividends."

Statoil's exploration portfolio in Brazil includes seven licenses. Over the past year, Statoil has made two discoveries at Peregrino south and Pao de Acucar.

Statoil will formally take title of the FPSO on July 31.

Development of Edvard Grieg field gets PDO nod

Lundin Petroleum AB unit Lundin Norway AS has received final approval for the plan for development and operation (PDO) for Edvard Grieg oil and gas field offshore Norway from the Norwegian Parliament. The Norwegian Ministry of Petroleum and Energy concurred with the field development plan in April.

Edvard Grieg field was previously called Luno (OGJ Online, May 3, 2012).

The Edvard Grieg is the first stand-alone development project operated by Lundin Petroleum on the Norwegian Continental Shelf. First production from Edvard Grieg field in PL338 is expected in late-2015 with a forecast gross peak production of 90,000 b/d of oil and 1.5 million standard cu m/day of gas.

The capital cost of the Edvard Grieg development including platform, pipelines, and production wells is estimated at $4 billion. The Edvard Grieg platform design capacity will accommodate in excess of 130,000 bo/d and 4 million standard cu m/day of gas when production from DNO ASA-operated Draupne field is combined with that from Edvard Grieg (OGJ Online, Mar. 5, 2012).

Major contracts for the field—jacket, topside, drilling, and marine installation—have already been awarded subject to final PDO approval.

Lundin Petroleum is operator of Edvard Grieg with 50% working interest. Other partners are Wintershall Norge AS 30% and RWE Dea Norge AS 20%.

PROCESSINGQuick Takes

Shell's Sydney refinery closure brought forward

Shell Australia has brought forward the date of closure of its Clyde refinery in Sydney to the end of September.

The closure follows the decision made in July 2011 to convert the 79,000 b/d facility to an import fuel terminal.

Originally Shell gave a closure date of mid-2013, but continued losses have brought the date forward.

Shell says its decision is consistent with its strategy to focus its refining portfolio on larger assets and build a profitable downstream business in Australia. The refinery has continued to struggle against sustained poor industry margins and intense competition from mega-refineries in Asia.

The Clyde closure comes as Caltex is moving towards closure of its Sydney refinery at Kurnell. A final decision there is expected in the next 3 months.

Optimization of Vadinar refinery complete

Essar Energy PLC has completed the optimization of its recently expanded Vadinar refinery in Gujarat, India, pushing crude capacity to 405,000 b/d.

The privately held Indian company completed an expansion in March that boosted capacity to 375,000 b/d from 300,000 b/d (OGJ Online, Mar. 30, 2012).

The optimization project, completed 4 months ahead of schedule, included conversion of a visbreaker into a crude distillation unit able to process extra-heavy feedstock.

The refinery now can handle feeds of as much as 60% ultraheavy crude and 80% heavy plus ultraheavy.

Nearly 80% of its output can be light and middle distillates, and more than 50% of its diesel and gasoline will meet Euro IV and Euro V standards.

Mandan refinery expansion nearly complete

Tesoro Corp. expects to complete the expansion of its refinery at Mandan, ND, by the end of June, according to Greg Goff, president and chief executive officer. The company is boosting crude capacity to 68,000 b/d from 58,000 b/d in response to growing oil production from the Bakken shale and other formations in the Williston basin (OGJ Online, Mar. 21, 2011).

Goff mentioned the refinery expansion in an announcement about the successful conclusion of negotiations over labor contracts covering six of its refineries with the United Steelworkers.

TRANSPORTATIONQuick Takes

Magellan assesses Permian-to-Houston oil pipeline

Magellan Midstream Partners LP and Occidental Petroleum Corp. have launched of an open season to assess customer interest in transporting Permian basin crude oil from Colorado City, Tex., to the Houston-Texas City refining complex.

The proposed 278,000-b/d BridgeTex Pipeline would include roughly 400 miles of newly constructed pipeline and an expansion by Magellan of its distribution system between East Houston and Texas City. Subject to sufficient commitments from shippers and necessary regulatory approvals, the joint venture expects BridgeTex to begin service by mid-2014.

Magellan and Oxy will form a new project company to develop the project and will share commercial responsibilities. A joint project team will oversee building the pipeline, with Magellan serving as operator. Interested customers must submit binding commitments by July 11.

Earlier this year Magellan held an open season to solicit binding commitments to ship crude from Crane, Tex., to its East Houston terminal (OGJ Online, Feb. 22, 2012). Shipments would occur on a portion of Magellan's Longhorn pipeline, reversed and converted to ship Permian oil at a capacity of up to 225,000 b/d by mid-2013.

Qatargas signs LNG supply deal with Tepco

Qatar Liquefied Gas Co. Ltd. (Qatargas 1) has signed a long-term LNG sales and purchase agreement with Tokyo Electric Power Co. Inc. (Tepco), Japan's largest LNG buyer. The SPA was signed June 11 in Doha.

The deal marks the first long-term bilateral agreement between Tepco and Qatargas, the companies said. Under the terms of the agreement, Qatargas 1 will deliver 1 million tonnes/year of LNG on a long-term basis starting from 2012.

Tepco is one of the original eight Japanese buyers who signed a multiparty contract with the Qatargas 1 venture in 1994. Qatargas first began delivering LNG to Japan and Tepco in 1997, with the start-up of the Qatargas 1 project.

Qatargas 1 consists of three onshore LNG trains with a total combined capacity of 10 million tpy. Qatargas 1 joint venture partners are Qatar Petroleum, ExxonMobil Corp., Total SA, Mitsui, and Marubeni.

Rangeland ships first Bakken oil from rail terminal

Rangeland Energy LLC has shipped the first 120-car unit train from its COLT open-access crude oil marketing terminal in the North Dakota portion of the Bakken shale.

COLT also includes the 21-mile bidirectional COLT Connector pipeline linking it at a rate of 75,000 b/d with multiple existing and planned pipelines, including the Tesoro and Enbridge systems, at Rangeland's Dry Fork terminal near Tioga, ND.

Enbridge is building an 80,000-b/d rail terminal at Berthold, ND, to be in service first-quarter 2013 (OGJ Online, Mar. 1, 2012). The company says it will have a total of 475,000 b/d of North Dakota shipping capacity available by 2013.

Rangeland's COLT, sited in Williams County, ND, uses a combination of gathering pipelines and trucks to aggregate crude produced in the Bakken and Three Forks shales into its 720,000 bbl of storage. Storage consists of five 120,000-bbl tanks at COLT and a sixth tank at Dry Fork.

BNSF Railway Co. provides transportation from the rail part of the terminal to market. Initial rail transport capacity is 120,000 b/d.

Eagle Ford oil pipeline due July start-up

Enterprise Products Partners LP has begun accepting deliveries for and commissioning the first phase of its Eagle Ford crude oil pipeline between Wilson County and Sealy, Tex. (OGJ Online, Sept. 1, 2010).

The 147-mile, 24-in. OD pipeline, scheduled to start up in July, can carry 350,000 b/d of oil.

The pipeline, linked to EPP's Rancho pipeline at Sealy, connects oil produced in the Eagle Ford shale play with Gulf Coast facilities that include the company's ECHO crude oil storage complex under construction on the Houston Ship Channel.

An 80-mile, 200,000-b/d second phase of the pipeline will extend from Wilson County to near Gardendale, Tex., in La Salle County (OGJ Online, May 6, 2011).

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