Judge orders BOEMRE to act on permit applications
A federal district judge in New Orleans ordered the US Bureau of Offshore Energy Management, Regulation, and Enforcement to decide whether to issue five pending Gulf of Mexico offshore drilling permit applications to Ensco Offshore Co. within 30 days.
The Dallas offshore drilling contractor applied for four of the five permits during the 5-month deepwater drilling moratorium imposed by US Interior Sec. Ken Salazar following the Macondo well blowout, which destroyed the Deepwater Horizon semisubmersible rig on Apr. 20 and set off a massive oil spill. DOI said it was reviewing the ruling.
Judge Martin L.C. Feldman, of Louisiana's eastern district, wrote in his Feb. 17 order that drilling permits were processed in about 2 weeks time before the Macondo accident.
"In stark contrast, the five permits have been pending from 4 to some 9 months," Feldman said. "These delays have put off indefinitely drilling in the Gulf of Mexico. Ensco has incurred significantly reduced standby rates on its rigs and has been forced to move some…to other locations around the world."
He rejected the federal government's argument that Congress, when it passed the Outer Continental Shelf Lands Act in 1953, decided not to impose a time limit and consequently left the matter to the DOI agency responsible for managing the OCS.
That view, said Feldman, "would produce autocratic discretion." He noted DOI argued delays are inevitable in a more regulated environment, and conceded that in the spill's wake, some delays are understandable.
"But now, nearly a year after the spill occurred, delays, particularly those of the length at issue here, become increasingly unreasonable," Feldman continued. "The permitting backlog becomes increasingly inexcusable."
BHP Billiton to buy Chesapeake Fayetteville assets
BHP Billiton Petroleum agreed to buy all of Chesapeake Energy Corp.'s interests in the Fayetteville shale gas play in Arkansas for $4.75 billion.
The company will acquire 487,000 acres, from which net production averages about 415 MMcfd of gas equivalent, and 420 miles of pipeline and gathering assets. It said the acquisition includes "development options that will support substantially higher production over a 40 year operating life."
It's BHP Billiton's first investment in the US shale gas business. Chesapeake agreed to provide essential services related to the properties for up to 1 year, for which it will collect a fee.
BHP Billiton will become operator of the properties.
Alberta's ERCB responds to pipeline risk report
Alberta's Energy Resources Conservation Board (ERCB) responded to the Natural Resources Defense Council (NRDC), Pipeline Safety Trust, National Wildlife Federation, and Sierra Club report "Tar Sands Pipeline Safety Risks," describing it as misleading regarding pipeline safety in Alberta and on the characteristics of diluted bitumen.
NRDC's report described tar sands crude as having 5-10 times as much sulfur as conventional crude and more chloride salts. The report also characterized the crude pipeline system in Alberta as newer but carrying more tar sands oil than the US system, before stating the Alberta system had experienced 16 times more safety incidences due to internal corrosion than the US system, which it saw as a strong indicator of the corrosive nature of raw tar sands oil (OGJ Online, Feb. 17, 2011).
ERCB described these statements as factually inaccurate. "The NRDC's comparison of ERCB data with that collected in the US is flawed, as it selected data from a much broader array of ERCB pipelines than those included in US data as hazardous liquid pipelines," according to ERCB. "Additionally, the NRDC did not recognize that the ERCB requires all incidents to be reported, regardless of whether or not any product is spilled, and also regardless of spill volume, whereas in the US only spills of 5 bbl of liquids or more are required to be reported."
According to ERCB, in the category identified by NRDC—pipelines shipping bitumen and blends of bitumen—ERCB identified only three spills resulting from internal corrosion between 1990 and 2005. ERCB places the resulting average failure frequency at 0.03/1,000 km/year, lower than the US rate it cites from the NRDC study of 0.08/1,000 km/year.
ERCB also noted that "analysis of pipeline failure statistics in Alberta has not identified any significant differences in failure frequency between pipelines handling conventional crude versus pipelines carrying crude bitumen, crude oil, or synthetic crude oil."
ERCB noted the tariff specification for the Keystone XL project was virtually the same in regards to water content and solids contents as that specified for other heavy oil pipelines, concluding that there is no reason to expect this product to behave in any substantially different way than other oil pipelines.
Continental, Jordan seek France shale permits
Continental Resources Inc., Enid, Okla., said it initiated a process in the fourth quarter of 2010 to secure permits to develop four blocks totaling 67,000 net acres in the Paris basin in France.
Continental said it is pursuing the Paris basin opportunity in an 80-20 joint venture with Jordan Oil & Gas, Healdsburg, Calif. The two companies have worked together on several projects in North Dakota, and Jordan Oil & Gas has operating experience in France and other international oil and gas plays.
If awarded the 5-year permits, Continental and Jordan together would commit to invest at least $13.8 million over 4 years. The French government is expected to rule on the permit applications by yearend.
Continental said it believes it could recover large oil reserves from the permits using technology it has developed in the Bakken formation in North Dakota and Montana.
Apache finds gas with Zola off W. Australia
A group led by Apache Energy Ltd. made a natural gas discovery with its Zola-1 wildcat well in the primary Triassic-age Mungaroo formation target on permit WA-290-P off Western Australia. The find is on trend with Gorgon gas field, the group said.
Data obtained while drilling indicate the presence of gas from the top of this primary reservoir, which is the same as that at Chevron Australia's Gorgon field, about 40 km to the north.
The Zola prospect is a large tilted fault block that has been delineated by high-quality, newly reprocessed 3D seismic data.
The structure's size suggests a range of recoverable reserves of 1-2 tcf of gas.
The group said the Mungaroo section will be drilled through before wireline logs are run to confirm the extent and thickness of the gas column.
The well is being drilled by the Stena Clyde semisubmersible rig.
Apache is operator with 30.25%. OMV AG has 20%, Santos Ltd. 24.75%, Nippon Oil Exploration 15%, and Tap Oil Ltd. 10%.
Seismic indicates large structures off Bahamas
Preliminary onboard processing of 2D seismic in southern Bahamas waters shows numerous structures with four-way dip closure much larger than previously expected, said Bahamas Petroleum Company PLC.
Independent consulting geological analyses of the January 2011 2D seismic preliminary mapping results and June 2010 fully processed prestack time migration data provide evidence of giant-size structures capable of holding several hundred million barrels of oil on its southern licenses, the company said. Detailed processing will take 2 months.
The presence of a potential Middle Jurassic salt layer may point to a further subsalt play in the area, Bahamas Petroleum said. The company is considering a 3D seismic survey, and several vessels are available.
Bahamas Petroleum posted the consulting studies on its web site. It said they provide the first structure maps that document the size and extent of closure of the features, based on 1,120 km of seismic data, and demonstrate the consistency of fold formation, the continuity of folds along the structural trend, the ability to seismically map internal continuity of reservoir-seal strata across the folds, and the geometric form of the folds.
The extent and style of structural geometry of the large-scale folds was not possible from historical seismic data, said Dr. Paul Crevello, chief executive officer of Bahamas Petroleum.
Nonexecutive Chairman Alan Burns said, "These structures are exceptional in the size and extent of the four-way closure, indeed I am not aware of any anticlines of this size in the Gulf of Mexico-Caribbean region."
Strat test cores oil on Llanos CPO-17 block
A stratigraphic well on Hocol SA's CPO-17 block in Colombia's Llanos basin has cored oil shows in several formations, said 50% partner Maurel & Prom, Paris.
The first well, drilled to a depth of 864 m, has shown the presence of in situ oil in Basal Oligocene sands.
Hocol recovered 96 m of cores of which 27 m have oil impregnation and 9 m show significant oil saturation. Further analysis is being carried-out to determine reservoir parameters. There were also oil indications during drilling in the C5 and C7 formations.
The work program for this prospect includes more stratigraphic wells and a regular exploration well, Merlin-1, with a main Oligocene objective to allow for possible production testing. Other large prospects have been defined from 680 line-km of 2D seismic shot in 2010.
CPO-17 covers 2,103 sq km 200 km southeast of Bogota between Castilla and Rubiales oil fields. It was awarded in 2008.
Drilling & Production — Quick TakesManifa drilling sets new Saudi well length record
Saudi Aramco reported that a recent well in Manifa oil field, drilled to 32,136 ft TD, set a new length record for wells drilled in Saudi Arabia. This length surpassed the previous 30,850 ft in an earlier Manifa well.
A Precision Drilling Corp. land rig drilled both wells.
Discovered in 1957, Manifa field is in shallow waters southeast of Tanajib, about 200 km northwest of Dhahran.
Aramco is developing the field from 27 drilling islands connected by a 47-km long causeway, in addition to 16 onshore drill sites and 13 offshore platforms.
During the May 2010 Offshore Technology Conference, Zuhair Al-Hussain, Aramco vice-president, drilling and workovers, said production from Manifa will start in mid-2013 but will not ramp up quickly to the original target of 900,000 b/d of Arab heavy oil (OGJ, May 10, 2010, p. 19).
Total begins production at Itau field
Total SA has begun production at the Itau gas-condensate field on Block XX, Tarija Oeste, 400 km south of Santa Cruz city in Bolivia's Andean Cordilleras foothills.
The first phase of the development, which came on stream on Feb. 2, is designed to produce 1.5 million cu m/d of gas, which will be processed in facilities of the neighboring San Alberto field. Most of the production will be exported.
Additionally, Total said that the Block XX joint venture also submitted a development plan that by mid-2013 aims to increase Itau's production to 5 million cu m/day (cmd) from the current 1.5 million cmd. The plan is subject to approval by Bolivia's state-owned Yacimientos Petroliferos Fiscales Bolivianos.
Total declared the Itau gas-condensate field commercial in 2009, 10 years after its discovery. At the time, Total expected Itau would be bought on stream during 2010 at an initial 50 MMcfd (OGJ Online, Aug. 4, 2009).
Statoil seeks contract for less expensive rigs
Statoil issued a tender for a minimum of two new type, less-expensive rigs for drilling and completing wells in the mature areas on the Norwegian continental shelf.
Statoil said that the specially-designed category D rigs should have a design for operating in 100-500 m of water and be capable of drilling to an 8,500-m depth.
The rigs delivered to the NCS in recent years were first and foremost constructed for operations in deep water," says Jon Arnt Jacobsen, chief procurement officer in Statoil.
"That means that they are big and too costly for our requirements and challenges on the NCS. We are therefore taking steps to rejuvenate the rig fleet and ensure that the right rig meets the right requirements."
Statoil wants to contract the rigs for either 8 years with four 3-year options or for a 20-year firm contract period. It said that this is an unusually long contract period and will reduce the risk for the drilling contractor that will build the rigs. Statoil is also considering taking an ownership stake in the rigs.
"The goal is that the new rig will drill 20% more effectively than conventional rigs," says Jacobsen. "This will help to counteract the cost trends in the rig market."
Statoil plans to award the contract in third-quarter 2011 with delivery of the rigs set for second-half 2014.
Chevron lets Tahiti Phase 2 contract
Chevron Corp. contracted Subsea 7 SA for the engineering and installation of the Tahiti Phase 2 development in about 4,000 ft of water in the Gulf of Mexico, about 190 miles south of New Orleans.
Subsea 7's workscope includes the installation of one 7.5-in. by 13,000 ft long flexible riser, one 4-in. by 4,500 ft long umbilical, five rigid well jumpers, 10 electrical flying leads, and seven steel flying leads.
It also will transport the flexible riser from Le Trait, France to the Gulf of Mexico and commence immediately the engineering work at its Houston office. Plans are to install the flexible riser and umbilical in third-quarter 2011 and tie in five wells through mid 2012.
For the installation work, Subsea 7 will use the Seven Oceans (pipelay) Skandi Neptune (construction/flexlay), and the Ross Candies (light construction/installation, maintenance, repair) vessels.
Chevron began production from the Tahiti spar in May 2009. The field lies in Green Canyon Blocks 596, 597, 640, and 641.
Chevron is the operator of Tahiti and holds a 58% interest. Its partners are Statoil Gulf of Mexico LLC 25% and Total E&P USA Inc. 17%.
PROCESSING — Quick TakesUS refiners Holly, Frontier Oil to merge
Inland US refiners Holly Corp. and Frontier Oil Corp. have agreed to merge in what the companies described as "an all-stock merger of equals transaction."
Holly operates the 100,000 b/d Navajo refinery at Artesia, NM; a 125,000 b/d refinery in Tulsa; and a 31,000 b/d refinery at Woods Cross, Utah. It also produces and markets asphalt and has pipeline and logistics assets.
Frontier owns a 135,000 b/d refinery at El Dorado, Kan., and a 52,000 b/d refinery in Cheyenne, Wyo. It also markets products along the eastern slope of the Rocky Mountains and in neighboring plains states.
The new company, HollyFrontier Corp., will be based in Dallas, Holly's headquarters. It will have an enterprise value estimated at $7 billion.
Mike Jennings, chairman, president, and chief executive officer of Frontier, will be president and CEO of the combined company. Matt Clifton, Holly chairman and CEO, will be executive chairman.
The new board will have seven directors each from the predecessor boards.
EPA begins air pollution study near Hovensa refinery
The US Environmental Protection Agency began a 3-month study of air pollution from Hovensa LLC's US Virgin Islands refinery and other sources.
The federal environmental regulator installed air monitoring equipment to measure volatile organic compounds at three locations where the biggest air pollution impacts from the plant and other facilities in the area.
Hess Corp., which built the refinery in 1966, and Petroleos de Venezuela SA, Venezuela's national oil company, jointly operate the plant. It has a 500,000 b/cd crude oil processing capacity and can store up to 32 million bbl of crude oil and products.
EPA said the study will provide information on whether air quality near the three monitoring locations poses health concerns, and to help guide strategies for reducing air pollution.
The Virgin Islands Department of Natural Resources monitors particulate matter on St. Croix, where the refinery is located, while the refinery tracks its sulfur dioxide emissions, EPA noted. That information also will be reviewed, EPA said.
Following standard EPA monitoring protocols, air quality monitors at the three locations will collect outdoor air samples over 3 months. Results from all the locations will be analyzed to evaluate the potential for health concerns related to long-term exposure to identified pollutants, EPA said. It expects to release the preliminary monitoring data by late spring and issue a final report this summer.
Valero starts up benzene reduction at refineries
Valero Energy Corp. has successfully started up advanced reformate splitters at refineries in Texas and Tennessee.
The three Mobile Source Air Toxic (MSAT) II benzene concentration units are at Valero's Port Arthur and Sunray, Tex., and Memphis, Tenn., refineries. They use advanced reformate splitter Dividing Wall Column towers conceived by Valero and designed and optimized by KBR.
A fourth unit at Valero's St. Charles refinery in Norco, La., and will be commissioned later this year.
The DWC tower concentrates and removes benzene from gasoline streams to allow a refinery to meet US regulatory mandates limiting benzene content in motor gasoline.
TRANSPORTATION &mdash: Quick TakesQatargas 4 ships first cargo of LNG to India
Qatargas and Shell announced the first cargo of LNG from their Qatargas 4 (QG4) Project is bound for India's Hazira receiving terminal aboard the Q-Flex LNG carrier Al Ruwais, owned by Qatar Gas Transport Co.
QG4 produces 1.4 bsfcd of gas, delivering 7.8 million tonnes/year of LNG and 70,000 b/d of condensate and LPG. Qatargas's seventh train, QG4, brings the firm's total production capacity to a record 42 million tonnes/year of LNG.
Due to the increased production from QG4, Qatargas earlier this month announced it had become the world's largest LNG producer (OGJ Online, Feb. 10, 2011).
"Qatargas cements its place...as the world's premier LNG supplier," said Peter Voser, chief executive officer of Royal Dutch Shell PLC on Feb. 9. "Cargoes from the QG4 project will enable new customers around the world to benefit from using cleaner-burning natural gas from Qatar."
The QG4 project was constructed and is operated by Qatargas. The project's shareholders are Qatar Petroleum with 70% interest and Shell with 30% interest.
Enbridge books capacity for Bakken pipeline expansion
Enbridge Energy Partners LP and Enbridge Income Fund Holdings Inc. finalized 100,000 b/d of open season capacity commitments with additional shippers for the Bakken Expansion Program on the Enbridge North Dakota System, owned by EEP, and the Enbridge Saskatchewan System, owned by the Enbridge Income Fund.
Added capacity from this expansion will total 145,000 b/d, of which 25,000 b/d will be available by early 2011, following completion of the Portal Reversal Expansion Project, and the remaining 120,000 b/d by late 2012. The 2012 timing is earlier than the early-2013 projection that Enbridge estimated when it first announced the expansion (OGJ Online, Aug. 25, 2010).
The expansion program will originate at Beaver Lodge, ND, and follow existing EEP and EIF right-of-way to terminate at and deliver to the Enbridge mainline terminal at Cromer, Man. Once on the Enbridge mainline, Bakken production will have access to multiple markets.
Regulatory arrangements require a maximum of 115,000 b/d be held by committed shippers, with at least 30,000 b/d reserved for uncommitted volumes. The majority of agreements are for 10-year terms. Enbridge places the ultimate expansion capacity of the program at up to 325,000 b/d with modifications and additional facilities.
Enbridge expects total cost of the program to be near $560 million, involving US projects by EEP costing about $370 million and Canadian projects by EIF costing $190 million (Can.).
Energy Transfer to build Eagle Ford pipeline
Energy Transfer Partners LP will build a new 160-mile, 30-in. OD natural gas pipeline in the Eagle Ford shale.
The Rich Eagle Ford Mainline (REM) will have initial capacity of 400 MMcfd, expandable to 800 MMcfd. It will originate in Dimmitt County, Tex., and extend to ETP's Chisholm Pipeline for delivery to both existing processing plants and a new 120,000 MMcfd plant. ETP expects REM to enter service fourth-quarter 2011.
The project will expand ETP's midstream infrastructure in the Eagle Ford, which includes the recently completed Dos Hermanas pipeline and the Chisholm pipeline scheduled for completion in second-quarter 2011.
The initial phase of the Chisholm Pipeline will consist of 83 miles of 20-in. OD line extending from DeWitt County, Tex., to ETP's LaGrange processing plant in Fayette County, Tex. The pipeline will have an initial capacity of 100 MMcfd, with anticipated expansion to more than 300 MMcfd (OGJ Newsletter, Oct. 25, 2010).
ETP entered into multiple long-term agreements with shippers to underpin REM and estimates total cost of the natural gas pipeline, processing plant, and additional facilities at $300 million.
More Oil & Gas Journal Current Issue Articles
More Oil & Gas Journal Archives Issue Articles
View Oil and Gas Articles on PennEnergy.com
