GENERAL INTEREST - Quick Takes
Chevron to sell fuels, aviation business in SpainChevron Corp. agreed to sell its Spanish fuels, finished lubricants, and aviation business to Cia. Espanola de Petroleos SA (CEPSA).
The companies being sold are Chevron Espana SA and Chevron Estaciones de Servicio. The sale is subject to regulatory approvals. CEPSA plans to buy 62 Texaco-branded service stations in the Canary Islands and its aviation supply agreements at 11 airports. The transaction also includes the Valencia lubricants blending plant.
Chevron will retain its marine lubricants business in Spain.
BOEMRE announces EIS for 2012-17 lease sales
The US Bureau of Ocean Energy Management, Regulation, and Enforcement began environmental reviews for proposed Gulf of Mexico oil and gas lease sales during 2012-17 by announcing it would prepare an environmental impact statement (EIS) for the offerings.
The US Department of the Interior agency said it will propose a single, multi-tiered EIS for all proposed sales in the gulf's central and western planning areas during the next 5-year planning period for the US Outer Continental Shelf.
It said federal, state, and local government agencies, and other interested parties can submit comments to help BOEMRE determine significant issues and alternatives which need to be analyzed in the EIS. The agency also has scheduled public scoping meetings in Houston on Feb. 15, New Orleans on Feb. 16, and Mobile, Ala., on Feb. 17 in conjunction with similar meetings for preparation of the overall programmatic EIS for the entire 2012-17 federal OCS oil and gas leasing program.
PTTF recommends against regulation of CO2 network
The Pipeline Transportation Task Force's (PTTF) research into options for a future national US carbon dioxide pipeline system found the current state-based regulatory system sufficient to handle CO2 transportation needs for the foreseeable future. PTTF presented the findings in its final report, "A Policy, Legal, and Regulatory Evaluation of the Feasibility of a National Pipeline Infrastructure for the Transport and Storage of Carbon Dioxide."
The report noted that in response to demand for CO2 for enhanced oil recovery and other uses, the private sector had successfully constructed and is operating about 4,000 miles of CO2 pipelines in the US. The task force recommended the status quo model of private sector pipeline development and state regulation be continued. The report explicitly stated that "no federal role is required in order to develop CO2 pipeline projects."
It said, "The assumption that a federal mandate will produce the desired result (capture, transportation, and storage of nationally produced CO2) may not follow. Other state-based regulatory solutions should be carefully considered before pursuit of an untested federal strategy that could prove harmful to future CO2 pipeline construction."
The report also urged care be taken to ensure pipelines transporting CO2 for storage-only purposes are not viewed less favorably by the public then pipelines transporting CO2 for EOR.
The Interstate Oil & Gas Compact Commission and the Southern States Energy Board assembled regulators, policymakers, and industry representatives to form PTTF. The PTTF study focused on identifying various pipeline regulatory and business development models and the opportunities and difficulties associated with each of them.
EXPLORATION & DEVELOPMENT - Quick Takes
Statoil to develop find near Gullfaks SouthStatoil plans to develop a gas and condensate discovery in the Norwegian North Sea via tieback to facilities on nearby Gullfaks South field.
The 34/10-53 S well confirmed about 300 m of gas pay in the Middle Jurassic Brent Group. The Odfjell Drilling Deepsea Atlantic semisubmsersible rig drilled the well to 3,847 m vertical depth below sea level in 136 m of water.
The well, 2 km west of Gullfaks South in an area called Rimfaks Valley, bottomed in the Early Jurassic Statfjord formation, which yielded no hydrocarbons.
Statoil did not formation-test the well. It estimated recoverable oil equivalent hydrocarbons at 19-75 million bbl.
Statoil said the rig will plug the discovery well and drill a sidetrack, 34/10-53 A, to test a Brent Group prospect called Opal west of Rimfaks Valley.
Newfield adds oil area to Arkoma Woodford play
Newfield Exploration Co. has begun producing oil from the Woodford shale on the far west side of its predominately dry gas play in the Arkoma basin in southeastern Oklahoma.
The company, which has drilled six wells in Coal County, Okla., reported a peak initial rate of 1,400 b/d of oil equivalent, 35% oil. Four wells averaged 950 boe/d the first 30 days on production, 840 boe/d the first 60 days, and 760 boe/d the first 90 days. The oil is 41° gravity.
Newfield plans to run two to three rigs and drill 12-18 wells in the oily part of the play in 2011. It has identified 100 potential well locations so far.
Practically all of the company's 172,000 net acres in the overall play are held by production. The leases are in Atoka, Coal, Hughes, and Pittsburg counties.
Realm Energy builds European shale acreage
Realm Energy International Corp., White Rock, BC, is building a portfolio of shale gas and shale oil acreage in continental Europe, holding acreage in Poland and Germany and with more under application in other basins.
The company holds 465,000 net acres on two permits in the Baltic basin in northern Poland and one permit in the Podlasie basin in southeastern Poland. It is completing first-year work commitments that include a geologic assessment of existing log and seismic data and designing three seismic programs.
It holds 15,888 acres southwest of Hanover in the middle of Germany's Lower Saxony basin where a regional geological study should be finished by the end of February. It targets two prospective organic rich shale units. Also, several wells had oil and gas shows in tight sandstones.
The company has applied for more than 2.4 million acres in two basins in France, of which 1.65 million acres are on nine exploratory permits in the Paris basin. Realm Energy is in discussions with an undisclosed integrated North American energy company and leading shale player to join it in developing the Paris basin shale oil play.
Realm Energy and Halliburton Consulting are evaluating shale gas and oil opportunities in other European basins. This subsurface work has resulted in additional, large-scale shale exploration opportunities in respect of which Realm Energy has either submitted or is in the process or submitting new exploration permit applications.
High-pressure Cretaceous gas hit off Cameroon
Bowleven PLC has cemented off the lower portion of the Sapele-1 exploratory well off Cameroon after encountering a high-pressure gas reservoir in the Cretaceous.
Sapele-1 went to a total depth of 4,733 m on Block MLHP-5 of the Etinde Permit in the Douala basin. The company plans to test the well's Tertiary discoveries and drill three firm Tertiary and Cretaceous appraisal wells and one contingent well in 2011 using an additional rig expected to arrive late this month.
Bowleven halted drilling due to a "rapid influx of very high pressure gas" that precluded logging.
"Based on an initial analysis of the major step change in pressure encountered and the interpretation of the seismic, it is considered that the well may have encountered a significant hydrocarbon column in the Cretaceous.
"Further analysis of mudlogging and wireline data, together with gas chromatograph ratio analysis, has confirmed oil shows were encountered within thin sands in the upper part of the Cretaceous Epsilon Complex. Further interpretation and calibration of the well and seismic data is required to assess fully the implications for Cretaceous volumetrics," Bowleven said.
DRILLING & PRODUCTION - Quick Takes
Shell drops plans for Beaufort Sea drilling in 2011Shell Alaska dropped its plans to drill in the Beaufort Sea this year, Shell Alaska Vice-Pres. Peter Slaiby said during a Feb. 3 news conference in Anchorage. The announcement came after a ruling last month revoked federal clean air permits to allow the drilling.
A federal environmental appeals board in January ruled the US Environmental Protection Agency needs to do more extensive analysis of nitrogen dioxide emissions from vessels involved in drilling operations. The ruling was based upon appeals from Alaska Native and conservation groups.
Slaiby said Shell's decision to delay Beaufort exploratory drilling stemmed from "continuous regulatory delays." Royal Dutch Shell PLC has worked for 5 years and invested more than $50 million pursuing air permits to drill in Arctic waters off Alaska, he said.
Shell intends to work closely with the EPA to identify an improved process for delivering air permits for 2012, Slaiby said.
"Shell has dedicated significant time and resources to commencing a world-class, environmentally responsible exploration program for Alaska, and the loss of another drilling season is extremely disappointing," he said.
Previously, Shell Alaska had planned exploratory drilling during 2010 in both the Chukchi and Beaufort seas, but those plans were put on hold following the oil spill in the Gulf of Mexico from the deepwater Macondo well operated by BP PLC.
Sen. Lisa Murkowski (R-Alas.) issued a statement after Shell's announcement. Murkowski said the government's decision could "result in all of us paying more for gasoline-not to mention the loss of jobs and revenue that responsible development brings."
"We talk a lot about the economy, but rarely do our actions match our rhetoric," Murkowski said. "That's unfortunate."
Shell Offshore Inc. last year submitted an application to the US Bureau of Ocean Energy Management, Regulation, and Enforcement for a permit to drill an exploration well in the Beaufort Sea in 2011. The application was for the shallow waters of Camden Bay (OGJ Online, Oct. 7, 2010).
Eni starts Nikaitchuq oil field off Alaska
Eni SPA has started oil production from Nikaitchuq field off Alaska's North Slope. The company, with 100% interest, expects production to peak at 28,000 b/d and last 30 years. It estimates reserves at 220 million bbl.
At full development, the field will have 26 producing wells, 21 water injectors, and 5 water source and disposal wells. Twenty-two of the wells will be onshore and the rest offshore, drilled from an artificial island. The field lies in an average 3 m of water. Eni has completed the processing facility and 12 onshore wells. It plans to drill the remaining wells by 2014.
The wells have vertical depths of 4,000 ft and vertical reaches up to 20,000 ft. The operator says the under-seabed pipeline bundle connecting the on and offshore facilities is the heaviest ever installed in the Arctic.
The processing facility can treat 40,000 b/d of heavy crude with sand and as much as 120,000 b/d of water, enabling Eni to ship sales-quality crude through the Trans-Alaska oil pipeline with no further processing.
Range hikes Marcellus resource, pursues Utica
Range Resources Corp., Fort Worth, said its unproved resource potential rose to 35-52 tcf of gas equivalent at the end of 2010 compared with 24-32 tcfe a year earlier.
The company said its Marcellus shale resource potential rose to 20-31 tcfe due to higher per-well reserves. It also included for the first time the unproved resource potential for the overlying Upper Devonian shale in the Appalachian basin. That figure is 10-14 tcfe.
The remainder is attributable to the Nora area in Virginia and the Permian and Midcontinent areas where Range holds more than 560,000 net acres.
Range said its first Utica shale well in Pennsylvania averaged an encouraging 4.4 MMcfd of gas equivalent on a 7-day production test. No Utica shale resource potential is included in the yearend estimate, but that issue will become clearer as Range and others drill more Utica wells in 2011.
PROCESSING - Quick Takes
Fire extinguished at Mont Belvieu complexEnterprise Products Partners LP, Houston, said Feb. 9 that it found the contract worker missing since a Feb. 8 fire at the west storage network at the company's Mont Belvieu, Tex., complex about 35 miles east of Houston (OGJ Online, Feb. 8, 2011). The worker did not survive the fire.
Much of the residual product in lines around the storage network burned off, and Enterprise cut off all flow of any product that was feeding the fire, a spokesman said Feb. 9.
Cause of the fire will be investigated, the spokesman said, adding that the company also is evaluating the damages to the complex.
Previously, Enterprise reported that the main facilities at the Mont Belvieu complex "were not damaged" and "remain operational." These unaffected systems include "the natural gas liquids fractionators, the propylene fractionators, the butane isomerization units, the octane enhancement facility, north and east facilities, and the import-export terminals on the Houston Ship Channel."
Aramco taps KBR for Jazan refinery work
Saudi Aramco has let a front-end engineering and design and project management services contract to KBR for a grassroots refinery in the Jazan area of southern Saudi Arabia.
KBR reported crude capacity of the refinery, to be built in conjunction with a marine terminal on the Red Sea, at 400,000 b/d. Aramco earlier has described capacity as 200,000-400,000 b/d.
Aramco says the refinery ultimately will be integrated with a world-scale power and water facility. The terminal will be able to receive very large crude carriers. The refinery will have berths to support product exports.
The refinery will be able to process Arabian crude oils and to yield about 75,000 b/d of gasoline, 100,000-160,000 b/d of ultralow-sulfur diesel, and 160,000-220,000 b/d of fuel oil, according to Aramco.
UAE refinery expansion contracts awarded
Engineering and construction contractors for Abu Dhabi Oil Refining Co. (Takreer) have awarded contracts for mass-transfer equipment to GTC Technology Korea Co. Ltd., a unit of Houston-based GTC Technology International LP, as part of an expansion of the 350,000-b/d refinery at Ruwais.
The project is to be completed in 2013. No contract amount was announced.
The South Korea company will provide mass-transfer equipment for the crude distillation unit, saturated gas plant, and residue catalytic cracking unit under the subcontracts awarded by South Korean engineering and construction companies GS Engineering & Construction Ltd. and SK E&C Co. Ltd.
The scope includes engineering and fabrication of a variety of mass-transfer equipment including high-performance valve trays, structured packing, grid packing, vapor horns, and FCC feed distributors.
The RCCU is, according to the GTC Technology announcement earlier this month, the largest single unit of its kind in the world. The contract includes a "giant‐sized pre-flash column, crude column, and residue fluidized catalytic cracking main fractionator." The expansion includes 21 process units, off sites, and utilities, it said.
TRANSPORTATION - Quick Takes
TransCanada begins Keystone oil deliveries to CushingTransCanada Corp. has begun commercial deliveries of crude oil to Cushing, Okla., on the second phase of its $12 billion Keystone Pipeline system. The second phase is a 298-mile extension from Steele City, Neb., to Cushing and increases Keystone's nominal capacity to 591,000 b/d, of which 530,000 b/d is contracted.
The next phase of expansion for the Keystone Pipeline system is the proposed US Gulf Coast Expansion (Keystone XL) project. Keystone XL is a 1,661-mile, 36-in. OD oil pipeline beginning at Hardisty, Alta., and extending southeast through Saskatchewan, Montana, South Dakota, Nebraska, and Oklahoma to delivery terminals near Port Arthur, Tex.
Keystone XL needs approval by the US Department of State before construction can begin (OGJ Online, Jan. 27, 2011). TransCanada expects Keystone XL to enter service in first-quarter 2013, pending approval.
TransCanada concluded on open season in January for its Bakken Marketlink and Cushing Marketlink projects to deliver US-sourced crude from Baker, Mont., to Cushing and the US Gulf Coast. Bakken Marketlink secured 65,000 b/d of firm, term contracts. Cushing Marketlink will have capacity to move 150,000 b/d from Cushing to the US Gulf Coast. Both Bakken Marketlink and Cushing Marketlink will use pipeline facilities forming part of TransCanada's Keystone XL system. Combined the two projects will transport up to 250,000 b/d of US crude oil production to the Gulf Coast (OGJ Online, Jan. 27, 2011).
TransCanada's Horn River pipeline receives NEB OK
Canada's National Energy Board approved TransCanada Corp.'s Horn River natural gas pipeline project. The pipeline will connect British Columbia shale gas supplies to TransCanada's Alberta System. TransCanada anticipates bringing Horn River into service second-quarter 2012.
The $310 million, 155-km Horn River line consists of a new 36-in. OD line and acquisition of an existing 24-in. OD line. The project will provide firm service for Alberta System gas transportation contracts exceeding 630 MMcfd by 2014.
TransCanada expects British Columbia shale gas supplies to climb to more than 5 bcfd by the end of the decade and the Horn River pipeline is the company's second major pipeline connecting its Alberta System to these supplies. The first extension of the Alberta System into British Columbia was the Groundbirch pipeline, which came into service in December 2010. Horn River and Groundbirch shippers have committed to Alberta System contracts reaching 1.9 bcfd by 2014.
TransCanada plans to bring its Keystone Phase 2 crude pipeline and Guadalajara gas pipeline in Mexico into service during 2011. Keystone Cushing (Phase 2) extends 36-in. OD pipe from Steele City, Neb., to Cushing, Okla. TransCanada commenced commercial operation on the 435,000 b/d Keystone Phase 1, June 30, 2010. Phase 2 will boost capacity to 591,000 b/d.
The Guadalajara Pipeline will move gas from an LNG terminal under construction near Manzanillo on Mexico's Pacific Coast to both Guadalajara and the CFE CT Manzanillo power plant. The pipeline's first segment consists of about 6 km of 24-in. OD pipeline capable of transporting 500 MMcfd to the power plant. The second segment will consist of a 30-in. OD pipeline extending roughly 295 km between the Manzanillo LNG terminal and an interconnection with Pemex Gas y Petroquimica Basica. This segment will be bidirectional and capable of transporting as much as 320 MMcfd of gas.
Plains All American plans Shafter LPG expansion
Plains All American Pipeline LP reported plans to construct its Shafter Expansion Project, consisting of a 10,000 b/d LPG pipeline system and related upgrades to its Shafter LPG processing facility near Bakersfield, Calif. A 5-year transportation agreement with a unit of Occidental Petroleum Corp. underpins the project, currently expected to cost about $50 million. Oxy also has a general partner ownership stake in Plains All American.
The pipeline will link the Shafter facility with Oxy's Elk Hills gas processing plant and related infrastructure. Plains has targeted a third-quarter 2012 in-service date.
The Shafter expansion involves building a 15-mile LPG pipeline system as well as enhancing Plains' storage and rail capabilities at the Shafter facility. The facility currently includes roughly 200,000 bbl of NGL storage and a processing facility with 14,000 b/d butane isomerization capacity and 12,000 b/d NGL fractionation capacity. Plains expects to spend $30 million on the Shafter project in 2011 and the balance during 2012.
Egyptian gas supplies to Israel to resume Feb. 17
East Mediterranean Gas Co. (EMG) advised Ampal-American Israel Corp. that Egyptian National Gas Co. (Egas) expects to be supplying pipeline gas to EMG and therefore to EMG's Israeli clients by Feb. 17. Ampal owns a 12.5% interest in EMG.
Ampal announced Feb. 6 that an explosion and fire in a metering station along the 10.3 billion cu m/year Arab Gas Pipeline from Egypt to Jordan, owned and operated by Egas subsidiary GASCO, had interrupted these supplies. The affected GASCO station is about 30 km from the EMG line into which it feeds. GASCO is repairing a 200-m long segment of its line which was damaged by heat from the explosion.
Neither EMG's interconnect site its pipeline were damaged.
Venezuela orders crude tankers from Itochu Corp.
Itochu Corp. has won an order to supply four Aframax tankers to a subsidiary of Venezuela's Petroleos de Venezuela SA (PDVSA) and has commissioned Sumitomo Heavy Industries to build the vessels.
The ships will have a capacity of 104,300 dwt each and are scheduled for delivery in 2012. The four new vessels are likely to be added to a group of PDVSA tankers that transport oil produced in Venezuela to its refineries in the US and Europe.
Construction of the tankers will cost ¥25 billion with funding to be provided by the Japan Bank for International Cooperation, which reportedly agreed to provide ¥20 billion.
The agreement follows earlier ones in 2009, when Venezuela signed 12 energy-related agreements with Japan. At the time, PDVSA signed an MOU with Itochu, Mitsubishi, Itochu, Mitsui, and Marubeni regarding possible cooperation on the Mariscal Sucre LNG project.
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