General Interest - Quick Takes
MMS okays suspensions for ultradeep wells
The US Minerals Management Service has issued a final rule that will allow suspensions of operation (SOOs) to oil and gas operators contemplating ultradeep wells (deeper than 25,000 ft TVD) in the Gulf of Mexico.
A SOO temporarily suspends time counted toward lease expiration for companies needing more time for data analysis prior to drilling.
MMS officials said the availability of SOOs might increase US production by accommodating the complexity and cost of drilling ultradeep wells.
MMS’s final rule grants SOOs under the following circumstances:
• The lease has either a 5-year or 8-year primary term with a requirement to drill within the first 5 years.
• The lessee or operator has approved plans to drill an ultradeep well on the lease.
• Before the end of the fifth year of the primary term, the lessee or operator must have acquired and interpreted geophysical data that indicate that all or a portion of a potential hydrocarbon-bearing formation is ultradeep and that include full 3D depth migration over the entire lease area.
• Before requesting the suspension, the lessee or operator has conducted, or is conducting, additional data processing or interpretation of the geophysical information with the objective of identifying a potential ultradeep hydrocarbon-bearing geologic structure or stratigraphic trap.
• The lessee or operator demonstrates that additional time is necessary to complete current processing or interpretation of existing geophysical data or information; to acquire, process, or interpret new geologic or geophysical data or information that would impact the decision to drill the same geologic structure or stratigraphic trap; or to drill into the potential hydrocarbon-bearing formation identified as a result of the activities conducted in previous paragraphs.
Deepwater leases with 10-year primary terms are not covered by the final rule because MMS believes that 10 years is sufficient to explore and develop deep prospects.
The final rule becomes effective Jan. 17.
Sakhalin II Phase 2 clears EDRB hurdle
Sakhalin Energy Investment Co. Ltd. has received a determination from the European Bank for Reconstruction and Development (EBRD) that its Sakhalin II Phase 2 is “fit for purpose” on environmental and social issues management.
EDRB is a prospective lender to the huge offshore oil and gas development and LNG project in Russia’s Far East, which has been hampered by rising cost estimates and delays.
Early this year, Royal Dutch Shell PLC, parent of Sakhalin Energy’s lead partner, warned that costs for the phase might reach $20 billion, twice the original estimate for the entire Sakhalin II project (OGJ, July 25, 2005, p. 26).
The project also has encountered delays related to environmental issues (OGJ, Aug. 8, 2005, p. 30).
Shell now plans to start year-round oil production, which depends on pipeline construction, in late 2007 and LNG sales in the summer of 2008.
Sakhalin II produces about 80,000 b/d during summer, with oil moving to Japan via tanker.
Prospective lenders have been reviewing Sakhalin II Phase 2 for 3 years.
EDRB’s fit-for-purpose declaration allows the start of a 120-day period of public disclosure of and consultation on the project’s environmental, social, health, and safety issues and mitigation documentation.
Oil tax proposed to fund alternative energy
A new tax on revenue from California oil production to fund an alternative-energy program has been proposed for consideration in the November 2006 election.
The California attorney general received an initiative for the new levy last month.
“The initiative is reportedly being sponsored by the Natural Resources Defenses Council, which has significant financial resources available as an organization,” said the California Independent Petroleum Association.
CIPA hired a law firm to analyze the proposal and identify points that may be open to legal or constitutional challenge.
The proposed “California Energy Independence Fund Assessment” would apply at rates as high as 6% on gross revenue from Californian oil production.
Proceeds would finance the “Clean Alternative Energy Program.” The initiative, which emphasizes ethanol and biodiesel projects, targets $4 billion over 10 years.
Producers and royalty owners would be taxed separately.
The tax rate would vary with the price of crude oil, reaching the maximum rate when the price exceeded $60/bbl. The rate would be lower for stripper production, which would be exempt when the crude price was below $50/bbl.
The initiative would prohibit producers from passing the tax through to consumers. ✦
Industry Scoreboard
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Exploration & Development - Quick Takes
Deep gulf well is an oil strike, Nexen says
The deepest well drilled so far in the Gulf of Mexico is an oil discovery, says Nexen Inc., the block operator.
The first well on the Knotty Head prospect on Green Canyon Block 512 indicated 600 ft of net oil pay in multiple zones, Nexen said.
Fluid samples, conventional cores, and sidewall cores were taken in the productive intervals. Analysis indicates high-quality crude oil in good quality reservoir sands, Nexen said.
The well, in 3,557 ft of water, reached 34,189 ft MD, the longest penetration to date in the gulf (OGJ Online, Dec. 16, 2005).
Transocean Sedco Forex Inc.’s Discoverer Spirit ultradeepwater drillship began drilling the Knotty Head well in March 2005 and will drill a sidetrack appraisal well. Additional appraisal drilling is planned this year to determine the extent of the discovery.
Nexen, Anadarko Petroleum Corp., BHP Billiton Ltd., and Chevron Corp. each holds a 25% working interest in the block.
DNO well in northern Iraq encounters oil
DNO ASA, Oslo, said its well in the Kurdish area of northern Iraq, Tawke-1, encountered mobile oil at the top of the first of three prospective reservoir intervals (OGJ, Dec. 12, 2005, Newsletter).
Tawke-1, spudded on Nov. 28, reached the interval at 350 m. The drilling is part of production-sharing agreements signed with the Kurdistan regional government in June 2004.
The operation is controversial because the agreement does not involve Iraq’s formative central government.
The 24° gravity oil was circulated out and flared.
DNO plans to drill the full reservoir section, which the company believes could be 800 m thick, and to conduct wireline logs. DNO is the operator with 40% interest.
Foxtrot wildcat tests gas off Ivory Coast
Foxtrot International LDC, Abidjan, has tested natural gas from a 20-m perforated interval on the 930 sq km Block CI-27 in 400 m of water off Ivory Coast.
The Mahi-1 exploration well encountered a 135-m hydrocarbon column. It flowed at rates of 32 MMcfd of natural gas and 250 b/d of condensate through a 1-in. choke. The well was drilled by the GlobalSantaFe Aleutian Key semisubmersible.
Mahi-1 is 5 km south of the offshore Foxtrot gas field, which produces about 80 MMcfd. Block CI-27 also contains the Manta gas field, for which an application for development has been submitted. The block, operated by Foxtrot, has an estimated 300 bcf of gas reserves.
Partners in the block include state-owned Petroci, 40%; Bouygues Group unit SECI, 24%; Energie de Cote d’Ivoire (Enerci), a joint venture of Gaz de France and EDF Group, 12%; and Foxtrot, 24%.
ENI strikes oil in eastern South China Sea
CNOOC Ltd. reported a discovery in the ENI China BV Huizhou (HZ) 25-4-1 well in the eastern South China Sea.
The well is on Block 16/19 in the Pearl River Mouth basin about 180 km southeast of Hong Kong.
The well was drilled to 3,900 m TD in 102 m of water. On test, HZ25-4-1 flowed at 5,000 b/d. CNOOC has the right to acquire up to 51% working interest in any commercial discoveries on the block.
The discovery is 60 km from the producing HZ 19-3/2/1 oil fields on Blocks 16/08 and 16/19 (OGJ Online, Nov. 16, 2004). The fields have two platforms, 14 wells, and a subsea pipeline to the Nanhai Faxian floating production, storage, and offloading vessel.
Woodside to start Angel field development
Woodside Energy Ltd. reported that development of the Angel gas and condensate field off Western Australia will begin immediately following final investment decisions by North West Shelf Venture participants (OGJ Online, Nov. 1, 2005).
The $1.6 billion (Aus.) project will include installation of an offshore production platform-the venture’s third major structure on Australia’s North West Shelf-and associated infrastructure.
The remotely operated processing platform will be in 80 m of water about 49 km east of the venture’s North Rankin production facility, to which it will be connected by a new pipeline. The 7,500-tonne jacket substructure and 7,000-tonne topside are expected to be fully operational by fourth quarter 2008. Eight drilled and grouted, piled foundations weighing more than 3,000 tonnes each will secure the jacket to the seabed.
Three production wells will be drilled in 2006-07. The processing unit will have a capacity of 800 MMscfd of gas and 50,000 b/d of condensate.
Equal partners in the North West Shelf Venture are Woodside Energy (operator), BHP Billiton (North West Shelf) Pty. Ltd., BP Developments Australia Pty. Ltd., Chevron Australia Pty. Ltd., Japan Australia LNG (MIMI) Pty. Ltd., and Shell Development (Australia) Pty. Ltd. CNOOC NWS Private Ltd. is a member of the venture but does not hold an interest in its infrastructure.
Pertamina signs contracts for Libyan blocks
Indonesia’s state oil and gas firm PT Pertamina has signed contracts with Libya to explore and develop two blocks, one onshore and the other offshore.
Pertamina is expected to spend $3.6 billion to develop the Sirte Block in the Sahara Desert and the Sabrata Block in the Mediterranean Sea over a 30-year contract period under an agreement with Germany’s Commerzbank AG. Pertamina said it would initially spend $49.1 million to conduct seismic tests and drill two wildcat wells on the Sirte Block and another two wells on the Sabrata Block over a 5-year exploration period.
The company will start exploration in both blocks in 2006.
Pertamina would get 11.7% of the revenue from Sabrata during production period and 8.8% from Sirte, according to a company spokesman. He also said the Libyan government would bear 50% of the development cost and would repay 87.6% of the production cost.
The two blocks cover a total of 3,671 sq km. ✦
Drilling & Production - Quick Takes
Flow starts from Devil’s Tower satellites
Dominion Exploration & Production Inc. reported first production from three subsea wells in the deepwater Triton and Goldfinger oil fields, 140 miles southeast of New Orleans, on Mississippi Canyon Blocks 771, 772, and 728 in the Gulf of Mexico.
The wells are tied back to the Devils Tower dry-tree spar in 5,610 ft of water on neighboring Mississippi Canyon Block 773.
Dominion’s partner, Pioneer Natural Resources Co., Irving, Tex., reported that production from the fields has reached 40,000 boe/d. Pioneer said that production is expected to reach 50,000 boe/d as production is optimized via multizone completions in the Triton wells.
Dominion E&P made the Goldfinger oil discovery in 5,423 ft of water in early 2004 (OGJ Online, Apr. 14, 2004). It drilled the Triton discovery well, MC 772 No. 4, in 2002 and an appraisal well, MC 728 No. 1, in 2003.
Triton and Goldfinger production flows to the spar via insulated 6-in. by 10-in. pipe-in-pipe flowlines. Devils Tower is owned by Williams Cos. Inc. and operated by Dominion E&P.
The 6-mile tieback was accomplished with 3.5 days of production shut-in time on the spar. The wells were ready for commissioning a few days before Hurricane Katrina struck in late August 2005, Dominion E&P said.
“Since then, sustained production from Devils Tower has been limited by damage to downstream infrastructure owned by other companies,” the company reported. “Now that more downstream infrastructure has become available, the subsea wells have been brought on line.”
Dominion E&P owns a 75% working interest in Devils Tower, including the Triton and Goldfinger tiebacks. Pioneer owns the remaining 25%.
Norway approves Tordis IOR project
Statoil ASA received approval from the Norwegian government for a 2 billion kroner improved oil recovery (IOR) project at Tordis oil field in the North Sea.
The IOR project, scheduled to start in the second half of this year, is expected to boost recovery by about 35 million bbl. It will also reduce discharges of produced water to the sea.
“The project will be the first in the world to adopt full-scale subsea separation,” Statoil said.
The subsea separation system is due on stream in October 2007. Kongsberg FMC, under a 625 million kroner contract, will build the subsea separation station, which will be lifted into place in 2007 by Saipem UK under a 50 million kroner contract (OGJ Online, Nov. 10, 2005).
Stolt Offshore was awarded a 200 million kroner contract for marine operations in the field. Tordis is produced through subsea installations tied back to Staoil’s Gullfaks C platform.
La Vela field gas flow starts in Venezuela
Gas production has begun from the La Vela field in the East Falcon Unit at the base of Venezuela’s Paraguana Peninsula.
The Vinccler Oil & Gas CA unit of PetroFalcon Corp., Carpinteria, Calif., began delivering an initial 5 MMcfd of gas into Petroleos de Venezuela SA’s Interconnection Centro Occidente pipeline to the Paraguana Refinery Complex. It is the first field to deliver into the 36-in. system.
Vinccler plans to boost deliveries this year as it expands field facilities and hooks up more wells. It has reactivated the LV-6X, 7X, and 8X wells and drilled the 9 and 10X wells. The wells tested several oil and gas reservoirs as deep as 8,000 ft.
The company plans to tie in 15 MMcfd of shut-in gas production from the Cumarebo field on the same block next year.
Vinccler will focus its 2006 drilling program on developing an oil and gas accumulation at about 2,000 ft in the 10X well and on delineating the deeper reserves of the overall anticlinal structure.
OMV group signs letter for Maari platform
A consortium led by OMV New Zealand Ltd. has signed a letter of intent with Clough Ltd. of Perth for a contract to build and install the Maari oil field wellhead platform in the Taranaki basin off New Zealand.
The final agreement for the $170 million (Aus.) contract will be completed in a month. Clough will undertake engineering, procurement, construction, and installation of facilities related to the platform. Clough will apply its self-elevating DrillAce platform concept implemented in 2004.
The Maari field, discovered in 1983, lies in 100 m of water about 80 km off the North Island. Development comprises the wellhead platform with five producing wells and three water injectors tied back to a floating production, storage, and offloading vessel and shuttle tanker export arrangement. Total development costs are estimated to be $360 million.
Production is expected to reach 35,000 b/d, starting in first quarter 2008. Reserves are estimated at 50 million bbl.
Field interests are OMV 69%, Horizon Oil Ltd. 10%, Todd Petroleum Mining Co. Ltd. 16%, and Cue Inc. 5%. ✦
Processing - Quick Takes
Jamnagar refinery hydrogen capacity to grow
Reliance Industries Ltd., Mumbai, has let a contract to Linde AG, Wiesbaden, Germany, for five hydrogen units at its 660,000 b/cd refinery at Jamnagar, Gujarat.
Linde will perform basic and detail engineering, supply of equipment and materials, assistance for erection, and supervision of commissioning.
The work will increase production capacity to 525 MMscfd of hydrogen. It will make Jamnagar, according to Linde, “one of the largest pure hydrogen sources worldwide.”
Schwedt refinery to get etherification plant
PCK Raffinerie GMBH has let a €25 million turnkey contract to Uhde GMBH for a plant for the etherification of light naphtha with bioethanol at its 220,000 b/cd refinery at Schwedt, Germany.
The contract includes the engineering, supply of all material and equipment, construction management, commissioning supervision, and personnel training.
The plant, using a process licensed by Neste Jacobs Oy of Finland, will have the capacity to produce nearly 1 million tonnes/year of high-quality, light naphtha. It is scheduled to be on stream in September.
The refinery will use light naphtha produced by the plant as a high-octane blending component of gasoline.
FEED contract let for refinery expansion
Marathon Oil Corp. has let a front-end engineering design (FEED) contract to Fluor Corp. for a $2.2 billion expansion of its 245,000 b/d Garyville, La., refinery. The contract value was not disclosed.
Marathon plans to increase the facility’s crude capacity to 425,000 b/d. It plans to add a crude distillation unit, hydrocracker, reformer, kerosine hydrotreater, delayed coker, additional sulfur recovery capacity, and other infrastructure (OGJ Online, Oct. 27, 2005).
Fluor will provide FEED services for the processing units, utilities, and off sites. ✦
Transportation - Quick Takes
Contract let for Qatargas Trains 6 and 7
A joint venture of France’s Technip SA and Japan’s Chiyoda Corp. has won a $4 billion contract to build two LNG trains in Qatar.
The venture will conduct engineering, procurement, and construction of Trains 6 and 7 at the Qatargas plant in Ras Laffan.
Qatargas III, a joint venture of Qatar Petroleum (QP, 68.5%), ConocoPhillips (30%), and Mitsui & Co. Ltd. (1.5%), owns Train 6, which is to begin production in 2009 (OGJ Online, May 3, 2005).
Qatargas IV, a joint venture of QP (70%) and Royal Dutch Shell PLC (30%), owns Train 7, production from which is expected to start up at yearend 2010.
The trains each will have a production capacity of 7.8 million tonnes/year, with the output largely to be sold to the US.
Atlantic LNG’s Train IV starts production
Atlantic LNG Co. of Trinidad and Tobago (ALNG) has begun production from Train IV at its Port Fortin natural gas liquefaction plant in Trinidad and Tobago.
The $1.2 billion Train IV, currently one of the world’s largest liquefaction trains, has capacities of 5.2 million tonnes/year of LNG and 12,000 b/d of NGL and has a 700 m jetty and 160,000 cu m storage tank.
All of its LNG will be sold in the US, where Trinidad and Tobago is the leading LNG exporter. ALNG now will export 15 million tonnes/year to the US, an increase of 60% over its 2004 exports.
Train IV is owned by BP Trinidad & Tobago LLC, 37.78%; BG Group PLC, 28.89%; Repsol YPF SA, 22.22%; and National Gas Co. of Trinidad & Tobago LLC (NGC), 11.11%.
BP is expected to receive the first shipment of LNG at the Lake Charles, La., terminal. The train originally was scheduled for commissioning in the first quarter of this year (OGJ, Mar. 24, 2005, Newsletter).
Trinidad and Tobago has announced its intention to build another LNG train and has begun discussions with the Patrick Manning administration and potential LNG investors.
In addition, the LNG partners are expected to begin work immediately on debottlenecking Trains II and III, designed for total production of 6.7 million tonnes/year of LNG. Debottlenecking is expected to lead to the near equivalent of another small train of additional LNG production.
ALNG’s first train was built in 1995 to liquefy natural gas for export by BP Trinidad LNG BV, British Gas Trinidad LNG Ltd., Repsol International Finance BV, Suez LNG Finance SA, and NGC.
Kazakhstan-China oil line section filling
Line-fill has begun on the 614-mile, 32-in. crude oil pipeline between Atasu in northwestern Kazakhstan and Alashankou in China’s northwestern Xinjiang region.
The pipeline, part of a much larger project linking Kazakhstan and China, will initially transport as much as 210,000 b/d of crude from Aktobe in northwestern Kazakhstan, where China operates an oil field, and Russian oil from Siberia.
Kazakh Energy and Mineral Resources Minister Vladimir Shkolnik earlier said transport operations would start in midyear this year after 600,000 tonnes of crude oil are pumped into the pipeline.
The Atasu-Alashankou pipeline is the second part of the three-part Kazakhstan-China oil transport project. When all three stages are complete, the Kazakhstan-China pipeline will span nearly 1,930 miles from Atyrau to Alashankou in China.
The first section, completed in 2003, crosses western Kazakhstan from the oil fields of the Aktobe region to the oil hub of Atyrau. The third stage of the pipeline will entail completion of the Kenkiyak-Kumkol pipeline in central Kazakhstan.
Once the Kenkiyak-Kumkol-Atasu pipeline is in operation, officials say, the plan is to add crude produced in Kazakhstan’s far western regions, including the offshore Kashagan field.
Nurbol Sultan, a deputy director general at state-owned transport company KazTransOil, said that after completion of the Kenkiyak-Kumkol section it would be technically feasible to boost the pipeline’s capacity to 1 million b/d.
Italian firm orders petrochemical carriers
South Korea’s STX Shipbuilding Co. has received a $145 million order to build three petrochemical carriers for Italy’s Petro Barbaro Shipping SPA.
STX Shipbuilding will start delivering the vessels to Pietro Barbaro Shipping SPA from 2008, the company said. Each carrier will have a cargo carrying capacity of 51,000 tons. ✦
