GENERAL INTEREST — Quick Takes
Venezuela, Trinidad and Tobago sign energy accord
Venezuela and neighboring Trinidad and Tobago signed a unitization agreement that will enable both countries to develop the Loran-Manatee natural gas fields along their shared maritime border.
"For Venezuela it signifies we will have available gas volumes that we have on our side of the Deltana Platform, to continue sending gas to the Gran Mariscal de Ayacucho gas complex and eventually for our projects to export gas," said Venezuela's Energy Minister Rafael Ramirez.
"This is a start, and we are going to be looking towards other areas where accords can be made," said Trinidad and Tobago Energy Minister Carolyn Seepersad-Bachan, who added, "Our experience with exploration lately has not been as fruitful as in previous years."
Ahead of her arrival in Venezuela, Seepersad-Bachan said the cross-border field, estimated to hold 10 tcf of gas, has been under discussion for almost 20 years.
Venezuela's share of the unitized field will be 73.06% while Trinidad and Tobago's take will be 26.94%.
"It's a big accomplishment," Seepersad-Bachan said. "I mean it's going to be the first of its kind [involving] Trinidad and Tobago, and I think in this hemisphere as well, where you would have a cross-border field."
Loran field lies on Block 2 of the Plataforma Deltana. Petroleos de Venezuela SA has a 61% stake in the block and Chevron Corp. has 39%. ConocoPhillips was formerly a participant in the project as well, but it sold its stake to PDVSA last year. Chevron operates the Manatee prospect on Block 6(d) in Trinidad and Tobago—in partnership with BG Group.
Seepersad-Bachan said a market for the gas has not yet been determined, but indicated at least part of the gas should go to Trinidad and Tobago since the island is closer to the fields than is any developed area of Venezuela. In addition Trinidad and Tobago already has necessary infrastructure and is a major exporter of LNG through its Atlantic LNG facilities.
The two countries also are expected to negotiate similar agreements for the Dorado-Kapot and Cocuina Manakin fields, also on the shared maritime border.
API to make more standards available on line
The American Petroleum Institute will provide free on line public access to more of its standards and practices, including several that deal with safety, the trade association said on Aug. 23. It said 160 standards will be available on line once changes to its web site are complete.
Some API standards and practices already are available at www.api.org while others can be reviewed in person at government agency offices, according to API. The procedures are recommendations that are developed by committees from the oil and gas industry to keep operations safe and successful. API began the program in 1924.
"As API standards have been referenced in the Federal Register in rulemaking procedures, having copies available for public review in only a few locations did not meet our industry's goal for transparency," explained API Pres. Jack N. Gerard. "The industry's standards represent our commitment to safe and successful operations and practices. Wider access through online viewing platforms is part of our commitment."
API said the standards that will now be available represent almost one third of its total and will include all that are safety-related or have been incorporated into federal regulations. They will include process safety standards on refinery and chemical plant operations and equipment, offshore drilling standards, hydraulic fracturing and well construction standards, and pipeline safety standards on welding and public awareness programs.
The newly accessible standards will be available for review, and hard copies and printable versions will continue to be available for purchase, API said. The standards are generally technical and designed principally for use by oil and gas companies. Revenue from their sale supports API's standards program, which operates on a nonprofit basis, the association said. API expects to continue to sell standards to oil and gas companies and other interested parties, it added.
KNOC bids $2.9 billion for Dana Petroleum
Korea National Oil Corp. launched a hostile takeover bid Aug. 20 for Dana Petroleum PLC, Aberdeen.
Dana Petroleum, which operates mainly in the North Sea and Egypt, has declined to recommend the offer, worth $2.9 billion at valuation last week.
Several of Dana Petroleum's large shareholders backed the offer, and the South Korean state energy company said it had received support for 48.62% of the British company's shares. KNOC is seeking at least 90% of the stock.
Exploration & Development — Quick Takes
Apache extends drilling in Faghur basin
Houston independent Apache Corp. reported two oil discoveries and a significant appraisal in the Faghur basin in the far southwest of Egypt's Western Desert.
Pepi-1X, drilled 10 km south of the company's Phiops field, flowed on test 4,216 b/d of oil and 4.9 MMcfd of natural gas from a 68-ft gross interval in the Lower Safa formation.
Buchis South-1X, also drilled 10 km south of Phiops, logged 131 ft of pay in several Cretaceous zones, including the Kharita and Alam El Buieb (AEB) sands. A test in one AEB zone flowed 1,647 b/d of oil.
The Faghur-8X step out appraisal extended the Faghur field by 2.7 km to the east. The well logged 79 ft of stacked Cretaceous pay in multiple AEB sands. A well test in one AEB sand flowed at an average rate of 2,992 b/d of oil.
The Pepi and Buchis discoveries set up several additional exploration drilling opportunities on trend, and Faghur-8X increased the size of the field and set up a number of follow-up development drilling opportunities, Apache said.
Current gross production from Faghur basin is about 24,000 bo/d. Additional infrastructure projects are expected to bring processing and transportation capacity from the basin to 40,000 bo/d before yearend. In the second quarter, Apache's gross production in Egypt totaled 181,000 bo/d and 789 MMcfd of gas. Apache's net production during the period totaled 98,500 bo/d and 388 MMcfd of gas.
This year Apache has drilled five discoveries among eight exploration wells in the Faghur basin (OGJ, July 5, 2010, p. 42). Drilling is under way on two wells, WKAL I-3X and Nebra-1X, and five additional exploration wells are planned.
Apache continues to evaluate 3D seismic surveys, including a recently completed 400 sq km survey, to identify additional exploration opportunities in the basin, which extends across portions of several Apache-operated concessions.
Cairn finds noncommercial gas off Greenland
Cairn Energy PLC said its T8-1 exploratory well off Greenland has discovered the first hydrocarbons in the Baffin Bay basin.
The well, operated by Cairn's Capricorn Oil Ltd. unit, has not reached target depth, but the discovery of biogenic gas with components of thermogenic gas in thin sands is indicative of an active hydrocarbon system, Cairn noted. Drilling is to be finished by the end of August.
Meanwhile, Cairn expects the Alpha-1 well on the Cretaceous Alpha prospect to reach its target objectives in September. The company sidetracked the well in the Tertiary volcanic section for mechanical reasons and is setting casing in the volcanics. The third exploratory well will be drilled on the T4 prospect 150 km northwest of Alpha and 150 km north of T8. The fourth well is dependent on the drilling schedule and is yet to be decided (see map, OGJ, Aug. 24, 2009, p. 38).
Alpha-1 and T8 are in 300-500 m of water on the Sigguk block 175 km off Disko Island, west Greenland. Planned target depths are 4,200 m and 3,250 m, respectively. The Stena Don semisubmersible and the Stena Forth drillship are drilling the wells.
Cairn said that on average two to three icebergs a day have drifted within a 25 km radius of the mobile drilling units. This is fewer icebergs than anticipated and well within the capability of the company's fleet of towing vessels to handle.
Statoil hits pay near Gudrun off Norway
Statoil is considering development of a small oil and gas discovery in the Norwegian North Sea via tieback to Gudrun field under development about 55 km north of Sleipner oil field.
The company estimates that the Brynhild discovery, on Production License 187 about 3 km east of Gudrun, holds 3-19 million boe of oil and gas.
The 15/2-9 wildcat and sidetrack penetrated 18 m of oil pay in the Upper Jurassic Draupne formation with good reservoir quality and 35 m of oil and gas pay of variable reservoir quality in Middle Jurassic Hugin.
The Transocean Leader semisubmersible drilled the well to the Middle Jurassic Sleipner formation at a vertical depth of 4,630 below sea level in 108 m of water.
"The Brynhild find is a valuable addition to the field development project on the Gudrun field, although it's no secret that the size of the discovery didn't quite meet the expectations we had beforehand," said Tom Dreyer, Statoil vice-president for infrastructure-led exploration in the North Sea.
The only other well on PL 187 was drilled in late 1998 and early 1999 by Amoco Norway to test Paleocene Balder and Hermod sandstones. It was a dry hole.
Statoil operates the license with a 65% interest. Partners are GDF Suez Norge E&P AS, 25%, and Marathon Petroleum Norge AS, 10%.
The semi next will drill a shallow well to test seabed conditions at Gudrun, where Statoil plans to install a 16-slot platform and begin development drilling next year (OGJ, June 28, 2010, Newsletter).
Abraxas, Blue Stone in Eagle Ford venture
Abraxas Petroleum Corp., San Antonio, and Blue Stone Oil & Gas LLC, Denver, have formed a joint venture to develop Abraxas acreage in the Eagle Ford shale play of South Texas.
Abraxas will contribute 8,333 net acres to the joint venture in exchange for a $25 million equity interest, while Blue Stone will contribute $25 million for an equivalent stake. Blue Stone has committed to invest a further $50 million. At full funding, its interest will rise to 75%.
The venture will acquire additional 3D seismic data, expand the acreage position, and drill and complete wells in the Eagle Ford shale. Its target area covers 12 counties.
Abraxas President and Chief Executive Officer Bob Watson said he expects the venture's funding to support drilling and completion of 10 wells, which his company will operate. Blue Stone will manage day-to-day business.
Drilling & Production — Quick Takes
Roc gains CNOOC approval for Beibu Gulf plan
A joint venture led by Roc Oil Ltd., Sydney, has received approval from China's CNOOC for the overall development plan for three offshore oil fields in the the Beibu Gulf.
CNOOC has signed a supplemental development agreement for the 6.12, 6.12 South, and 12.8 West oil fields attached to the Block 22/12 petroleum contract area, thus confirming the national company's 51% participating interest and the arrangements concerning facility integration plus the sharing of services and personnel.
Roc's Beibu Gulf development includes the use of existing CNOOC-operated processing, pipeline, storage, and sales facilities on the 12.1 oil field to host production from the three fields. Estimated total recoverable reserves range from 15-72 million bbl.
The commercial terms encompass tariff charges for use of the CNOOC pipeline and terminal facilities as well as other cost-sharing arrangements.
CNOOC will take up operatorship of the new project's facilities on behalf of the Roc JV and be responsible for engineering and construction. This is expected to take advantage of existing synergies and lower cost structures.
As many as four new exploration wells will be drilled from the 6.12 South and 12.8 West platforms during the development work.
Final investment decision on the Beibu Gulf project is scheduled for October or November. The fields should then be brought on stream during second-half 2012.
Sudan to boost oil output by 33% in 2011
Sudan's Oil Minister Lual Deng said he expects the country to increase its oil output next year to 600,000 b/d, up from 450,000-470,000 b/d currently.
"For next year, all things being equal, we expect between 500,000 and 600,000 [b/d]. We are aiming at 650,000 [b/d]," Lual told a government-sponsored seminar on transparency in the country's oil sector.
"It is the lack of transparency, or the perceived lack of transparency, that has fuelled mistrust between partners," he said, referring to the split between northern and southern regions of the country.
"We hope to comfort all the Sudanese people that there will be transparency even if there was none in the past," said Lual, who is from the former southern rebel Sudan People's Liberation Movement (SPLM).
"We want to enhance trust between the north and south," said Lual, aware of independent reports that the lack of transparency could destabilize the 2005 agreement that ended Sudan's civil war between north and south.
The accord, which was based on an agreement to share oil revenues, gives the south Sudanese the right to vote in January in a referendum on whether to remain part of Africa's largest country, or to become independent.
According to Lual, Sudan will publish daily production figures and conduct a full independent audit of the oil industry since 2005, which could help prevent future conflict over oil. The pledge aims to remove a source of contention ahead of the referendum. "The audit is basically to look at the production since 2005—it will be done by an independent firm," Lual said. "Our preference is to accelerate the process so that the results are made available before the referendum," he added.
Most of Sudan's estimated 6 billion bbl of oil reserves are in the south, but the north holds most of the country's infrastructure, including its major pipelines, refineries and oil export terminal at Port Sudan on the Red Sea.
Suncor reports oil sands hydrogen unit outage
Suncor Energy Inc. reported an outage at a hydrogen reformer unit in its oil sands base plant in Fort McMurray, Alta.
The cause of the outage was being evaluated, Suncor said Aug. 20. The production mix of low and high-sulfur products will be affected pending repair of the unit.
Oil sands production continues to be more than 300,000 b/d, the company said.
PROCESSING — Quick Takes
Essar: Refinery upgrade mostly on track
Essar Energy, Mumbai, says an expansion and upgrade of its 300,000-b/sd refinery at Vadinar, India, is mostly on schedule except for two of nine processing units, including a delayed coker.
The expansion, which might be followed by another, will take total throughput capacity to 375,000 b/sd and is due for completion next March.
But the coker and vacuum gas oil hydrotreater are about 3 months behind schedule, the company said in a report on first-half earnings.
"Actions are being taken to bring these units back on track," the report said. "Production is expected to commence within the next 12 months."
In addition to crude and vacuum distillation, the refinery's main units now are for fluid catalytic cracking, continuous catalytic reforming, diesel hydrodesulfurization, and naphtha hydrotreating. The facility began commercial operation in May 2008.
Essar, also a major producer of electric power, reported first-half earnings after tax and before noncontrolling interests of $111.9 million, down 28% from a year earlier, on total revenue of $4.77 billion, up 66%.
In a July prospectus for a public offering of shares in the UK, the company said it is considering a second expansion that would push total operating capacity to 750,000 b/d, which would make the refinery one of the world's largest.
Vadinar is near Jamnagar on India's west coast, where Reliance India Ltd. recently completed a refinery adjacent to an existing facility that brought total capacity to 1.24 million b/d, making the complex the largest on a single site in the world.
ONGC awards gas processing work
India's Oil & Natural Gas Corp. has awarded gas processing contracts worth 11.95 billion rupees ($25 million) to Larsen and Toubro Ltd., Mumbai, to expand processing capacity at ONGC's gas processing plants at Uran and Hazira.
The additional units at Uran, according to Larsen and Toubro, will expand processing capacity by 5 million standard cu m/day. Among new capacities to be installed are gas sweetening, LPG recovery, condensate fractionation, condensate handling, and other units.
The additional gas processing facilities project for Hazira will increase capacity by 5.6 million standard cu m/day and include gas sweetening, gas dehydration, dewpoint depression, and other units.
The scope for Larsen and Toubro includes project management, residual basic design, planning and monitoring, residual process engineering, detailed engineering, procurement, supply, fabrication, manufacturing, inspection, transportation, storage, construction, installation, testing, mechanical completion, precommissioning, commissioning, performance guarantee tests, and transferring ownership to ONGC.
Maintenance continues at Peruvian refinery
Repsol YPF SA is continuing with maintenance on several production units at its 108,000-b/d La Pampilla refinery in Peru's Callao province.
The 15,500-b/d fluid catalytic cracking unit has a turnaround scheduled for March 2011. The FCCU unit will be kept off-line for 23 days.
Repsol YPF is currently evaluating offers for equipment procurement.
Shell selling small Germany refinery
Royal Dutch Shell PLC entered a binding agreement to sell its 90,000-b/d Heide refinery in Germany to Klesch & Co., a family investment firm based in London and Geneva.
Shell didn't disclose terms. It said the deal, which is subject to regulatory approval and includes local infrastructure and businesses, is part of its plan to reduce global refining capacity by 15%.
The refinery's processing capacities are 15,000 b/d visbreaking, 18,000 b/d cyclic catalytic reforming, 16,000 b/d catalytic hydrocracking for distillate upgrading, and 25,000 b/d catalytic hydrotreating for pretreatment of cat reformer feed.
TRANSPORTATION — Quick Takes
Nabucco confirms two-feeder routing cuts Iran
Nabucco Gas Pipeline International GMBH confirmed that feeder lines into the natural gas pipeline would run to the Turkish-Georgian and Turkish-Iraqi borders and ordered engineering works for these two lines. Nabucco, however, cited political concerns in tabling a third potential feeder line to the Turkish-Iranian border. The two-feeder routing plan offers Nabucco access to supplies from Azerbaijan, Turkmenistan, and Iraq.
In April European Union Energy Commissioner Gunther Oettinger touted the importance of Turkmenistan as a gas supplier to Europe through a southern Caspian corridor. Other southern corridor projects cited by Oettinger as part of the EU's efforts to diversify supply sources away from Russia include the White Stream pipeline from Georgia and the Interconnector among Turkey, Greece, and Italy (ITGI). Parties to the ITGI signed a memorandum of understanding on the project in June, with the 804-km line expected to enter service in 2015 (OGJ Online, June 21, 2010).
The 56-in. OD Nabucco pipeline will bring gas to the Baumgarten hub in Austria near the Slovakian border at a rate of 31 billion cu m/year, before moving it on to Western Europe. Feasibility studies have led to a two-stage construction plan. The first phase, starting in 2011, calls for 2,000 km of pipe between Ankara, Turkey, and Baumgarten, allowing 8 billion cu m/year of gas from the existing Turkish pipeline network to be transported through the line by 2014 (OGJ, Feb. 15, 2010, p. 48). Second-stage construction would begin in 2012 and build eastward from Ankara to the Iraqi and Georgian borders, bringing total pipeline length to 3,300 km.
Ecopetrol plans 450,000-b/d crude oil line
Ecopetrol SA incorporated a new special-purpose company, Oleoducto Bicentenario de Colombia SAS, to construct and operate a 960-km, 450,000-b/d oil pipeline to move crude from the Llanos basin to the port of Covenas for export.
Ecopetrol estimates investment costs for the first phase of the line, from Araguaney to Banadia, and system upgrades at the port of Covenas at $1.031 billion. The total estimated cost of the project, including the line's Phase 2 (Banadia to Ayacucho) and Phase 3 (Ayacucho to Covenas) is $4.2 billion. Phase 1 construction would begin in October with completion of the entire pipeline expected by yearend 2012.
Ecopetrol Pipelines International Ltd. initially will be the project's sole shareholder, but Ecopetrol plans to capitalize the project by inviting participation by other producers.
The Llanos basin is one of Colombia's most prospective with, most recently, Canacol Energy Ltd., Calgary, announcing positive test results from the Ubaque reservoir at its RH-6 development well in the basin's Rancho Hermoso field.
Ecopetrol assumed direct operation of Llanos' giant Cupiagua and Cupiagua Sur fields on June 30, following 28 years of joint operation with BP PLC affiliates and others.
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