Judy Maksoud Houston
Canada's Heritage Oil has encountered gas with the Tibat-1 gas/condensate disc-overy well offshore Oman.
The Tibat-1 well tested 10-12 MMcf/d, with associated condensate production rates of 750-900 b/d.
Drilling operations began on the Tibat prospect in late October of last year. Tibat was drilled from block 8 in the Arabian Gulf off the Musandam peninsula about 12 km south of the producing Bukha field platform.
The Tibat prospect targeted the same two reservoirs that are the producing zones in the Bukha field. The two prospective targets at Tibat, Mauddud and Thamama, are mapped in a fault bounded structure similar to Bukha and are located at 2,550 m and 2,710 m respectively.
Heritage holds a 10% interest in both block 8 and block 17 through its wholly owned subsidiary Eagle Energy (Oman) Ltd. Novus Petroleum Ltd. operates the Tibat-1 well with 40% interest. Other partners are LG International Corp. with 25% interest and Atlantis Holding Norway with the remaining 25%.
Apache Corp. has a successful appraisal well in the West Mediterranean Concession offshore northern Egypt. The Abu Sir-2X well was drilled in 3,373 ft water depth to a TD of 13,162 ft.
Abu Sir-2X is Apache's fifth well in the deep-water Egyptian program and the first appraisal well after four successful exploratory wells: Abu Sir, Al-Bahig, El Max-1X, El King-1X.
Drilling logs indicated the presence of 100 net ft of possible pay. Apache operates the West Mediterranean Concession with a 55% interest. RWE Dea has a 35% interest, and BP Egypt Co. holds the remaining 10%.
ConocoPhillips plans to spend $361 million on a new drilling and production platform in the Ekofisk region of the Norwegian North Sea.
The objective is to increase oil and gas recovery from the area by adding reserves of 64 MMboe and to raise the area's processing capacity.
Ekofisk is made up of four producing fields: Ekofisk, Eldfisk, Embla, and Tor, which together account for 10% of Norway's total production.
The Ekofisk reservoir is estimated to contain 8.7 Bboe, of which 6.9 billion is oil. The field has produced more than 2.5 Bboe, of which 1.7 billion was oil.
ConocoPhillips Norway operates the block with 35.1% interest. Partners are TotalFinaElf, with 39.9%, Norsk Agip with 12.4%, Norsk Hydro with 6.7%, Petoro with 5%, and Statoil with 1%.
Eni postponed first oil from the Abo field offshore Nigeria for a month due to delays caused by the late arrival of the FPSO from Sing- apore.
The Abo field is in OPL 316 in 1,800 ft of water. The field holds over 700 MMbbl of oil. Initial production was to begin at 10,000 b/d in March and to peak at 30,000 b/d in September.
Chinese companies are snapping up real estate in the Caspian Sea. In late 1Q 2003, China National Offshore Oil Co. bought half of the BG Group's interest in the North Caspian Sea production sharing agreement (PSA). Weeks later, BG agreed to sell its remaining interest to Sinopec International Petroleum Exploration and Production Corp.
The purchase will be final when Kazakhstan and Chinese authorities approve the agreement and the PSA partners waive pre-emption rights. When the transaction is complete, Sinopec will own 8.33% interest in the PSA, which encompasses the Kashagan oil field, the Kalamkas oil discovery, and the Kairan, Aktote, and Kashagan SW prospects.
BG will retain interest in the Karachaganak field and the Caspian Pipeline Consortium, which was formed by the governments of the Russian Federation, the Republic of Kazakhstan, the Sultanate of Oman, and a consortium of oil producers. CPC is developing a unitary overland pipeline transport system to export crude oil from Tengiz oil field to a deepwater terminal on the Black Sea.
The North Caspian Sea PSA covers 5,600 sq km of the Kazakhstan section of the Caspian Sea.
Eni operates the PSA with 16.7% interest. Partners are BG with 16.7%, ExxonMobil with 16.7%, Shell with 16.7%, TotalFinaElf with 16.7%, ConocoPhillips with 8.3%, and Inpex with 8.3%.
In mid March, the government of Kazakh-stan ratified a Russian-Kazakh agreement to divide the northern part of the Caspian Sea.
The agreement represents one small step toward resolving distribution of the Caspian's resources among the five littoral states.
ExxonMobil Corp. has announced first production from the Bintang gas field in the South China Sea. The Bintang field, 137 mi offshore Terengganu, Malaysia, is expected to produce 1 tcf of gas, with a peak production rate of 355 MMcf/d.
Bintang is the second field to be developed under a gas production sharing contract (GPSC) with Petronas Carigali, a subsidiary of Malaysia's state-owned Petronas, and ExxonMobil, operator of the 50/50 joint venture (JV).
The JV advanced the development of Bintang under the terms of the GPSC to meet increasing national demand for gas on the Malaysian peninsula.
ExxonMobil subsidiary Mobil Exploration and Producing Australia Pty Ltd. confirmed that further exploratory drilling on the Jansz field off the northwest coast of Western Australia has indicated the presence of a world-class gas resource.
The Jansz-2 well was drilled late last year to determine the extent of the Jansz-1 discovery made in 2000 in the WA-18-R exploration permit. Jansz-2 was drilled in 4,430 ft water depth to 10,800 ft TD.
ExxonMobil's Jansz field off Western Australia could hold 20 tcf of gas. Source: ExxonMobil.
The Jansz field covers more than 766 sq mi and is estimated to contain 20 tcf of recoverable gas.
"ExxonMobil believes the Jansz field to be the largest gas discovery ever in Australian waters, representing around 40% of the undeveloped, discovered gas resources in the deepwater Carnarvon basin," said Jon Thompson, president of ExxonMobil Exploration Co.
ExxonMobil operates the WA-18-R permit with 50% interest. ChevronTexaco holds the remaining 50%. ChevronTexaco operates the adjacent block, WA-267-P, with 50% interest. ExxonMobil holds a 25% interest, with Shell and BP each holding 12.5%.
The JV plans to drill appraisal well Jansz-3 and perform a production test in mid-2003 to further delineate the reservoir.
In late 3Q 2002, Unocal Corp. subsidiary Unocal Makassar Ltd. began drilling operations on Phase 1 of the West Seno field offshore East Kalimantan, Indonesia. The first well of a 28-well development program was spudded from a TLP in 3,200 ft water depth in the Makassar Strait.
Offshore installation of the floating production unit to its pre-laid deepwater moorings and hookup to the TLP and export pipelines were scheduled to be complete by mid May. Offshore commissioning and startup activities are to be complete in June, when the field is scheduled to come on production.
Initial production of 12,000-15,000 b/d is expected from the first five pre-drilled development wells. Production is expected to increase to 35,000-40,000 b/d by year-end 2003 and continue ramping up in 2004 as the remainder of the Phase 1 drilling program is executed.
Phase 2, which is expected to come online about two years after Phase 1 production begins, will include a second TLP, infield pipelines, and up to 24 additional development wells. Production is targeted at 60,000 b/d of oil and 150 MMcf/d of gas in 2005. Ultimate recovery from the field is expected to be 210-320 MMboe.
Unocal Makassar Ltd. operates the Makassar Strait PSC with 90% interest. Pertamina Upstream holds the remaining 10%.
The US Minerals Management Service has issued the Proposed Notice of Sale for Beaufort Sea outer continental shelf Lease Sale 186, which is tentatively scheduled for September 2003. The MMS also issued the final environmental impact statement (EIS) that evaluates Sale 186 plus two other proposed sales in the Beaufort Sea. Sale 195 is scheduled for 2005, and Sale 202 is scheduled for 2007. The notice of availability for the final EIS was issued in February.
The proposal in place is for the entire area, which includes 1,850 whole or partial blocks covering 9.7 million acres, to be offered for lease. The sale area extends from the Canadian border on the east to near Barrow, Alaska, on the west.
Alaska's Beaufort Sea. Source: US MMS.
The proposed notice also includes proposed royalty suspensions on the production of oil and conden-sate, subject to price thresholds.
BHP Billiton has committed up to $327 million for the first development phase of the Greater Angostura oil and gas field off Trinidad. The shallow-water field is in block 2(c), 40 km off the northeast coast. Gross mid-case volumes are 450 MMboe, which comprises 160 MMbbl of oil and 1.75 tcf of natural gas.
Phase 1 covers the engineering, construction, and installation of production and transportation facilities required to recover the oil reserves of the field. The development consists of three satellite wellhead protector platforms that will be connected via flowlines to a steel jacket central production platform. The commercialization of the gas resource is expected to occur as the second phase, three to nine years after first oil, and will use Phase 1 infrastructure with secondary enhancements. The timing of the commencement of gas sales will largely depend on reservoir performance and oil recovery considerations.
The government of Trinidad and Tobago has already issued regulatory approvals.
The joint venture will pursue an aggressive schedule to achieve first oil by the end of 2004. Field life has been estimated at 19-24 years for oil and gas production.
"With our sanction of the Angostura project, Trinidad and Tobago will become a core development area for BHP Billiton," said Philip Aiken, president and CEO of BHP Billiton Petroleum.
BHP operates block 2(c) with 45% interest in the Greater Angostura field. Talisman (Trinidad) Ltd. holds a 25% working interest, and TotalFinaElf S.A. holds the remaining 30%.
Hardman Resources has completed a 2D seismic survey offshore French Guiana in northeastern South America. Fugro Data Services AG gathered a spread of 7,750 km of seismic data.
The survey began in December of last year and concluded in February. Data processing is expected to be complete by the end of May.
Hardman was awarded an exclusive exploration license (EEL) in June 2001. The EEL covers 65,000 sq km, which covers the entire offshore zone from the 12-mi limit to the 3,000-m water depth. The EEL provides for a five-year exploration program with a well commitment due at the end of the first three years. Hardman holds a 97.5% interest in the license.