Asia-Pacific
Things are still buzzing in Bohai Bay. In mid-third quarter, Anadarko Petroleum Corp. began oil production from the unitized CFD 11-6/CFD 12-1S development project.
The company brought a number of wells online and was producing 15,000 b/d of oil by the end of October. Development drilling is ongoing, with gross production expected to ramp up to 22,000 b/d from 22 wells by mid-2007.
Anadarko operates the development with 29.18% interest. Partners include CNOOC Ltd. with 51%, Newfield Exploration Co. with 12%, and Ultra Petroleum Corp. with 7.82%.
Meanwhile, in the Mahakam block offshore Indonesia, Total has found a new shallow-water gas discovery between the Tunu and Peciko fields.
The Tunu Great South-1 well, 8 km (5 mi) southwest of the southernmost platform in the Tunu field, encountered a number of gas reservoirs that confirm an extension of the southern zone of Tunu.
A production test will confirm the find, and further wells will be drilled to appraise field potential.
The new resources could come onstream by 2009.
Total operates the Mahakam block on behalf of the 50:50 Total-Inpex joint venture.
Chevron discovered gas of its own with the Clio-1 well in permit WA-205-P, 150 km (90 mi) offshore northwestern Australia.
The well discovered 190 m (623 ft) of net gas sands, making Clio one of the top wells in Australia in terms of total net pay.
According to Jay Johnson, managing director of Chevron Australia, Chevron will undertake further work, including a 3D seismic survey program starting in mid-December, to better determine the find’s potential.
The interesting news in the Timor Sea is that Petronas and its partners won a PSC for an offshore block in the Joint Petroleum Development Area (JPDA) between Timor Leste and Australia.
Block 06-102 lies 250 km (155 mi) offshore Timor Leste, about 450 km (280 mi) from Darwin, Australia, and covers 4,125 sq km (1,593 sq mi). It is the first block to have been awarded by the Timor Sea Designated Authority.
PSC terms require a 300-sq-km (116-sq-mi) 3D seismic survey, geological and geophysical studies, and three exploration wells during the first three years of the exploration phase.
The PSC marked Petronas’ entry into the Timor Leste/Australia’s upstream sector.
Petronas, through subsidiary PC (Timor Sea 06-102) Ltd., holds 50% equity in the PSC and will be the operator. The remaining equity is shared by Korea Gas, with 30% interest, Samsung with 10% interest, and LG International with the remaining 10%.
Americas
Trinidad remains a hot play for BHP. In mid-November, the company hit oil with the Ruby-1 exploration in block 3(a), 48 km (30 mi) off the northeast coast and 8 km (5 mi) east of the central processing platform for the Greater Angostura field on block 2(C).
Ruby-1 was drilled to a TD of 1,753 m (5,750 ft) and encountered 366 m (1,200 ft) of hydrocarbon bearing sands, including more than 244 m (800 ft) of net pay.
BHP operates block 3a with 25.5% interest. Partners include Talisman (Trinidad block 3a) Ltd. with 25.5%, Anadarko Petroleum Corp. with 25.5%, Petrotrin with 15%, and Total with the remaining 8.5% interest.
Offshore Brazil, Shell is moving its deepwater BC-10 development into production. The operator has let the initial contracts for developing this heavy oil project, which is in the Campos basin offshore Espirito Santo state. The block lies 120 km (75 mi) southeast of Vitoria in water depths of 1,500-2,000 m (4,921-6,562 ft).
Among the initial contracts is the award of a leased FPSO with 100,000 b/d processing capacity.
BC-10 will be a phased development, with the first phase focusing on the Ostra, Abalone, and Argonauta fields, and a second phase that will address a fourth field. The design calls for a development with subsea wells and manifolds, with each field tied back to a centrally located FPSO moored in 1,780 m (5,840 ft) of water.
The BC-10 development will be the first full field development based on subsea oil and gas separation and subsea pumping. Technology requirements also include artificial deepwater lift via high-power electric pumps in seabed caissons and horizontal wells.
Agência Nacional do Petróleo, Brazil’s national petroleum agency, approved the phased development plans in early October.
First production is expected around 2010.
Africa
Angola is still one of the hottest plays in the world.
In early November, Chevron Corp. subsidiary Cabinda Gulf Oil Co. Ltd. (CABGOC) began oil production from the Landana North reservoir in the Tombua-Landana field in deepwater block 14 offshore Angola.
Tombua-Landana is Chevron’s third operated deepwater development offshore Angola. The 46-well project lies 80 km (50 mi) offshore in >356 m (>1,200 ft) of water. The development will use a compliant piled tower with one subsea center. Projected peak production from the completed development is 100,000 b/d of oil by 2010.
Meanwhile, Sonangol and Total subsidiary Total E&P Angola confirmed and expanded the potential of the Orquidea-2 appraisal well in deepwater block 17 offshore Angola.
Orquidea-2, 2 km (1.2 mi) from the Orquidea-1 discovery well, is in 1,165 m (3,822 ft) water depth. The well identified and confirmed the Miocene objectives encountered by Orquidea-1 and also identified deeper Oligocene reservoir levels, both of which are oil-bearing.
The Orquidea structure is near the Lirio, Cravo, and Violeta finds.
This dual drilling success confirms the potential for development of a fourth production zone in block 17, for which preliminary design is under way. The production zone is in the northwestern section of the block and will complete the Girassol and Dalia zones, to be followed soon by the Pazflor production zone.
Sonangol is concessionaire of the block, which Total E&P Angola operates with a 40% interest. Partners include Esso Exploration Angola (Block 17) Ltd. with 20%, BP Exploration (Angola) Ltd. with 16.67%, Statoil Angola Block 17 AS with 13.33%, and Norsk Hydro Dezassete A.S. with 10%.
Petrobras recently signed four production sharing contracts with Sonangol for blocks 6/06, 15/06, 18/06 and 26.
Shallow-water block 6/06 covers 4,930 sq km (1,903 sq mi) in the Kwanza basin. The initial phase of the contract requires that Petrobras gather 3D seismic data and drill two exploration wells. Petrobras operates the block and will retain 40% of the rights.
The 4,611-sq-km (1780-sq-mi) block 18/06 is in the deepwater of the Lower Congo basin, just south of areas already producing oil. Petrobras operates the block with a 30% stake. This contract requires that Petrobras obtain 3D seismic data and drill seven exploration wells.
Block 15/06, is also in the Lower Congo basin and is adjacent to deepwater production fields. Petrobras holds 5% interest and is a non-operating partner.
Deepwater block 26 covers 4,838 sq km (1,868 sq mi) in the Benguela basin off southern Angola. As operator, Petrobras will have 80% of the rights. On this block too there is a requirement for a seismic program and two wells.
With the contracts for these four exploratory blocks, Petrobras became an operating company in Angola for the first time.
Central Asia
In late October, the BP-operated Azerbaijan International Operating Co. (AIOC) began oil production from the East Azeri platform four months ahead of schedule.
East Azeri completes Phase 2 of the Azeri-Chirag-Gunashli (ACG) field development in the Azerbaijan sector of the Caspian Sea. Phase 3, which will develop the deepwater Gunashli area of ACG, remains on schedule to begin production in 2008
East Azeri (EA) lies in 150 m (492 ft) of water on the east side of the Azeri field. Production on this platform began from the first of eight pre-drilled wells Oct. 21. Production will increase through mid-2007 as the other pre-drilled wells are brought online. When it reaches plateau, the EA facility will produce 260,000 b/d of oil, bringing Azeri production, including West and Central Azeri, to over 800,000 b/d.
A new 30-in. (762-mm) subsea pipeline will transport EA oil to the onshore Sangachal terminal. Associated gas produced from EA that is not used for fuel on the platform will flow via in-field subsea pipelines to the compression and water injection platform for re-injection into the reservoir for pressure maintenance. Surplus gas will be exported via an existing gas subsea pipeline to the Sangachal terminal and on to the Azerigas system for domestic use.
Middle East
Petrofac Ltd. has agreed to acquire a 45% interest in the Chergui concession, Tunisia, for $30 million. Petrofac will acquire the interest from Tunisian state oil company Entreprise Tunisienne D’Activities Petrolieres (ETAP), which holds the remaining 55% interest. Petrofac will operate the concession.
The Chergui gas field, on and around Kerkennah Island, near Sfax, Tunisia, was discovered as part of the West Kerkennah exploration permit granted in the late 1970s. Preliminary reserves were estimated at 50 bcf. Petrofac will invest $20 million to complete the development. The work includes constructing a 20 MMcf/d central production facility and completing a 57-km (35-mi) pipeline to shore that already is under way. First production is expected next year. Produced gas is to be sold to Société Tunisienne d’Electricité et Gaz under the gas pricing formula fixed by existing law, in which the price of gas is linked to FOB Med Fuel oil prices.
“Tunisia has a well-developed and stable hydrocarbon regime which offers interesting opportunities for Petrofac. Chergui is an attractive investment and fits our business model of working with national oil companies and local partners to catalyze developments,” says Amjad Bseisu, chief executive of Petrofac Resources.
Indian investment in Iran seems to be paying off. ONGC Videsh Ltd. (OVL), the overseas investment arm of ONGC, recently struck oil in the Farsi exploration block in the Persian Gulf.
OVL operates the block with 40% interest. Partners include Indian Oil Corp. Ltd. with 40% and Oil India Ltd. with the remaining 20% interest.
Europe
As 2006 draws to a close, Statoil is looking back on a profitable year. For the third quarter, company income before financial items, income taxes, and minority interest, increased to $4.7 billion, up from $3.9 billion in 3Q 2005.
The financial statement shows continued growth. Gross income for the quarter totaled $4.7 billion, up from $3.7 billion for 3Q 2005. The $963 million increase resulted primarily from a 13% increase in the average oil price and a 33% increase in the average price of gas. Net income, however, showed a $155,000 loss. Earnings were offset by effects from financial items and taxes.
“Statoil continues to show high earnings despite temporarily lower production on the Norwegian continental shelf (NCS),” CEO Helge Lund said. “High exploration activity on the Norwegian continental shelf, as well as in our international business, characterizes Statoil’s third quarter. We are continuing to add resources and are bringing new assets into production.”
Lund called particular attention to the strengthening of Statoil’s deepwater position in the US Gulf of Mexico. This includes both the successful Jack well test as well as the signing of the agreement between Statoil and Plains Exploration & Production, pursuant to which Statoil will acquire PXP’s working interest in two GoM deepwater discoveries and one exploration prospect.
Statoil completed 16 exploration wells in 3Q 2006, nine on the NCS and seven internationally. Six wells resulted in discoveries. By comparison, the company completed six exploration wells in 3Q 2005.
In the first nine months of 2006, Statoil completed 29 exploration and appraisal wells, 14 on the NCS and 15 internationally. Of these, 11 resulted in discoveries. The company completed only 16 exploration wells in first nine months of 2005.
Judy Maksoud, Houston
