Africa
The biggest news offshore West Africa is that state oil company Sonangol and Total have brought the deepwater Dalia field into production.
Discovered in September 1997 in block 17, 135 km (84 mi) offshore Angola in 1,200-1,500 m (3,937-4,921 ft) water depth, Dalia contains an estimated 1 Bbbl of recoverable oil. It was the largest deepwater development to be brought onstream in 2006 and among the largest projects of its kind in the world.
The Dalia development comprises 71 wells, 31 for water injection, three for gas injection, and 37 producers tied into nine manifolds. The subsea installation consists of 40 km (25 mi) of insulated production flowlines linked to eight high-tech flexible risers manufactured for the project. TheDalia FPSO has an oil treatment capacity of 240,000 b/d and storage capacity of 2 MMbbl.
Total E&P Angola operates block 17 with 40% interest. Partners include Esso Exploration Angola (Block 17) Ltd. with 20% interest, BP Exploration (Angola) Ltd. with 16.67% interest, Statoil Angola Block 17 AS with 13.33% interest, and Norsk Hydro Dezassete A.S. with 10% interest. Sonangol is the block 17 concessionaire.
Total also has been busy offshore Gabon. The company recently added an exploration and production sharing contract for the Diaba license to its West Africa holdings. The 9,075-sq-km ( 3,504-sq-mi) Diaba license lies in 100-2,500 m (328-8,202 ft) water depth 50 km (31 mi) off southern Gabon.
Total has added to its acreage offshore Gabon with the 9,075-sq-km (3,504-sq-mi) Diaba license.
The three-phase exploration program includes a 2,000-km (1,243-mi) 2D seismic survey, a 700-sq-km (270-sq-mi) 3D survey, and an obligation well.
Total Gabon has an 85% in the Diaba license, with the Gabonese Republic holding a direct interest of 15%.
While Total adds acreage in Gabon, Amni International Petroleum Development Co. Ltd. and Afren Plc. have completed appraisal drilling on the Okoro field offshore Nigeria.
Okoro-3 was the first well drilled by the group on OML 112 in the shallow-water Niger Delta. The well reached TD at 1,981 m (6,500 ft) in the Miocene Agbada formation. The well confirmed the eastern extension of the field as well as the hydrocarbon contacts seen in both sand formations in the initial discovery.
Following testing on Okoro-3, the group drilled a second appraisal well, a deviated sidetrack from the Okoro-3 wellbore, to further evaluate both reservoirs and to provide greater control for planning future horizontal production wells. The Okoro-3 sidetrack reached a TD of 2,094 m (6,870 ft), encountering 21 m (70 ft) of net oil pay.
Well results are still being evaluated in preparation for a field development plan to be submitted to the Nigerian government this month. A fast-track development plan is in place to produce first oil in early 2008.
An interesting development involving Nigeria, Cameroon, and Equatorial Guinea could expand gas production in the region.
In early December, African Gas Development Corp. and the national gas company of Equatorial Guinea, Sociedad Nacional de Gas GE (Sonagas), signed an exclusive joint venture agreement to monetize gas supplies from Nigeria, Cameroon, and Equatorial Guinea through infrastructure and facilities in Equatorial Guinea.
This exclusive JV between Sonagas and Afgas, using Afren Plc. as the preferred upstream supplier, intends to assemble the necessary regional gas supplies, primarily from Nigeria and Cameroon, to supplement existing Equatorial Guinea gas sources.
The JV will be responsible for providing all subsea pipelines, facilities, and related infrastructure for the gas projects.
Americas
Husky Energy Inc. has been busy in Atlantic Canada. The White Rose delineation program completed in late 2006 has resulted in an increase in recoverable reserves assessment of 190 MMbbl of oil.
The North Amethyst K-15 delineation well in the southwestern section of the field revealed a 50-55 m (164-180 ft) oil column with high reservoir quality in the Ben Nevis Avalon formation. Earlier in the year, Husky’s O-28 delineation well, drilled in the western section of the field, resulted in an upgrade in estimated recoverable resources from this area to 120 MMbbl. A further delineation well is planned in 2007 to confirm the resource estimates and to assist in future development planning.
The combined estimate of 190 MMbbl of recoverable resources from the K-15 and O-28 wells is incremental to the White Rose proven and probable reserves.
Husky has begun front-end engineering on the southern extension of the White Rose field with wells F-04 and F-04Z. This southern extension is expected to be developed as a subsea tieback to theSeaRose FPSO. Subject to regulatory approvals, production from this pool is scheduled for late 2009. The K-15 discovery probably will be developed through the southern extension development as well.
Husky Energy operates White Rose with 72.5% interest. Petro-Canada holds the remaining 27.5%.
Husky and partner Hydro also had a significant discovery with the West Bonne Bay F-12 well nearby during delineation drilling.
The West Bonne Bay F-12 well is in license (SDL) 1040, 320 km (199 mi) southeast of St. John’s near the Terra Nova oil field. Husky drilled the well using the jackup rigRowan Gorilla VI.
The jackup drilled the F-12 well to a TD of 4,666 m (15,308 ft). Sidetrack well F-12Z further delineated the structure and gathered additional reservoir information. In both wells, hydrocarbons were encountered in the Upper Hibernia formation. Further analysis of core, fluid samples, and wireline log data is continuing to estimate the recoverable resources from this pool.
Hydro operates West Bonne Bay with 72.22% interest. Husky Energy holds the remaining 27.78%.
According to Husky’s publicized plans for 2007, the company will continue to invest in Atlantic Canada.
The company will spend $290 million offshore Newfoundland and Labrador next year. The program includes drilling and completion of a seventh production well in the White Rose oil field and delineation of the O-28 discovery in the West Avalon Pool north of the existing White Rose development.
Middle East
Indago Petroleum Ltd. subsidiary Indago Oman Ltd. began testing the West Bukha-2A (WB2A) well on block 8 offshore Oman in mid-4Q 2006 with the WB2A sidetrack of the original West Bukha-2 wellbore.
On the first of two 4-hr flow tests of the uppermost Shuaiba section of the Thamama section over a 4,363-4,383 m (14,314-14,380 ft) open-hole interval, the well achieved an average flowrate of 3,524 b/d of oil and 1 MMcf/d of gas on a 36/64-in. choke. The second test yielded an increased flowrate of 4,392 b/d of oil and 1.4 MMcf/d of gas through a 50/64-in. choke.
The company plans to conduct a second flow test in the Mishrif-Mauddud formation after testing Thamama.
Indago’s partners in the project are LG International 50%, and Heritage Oil Corp. subsidiary Eagle Energy (Oman) Ltd. 10%.
Asia-Pacific
Exxon is looking into deepwater exploration offshore the Philippines. Subsidiary Esso Exploration International Ltd. and Mitra Energy Ltd. have entered into an agreement to explore the deepwater Sandakan basin southwest of the Philippine Islands.
Under terms of the farm-in agreement, Exxon has a 50% operating interest in block SC 56. MEL retains a 50% equity interest in the block and will operate the 2D seismic acquisition phase of the exploration program.
The oil exploration agreement covers 2 million acres and is subject to approval by The Philippines Department of Energy.
India’s Reliance Industries Ltd. is taking a closer look at its cash cow in the Krishna-Godavari basin in the Bay of Bengal off India’s east coast. In mid-4Q 2006, RIL amended its development plan for the deepwater KG-DWN-98/3 block that will increase production from 40 MMcm/d to 80 MMcm/d.
Based on initial reserve estimates, RIL prepared an initial development plan for the two discoveries, Dhirubhai 1 and Dhirubhai 3. Exploratory work, including a 3D seismic survey and additional exploratory drilling, resulted in 13 discoveries following plan submission, indicating the field’s potential is greater then originally thought. RIL also obtained an independent assessment of reserves for the discoveries that indicate the fields could hold 11.3 tcf of gas, almost double the earlier estimates.
RIL made the world’s largest gas discovery in 2002 in this block, which covers 7,645 sq km (2,952 sq mi) in water depths to 2,700 m.
The company operates the block with 90% interest. Niko Resources Ltd. has the remaining 10%.
Europe
The Black Sea is seeing more activity of late. Toreador Resources Corp. and its joint venture partners TPAO and Stratic Energy Corp. hit gas-bearing sands with the Akcakoca-3 well offshore Turkey late in 4Q 2006. The well encountered 81 net m (266 net ft) of gas-bearing sands in seven zones.
Akcakoca-3 is the 10th successful well drilled in the South Akcakoca sub-basin natural gas project and the first well drilled by Toreador and its joint venture partners to assess the reserve potential along the Akcakoca trend in waters too deep for jackup rig operations.
Toreador operates the South Akcakoca sub-basin with 36.75% interest. TPAO has 51% interest, and Stratic owns the remaining 12.25%.
In the UK North Sea, AGR Peak Well Management, part of Norway’s Ability Group ASA (AGR) oil technology and services group, plans to undertake two drilling programs in 2007. The projects involve nine wells for six independent oil companies.
The projects will be carried out over a six- to seven-month period, with two drilling programs running in parallel, one scheduled to begin in April and the other in May.
Antrim Resources (N.I.) Ltd. will drill three wells, Nautical Petroleum Plc. will drill two wells, Bow Valley will drill one well, Vermillion Rep SAS will drill one well, Ithaca Energy (UK) Ltd. will drill one well, and Xcite Energy Resources Ltd. will drill one well.
The drilling campaigns will be on licenses in the central and northern North Sea.
Ability Group expects to plan and manage 26 wells for oil companies by the close of 2006 in spite of the tightness of the rig market.
Caspian
The Shah Deniz development in the Azerbaijan sector of the Caspian Sea became one of the world’s largest producing gas fields in mid-December.
With a 25.5% working interest, Statoil operates the Azerbaijan Gas Supply Co., which is responsible for selling output from this BP-operated discovery.
Statoil also has an 8.56% working interest in the Azeri-Chirag-Gunashli field in the Caspian. The Central Azeri component came on stream in 2005.
Some Shah Deniz gas will be sold domestically, but most is going to Turkey, with a portion going to Georgia through the new South Caucasus Pipeline.
This transport system stretches for 690 km (429 mi), paralleling the Baku-Tbilisi-Ceyhan oil pipeline from Azerbaijan to the Georgia-Turkey border.
According to BP, Shah Deniz will reach plateau production of roughly 9 bcm annually in 2009.
Judy Maksoud, Houston
