Jeremy Beckman • London
North/South America
Hibernia Management and Development has gained approval from Canada’s Federal and Provincial governments to extract oil from the AA block offshore Newfoundland. The company plans to access the reserves by drilling two producer and two water injector wells from the gravity base structure on the Hibernia platform to the northwest. The development could generate up to 25,000 b/d of oil, extending the Hibernia facilities’ life-span from 2027 to 2036.
Petrobras and partners BG Group and Repsol have made a further pre-salt find in the BM-S-9 concession in the Santos basin. The Abare West well, drilled in 2,163 m (7,096 ft) of water, 290 km (181 mi) from Sao Paulo, encountered oil, gas, and CO2 in pre-salt reservoir sections. The location is 30 and 40 km (18.6 and 24.8 mi) from the Iguassu and Carioca discoveries in the same concession, and 50 km (31 mi) west of Guara, drilled in June 2008.
A recent drillstem test on Guara flowed at a constrained rate of 7,200 boe/d, and test data suggests a permanent production well could deliver an initial 50,000 boe/d. The consortium estimates recoverable reserves at Guara at 1-2 Bboe, and plan a development based on a 120,000 boe/d platform. This should start up in 2012 following the completion of the first phase of development at Tupi field, also in the Santos basin. Here, an extended well test resumed last month following a two-month suspension to replace a subsea tree.
In Rio de Janeiro, Petrobras and Schlumberger have teamed with Brazil’s Federal University to build a $10-million research complex. This will tackle technology issues associated with the growing band of ultra deepwater sub-salt finds in Santos and Campos basins. In further recognition of the country’s new priorities, Petrobras was due to launch a tender last month for the construction of at least nine new drilling rigs.
Location of the Pearl gas discovery in the Gulf of Venezuela.
Repsol also has participated in what may be Venezuela’s largest gas discovery to date, drilled in shallow water in the Gulf of Venezuela. Initial analysis suggests the Pearl structure could hold 7-8 tcf of gas drawn from a reservoir 33 sq km (12.7 sq mi) in area and 240 m (787 ft) thick. Assuming the field goes forward for development, PDVSA will take a 35% stake with Repsol and Eni each retaining 32.5%.
UK independent Desire Petroleum aims to start drilling its prospects in the North Falkland basin early next year. The company has a Letter of Intent with Diamond Offshore Drilling for four wells using the semisubOcean Guardian. Following shipyard work, the rig should mobilize in November to arrive in Falkland waters next February.
Desire has been building an inventory of structures on its acreage over the past decade, but its efforts to drill have been frustrated by rig rates/availability, and a lack of consensus among other operators in the region over pooling funds for a rig hire. However, theOcean Guardian will be made available to Desire’s partners Rockhopper Exploration and Arcadia. The company believes it is in the interests of all concerned to drill as many wells in the basin as possible to test its full potential. No wells have been drilled off the Falkland Islands since 1998.
Northern Europe
Providence Resources has exercised an option to acquire 40% of the Labuan Energy-operated Kinsale Head Area off southern Ireland, comprising the producing gas fields Kinsale Head, South West Kinsale, and Ballycotton. Providence has a further option to take on 40% of Labuan’s 86.5% operated interest in the nearby Seven Heads gas field.
Labuan, a subsidiary in Petronas, assumed control of these assets earlier this year from previous operator Marathon. The package should double Providence’s existing production to over 4,000 boe/d, also providing the means to monetize its own stranded discoveries nearby in the Celtic Sea.
Maersk has produced first oil from its subsea Affleck development in UK North Sea block 30/19a. The field has been developed with two horizontal producer wells tied back to theJanice production semisubmersible via a newly installed 28-km (17.4-mi) flowline. Associated gas is exported to partner Talisman Energy’s Clyde platform via another new spur line.
To the north, Maersk has contracted Subsea 7 for flexibles/umbilical jumper installations and tie-in/testing of two wells for the Gryphon South and Tullich fields, both tiebacks to the Gryphon FPSO. Work will be conducted by the DSVSeven Pelican.
West Africa
Anadarko Petroleum has discovered hydrocarbons with its deepwater Venus B-1 exploration well offshore Sierra Leone. The well, drilled by the semisubBelford Dolphin in 5,900 ft (1,798 m) of water, encountered over 45 ft (13.7 m) net pay in this first-ever deepwater test in the Sierra Leone-Liberian basin.
Venus confirms the existence of an active petroleum system in the basin, says Anadarko’s Bob Daniels, SVP for Worldwide Exploration. The company plans to continue drilling in the West Africa Cretaceous Trend with another exploratory well on the South Grand Lahou prospect in Cote d’Ivoire offshore block CI 105.
Oil production is under way from the Chevron-operated Tombua-Landana development in 366 m (1,201 ft) of water, 80 km (49.7 mi) offshore Angola in block 14. The $3.8 billion project is based around a 474 m (1,555 ft) tall compliant piled tower with subsea production equipment, and is expected to deliver 100,000 b/d of oil at peak in 2011. The facilities are designed to prevent any discharge of produced water and any routine gas flaring. Recoverable reserves for the two fields are estimated at 350 MMbbl.
In deepwater block 15, Esso Exploration Angola has contracted AMEC for detailed design, procurement, and logistics support for its Kizomba satellites project. Work will be managed by the Amec/Prodiaman joint venture in Luanda, Paragon Angola. GE Oil & Gas will supply subsea production equipment for the same project, which is linked to Kizomba A and B.
London-based Afren is teaming with Addax Petroleum to develop Okwok oil field offshore southeast Nigeria in OML 67. Okwok was discovered in 1967 by ExxonMobil/NNPC. Addax and Oriental Energy Resources took control in 2006, drilling three further appraisal wells.
Under the new farm-in arrangement, Afren will fund a further exploratory/appraisal well in mid-2010 or earlier, followed by a development jointly financed with Addax. Okwok has estimated recoverable reserves of 70 MMbbl, and is 15 km (9.3 mi) east of Afren/Oriental’s Ebok field. Both fields could be developed in tandem with shared storage and export facilities to reduce costs.
Mediterranean Sea/Black Sea
The jackupEnsco85 has initiated drilling operations at Aegean Energy’s Epsilon field offshore Greece. This is the company’s second successive development in the north Aegean Sea following completion of well PNA-H3 earlier this year in the Prinos North field. Schlumberger is providing management services for the 90-day well. With a planned total depth of 5,500 m (18,045 ft) and a vertical depth of 2,900 m (9,514 ft), this should be the deepest and longest well to date in Greek waters.
Gas has started flowing from the Petrobel-operated North Bardawil field offshore northern Egypt. Two subsea wells, drilled by the semisubScarabeo-4, are tied back to the Barboni production platform, with gas exported through a 24-km (14.9-mi) pipeline in water depths of 110-350 m (361-1,148 ft). The development includes a smart completion system which partner Eni claims is a first offshore Egypt.
Stratic Energy says the jacket and deck for the South Akcakoca Phase 2 gas project offshore Turkey are under construction. Float-out and offshore installations should follow next summer, and should include a pipeline tie-in to the existing export system, with first gas scheduled for fall 2010.
Middle East/India
J Ray McDermott ME has installed the Q9 platform topsides and two decks for Qatar’s GG3&4 project. All were fabricated in Jebel Ali, UAE, and installed by the crane bargeDB 101. The offshore lift program included the removal of two temporary decks. QWP is one of three platforms designed to supply gas for Qatargas’ Train 6 and Train 7 LNG facilities via two 38-in. (97-cm) subsea pipelines.
In the same region, development of the Al Shaheen field was 80% complete in September, according to operator Maersk. Installation of new production facilities should be completed by early 2010. The field’s oil output has been restricted recently to an average of 310,000 b/d.
Press reports in Iran claim that three Indian oil companies – ONGC Videsh, Indian Oil Corp., and Oil India – are willing to invest $5 billion to develop the 21.68 tcf Farzad-B field in the Persian Gulf. Further reports suggest that Venezuela’s PDVSA has agreed to participate in development of the South Pars 12 gas project.
India’s Ministry of Petroleum has signed a memorandum of understanding with the Minerals Management Service under which the two will address issues of mutual interest regarding offshore oil, gas, and mineral resources. Objectives include sharing best practices in leasing, resource evaluation, and methane hydrate R&D.
Australia
The partners in the Gorgon joint venture have approved the investment program for the LNG project offshore Western Australia. Chevron is the operator with a 50% interest, the remainder divided between ExxonMobil and Shell. Gas will be drawn from fields in the Greater Gorgon area, starting with Gorgon and Jansz-Io, thought to be Australia’s largest gas discoveries to date.
Subsea production facilities in water depths of up to 1,200 m (3,937 ft) will be linked to two subsea pipelines with a combined length of 240 km (149 mi). These will transport the gas to a new LNG terminal with capacity of around 15 Million metric tons/yr (16.5 MM tons/yr) to be built on Barrow Island, by the KJVG consortium comprising KBR, JGC, Clough and Hatch. The Gorgon venture partners already have concluded long-term supply agreements for their share of the output to buyers in China, Korea, and India.
Production has started from the Eni-operated Blacktip gas field in the southern Bonaparte Gulf offshore northern Australia. Following processing at an onshore plant near Wadeye, the gas is delivered to the Northern Territory’s Power Water Corporation under a 25-year supply contract. Output will eventually build to 18,000 boe/d.
Drilling was due to get under way this month or in November on the Albacore prospect in the northern Taranaki basin, operated by Westech. New Zealand Oil & Gas (NZOG) recently agreed to farm into 40% of the surrounding permit PEP 38491, in water depths of 95 m (311 ft). The Albacore-1 well will target three separate, potentially hydrocarbon-bearing zones recently defined by 3D seismic.
Asia-Pacific
CNOOC has brought on stream its Ledong (LD) 22-1 gas field in the Yinggehai basin of the western South China Sea, initially producing 30 MMcf/d from five wells. LD 22-1 is being jointly developed with LD 15-1 in shallow water via two eight-leg platforms and a total of 21 wells – LD 15-1 is due to start up later this year. Both fields share subsea production facilities to reduce costs. At peak, they will generate around 150 MMcf/d, the second largest of any independent gas field project offshore China, CNOOC claims. Following processing at the Dongfang 1-1 terminal, the gas is piped to industrial users in Hainan province.
In the deepwater sector of the South China Sea, Husky Energy has tested 52 MMcf/d of gas from its third appraisal well on the Liwan field. The well was drilled in 1,450 m (4,757 ft) water depth by theWest Hercules. Husky plans to submit a development plan around the turn of the year, with first production targeted for 2013.
