CATHERINE PLOWDON and PAUL FROYDENLUND, Deloitte Petroleum Services, London A mixed bag: Strong licensing, deal activity but less drilling offshore the UK and Norway
Signs of improved economic conditions and continuing high oil prices have supported increased deal activity in the North Sea throughout 2010 and into 2011. Between July 2010 and June 2011, the number of farm-ins has risen significantly, with favorable commodity prices acting as an incentive for companies to increase their equities in reserves. Conversely, the number of corporate deals has dipped, possibly an indication of increased economic stability in Northwest Europe. Licensing activity continues with the awards of the UK’s 26th round, the Norwegian Awards in Predefined Areas (APA) 2010 and the announcement of APA 2011. Exploration and appraisal drilling in Northwest Europe remains dominated by the Norwegian and UK sectors. The UK has seen a downward trend in drilling over the last year, especially of exploration wells. Only 20 exploration and appraisal wells were drilled on the UK continental shelf from January through June, the lowest first-half rate since 2002. The opposite trend is seen in Norway, where exploration, in particular, remains strong. In Greenland, Cairn Energy’s frontier drilling program has shifted the industry’s focus to areas of Northwest Europe that have not experienced any activity for a decade. UNITED KINGDOM In the fourth quarter of 2010, the UK Department for Energy and Climate Change (DECC) released details of the blocks awarded in the country’s 26th offshore licensing round. After considering applications submitted in April 2010, DECC offered 144 licenses, covering 268 blocks and partial blocks. A further 45 licenses, in 99 blocks located near protected conservation areas, may be awarded subject to the results of more detailed environmental assessments. Subsequently, in June, DECC awarded a further 26th-round block to Centrica subsidiary Venture Production (67.5%, operator) and its partners MPX (20%) and Sorgenia (12.5%). The block, formerly called 29/9e, has now been amalgamated into block 29/9d, license P1565, awarded to Venture and its partners in the 25th round. The combined block will retain the designation 29/9d and the original block 29/9d’s contingent well commitment date of Feb. 11, 2013. The partnership has purchased long-offset data, which Centrica is currently interpreting. In the last 12 months, the number of farm-ins in the UK has been particularly high at 45, greatly exceeding the number of asset acquisitions. This suggests that companies are looking to reinstate projects put on hold by the recession, and to share risk as drilling activity takes off once again. Significant asset acquisitions include Dana’s agreement to acquire Petro-Canada’s interest in fields around the Triton area and Scott and Telford fields, Scottish and Southern Energy acquiring a package of natural gas and infrastructure assets from Hess, and IGas Energy signing an agreement to become the operator and sole owner of Nexen Petroleum’s onshore UK licenses. Only two corporate deals were announced during the past year in the UK, compared with 11 in the previous year: Bridge Resources divested its subsidiary Bridge North Sea Ltd. to Perenco, and Atlantic acquired Volantis Exploration. Exploration and appraisal drilling. From July 2010 through June 2011, exploration and appraisal (E&A) drilling fell by a third compared with the same period in 2009 and 2010, with 52 wells spudded on the UK continental shelf (UKCS), compared with 78 wells in the previous 12 months. During the past 12 months, 44% of all E&A wells were spudded for wildcat exploration, while the remaining 56% were drilled to appraise existing discoveries. In first-half 2011 alone, exploration drilling was trending down as a proportion of total E&A activity, to 35% from 48% in 2010, although this percentage is liable to change once the figures from second-half 2011 are included. During the first six months of 2011, 17 E&A wells were drilled, representing a 51% decrease compared with first-half 2010. E&A drilling levels for 2011 are lower than in previous years, despite improving economic conditions and further stability in the oil price. UK companies are likely adjusting their UK-focused strategy in light of the recent increases in the supplementary corporation tax imposed on oil and gas producers. However, due to the long lead time associated with planning and drilling wells, it is unlikely that these fiscal changes have influenced drilling activity to date. The tax increase, together with the global impact of unrest in North Africa and the Middle East, is likely to manifest itself in the shape of corporate investment in the North Sea in the medium and long term. The UKCS saw its highest level of activity in 1990, with 257 E&A wells drilled, Fig. 1. Drilling fell more or less steadily throughout the rest of the decade, reaching a nadir of 39 E&A wells in 1999. Activity rebounded with increasing oil prices from 2001 onward, reaching an 11-year high of 123 wells in 2007 and maintaining that level the next year. Since 2008, drilling has fallen in response to economic and price uncertainty. Oil prices have experienced sustained growth since 2009, and so far in 2011 the Brent oil price has not experienced a monthly average below US$100/bbl. It would ordinarily be reasonable to assume that drilling across the UKCS would increase during the second half, the summer months historically being the busier period. Furthermore, improved economic conditions should open access to capital for E&A campaigns. However, over the last 18 months the UK has seen a clear downward trend in E&A drilling, while other countries in Northwest Europe have seen much wider variation in activity, Fig. 2. The latest fiscal changes may encourage an upsurge: On July 5, the government increased the annual rate of the ring-fence expenditure supplement for the North Sea to 10% from 6%. The increase will support investment in marginal fields by allowing companies with insufficient taxable income to uprate losses by 10% for six accounting periods. Between July 2010 and June 2011, 46% of all E&A wells drilled in Northwest Europe were spudded on the UKCS. Of those UKCS wells, 37% were spudded in the central North Sea. The Moray Firth and southern North Sea each had 15% of all E&A wells drilled, and 23% were drilled in the northern North Sea. Substantially less drilling took place in the Faroese-Shetland escarpment and West of Shetland basin: 4% and 6%, respectively. Figure 3 highlights the companies that have participated in drilling activity in the UK since mid-2010. During that period, six discoveries were announced on the UKCS. Centrica-operated exploration well 44/28a-6 encountered gas within the Fulham prospect; the well has been suspended for use as a future producer. This well is separate from the Arrol discovery directly to the north. Centrica also operated well 43/28a-6 on the Pegasus prospect, encountering gas within a Carboniferous reservoir. Total announced a gas and condensate discovery on the Edradour prospect at exploration well 206/4-2. The discovery is about 40 km east of Laggan and Tormore fields. The well encountered gas and condensate within a Cretaceous reservoir, displaying good petrophysical properties. Sterling Resources operated six wells at Cladhan field in the northern North Sea, which the company had discovered in 2008. Wells 210/30a-4, 210/30a-4Z and 210/30a-4X all targeted the Upper Jurassic reservoir units. Well 210/30a-4 was drilled downdip of the original Cladhan discovery well. Well 210/30a-4Z was drilled in August 2010 to appraise the level of the oil-water contact, which had not been encountered in previous wells; however, no oil-water contact was observed. On test, the well produced a facility-constrained flowrate of 5,900 bpd. Well 210/30a-4Y tested the previously untargeted central channel of the Cladhan turbidite system and encountered a 258-ft gross hydrocarbon column, with net pay of 108 ft; the Jurassic reservoirs at this location were found to be water-bearing. The third sidetrack to well 210/30a-4X, drilled to test the northern channel, encountering 105 ft of net reservoir, with a 5-ft interval of oil-bearing sands. Hurricane drilled well 205/21a-5 on the Whirlwind prospect. The well encountered light oil within a fractured basement reservoir, which is geologically similar to the Lancaster discovery 12 km to the north. Wintershall drilled well 21/27b-7 on the Blakeney prospect. The discovery consists of a four-way dip closure, formed from sediment overlapping a prominent chalk high. The well encountered oil within the Tay sandstone; pre-drill estimates indicate that the prospect holds 20 million bbl of oil. Finally, Encore discovered oil at the Varadero prospect, 4 km north of the Catcher discovery, using exploration well 28/9-2. Initial estimates indicated 400 ft of excellent-quality sands within the Tay sandstone. In the first six months of 2011, none of the exploration wells drilled on the UKCS has been deemed successful—i.e., classified by the operator as an oil, gas or condensate well, or any combination thereof. However, a number of exploration wells that were drilled have yet to have their results confirmed by the operator. In 2010, one third of all wells drilled were classified as successful, suggesting that it is unlikely that 2011 will see no successful exploration wells drilled, Fig. 4. So far this year, 65% of all wells were drilled to appraise existing discoveries; these wells are by nature more likely to encounter hydrocarbons than true wildcats. Development and production. Three oil fields and one gas field commenced production offshore the UK during second-half 2010, following just one field, Lochranza, in the first half. So far in 2011, one field has come onstream: The ExxonMobil-operated Loirston oil field began producing in March after being developed via a single extended reach well from the Beryl Alpha platform. Loirston oil is commingled with other production on the platform.
Bardolino commenced production in September, having been developed as a single well tied back to the Howe subsea manifold. Hydrocarbons are subsequently taken to the Nelson platform via pipeline for separation and export. Burghley, discovered in 2005, came onstream in October. It is a subsea development tied back to the Balmoral floating production unit (FPU), with processing aboard the FPU. Oil is exported via the Forties pipeline system; gas is partly used as fuel for the FPU, and the remainder is flared. Auk North was discovered in 2007 and was granted separate field status from Auk field in 2009. Development involved drilling of three subsea wells in the Rotliegend formation, which are tied back to the Fulmar platform. Production commenced in November, and an additional subsea well is planned to be drilled in 2011. The Babbage gas field was discovered in 1988, and development was approved in January 2009. The first phase of development consisted of installation of a normally unmanned installation, pipeline and the drilling of three initial wells from a central top-hole platform. Phase 2 consists of one or two additional wells drilled from a drilling rig cantilevered over the platform. Production commenced in August 2010.
NORWAY The Norwegian Ministry of Petroleum and Energy received applications from 41 companies for the 2010 Awards in Predefined Areas (APA) by the Sept. 15 deadline. This high number of applications suggests that companies are recovering from the economic crisis and are keen to increase exploration activities. Norway offered 50 production licenses to a total of 39 companies in APA 2010. Of the 50 licenses, 31 are located in the North Sea, 17 in the Norwegian Sea and two in the Barents Sea. Twenty-two companies have been offered operatorship, two of which—Edison and Spring Energy—have not previously been operators on the Norwegian continental shelf (NCS). To comply with obligations stipulated in the offers, new seismic data will be acquired in six areas and three fixed wells will be drilled: two in the North Sea, by Statoil and Talisman, and one in the Norwegian Sea, by Wintershall. The other production licenses are subject to “drill or drop” conditions giving the licensees between one and three years in which to make a decision to drill. Statoil was awarded the highest number of licenses, 11 in total and eight as operator. Wintershall and Lundin were also very successful, each being awarded 10 licenses. The energy ministry subsequently announced APA 2011, with applications due by Sept. 14, and the new production licenses planned to be awarded in late 2011 or early 2012. The predefined areas have been expanded in comparison with APA 2010, with 62 blocks or partial blocks on offer: 56 in the Norwegian Sea and six in the North Sea. The APA licensing system was introduced in 2003 to replace the annual North Sea Awards. This annual process is designed to encourage exploration and development within the large amount of area close to existing discoveries and infrastructure. In addition to the APA system, the energy ministry also holds ordinary concession rounds, usually every two years, such as the recently completed 21st licensing round. This award process focuses on issuing licenses in frontier regions of the NCS. Thirty-seven companies, either individually or as consortia, submitted applications in the 21st licensing round for the NCS by the Nov. 3 deadline. The round, announced June 23, 2010, encompasses 94 blocks and partial blocks, of which 43 are in the Norwegian Sea and the remaining 51 are in the Barents Sea. On April 15, the ministry announced that 24 licenses had been awarded, 12 in the Barents Sea and 12 in the Norwegian Sea. The 24 licenses were awarded to 13 different operators in total; Statoil was awarded by far the most with eight operated licenses and non-operated interest in three additional licenses. The trends in deal activity in Norway are similar to those in the UK. There have been considerably more farm-ins in the past 12 months than in the previous year, with a total of 22 announced, increasing from five. There has been no corporate deal activity. On an asset level, the number of deals has decreased considerably, with three asset acquisitions and one asset divestiture announced in the past 12 months in comparison with 12 asset deals in the previous year. Two of the acquisitions were by Talisman, which bought Noreco and Spring Energy’s interests in production license (PL) 378, containing the Grosbeak discovery, and Spring Energy’s interest in PL 375 and PL 551. Hess completed two transactions to bring its interests in Valhall and Hod fields to 64.05% and 62.5%, respectively. The company assumed Shell’s 28.09% interest in Valhall and 25% interest in Hod, in return for which Shell assumed all of Hess’ interest in BP-operated Clair field, in the UK sector, and its upstream portfolio in Gabon. Additionally, Noreco agreed to divest its interests in Brage and Hyme (formerly Gygrid) fields to Core Energy in return for a cash consideration of $85 million net of tax.
Exploration and appraisal drilling. From July 2010 through June 2011, 39 E&A wells were spudded on the NCS, a 35% decrease from the 60 E&A wells drilled during the same period of 2009 and 2010. In the whole of 2010, 49 E&A wells were spudded on the NCS, vs. 66 during 2009, Fig. 5. The trend so far in 2011 suggests that E&A drilling for the year will reach a level similar to last year’s, but is unlikely to equal the record number of wells spudded in 2009. Of all the offshore E&A wells drilled in Northwest Europe from July 2010 through June 2011, 35% were drilled on the NCS. Overall E&A drilling on the NCS continued to be lower than on the UKCS. However, across the NCS a substantially greater proportion of wells spudded were for exploration (78% in 2010, 76% in first-half 2011) compared with the UK sector, assisted by tax incentives. From July 2010 through June 2011, a total of 11 discoveries have been announced on the NCS. Lundin made discoveries with three exploration wells. Well 16/2-6 was drilled on the Avaldsrobynnes prospect, 25 km east of the Luno discovery, and encountered a 55-ft oil column. The accumulation is trapped within a combination of stratigraphic and four-way dip closures. Lundin’s Apollo discovery well, 16/1-14, encountered oil within two sequences of Paleocene and Lower Cretaceous sandstone. A 130-ft oil column was found within the Hemidal formation, and a separate 32-ft oil column was found within the Lower Cretaceous interval. Lundin’s third discovery during this period was made on the Tellus prospect. This well tested a separate fault segment north of the Luno discovery, and was the first to prove oil within a basement reservoir. RWE discovered oil with well 35/9-6 S on the Titan prospect. The well encountered a 1,427-ft hydrocarbon column within the Heather formation, Brent group, Drake formation and Cook formation. Initial well data suggest that the reservoirs are of variable quality and thickness. Statoil’s exploration well 15/6-12 on the McHenry prospect, 6 km northeast of its Dagny discovery, encountered a 13-ft oil column in a poor-quality reservoir of the Hugin formation. Statoil’s initial assessments suggested that the discovery is subcommercial, with 1.2–6 million bbl of recoverable oil. Statoil also discovered oil on the Opal prospect with well 34/10-53 S, which encountered a 985-ft gas and condensate column in the Middle Jurassic Brent group. The third success for Statoil during this period was on the Krafla prospect. Well 30/11-8 S encountered oil within a Middle Jurassic reservoir, and tested a 650-ft hydrocarbon column in good-quality reservoir. Preliminary assessments suggest that the discovery contains 12.5–56.5 million boe. Statoil also had success in the West Barents Sea with exploration well 7220/8-1 on the Skrugard prospect, which encountered a 400-ft oil column in the Middle Jurassic Stø and Normela formations. The discovery is estimated to contain 150–250 million boe of recoverable hydrocarbons. Marathon made a discovery on the Caterpillar prospect with well 24/9-10 S. Both the parent well and its sidetrack, 24/9-10 A, proved an 85-ft oil column in the Paleocene Hermod formation. The reservoir was deposited as part of a submarine fan sourced from the UKCS. The discovery is estimated to contain 5–12 million boe. Noreco achieved success on the Svanøgle prospect with well 17/6-1. The well encountered a 16-ft oil column in the Sandnes formation, which exhibited poor reservoir quality. Better reservoir quality was observed in the underlying section of the reservoir; however, this was found to be water bearing. It is likely that the discovery will be classed as subcommercial. Total drilled well 25/5-7 on the David prospect, encountering gas and condensate within a Middle Jurassic formation. The David discovery is thought to contain 15–20 million boe. Figure 6 highlights the companies that have participated in drilling activity over the last 12 months in Norway. Development and production. In the past 12 months, five fields have begun production in Norway, vs. two that came onstream in the previous year. The continued economic stabilization may have encouraged development plans to progress toward production startup. The Morvin oil field came onstream in August 2010 after Norway’s Petroleum Safety Authority gave Statoil approval to start up the field. Morvin is a subsea development with two templates and four production wells. The production stream travels through a 20-km pipeline to the Åsgard B platform for processing. The northern structure of the Gjøa gas field was discovered in 1989, and the southern structure in 1991. Due to complex geology, remoteness from infrastructure and water depth, development was shelved. In August 2006, a decision was made to develop the field with a semisubmersible platform and five subsea templates. After a five-year development period, the field came onstream in November. In March, operator GDF Suez said it will likely shut in the field during October to replace faulty gas export risers, which will allow the company to fully exploit the platform’s 600-MMcfd design capacity. Vega and Vega South fields began production together in December. The development plan for Vega included three well templates on the seabed. One template is tied to Vega North, one to Vega Central, and the last processes the gas and condensate from Vega South, which are then sent through an 11-km pipeline to Vega and then on to the Gjøa platform. Trym field was discovered in 1990, but was not considered commercial until the development of nearby infrastructure in Denmark. Dong Energy submitted a development plan in October 2008, and the Norwegian government approved it in March 2010. Trym is being developed via a subsea template tied back to Harald field in the Danish sector. Production from the first of two wells commenced in February. NETHERLANDS License awards continue to be sporadic in the Netherlands, with two announcements over the past 12 months. Cirrus was awarded operatorship of block T1 following the conclusion of the open application period at the end of 2010. The Ministry of Economic Affairs also announced, at the beginning of 2011, that it was accepting applications for an exploration license in block E/5. The last day for submission was June 7, and one application was submitted. Over the past year, four farm-ins, one asset acquisition and two corporate acquisitions have been announced. This level of deal activity is similar to that of the previous year, when three corporate-level deals and two asset-level deals took place. However, farm-in activity has increased; no farm-ins took place between July 2009 and June 2010. Since then, Ascent is set to acquire McLaren Resources’ 27% interest in blocks M/10 and M/11, conditional upon Ascent obtaining a license extension for drilling. Elko Energy farmed out its interests in blocks P/1 and P/2 to Chevron in return for royalties from gas and condensate sold from the blocks. Dutch authorities approved the transfer to Sterling Resources of interests in five licenses within the F-quad and L-quad areas. Sterling will acquire a 50% operated interest in blocks F/14UP, F/16UP, F17aUP, F/18UP and L/1bUP from Grove, a subsidiary of Canadian producer Stratic, which was recently acquired by EnQuest. Chevron has assigned part of its interest in blocks P/1 and P/2 to Taqa Energy. Oranje-Nassau Energie (ONE) signed an agreement with Nederlandse Aardolie Maatschappij B.V. (NAM) to acquire the company’s 42% equity in block Q/16a. Finally, Tullow Oil agreed to acquire Nuon E&P from the Vattenfall Group for a cash consideration of €300 million. A total of 12 E&A wells were drilled on the Netherlands continental shelf between July 2010 and June 2011, 11% of the total drilled in Northwest Europe. This compares with 10 E&A wells spudded during the same period in 2009 and 2010. GDF Suez drilled exploration well K/9ab-B6 on the northern flank of the K/9ab-B accumulation. The well targeted a prospect that is thought to have been identified using a new 3D seismic survey, commissioned by GDF Suez, that was shot over the block. The company spudded eight of the 12 E&A wells in the Netherlands during the last 12 months, focused on block K/12. A number of those wells were suspended due to a series of mechanical failures during drilling. DENMARK Licensing and deal activity in Denmark has remained low over the past 12 months. The Danish Energy Agency (DEA) awarded one exploration license to Noreco, Elko and Nordsøfonden covering open acreage adjacent to their license 2/05. The new license, 1/11, has a term of six years and requires a commitment to drill an exploration well within two years. The partners have selected a well location and intend to drill the well before the end of 2011. Dong Energy also submitted an application for an exploration and production license on a non-licensed area bordering license 4/95, where the company is a participant. The Ministry for Climate and Energy has initiated a so-called “neighboring block” procedure to issue an E&P license covering the area, and the DEA is now processing the application. There have been three farm-ins (one completed and two offered) altogether during the last 12 months, vs. one farm-in the previous year. Dong sold a 15% interest in licenses 4/98 and 3/09 to Germany’s Verbundnetz Gas; Sweden-based PA Resources and its Dutch partner Spyker Energy are seeking an additional partner or partners to farm into license 12/06; and Shell and Maersk Oil are jointly offering up to 60% interest in the Elly and Luke development projects. In 2010, Dong drilled two exploration wells in the far western part of the Danish North Sea. Well 5604/26-5 encountered oil on the Solort prospect east of the Svend field, within a Paleogene sandstone; well 5604/16-1 on the Sara prospect encountered oil within a Paleogene reservoir. These two wells, the only ones offshore Denmark, represent just 1% of all E&A activity in Northwest Europe during the last 12 months, continuing a downward trend in Danish E&A activity since 2002. IRELAND Three licensing options were announced in Ireland during the past 12 months. Domestic producer Providence Resources signed a 10-month option agreement with the UK’s Star Energy Group in relation to Providence’s 100% owned and operated standard exploration license (SEL) 1/07. UK-based Enegi Oil was offered a 100% interest in an onshore petroleum licensing option to undertake a work program on areas of interest within the Clare basin, which the company believes to hold shale gas potential. Another British firm, Chrysaor, exercised its option to double its equity stake in the Spanish Point area in frontier exploration license (FEL) 2/04 and adjacent FEL 4/08. Chrysaor doubled its interest in the Providence-operated licenses to 60% and will manage the drilling of the Spanish Point program. There have been three farm-ins, two asset acquisitions and two asset divestitures in Ireland over the past year, similar to the previous year. In the past 12 months, Providence has been particularly active, farming out up to a 65% interest in the Nemo oil discovery to Nautical; increasing its stake in and assuming operatorship of the Barryroe oil discovery; assigning a 10% nonoperated interest in Helvick field to Lansdowne; and granting Sosina the right to acquire up to 50% equity in license 2/07, containing the Hook Head oil accumulation. Additionally, Serica and RWE are seeking one or more partners to farm into FEL 1/06. The new partner(s) will help drill one or two wells in 2011 in return for up to 50% equity. Austria’s OMV agreed to pay ₤3 million to Ireland’s San Leon Energy to be removed from exploration license 3/05, the Rockall license. Eni is looking to divest its entire Irish exploration portfolio, comprising interests in four deepwater licenses offshore western Ireland. Any potential buyers will have to drill a well on each of the Dunquin and Fiachra prospects in licenses 3/4 and 7/79, respectively. OTHERS In Germany, the state of Schleswig-Holstein awarded PA Resources offshore license B20008-73 early this year. No deal or licensing activity was reported throughout the whole of 2010, so this is a positive announcement for the country. Greenland allocated seven exclusive E&P licenses for blocks in its portion of Baffin Bay at the end of 2010, to ConocoPhillips, Shell, Statoil, GDF Suez, Cairn Energy, Maersk Oil, Dong and Greenland’s NOC, Nunaoil. The Bureau of Minerals and Petroleum had received 17 block applications from 12 companies. Altogether, the blocks granted cover an area of 70,768 sq km, bringing the total area of exclusive licenses in Greenland to about 200,000 sq km. Cairn acquired operatorship of the Atammik and Lady Franklin blocks from Encana at the beginning of this year and has subsequently drilled on the blocks. Cairn’s activities in Greenland have once again seen the focus of the industry frontier in Northwest Europe shift further west. In 2010, Cairn subsidiary Capricorn Exploration launched a three-well drilling campaign. Well Alpha-1S1 encountered oil shows within volcanic sections. To comply with Bureau of Minerals and Petroleum requirements, drilling ceased toward the end of September 2010, with the well still in the volcanic sections. Cairn may choose to re-enter this well in a future drilling program. Cairn also drilled exploration wells T4-1 and T8-1. T4-1 targeted a Tertiary prospect, but failed to encounter significant hydrocarbons and found only thin reservoir-quality sandstones. T8-1, targeting a different stratigraphic layer, encountered biogenic gas within thin sandstones. This discovery is considered subcommercial. The potential of the West of Greenland basin has yet to be proven, but Cairn has identified seven prospects there, of which four will be drilled this summer with the hope of verifying the first commercial discovery. Each of the four wells will be drilled in a different block: Atammik, Lady Franklin, Napariaq and Eqqua. In June, Cairn spudded two of the four planned wells: AT-7 in the Atammik block and LF-7 in the Lady Franklin block. The Faroe Islands in 2011 have seen their first deal and licensing activity since the end of 2008, when three licenses awarded in the third Faroese licensing round. License 015 was awarded to Geysir, a subsidiary of Norway’s Sagex Petroleum; the Kúlubokan license (016) was awarded to Statoil (50%, operator), Dong (30%) and two Faroese firms, Atlantic (10%) and Faroe Petroleum (10%); and the Rannva extension (017) was awarded to Faroe Petroleum. In the first quarter, ExxonMobil acquired a 50% interest in licenses 009 and 011 and a 49% interest in license 006 from Statoil. Additionally, in the second quarter, Sagex and Atlantic announced plans to retain the southern part of license 014, containing the Marselius prospect, and progress to the next exploration phase there, and to relinquish the northern part of the license. Sagex will also progress to the next exploration phase in license 013.
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CATHERINE PLOWDON is a European Analyst for Deloitte Petroleum Services in London. She writes the “Licensing and Deals” report of the Weekly Service, a newsletter covering industry news across the region. Ms. Plowdon joined Deloitte in March 2010 after completing a BSc degree with honors in geology and geography at the University of Birmingham. / cplowdon@deloitte.co.uk |
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PAUL FROYDENLUND is a European Analyst for Deloitte Petroleum Services in London, where he produces analyses of all producing oil and gas fields in Northwest Europe for Deloitte’s Upstream Petroleum Reports. Mr. Froydenlund earned a BSc degree with honors in geology from the University of Edinburgh in 2008 and an MSc degree in petroleum geoscience from Imperial College, London, in 2010. / pfroydenlund@deloitte.co.uk |
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Record IP rate after 4D seismic In June, US independent Apache achieved a record initial production (IP) rate at its development well at 40-year-old Forties field in the UK sector of the North Sea. The Charlie 4-3 well commenced production at 12,567 bopd, the highest rate at Forties since 1990. Earlier, Apache achieved IP rates of 11,876 bopd from the Charlie 2-2 well and 8,781 bopd from the Delta 3-5 well. During 2010, Apache acquired a new 4D time-lapse seismic survey over Forties field, which improved the ability of its geoscientists to discern accumulations of bypassed oil. Apache is identifying additional 4D-driven targets and expects to drill a total of 16 wells in the field during 2011. When Apache acquired Forties field in 2003 from BP, the field was producing 40,000 bopd. Now gross production rates have reached as high as 70,000 boepd. At the Charlie platform alone, Apache development drilling has increased production from a low of less than 5,000 bopd in 2006 to a present rate of 30,000 bopd. |
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