Industry remains buoyant in North Sea

Independents are taking the lead at the wellhead as drilling continues to rise and licensing activity booms.

Rhydian A. Williams, Deloitte Petroleum Services, UK 

With global escalation in oil prices and costs, increased speculation and tighter margins coupled with the looming economic downturn, one would expect a level of caution and potential stagnation in the industry. However, the oil and gas industry in the North Sea remains buoyant. Interest at the licensing stage has never been higher, with record levels reported. Exploration and appraisal drilling continues to rise, with independents taking the lead at the wellhead while developing their portfolios through asset trade and farm-in activity.

OIL AND GAS PRICES

After fluctuating below an imaginary US$40/bbl ceiling for 20 years until mid-2004, the oil price began creeping upward amid speculation of a lack of US refining capacity, instability in key producing regions and a sustained demand for light products in developing economies. At that time, rumors of US$100 oil and above were still frowned upon, and an upward curve turned away from US$80 in late 2006, with mild weather allowing OPEC to maintain production and replenish stocks.

The apparent downturn in late 2006-early 2007 was sharply reversed in the face of further concerns over demand, capacities, political instability and financial speculation. From then on, the curve rocketed skyward, with WTI daily spikes breaching a psychologically significant US$100/bbl in November 2007, followed by Brent in February 2008. Since March, both indices have showed consistent monthly averages above US$100/bbl, spurred by predictions of US$200 oil by the same commentators who forecast US$100 a while back, Fig. 1.

Fig. 1. Monthly average oil (Brent) and gas (UK’s NBP) prices over the past 6 years.

The recent upturn has been attributed to a number of factors including demand growth in China and India, whose economies still show no sign of being hurt by the economic slump affecting many OECD countries. Lack of capacity in OPEC, continued unrest in the Middle East and West Africa and political pressures in Venezuela and other parts of South America have also increased this demand-led upward pressure to a point where laws of supply and demand no longer seem to apply.

In the wake of International Energy Agency and US Energy Information Administration reports showing weaker demand, negative non-OPEC supply growth and low US crude imports, market attention has turned to OPEC. Saudi Arabia’s call for a producer-consumer meeting in June 2008 shows its growing concern over high prices. In tandem with this, a number of commentators expect oil prices to reach a turning point in the first quarter of 2009. Financial demand for oil (for example as a hedge against a weak dollar) continues to distort oil prices, perhaps unsustainably. Unless OPEC refuses to boost production, there is a consensus that 2009 prices will soften to slightly below US$100/bbl. Refining capacity additions may well outpace demand to 2012. OPEC capacity, led by Saudi Arabia, should loosen upstream supply, even without non-OPEC growth. The cost of producing oil is stabilizing. Chinese and Indian demand also may plateau for structural and macro-economic reasons.

Following supply-demand issues in late 2005 and problems with the Rough gas storage field in 2006, the UK’s volatile gas market appeared to subside in 2007 with supply concerns eased due to the opening of several key pipelines into the UK and the commencement of major LNG projects. From late 2007 to present, the National Balancing Point (NBP) day-ahead price has become realigned with the steeply rising oil price.

UNITED KINGDOM

In the past year, the UK has seen its highest number of license applications ever. Appraisal drilling was high in 2007, with 2008 levels looking to stay consistent. Asset activity has also remained high, with smaller companies gaining significant acreage.

Licensing/deals. In February 2008, the Department for Business, Enterprise and Regulatory Reform (BERR, formerly the Department of Trade and Industry, or DTI) invited applications for licenses in the 25th Seaward Licensing Round, offering a record-breaking 2,297 blocks and partial blocks, Table 1. Following the application deadline for Traditional, Frontier and Promote licenses, BERR announced that a record 193 applications had been made by 131 companies, including 15 new applicants. This represents the highest number of applications ever made and a 31% increase on 24th Round applications. Any licenses awarded in the 25th Round will contain conditions to protect environmental interests and those of other sea users. In addition, activities carried out under the licenses will be subject to a range of legislation designed to protect the marine environment, including a law that implements the EU’s Environmental Impact Assessment Directive, Habitats Directive and Wild Birds Directive with respect to offshore oil and gas activities. BERR plans to make 25th Round license offers later in 2008.

TABLE 1. UK blocks offered and applications in the past six licensing rounds

BERR announced that parts of Cardigan Bay on the Welsh coast may be off limits for exploration due to a school of bottlenose dolphins. The decision was made after a report by sea mammal researchers at St. Andrews University found that not enough was known about the dolphin population in the Cardigan Bay area to judge how they might be affected by exploration. However, part of the Moray Firth, which is also home to a population of bottlenose dolphins, looks more likely to get the go-ahead for an exploration license.

During first-quarter 2008, BERR announced that recent discussions in the government-industry forum “Pilot” on ways to increase exploration had led to a decision to make geotechnical information on acreage that has been worked and relinquished available for potential licensees. To achieve this, BERR will publish on the internet the relinquishment reports prepared by relinquishing licensees. Relinquishment reports have been required on all licenses since the 21st Round. Promote licensees must provide a report at the 2-year break point if the license is not continuing. However, the new initiative, which is supported by Oil & Gas UK and the Oil & Gas Independents’ Association, requests reports where a whole license or non-contiguous blocks in multi-block licenses (of any vintage) are relinquished. Relinquishment reports (subject to third-party data confidentiality checks that the operator producing the report would have to carry out) will be published either on receipt by BERR or-if extended confidentiality is requested when the report is submitted-after the next license round.

BERR has also announced 58 blocks and 11 discoveries included in the ninth release of the fallow process. Both blocks and discoveries are considered fallow after three years, and are classed B and released on the BERR website if the current licensees are unable to progress toward activity due to commercial barriers. Fallow B discoveries that have been listed on the website for 2 years, or Fallow B blocks that have been listed on the website for 1 year, will be relinquished if there are no agreed-upon plans for significant activity.

Over the past 12 months, on a corporate level, smaller corporate deals have dominated, with many corporate acquisitions and share trades changing the parentage of the smaller independents. OphiraVencap signed a letter of intent with North Sea Energy for the potential acquisition of all issued and outstanding shares of North Sea Energy. North Sea is a private Canadian company focused on development and exploration in the UK.

Centrica and Newfield signed a purchase-and-sale agreement through which Centrica acquired the entire share capital of Newfield Petroleum UK Limited, marking Newfield’s complete withdrawal from the North Sea. The assets listed in the US$486.4 million sale, completed in October 2007, include an interest in the producing Grove Field, an interest in the undeveloped Seven Seas discovery and interests in about 200,000 net acres of exploration licenses in the southern North Sea.

Also completed in October 2007, Bridge Resources acquired all the shares of Iceni, giving Bridge 100% interest in Moray Firth blocks covering 345 sq mi. Five of the six blocks have 3D seismic coverage, and oil shows have been recorded in a number of previous wells on the blocks.

Following its acquisition of 9.99% of Star Energy Group Plc, Petronas made a cash offer to acquire all issued and to-be-issued share capital of Star that is not already owned by Petronas.

In December 2007, Revus entered the UK Continental Shelf (UKCS) by signing an agreement with Palace Exploration to acquire 100% of the shares of its UK subsidiary Palace Exploration Company (UK) Ltd. The total consideration is US$258 million.

PA Resources signed an agreement to acquire the entire share capital of Scotsdale Ltd. Scotsdale holds licenses in the UK and Danish sectors of the North Sea, and has applied for acreage with existing discoveries offshore the Netherlands. The unrisked resources for the Scotsdale share of the portfolio are appraised at about 270 million boe.

Silverstone’s acquisition of Granby Oil and Gas was announced in first-quarter 2008. The companies have reached agreement on the terms of a recommended cash offer of £0.6345 per Granby share for Silverstone to acquire all issued and to-be-issued Granby share capital that is not already owned by Silverstone. The terms value Granby’s existing issued share capital at about £23.1 million.

UK asset activity has also remained high, with a number of majors and supermajors divesting significant acreage to independents and new entrants. A number of deals have been carried out whereby smaller companies are securing a foothold and/or re-aligning their positions on the UKCS. ExxonMobil and Shell have continued to offer several packages of assets. Shell initially announced in June 2007 that it would market assets in the Cormorant area, Eider, Hudson, Kestrel, Otter, Pelican and Tern Fields held by Shell and ExxonMobil. The assets offered for acquisition also include a proportion of Shell and ExxonMobil’s interests in the Brent System and Sullom Voe Terminal. Acquirers will have the opportunity to assume operatorship of the Cormorant area, Eider, Kestrel, Pelican and Tern, and to propose themselves for operatorship of the Brent system. The fields were originally offered as a single package for cash. Earlier in 2008, Abu Dhabi-based Taqa announced that it has entered into exclusive negotiations with Shell and ExxonMobil for the purchase of their interests in the Tern, Eider, Cormorant North and Cormorant South Fields and related subsea satellite fields and infrastructure.

In a further deal on Shell and ExxonMobil JV assets, Ithaca Energy (UK) Ltd. has agreed to acquire an interest in Block 30/6, Chalk Layers and Younger, which contain the Harrier and Stella discoveries, for an initial consideration of US$15 million. An additional US$15 million will become payable to Shell and Esso at the time of field development plan approval, and proceeds from production will be subject to a 5% overriding royalty.

Shell UK Ltd. and Enterprise Oil UK Limited, wholly-owned subsidiaries of Royal Dutch Shell Plc, have also divested an interest in a West of Shetlands license to Inpex UK Limited. Shell UK Ltd. has also announced that it is offering an opportunity to participate in another West of Shetlands license, P1192, in return for funding a well to be drilled on the North Uist oil prospect.

Fairfield Energy has acquired a 100% interest in Clipper South Field, in the Sole Pit Basin, from Shell and ExxonMobil.

Also from ExxonMobil, Perenco has acquired an interest in the Hewett area and an operated interest in Arthur, Excalibur, Galahad, Gawain, Guinevere, Lancelot, Malory, Mordred and Thames Fields. ExxonMobil also is offering equity in partial blocks that contain Barbara and Phyllis Fields. The supermajor is seeking offers for its entire interest in the blocks and is willing to consider exchange for other assets, cash consideration or a combination of these.

BG is offering equity in two UKCS gas discoveries, as well as the chance to farm in on a Moray Firth prospect with significant resource potential, including the Artemis discovery, the Courageous discovery and the Volante prospect.

In June 2008, Tullow Oil Plc announced that it has signed a memorandum of understanding with Eni SpA for the sale of its entire interest in the Hewett Unit Fields and related infrastructure, including the onshore Bacton terminal, for a total consideration of £210 million. Eni will assume Tullow’s share of all associated abandonment liabilities.

Faroe Petroleum has continued to develop its portfolio across North West Europe. In addition to farming in on a Faroese prospect from Shell, it has conducted a cross-border swap with E.On: Faroe exchanged half its interest in a Norwegian license for E.On’s interest in the UK Schooner gas field, the undeveloped UK Topaz gas field and in Norwegian license PL376. Faroe also granted Itochu subsidiary Cieco an option to farm in on a Shell-operated license on the Corona Ridge, in the West of Shetlands region, which contains the Cardhu prospect.

In December 2007, StatoilHydro announced that it had completed the acquisition of Chevron’s interests in the Bressay, Mariner and Mariner East Fields. This deal was first announced by Norsk Hydro in August 2007, before it merged with Statoil. StatoilHydro has also made an agreement with Silverstone and Wilderness Energy to cooperate on exploration in Quadrant 9 licenses in the northern North Sea.

With the increasing cost of oil and large premiums being paid for producing assets, farm-in deals have become increasingly popular, with several smaller independents taking minority interest in licenses to gain a foothold. One key farm-in opportunity is from Lundin Petroleum, which is offering interested parties a chance to farm in on Southwest Heather Field. Lundin says the field offers a short-term development opportunity; it is due to have a development well drilled in 2009 and to be developed via a subsea tieback to Heather.

In April 2008, Fairfield announced that it has reached a farm-in agreement with EnCore. The deal gives Fairfield an operated interest in partial block 9/27a. Fairfield will also have the option, but not the obligation, to increase its equity up to 62.5% on a promoted basis. Fairfield will also assume its equity share of the overriding royalty of 1.2%.

On May 15, 2008, Nautical announced that it has entered into a farm-out agreement with Canamens Limited. Canamens will fund its ongoing interest in the current Selkie well, plus a portion of Nautical’s costs, and assume operatorship. The farm-out terms provide for a US$20 million cap on the Selkie well expenses against an estimate of US$16 million.

Exploration and appraisal drilling. During 2007, 123 exploration and appraisal wells were spudded on the UKCS, 45% more than were started in 2006. However, after discounting sidetracks and re-spuds started in both 2006 and 2007, the drilling increase falls to 28%. Of the 2007 wells, 33% were exploratory and 67% were appraisal wells. So far in 2008, 60 exploration and appraisal wells have been spudded, an increase of 58% over the same period last year, Fig. 2.

Fig. 2. Exploration and appraisal wells drilled by company on the UKCS since July 2007.

Figure 3 shows that the number of wells drilled has greatly increased since 1999. Appraisal wells had a mammoth year in 2007, with the number drilled just topped by the activity of the mid-’80s. This spike is largely due to new techniques being adopted by some independents to drill sidetracks. It is also a response to the low risk of drilling appraisal wells relative to exploration wells and the value gained in the appraisal of discoveries because of the high oil price. Appraisal drilling in 2008 is expected to be consistent with 2007 levels.

Fig. 3. Exploration and appraisal wells drilled by year on the UKCS, along with average Brent oil price.

During second-half 2007 and first-half 2008, 14 discoveries were reported on the UKCS. Talisman made the first discovery at Cayley with Well 22/17-3 west of Montrose, Arbroath and Carnoustie Fields. Well 22/17-3 tested at a constrained rate of 29.7 MMcfd of gas and 2,846 bpd of condensate. Three downdip sidetracks were drilled to determine the extent of the discovery; however, these were suspended without comment.

Total drilled Well 205/5a-1 with the Sedco 714 semisubmersible rig on the Tormore prospect, in the Faroe Shetland Basin, about 9.3 mi southwest of the Laggan accumulation. It encountered gas condensate, and tested at 32 MMcfgd and 75 bopd. Total followed up its Tormore success in June 2008 by discovering the Islay accumulation with exploration Well 3/15-12, less than 0.6 mi west of the UK/Norwegian median. Upon testing, the Brent reservoir produced 43 MMcfgd. Total says it is developing a plan to connect the Islay well to the Alwyn facility.

Venture drilled Well 47/8c-4 to test the Channon prospect, east of Rough Field and north of Mercury Field. The well tested two Rotliegendes fault blocks extending across Blocks 47/3h and 47/8c, and gas was discovered in both. The 215-ft gross gas column included a net pay of 109 ft. The test maximum flowrate was limited by test equipment, and no formation water was produced during the test. Channon is estimated to contain 30-40 Bcfg. The well was suspended as a producer, as the promising test results offer an opportunity to develop Channon with the nearby Barbarossa discovery.

Well 44/19b-6 was drilled by ConocoPhillips and made a discovery within the Harrison prospect. The well encountered a 52-ft gas column in the targeted Carboniferous Lower Ketch Formation. Future evaluation will focus on the optimum development concept for this discovery, which will be tied into the Caister Murdoch System infrastructure.

Petro-Canada-operated Well 15/ 18a-12 encountered a 60-ft hydrocarbon column in the targeted Lower Forties reservoir of the Maria prospect. Preliminary log interpretations indicate that 45 ft of the column is oil pay and 15 ft is gas pay, with excellent reservoir sands. In December 2007, Petro-Canada made another discovery at the Surprise prospect with Well 13/21b-7. The well targeted the Valhall Formation and encountered two oil columns that total nearly 262 ft. Drillstem test data indicated that the reservoir can yield commercial flowrates. Further appraisal activity is planned.

Lundin enjoyed success with Well 21/8-3, which was drilled to target Paleocene and Jurassic sandstones and tested the Scolty and Banchory prospects. Well 21/8-3 encountered light oil in the Paleocene Scolty prospect, but the Banchory prospect was dry with no reservoir encountered at the targeted Jurassic level. Scolty is a four-way dip closure associated with a seismic amplitude anomaly with estimated recoverable oil resources of about 10 million bbl.

The Polly discovery was made by Ithaca-operated Well 12/16c-5 in February 2008. Polly was independently evaluated as potentially having 59 million bbl of recoverable oil. The well encountered 60 ft of gross Middle Jurassic Beatrice “A” sand, 10 ft of which tested water-free oil in formation tests.

Dana Petroleum made two discoveries, West Rinnes and East Rinnes, in April and May 2008, respectively. Well 210/24a-11 was drilled 1.2 mi southwest of Hudson Field. The well encountered a full Brent reservoir sequence within the West Rinnes structure, which displayed excellent sands throughout. The well was drillstem tested and flowed up to 7,800 bopd. Dana says initial analysis indicates that the Rinnes oil is very similar in quality to that being produced by Dana at nearby Hudson Field. Well 210/24a-11 was then sidetracked to target the East Rinnes prospect. Well 210/24a-11Z also encountered oil in a full Brent reservoir sequence, with the excellent sands in the Lower Brent, and the Upper Brent less well-developed. The well was not drillstem tested because of its similarity in reservoir quality and oil characteristics to West Rinnes.

Figure 4 shows the percentage of exploration wells that were successful on the UKCS each year since 1970, with a 5-yr centered moving average. A successful well is one that has been classified by the operator as an oil, gas or condensate well, or any combination thereof. The graph includes all re-entries and geological sidetracks but does not include re-spuds or mechanical sidetracks. Success has averaged about 34%. Following 2002, the success rate dropped significantly and remained low through 2005 before spiking at around 40% in 2006 and dropping thereafter.

Fig. 4. Exploration success by year on the UKCS.

Development and production. Fields brought onstream in the last year include Blane, Cavendish, Caravel, Chiswick, Starling and Wood.

Blane Field, straddling the UK/Norway median with 82% on the UK side, was discovered in 1989 in Paleocene Forties sandstone by Well N1/2-1. Three subsea wells were included in the development plans-two producers and one injector-which are connected to BP’s Ula platform 21 mi northeast. The Ula platform provides injection water and high-pressure gas processing. The oil is exported via Ekofisk to Teesside, where it is sold. Gas is sold offshore at Ula. First production was achieved on Sept. 12, 2007. In May 2008, Roc Oil announced plans to bring its Blane development well onstream at the end of the month after connection to Ula.

Cavendish Field, discovered in 1989, is developed by a fixed platform tied back to the Caister Murdoch System (CMS) operated by ConocoPhillips. In June 2004, Germany’s RWE submitted an environmental statement for the field’s development; DTI (now BERR) approval was granted in August 2005. Cavendish was initially expected onstream in 2005, but was delayed due to the need to blend the gas. Development drilling was conducted during 2006, and the field came onstream in July 2007 via a six-slot, normally unmanned installation and a 29-mi, 10-in. pipeline connected to CMS.

Caravel, discovered in November 2002, lies in a high-quality Rotliegendes sandstone formation with a 30 bbl/MMcf condensate-gas ratio. Ultimate recoverable reserves are estimated at 172 Bcf. Caravel has been developed using a normally unattended trident monotower powered by a renewable energy package. Liquids are exported via Corvette and the Leman compression complex to Bacton. The project involves two development wells on the four-slot tower and a 20-mi, 16-in. gas export pipeline to Corvette. Caravel came onstream in May 2008.

Discovered in 1984, Chiswick Field is a very tight and complex Carboniferous reservoir system. Technically recoverable reserves are estimated at 163 Bcf. Development approval was granted in July 2006, and the normally unattended platform and interfield pipeline to Markham Field were installed. In June 2007, the second development well was spudded, and in late July 2007 Venture hydraulically fractured the first production. First production was in September 2007. Gas is exported via Markham to the Den Helder terminal. Venture is undertaking subsurface remodeling to determine future timing of the second development phase.

Starling was discovered by exploration well 29/3a-2 in 1979 and was appraised by Well 29/3a-7 in 2003. The reservoir is compartmentalized and contains wet gas in a Forties turbidite reservoir. The field was developed through two production wells drilled in first-half 2007, connected to a subsea manifold at Starling and tied back to the Shearwater platform. Production commenced in January 2008. Gas is transported via the SEAL line to Bacton, with oil exported through the Forties system.

Discovered in 1996 by exploration well 22/18-6, Wood has been developed as a single subsea horizontal well, tied back to Montrose via a 6-in. production flowline. The gas from the whole Montrose/Arbroath area will also be incorporated into the development. Oil is exported via the existing Montrose export line to Forties. Wood came onstream in December 2007.

NORWAY

Norwegian exploration and appraisal drilling was up for the second straight year in 2007 with 32 new wells, 20 of them in the North Sea. The licensing stage also saw high activity, with an all-time high number of applying companies for 2007.

Licensing/deals. Following the application deadline for the Awards in Predefined Areas (APA) 2007 in September 2007, the Ministry of Petroleum and Energy announced that it had received applications from an all-time high of 46 companies. The licensing round opened in February 2007 comprised 197 blocks or partial blocks, allowing the industry access to extensive areas in the North Sea, Norwegian Sea and the Barents Sea. The acreage offered covers 20,427 sq mi, the sixth-largest area ever covered in a Norwegian award round. In February, the ministry announced that it is offering 52 licenses; 24 of them in the North Sea. There were 113 applications submitted by the deadline. Of the 37 companies awarded APA 2007 licenses, all but two already hold interests on the Norwegian shelf.

In May 2008, the energy ministry announced the blocks being made available under APA 2008. The area has been extended with 11 additional North Sea blocks, as well as additional blocks in the Barents Sea and Norwegian Sea.

In October 2007, the ministry invited oil companies to nominate blocks that they think should be included in the 20th Licensing Round. The blocks for nomination include those that are not licensed, included in the predefined areas or within excluded areas in the Barents Sea, Bjørnøya, the coast off Troms and Finnmark, or in Eggakanten, Nordland VI, Nordland VII and Troms II. Nominations are labeled “interesting” and “very interesting,” and companies can nominate no more than 15 blocks. In January 2008, the ministry announced that it had received nominations from 46 companies for blocks or partial blocks.

The most significant corporate deal in the Norwegian sector has been the merger of Norsk Hydro’s oil operations and Statoil, completed in October 2007. The new company was estimated in 2007 to have 1.9 MMbpd of production and proven oil and gas reserves of 6.3 billion boe.

Det Norske Oljeselskap ASA (DNO) and Pertra ASA completed a merger in fourth-quarter 2007. The largest shareholder of the new company, Det norske oljeselskap ASA, is DNO, which will initially hold about 39.67% of Det norske to increase the shares’ liquidity. DNO will then reduce its initial ownership by sale, dilution or dividends to a maximum of 25% by Dec. 31, 2008.

The new company, Det norske, has entered into an agreement to acquire Lundin’s entire interest in Production License (PL) 103B. The acquisition will give Det norske a unitized interest in Jotun Field, which lies largely in PL027B. Under the agreement’s terms, Det norske will pay a consideration of NOK72 million. Lundin has also announced that Aker Exploration ASA acquired an interest in Lundin’s PL304. In return, Aker will supply the Aker Barents drilling rig to drill the Aegis prospect in PL304.

Aker also entered a deal with StatoilHydro to acquire an interest in PL460. The license partners have already committed to drilling an exploration well within 2 years. Statoil also signed a deal to sell its interest in PL147, which contains Trym Field, to Bayerngas.

Dong A/S is exercising its preemption rights to increase its interest in Ula Field in a deal with Svenska Petroleum Exploration, for a consideration of US$130 million.

Revus Energy ASA and Grupa Lotos SA announced that they have signed a sales-and-purchase agreement, under the terms of which Lotos E&P Norge AS will acquire an interest in several licenses including the Yme Field re-development project. The total purchase price is US$52.5 million, including remaining tax balances. The net profit after tax for Revus will be about NOK200 million.

E.On Ruhrgas has agreed to acquire an interest in Skarv and Idun Fields from Shell through the acquisition of the company’s equity in several licenses.

Endeavour International Corp. entered an agreement with RWE Dea to align their interests in PL270 and PL426. The two licenses contain the Agat discovery and several risked resources. Together these are estimated by Endeavour to be in excess of 500 Bcfg equivalent.

Faroe has acquired an interest in PL289, which contains the substantial Marsvin prospect, from Gaz de France.

Farm-in deals have been less significant in the Norwegian sector than in the UK, although they have facilitated a number of transactions. Pertra signed a farm-in agreement with ExxonMobil to acquire 25% interest in the Eitri prospect in PL027B. The prospect lies 4.3 mi from Jotun Field, also in PL027B. Faroe announced that it has agreed to farm in on PL271 and PL302. The company will acquire an interest in the licenses from Noreco ASA by carrying Noreco’s costs associated with drilling the Yoda well.

Exploration and appraisal drilling. After several years of falling drilling activity in Norway, 2007 continued the trend set in 2006 with a rising number of wells spudded-32 new wells, 10% more than in 2006. Two-thirds of the new wells were drilled for exploration. Twenty of the 2007 wells were drilled in the North Sea. In the first three months of 2008, 14 exploration and appraisal wells were spudded in the Norwegian sector, 75% percent more than in the same period in 2007 and 56% more than in fourth-quarter 2007.

StatoilHydro has had a particularly active and successful year, drilling a number of promising exploration targets. Statoil-operated exploration well 16/2-3 was drilled to test the Ragnarrock prospect, which was drilled by 16/2-1 in 1967. Well 16/2-3 encountered light oil in Upper Cretaceous chalk. Small-scale formation tests within the reservoir showed limited flow properties. Appraisal well 16/2-4 was plugged and abandoned after proving light oil in Upper Cretaceous chalk and low-permeability limestone at Ragnarrock.

StatoilHydro-operated Well 25/11-25 S, between Balder and Grane Fields in the south Viking Graben on the northwestern margin of the Utsira High, encountered oil in Palaeogene rocks. Well 6407/6-6 was drilled on StatoilHydro’s Gamma prospect southeast of Mikkel Field. The well made a rich gas discovery in Middle Jurassic rocks, which is now being evaluated with regard to a possible connection to local infrastructure.

Statoil-operated Well 15/6-9 B was an appraisal sidetrack drilled to establish if there is gas/condensate above the oil found with Well 15/6-9 S in the Ermintrude structure. Well 15/6-9 S had found oil in Middle Jurassic sandstones, and a small gas find was also proven in Tertiary sandstones. Well 15/6-9 B found oil further down in the structure and was plugged and abandoned.

StatoilHydro’s Alve Field appraisal well 6507/3-5 S encountered gas after being drilled to a 12,579-ft TD into Lower Jurassic rocks. The well was drilled to prove hydrocarbons in reservoir rocks that are deeper than previous wells drilled in Alve.

Det norske’s exploration well 15/12-18 S encountered oil in the Paleocene rocks of the Ty Formation in the Storskrymten prospect, so sidetrack 15/12-18 A was kicked off to determine the oil accumulation’s extent. Well 15/12-18 A also encountered oil, but this time in the overlying Heimdal Formation. The sidetrack was drilled to a 9,961-ft TD in Cretaceous rocks.

In April 2008 it was announced that Noil-operated exploration well 16/1-9 had encountered oil in its primary exploration target of the Draupne prospect. The well was drilled to an 8,320-ft TD in the Early Triassic and proved light oil with a small gas cap in Middle Jurassic reservoir rocks. Draupne will be mapped in detail before planning a potential appraisal well to determine the size of the discovery.

Lundin drilled Well 16/1-8 to test the hydrocarbon potential of the Middle and Upper Jurassic sandstones in the Luno prospect, which is defined by 3D seismic as a large pinchout closure. Well 16/1-8 was drilled to a 7,136-ft TVD and discovered light oil in a clastic Jurassic reservoir. Lundin also drilled Well 7/4-2 on the Nemo oil and gas accumulation to an 11,207-ft TD into Permian Zechstein rocks, and encountered oil in the Upper Jurassic Ula Formation. The license partners will evaluate the well results to support a development decision for the field.

Dong drilled Well 1/3-10 to appraise the Oselvar discovery, which was made in 1991 with Well 1/3-6. The new well’s objectives were to investigate reservoir deliverability and to acquire fluid samples for fluids characterization. The well was drilled into the early Paleocene and encountered oil/condensate with associated gas. The well was tested and flowed. Following the success of original wellbore 1/3-10 S, 1/3-10 A was drilled deeper into the Oselvar structure to measure pressure and take water samples in the water zone. Dong is expected to submit a plan for development and operation of Oselvar by the end of 2008.

BG’s Phi-North exploration well 15/12-19 encountered oil and gas in the Jurassic Sleipner Formation and the Triassic Skagerrak Formation. Well partner Lundin confirmed that production testing of the well proved rates up to about 4,700 bopd from the oil zone. Field development studies are in progress to support a likely development decision.

StatoilHydro-operated Well 6407/8-4 S encountered gas in Middle Jurassic sands of the Galtvort prospect. The company says the size of the discovery has yet to be clarified and that sidetrack 6407/8-4 A is being drilled into the prospect’s northern segment.

THE NETHERLANDS

High commodity prices have helped Dutch North Sea activity to maintain its upward trend started in 2006.

Licensing/deals. Elko Energy has been awarded a 6-yr license for Block P/2, in which the company will hold 55% interest. Elko applied for Blocks P/1 and P/2 early in 2007. The company was awarded 33% operating interest in P/1 in June 2007.

Island Netherlands BV and Aceiro Energy BV have been awarded a 100% working interest in exploration license Q/13b. The license is effective March 19, 2008, and is valid for 5 yr. Island intends to file a request with the Minister of Economic Affairs to split the license into shallow (oil) and deep (gas) parts, defined by the top of the Trias stratigraphic marker. Island will operate the shallow part with a 100% interest, and Cirrus Energy Nederland BV, on behalf of its partner Petro-Canada Netherlands BV, will operate the deep part, in which Island will have no equity.

Island Oil & Gas was a wholly owned subsidiary of Island Oil & Gas Plc, until its entire issued share capital was sold in May 2008 to Delta Hydrocarbons BV. The consideration for the transaction includes a US$25 million purchase price and a US$10 million advance against the 2.5% overriding royalty interest payable to Island on the commencement of oil production from Amstel Field.

ConocoPhillips sold its wholly owned subsidiary Burlington Resources Nederland BV to n.v. Nuon. The sale gives Nuon 100% share capital of Burlington for a total transaction value of €476.7 million. Included in the acquisition are gas pipelines, processing facilities and interest in 35 gas fields and acreage.

Dutch authorities approved Northern Petroleum’s acquisition of Dyas BV’s interest in License P/12. The transfer was part of an agreement originally announced in April 2007 and involved Dyas acquiring an interest in onshore licenses for the Andel III, Papekop and the Drenthe part area (i.e., the Geesbrug and Groloo discoveries). In exchange, Northern acquired the interest in P/12 and interest in onshore license Zuid Friesland II.

In February 2008, Cirrus agreed to transfer 50% of its interests in the Q/11 and Q/14 licenses to Taqa. The consideration takes the form of a farm-in on a 2-for-1 basis relating to costs of the first exploration well on the acreage planned to be drilled in the Q14-Alpha prospect. Any gross well costs exceeding €12.5 million in the event of a dry hole, or €16.5 million if the well is tested, will be funded by the partners according to their working interests after the farm-out.

NAM (an ExxonMobil-Shell JV) offered a package of assets comprising the F/3a, F/17c, L/2, L/4c, L/5a, L/12b, L/15b and L/15c licenses, together with NAM’s interest in the Nogat gas transportation and processing infrastructure, the processing plant at Den Helder and the A6-F3 pipeline connecting the system with the market on the German continental shelf. Venture acquired NAM’s operating interest in the F3-FA accumulation in Blocks B/18a and F/3a.

Exploration and appraisal drilling. Eleven new wells were spudded in the Netherlands in 2007, continuing the increase in Dutch offshore drilling that began in 2006 after years of decline. For the sixth time since 1970, all the wells spudded offshore Netherlands were exploration wells.

Wintershall has twice sidetracked exploration well D/15-5, which is being drilled southeast of D15-FA Field. The well targeted the Tourmaline prospect and was suspended without comment.

Grove Energy drilled Well F/17-8, which is thought to target gas in deep Slochteren sandstone on a local high in the middle of the Central Graben. The well was mechanically sidetracked at 13,176 feet.

Gaz de France-operated Well G/16-7 was drilled on a prospect below the G16-FA platform. The field produces from Jurassic sandstones above a salt piercement capped by Zechstein dolomites; however, this exploration well was drilled into the flanks of the dome. The Bunter (Volpriehausen) reservoir it encountered has a similar geology to G14 and G17 Fields. Logs indicate the presence of gas, and Gaz de France has undertaken a testing program.

DENMARK

In April 2008, Norwegian Energy Company (Noreco) ASA announced that it has entered into a share sale agreement with Talisman Energy Inc. to acquire all the shares in Talisman Oil Denmark Ltd. for a consideration of US$83 million. The transaction includes the producing Siri Field and will increase Noreco’s daily production by more than 20% and add 4.35 million bbl of oil to the company’s proven and probable reserves.

Noreco announced that its subsidiary Altinex Oil Denmark has entered an agreement to acquire 12% interest in Licenses 9/06 (Gita prospect) and 9/95 (Maja prospect) from Chevron.

Polskie Górnictwo i Gazownictwo SA (PGNiG) announced that it has signed an assignment agreement for 40% interest and operatorship of E&P License 1/5 held by Willumsen Exploration Consultants ApS. PGNiG says it will begin exploration in prospective areas of Denmark with fellow licensees Odin Energi and Nordsøfonden.

Three new Danish wells were spudded in 2007, all in the first quarter; this is two less than the number started in 2006. During first-quarter 2008, Maersk spudded one new exploration well, 5505/13-HDE-1X, and Wintershall started drilling Valdemar appraisal well 5504/11-Bo-1X. In April 2008, Maersk announced that exploration well 5504/11-Bo3X had encountered hydrocarbons in the Bo South prospect. The Bo3X well was drilled to an 8,730-ft TD.

GERMANY

In an asset divestiture, Wintershall has offered interested parties the opportunity to farm in on exploration acreage covering 993 sq mi in the southwestern part of the German North Sea, in return for a carry in the costs of an appraisal well and past costs of a regional study. The offered acreage comprises License B20 008/71-consisting of Blocks H/15, H/16, H/17, H/18, L/1, L/2, L/3, L/4 and L/5. The regional study covered the full extent of the Southern German North Sea, and based on its results an appraisal well is planned for drilling on B20 008/71 in 2009. Wintershall holds a 100% interest in B20 008/71 and seeks to farm out up to 50% of its equity, while retaining operatorship. The license runs until May 31, 2009, and an extension beyond May 2009 is envisaged.

Recent German offshore drilling activity started in 2004, and continued in 2007 with one new well spudded. Gaz de France-operated Well J/10-1 encountered gas shows in the Rotliegendes Julius prospect. After logs and cores had indicated good porosities in the 164-ft-thick Rotliegends sands, Gaz de France’s German subsidiary tested the well. Although the flows were excellent, the gas turned out mainly to consist of nitrogen. The composition fits the regional trend, and theories that the Julius structure could be filled with methane have proven overoptimistic. The well was suspended. 

THE AUTHOR
	Rhydian A. Williams is a manager within the Deloitte Petroleum Services in London and leads the North-West Europe data team and associated reporting products. Mr. Williams works primarily within the upstream sector. He joined the Petroleum Services group in August 2000 after earning an MSc degree in petroleum sedimentology from Reading University in the UK.