Western Europe

Activity doesn’t track oil price increases

Despite strengthening oil prices, North Sea operators are cutting back after a healthy 2001

North Sea portions written by Arthur Andersen-Petroleum Services Group, London

United Kingdom. Results of the Nineteenth Licensing Round were announced last year, with eight licenses awarded. Texaco will operate, covering five blocks; Amerada Hess, three covering five blocks; BP, one covering one block; and Phillips, one, covering one block.

North Sea Map Click for enlarged view

Southern North Sea Map Click for enlarged view

In July 2002, companies were invited to bid for out-of-round Blocks 30/24, 42/25 and 43/21, which contain Argyll, Innes and Duncan fields. All three fields were abandoned in 1993. Tuscan Energy and Acorn North Sea were awarded licenses on Argyll, Innes and Duncan, with ATP Oil & Gas and CalEnergy being awarded licenses on 42/25a and 43/21a.

Two East Irish Sea blocks were awarded in August 2001. Partners Eclipse Energy and Rolls Royce Power Ventures won Blocks 113/28 and 113/29, which were held in licenses P711 and P712, respectively.

In the Twentieth Licensing Round announced in January 2002, almost 300 blocks and part-blocks were made available in the northern, central and southern North Sea. Larger independents and ‘niche developers’ are expected to play a key role in this round. Through April 29 applications have been made for 36 blocks or part-blocks.

In March, radical measures were enacted to maximize exploration in licensed UKCS acreage. Through this PILOT scheme, operators will be forced to ‘use it or lose it’ in a series of steps enforced to avoid inactivity.

Between July 2001 and June 2002, 59 new exploration and appraisal wells were spudded (including sidetracks, re-spuds and re-entries). Twenty-nine were classed as exploration holes. The most active operator was Kerr-McGee, which started 13 new wells. A majority (34%) of the wells was drilled in the Moray Firth.

In the last year, six new discoveries were made in the UK. In the Northern North Sea, Kerr-McGee found the Tullich and Blue Sky accumulations, while TotalFinaElf found gas and condensate in the Forvie North prospect. In the Moray Firth, BG’s Well 20/6-3 found the Buzzard accumulation, which is estimated to hold recoverable reserves of 500 MMbbl of oil. In the Southern North Sea, Conoco successfully drilled the Viscount field and BG found gas in the Rose R2 prospect.

During the year, successful appraisal drilling was been carried out on Beechnut (Amerada Hess), Blake Flank (BG), Buzzard (EnCana), Heather West (DNO) and Tullich (Kerr-McGee).

Fourteen fields were given development approval in 2001, including Apollo, Artemis, Caledonia, Clair, CMS III, Halley, Hannay, Hoton, Kestrel, Minerva, Penguin Cluster, Scoter, Whittle and Wollaston. Combined reserves in these fields are 420 MMbbl and 985 Bcf. The largest is Clair field, which has 270 MMbbl and is located in the West of Shetlands. Plans are to develop Clair using a production platform. Clair gas (along with other gas in the West of Shetlands area) will be reinjected in the Magnus field EOR project in the Northern North Sea.

Eight fields started production during 2001, including Blake, Brigantine, Elgin / Franklin, Foinaven East, Gryphon South, Kestrel, Leadon and Nuggets. Total reserves in these fields are 664 MMbbl of oil and 2,582 Bcf of gas. Six of the fields have been developed as subsea tiebacks, one as an FPSO and the other as a platform development. The largest field to start production was Elgin / Franklin with 414 MMbbl of oil and 1,807 Bcf of gas.

Total liquids production reached 934 MMbbl during 2001, down 0.5% from the previous year. Average production was 2.56 MMbpd. Gas production averaged 10,987 MMcfd, up 2%.

In July 2001, the opening of the Tenth Round was announced, where all unlicensed UK onshore acreage above the mean high-water mark was offered. Thirty applications were received from 21 companies covering 59 blocks. Twenty-two Petroleum Exploration and Development Licenses have since been offered to 10 companies. Two additional licenses are expected to be offered pending the receipt of further information.

Norway. After being invited to nominate blocks for the Norwegian Sea Seventeenth Licensing Round, 16 companies nominated 93 blocks and part-blocks. Before year-end, 32 blocks or part-blocks were offered. In May, two operatorships were awarded to Norsk Hydro, and one each to Agip, Phillips, Shell and Statoil. ChevronTexaco, BP, Conoco, DONG, Gaz de France and RWE-DEA, had submitted applications.

Sixty-eight blocks or part-blocks were offered in the North Sea Awards. Fourteen applications were submitted and 10 petroleum production licenses were awarded to 12 companies – Statoil ASA, Norsk Hydro, Phillips and RWE DEA each were awarded two licenses, Pelican AS and Kerr-McGee each were awarded one license. Partners in the licenses include TotalFinaElf, DONG, Svenska, Paladin, Enterprise and Norsk Agip.

In March, 6.5% of the SDFI was sold for a price consistent with that paid by Statoil for the initial 15% offering. Thirty licenses were sold to Norsk Hydro, TotalFinaElf, Shell, Conoco, Marathon Oil, Paladin Resources, Gaz de France, Idemitsu and DONG.

Thirty-seven wells were started between July 2001 and June 2002. Statoil was the most active operator drilling 51% of the wells. Most of the wells (70%) were located in the North Sea.

Seven discoveries were made during the past year. In the North Sea, several near-field accumulations were drilled. In the Oseberg area, Norsk Hydro drilled the Gamma West, Kappa North and J-Structure prospects. The company also drilled the Visund South structure. On the Gullfaks platform, Statoil drilled two wells and found a new gas condensate accumulation to the west of the field. In the Norwegian Sea, Norsk Hydro found gas and condensate in Colette to the west of the Midgard field, and Statoil found light oil in the Morvin structure north of Kristin. Successful appraisal wells were drilled on Gudrun (Statoil), Goliath (Agip) and Skarv (BP).

Development approval for five fields (Fram, Kristin, Mikkel, Sigyn and Vale) in the North Sea was given during 2001. These fields have combined reserves of 580 MMbbl and 88,638 Bcf of gas. Fram, Sigyn, Mikkel and Vale are being developed as subsea tiebacks. Kristin will be produced from a semi-submersible platform and will act as a processing hub for the Haltenbank West area. Vale has already started producing in early June 2002. Fram, Mikkel and Sigyn are expected to start production in 2003, and Kristin will start production in 2005.

Three fields went on-stream during 2001 (Glitne, Huldra and Tambar). Glitne, currently the smallest field in production on the NCS, is being produced from an FPSO. Huldra is a high-pressure / high-temperature gas condensate field and has been developed using a not-normally-manned platform. Tambar has been developed as another not-normally-manned platform tied to nearby Ula field. Gas exports through the new Vesterled line from Heimdal started in October 2001. The 33-mi, 32-in. pipeline can export 388 Bcf/year. Tune and Vale are expected to come on production in 2002. Tune is a platform development tied to the Oseberg field.

In 2001, oil production reached 3.4 MMbpd, a 3% increase over the previous year. Gas production increased 14% to 5.7 Bcfd. This substantial increase is attributed to Aasgard, Heidrun, Norne and Oseberg fields starting gas exports.

The Norwegian industry is now coming to the end of an important period of restructuring. In 2001, Statoil was partially privatized, with the Government selling 18.2% of the company. The Government also sold 15% of the State Direct Financial Interest to Statoil and another 6.5% to Norsk Hydro and other companies. As a consequence, Statoil will no longer manage the state’s direct interest in Norway’s fields and a new company (Petoro) was formed to perform this task.

Under the restructuring program, operation of the offshore network has been taken over by Gassco, a new company. Gassco will be in charge of maintenance and day-to-day operation of the network. The pipeline owners are negotiating to unitize ownership of the major trunklines in Norway under the Gasled 2 initiative. The Gasled deal will establish fair principles concerning third-party access and transit fees. It is expected that the results from Gasled will be announced this summer, and take effect in the beginning of 2003.

Netherlands. In 2001, Clyde was awarded a production license on Block M/7 for a 20-year period, together with three exploration licenses on M/4, M/1b and Q/2a. NAM also applied for a production license on adjacent Block M/1a. Wintershall applied for another two production licenses on part-Block E/18a and F/16, and also ‘spontaneous’ production licenses for the southeast corner of E/15 and the southwest corner of F/13, based on the F16/E18 field.

Following the award of production licenses for G/17c and d at the beginning of the year, GDF was awarded an exploration license on part-Block G/17a, with two well commitments. TFE was awarded an exploration license on Block F/12, with commitments to drill two wells. NAM applied for a production license on E/17a with an associated ‘spontaneous’ production license on E/16a related to the E/17 (Area 2) discovery. NAM also applied for a ‘spontaneous’ production license on G/16b related to the southern extension of the G/16-FA gas field.

Nineteen wells were spudded during the past year, with 16 classed as exploration wells and the remainder as appraisals. Both Clyde (a subsidiary of Conoco) and Wintershall were particularly active, drilling five wells each. Between July 2001 and June 2002, six exploration wells successfully encountered hydrocarbons. Gaz de France made two gas finds with wells K/12-15 and K/12-16, while to the southeast, Clyde encountered gas with wells L/16-14 and L/16-15. Clyde also made gas discoveries with wells P/12-14 and Q/4-10, the latter of which is currently being appraised with well Q/1-25.

Two Dutch fields were given development approval in 2001. Gaz de France’s G17d field, with reserves of approximately 106 Bcf, is expected to commence production this year through a minimum facilities platform with gas exported via a 43-mi pipeline tied into NGT. Also expected to start in early 2002 is the K01a field, with expected reserves of 460 Bcf.

Conoco started production last November from P6d field. Peak production is anticipated this year at 60 MMcfd. Estimated recoverable reserves are 177 Bcf. The F02-Hanze field, which also started production in 2001, is expected to add a further 40 MMbbl to the liquids reserves on the Dutch OCS.

Dutch offshore liquids production increased dramatically to around 40,000 bpd, an 82% increase over the 2000 average. Gas production also increased by 2% to 2.78 Bcfd in 2001.

Italy. The turning point for the upstream sector came late last year when the pipeline from the Val d’Agri complex in the Southern Apennines to the Taranto refinery finally came on stream. The 20-in., 150,000-bpd pipeline could be carrying 104,000 bpd by next year when Cerro Falcone field is developed.

This year, Agip was expected to receive approval to continue appraisal of its Miglianico discovery made along the Abruzzo coast last year. The discovery well tested 1,000 bpd of 34°API oil and more than 1 MMcfd of gas from 330 ft of gross pay identified by logs. Agip was last reported to be conducting additional seismic to help locate future drilling sites. Initial reserve estimates are from 40- to 45-MMbbl.

France. Exploration activity was nearly non-existent during 2001, but exploitation and development investments rose 18% as operators concentrated in the established oil fields of the Paris basin. Some 24 wells were drilled, several of which were horizontal. This year, exploration drilling is expected to resume, while development drops slightly.

The increased development work held 2001’s oil production decline to only 2.5%, compared to a 7.9% drop between 1999 and 2000. Crude production averaged 28,000 bopd in 2001, and came from 60 fields, 40% of which produce less than 300 bopd.

Gas production decreased by 3.2% to 272 Mcfd. Lacq field, in the South Aquitaine basin and operated by Elf AEPF, accounts for almost 95% of French gas.

Germany. After several years of low exploration activity, 2001 showed improvement in terms of wells drilled and seismic surveys conducted. Four wildcat wells were begun, with two completed to date. Both were unsuccessful. Geophysical survey activity levels (3D seismic) were as high as ever achieved in the country, with 923-sq-mi collected during the year. Most of this work occurred in the German sector of the North Sea.

Oil production from Mittelplate is expected to rise to 32,000 bpd. This should maintain Germany’s production at about 69,000 bpd, even as most other fields decline.

Denmark. Maersk was the most active operator drilling three of the six wells (three exploration and three appraisal) spudded during the past year. In August 2001, DONG drilled the Hejre-1 on Block 5603/28 (operated by Phillips) and encountered oil in Late Jurassic sandstones with good reservoir qualities. Phillips exploration well, Svane-1 on Block 5604/26, is currently being tested. Statoil successfully appraised the Siri and Stine fields, and Maersk drilled appraisal wells in Svend field.

Oil production during 2001 reached 349,000 bpd, 4% below 2000 rates. The decline was largely due to an explosion on the Gorm platform, which shut down Gorm and its satellites for almost four months.

Two additional fields (Stine Segment II and Tyra Southeast) came on stream in 2002, bringing the number of producing fields to 18. Stine Segment II has oil reserves of 4 MMbbl and commenced production via an extended reach well from Siri field in January 2002. Tyra Southeast has oil reserves of 30 MMbbl, and was developed using an unmanned wellhead platform tied back to the main Tyra field.

Danish oil production in 2002 is expected to reach 398 MMbpd, 14% above 2001 figures, then remain fairly constant until 2006.

Gas production during 2001 came from 14 fields and averaged 1,110 MMcfd. Gas production in 2002 is expected to average 1,091 MMcfd, a 2% decline.

Ireland. Irish gas production in 2001 reached 79 MMcfd, but is expected to decrease to 77.5 MMcfd this year. However, production should increase by 32% to 102 MMcfd in 2003 as a result of Ramco Energy’s Seven Heads field commencing production in the fourth quarter. Seven Heads contains 300 Bcf of gas and is expected to be developed using six subsea wells tied back to the Kinsale Head field.

By 2004, gas production could quadruple to 436 MMcfd, as first gas from the Corrib field goes on stream. Corrib, which is believed to contain 850 Bcf of gas, is to be developed with a total of seven subsea wells connected to shore via a subsea manifold or gas gathering system.

Faroe Islands. During 2001, the first wells were drilled offshore of the Faroe Islands. Of three wells (and one geological sidetrack), the first was Statoil’s 6005/15-1 on the Longan prospect, which was abandoned in September as a dry hole. BP’s Well 6004/12-1, which targeted the Svínoy structure, was sidetracked for geological reasons. Last October, BP announced the presence of oil and gas, although in non-commercial quantities.

Amerada Hess spudded 6004/16-1 on the Marjun prospect. Oil and gas were encountered in a 558-ft (gross) interval but it was not flow tested due adverse weather conditions.

In April 2002, Agip was given permission to postpone an exploration well in its 002 License. The well had been required to spud prior to August, but discouraging exploration results to date will require a reassessment of the seismic data and geological models.