The North Sea still plays a formidable role in the global search for oil and gas, though the supporting characters are shifting. Acreage is changing hands as smaller players invest to extend the lives of mature fields.
A Wood MacKenzie report says liquids production from offshore northwest Europe last year averaged 3.77 MMbbl/d, 2 MMbbl/d higher than 2001. And gas sales from the region increased by 9%, averaging 10.4 bcf/d in 2002.
An increase in hydrocarbons production is badly needed in an area where dependency is on the rise.
Spending forecasts for the region indicate that steps are being taken to arrest the increase in foreign dependence. Analysts at Douglas-Westwood have forecast Western Europe will lead the subsea market with a 27% share of the $48 billion to be spent over the next five years. Field development will continue to be a focus, with satellites tying in to production hubs that feed the escalating needs of the region.
According to a UK Offshore Operators Association report published in March, 260 offshore oil and gas fields were under development or in production last year
About half of the UK oil and gas reserves, 24-32 Bboe, are yet to be produced. This appears to be good news, but the other side of the coin is not so positive. Tax rates are onerous – 40% to 70% – and if the forecast of a 20% rise in taxes by 2010 is fulfilled, things will get much worse for operators before they get better.
Most of the fields in development today are considerably smaller than those of the past. That has been the impetus for a number of fields changing hands. The smaller reserves potential is attractive to smaller operators and independents, which invested heavily in the region last year.
In February 2002, independent EnCana drilled an appraisal well at Buzzard that flowed at 11,000 b/d from two producing zones and 2.2 MMcf/d of gas. EnCana operates these wells and is the largest acreage holder in the Buzzard-Etrick area, with interests in seven blocks covering more than 250,000 acres. Appraisal on Buzzard concluded in late summer 2002, confirming 400 MMbbl recoverable reserves.
In January, BP announced it would sell its interest in the UK Forties field to independent Apache. The sale is to be complete by mid-year. BP's share of production from Forties is 48,000 boe/d, a considerable asset for Apache.
Canadian Natural Resources, the world's fifth largest independent producer, will invest in the North Sea Ninian and Murchison production hubs this year. Current plans for the Ninian field include five well relocations, two through-tubing redirectional drill (TTRD) wells, 10 recompletions, one satellite exploration well, and a waterflood optimization plan. This is the first phase of a multi-year exploitation plan that will extend the productive life of the reservoir.
At Murchison, CNR will drill six additional infill wells and four TTRD wells in addition to optimization of waterflood activities.
While independents invest in boosting produc-tion, the UK has begun looking to neighbors to facilitate North Sea developments. Cooperation between the UK and Norway in the North Sea could help expand market access and open transportation and infrastructure for both countries.
In February, Shell subsidiary Enterprise Energy Ireland announced it would resume tests at its ultra-deepwater Dooish prospect off the northwest coast of Ireland in May. A hydrocarbon discovery confirmed in 3Q 2002 will be tested this month.
In 2002, the government announced a new licensing round that would open up the entire Porcupine basin off the west and southwest coast of Ireland for frontier exploration licenses.
In November 2002, Marathon Oil announced that an additional subsea gas well would be drilled and developed in Kinsale head in the Celtic Sea. The subsea tieback to the Bravo platform, to be completed in July, will raise production to 90 MMcf/d.
Late last year, Ireland's government awarded Ramco Energy a petroleum lease for its Seven Heads gas field development in the Celtic Sea. The Seven Heads partners planned to start development in April, re-completing one well and drilling five further producers, all of which will feed through to Marathon's Kinsale Head facilities off southern Ireland through a subsea manifold. Production, expected to peak at 80 MMcf/d, will meet 10% of the nation's gas needs.
Last August, Enterprise Oil postponed offshore export pipeline installation for its Corrib field following Shell's acquisition of Enterprise. First gas was originally scheduled for the end of this year, but is now expected early in 2004.
Early this year, Faroe Petroleum laid the groundwork for a summer exploration program on the deepwater Faeroese continental shelf. Dana Petroleum provided part of the funding that will allow Faroe to start exploration on licenses 2 and 5, which were awarded in the 2000 licensing round.
Amerada Hess spudded the first of its deepwater wells in the area in September to test the extent of the Marjun gas and condensate field discovered in November 2001.
Amerada has declined to estimate reserves sizes, but the general impression is that Marjun is a potentially huge field.
2002 saw the Nini and Cecilie developments tied back to the Siri platform on the Dutch continental shelf. Combined recoverable reserves from the fields are 65 MMbbl of oil. The fields are expected to go onstream this summer.
Last September, Denmark state-run oil and gas company DONG said it would spend $170.8 million in 2002 for new oil and gas activities off Norway's west coast, seeing the area west of Norway as a growth area in the next five to eight years. DONG will spend on average $145 million annually acquiring stakes in existing oil and gas licenses and $43 million a year in Norwegian oil exploration.
Last year, DONG bought Norwegian oil group Statoil's oil and gas activities in the Danish part of the North Sea for $120 million.
Statoil, Norway's biggest oil and gas producer, expects to have six new oil and gas fields in production by the end of 2003.
Snøhvit was the largest development project off Norway last year. The Snøhvit development comprises three fields – Snøhvit, Albatross, and Askeladd – in the Barents Sea. The Snøhvit development plan was approved last March. A subsea production system will feed an LNG processing facility to be built on a barge and located on the northwestern coast of Melkøya Island. Exports are expected to reach 5.75 bcm/yr of LNG, 747,000 tons of condensate, and 247,000 tons of liquefied petroleum gas. First production is expected in 2006.
Norway saw disappointing exploration results in 2002, and the Norwegian Petroleum Direc-torate expects only 15-20 exploration and appraisal wells to be drilled this year. The country took a hit last year with three dry ultra-deepwater wells. Most of last year's discoveries were small fields that were tied in to production hubs.
Some significant projects, however, will move forward this year. In March 2003, the board of directors of ConocoPhillips approved a plan for further development and growth of the Ekofisk area in the Norwegian North Sea. One of the objectives is to increase oil and gas recovery.
The project consists of two interrelated components: the Ekofisk 2/4 M platform and an increase in capacity. The steel jacket is to be installed in 2004. Production is to begin in the fall of 2005. The project requires 25 wells to be drilled.
Exploration drilling continued at a fairly high level off The Netherlands through 2002, but there were no significant discoveries.
A number of offshore gas projects are in development, and money has been committed to extending the life of one of the oldest offshore fields. Late last year, Nederlandse Aardolie Maatschappij awarded Stork a $795-million project to renovate the Groningen gas field on the North Sea coast of The Netherlands. New equipment installed over the next eight years will help sustain output from the 30-year-old field. Groningen, which is The Netherlands' principal gas supply, produces 2.12 tcf/yr of natural gas.
The Barents and Black seas off Western Russia offer Europe's newest frontier. Last April, TotalFinaElf and Rosneft signed an agreement for exploration of the Russian sector of the Black Sea. TFE signed an earlier agreement with Yukos for exploration of another Black Sea block, Shatsky, which has never been explored.
In 3Q 2002, Melrose Resources announced that it would develop the Galata gas field in the Black Sea offshore Bulgaria. A gas sales contract with state-owned Bulgargaz stipulates the company will receive 14 bcf/yr from the Galata field for the first three years of production. First gas is expected in January 2004.
Last year, Statoil announced the goal of continuing exploration and development in the Barents Sea. Extensive 3D seismic surveys are planned in the Barents Sea off northern Norway this year and next. That objective could be met in cooperation with Russian companies.
In August, TGS-Nopec and WesternGeco began a new 850-sq-km multi-client 3D survey in the Barents Sea over open non-licensed acreage. Final data from the survey became available early this year.
Also in August 2002, TFE announced it was interested in acquiring a 25% stake in the Shtokman offshore gas project in the Barents Sea, 550 km off the coast of Murmansk in 350 m water depth. The Shtokman field is one of the largest in the world with reserves of over 3.2 tcm of gas and 31 million tons of condensate. Investment would initially finance construction of an offshore gas pipeline that would deliver 22-23 bcm/yr to St. Petersburg. The critical hurdle is that the field is operated by Gazprom, which has not managed to work out with foreign partners how to move the project forward.
Portugal and Italy
Portugal closed the bidding on its first deepwater licensing round in December 2002 with only two bids offered for the deepwater and ultra-deepwater acreage. Repsol-YPF partnered with RWE-Dea for the two blocks.
Fourteen blocks were on offer in the frontier area. Only four wells have been drilled off Portugal in water deeper than 656 ft. With the lack of interest in the licensing round, there will not be much exploration activity in the coming year.
Early in 2003, Northern Petroleum was awarded a permit offshore Sicily near the boundary with Tunisia. Northern announced plans to search for oil and gas in the permit.
Lebanon and Israel
Early this year, Lebanon announced that a seismic survey found geological features indicating potential hydrocarbon deposits off the Lebanese coast. The 2,000-sq-km survey was gathered in 2002.
Lebanon and Algeria have signed an agreement for oil exploration along the Lebanese coast.
In January 2003, the Delek Group reported that platform installation was complete on the Mari-B gas field offshore southern Israel. Mari-B, a part of the Yam Thetis project, holds 1 tcf of gas. The next phase of the Yam Thetis project will see a subsea pipeline connecting the platform to a power station on shore. Phase two should be completed by mid-year.
Egypt and Libya
Apache Corp. has had a string of successes in the West Mediterranean concession offshore Egypt. The company had its first deepwater find in May 2002 with Abu Sir-1X in 3,255 ft of water, about 16 mi west of prior industry discoveries in the neighboring North Alexandria Concession. Al-Bahig followed in July and El Max-1X in September. In late November, the company saw its fourth deepwater discovery, El King-1X. Apache recently announced the successful appraisal of the Abu Sir field with the Abu Sir-2X well, drilled in January.
Apache also had a discovery in March in the Ras El Hekma concession. New 3D seismic indicates significant potential. The company plans to test the field with a second well.
Late in 2002, Eni announced a gas discovery on the Tennin field with exploration well Tennin 1 in the East Delta Deep Marine exploration license in the Nile Delta. Preliminary field appraisal set reserves at 15-30 bcm. Studies for development are underway.
Offshore Libya, the biggest project is development of the Buri field in the NC-41 permit 110 km north of Tripoli. Eni subsidiary Agip Gas BV operates the field on behalf of the Libyan National Oil Corp. and Eni Agip. The field contains 1.1 Bboe in recoverable reserves.
In September 2002, Bouygues Offshore signed an engineering, procurement, installation, and commissioning contract with Agip Gas for a subsea production system, which is part of the overall development of the Western Libya Gas Project in block NC-41C.
Production is to begin in 2004. Gas from the field will be transported to Mellitah on the Libyan coast, then on to Sicily, where it will enter a gas distribution grid. All of the gas supply contracts in place are for 24 years.
In August 2002, BG Tunisia announced an oil discovery in the Gulf of Gabes. The Hasdrubal Southwest-1 well confirmed an extension of a proven accumulation, and three additional development wells were planned for the area. The field contains recoverable reserves of 260 bcf of gas and 25 MMbbl of condensate. The company is evaluating test results and is planning to develop the area soon, with a first production target of 2006.
In September 2002, Algeria announced preparations to offer all of its offshore acreage in its next licensing rounds. The area is divided into three blocks: 143, 144, and 145.
WesternGeco shot 5,000 km of new 2D seismic on the acreage as part of its multi-client non-exclusive agreement with national oil company Sonatrach. No wells have been drilled for 30 years in Algeria's offshore.