Activity high across Europe, but costs and credit may take their toll

Lundin Petroleum continues to appraise the Luno field in block 16-1, first drilled in fall 2007, which it claims is the largest new find in the Norwegian North Sea of the past decade, with up to 190 MMboe recoverable. The company plans a further exploratory well this year to test the updip Luno extension prospect. Depending on the results, it may commit to a stand-alone development. The area is relatively undrilled, but that could change following StatoilHydro’s recent farm-in to three of Lundin’s licenses in the Greater Luno area.

Block 16-1 lies east of Gudrun, a high temperature/high pressure oil and gas field with potential reserves of over 200 MMboe. In March, the Norwegian major contracted Aibel for topsides front-end engineering design for a new fixed platform – a development plan could be submitted later this year.

Another standalone scheme also is taking shape for StatoilHydro’s Dagny/Ermintrude fields, 25 km (15.5 mi) northwest of the Sleipner A platform. This follows successful testing last fall of a new exploration model by the semisubTransocean Winner, which led to a major reserves upgrade on Dagny.

Elsewhere in the North Sea, Danish company Dong E&P submitted plans for two subsea developments – a three-well subsea tieback of the Oselvar oil and gas field to BP’s Ula platform, and a two-well, cross-border tieback of the smaller Trym field to Maersk’s Harald complex in the Danish sector.

Various consortia also are working on redevelopments, although Premier Oil has balked at the cost of Det norske’s proposals to re-work the abandoned Froy oilfield using a jackup platform. In September, ConocoPhillips awarded FEED contracts to Mustang and Aker Solutions for new platforms for fields in the Greater Ekofisk area.

StatoilHydro filed a PDO last June to improve oil recovery and gas exports from the Troll field. However, rising costs forced the company recently to postpone plans for one of the project’s key components, replacing flowlines in the gas wells on the Troll A platform.

In the Norwegian Sea, StatoilHydro has drilling successes in a new gas province north of Norne, close to the former BP-operated Luva discovery. The company also notched further finds in the Barents Sea, but not large enough to warrant development. Unlike the Goliat oil field, where operator Eni has chosen Sevan’s FPSO 1000 concept following a design competition with Aker Solutions. The Goliat development will be innovative in numerous ways, including electrification direct from the shore via a subsea cable.

UK

Although drilling activity was strong in UK waters last year, the number of new exploration and appraisal wells could drop by nearly 30% in 2009, according to a survey by operators/contractors’ association Oil & Gas UK. It predicts a total of 77 E&A well spuds, compared with 113 forecast early in 2008, before recession started to bite.

According to well management group AGR Petroleum Services, more rigs are available now in the North Sea at lower rates. Oil companies have reacted by holding out for even lower prices, but this has led some semisubmersible contractors to stack their rigs rather than accept short-term hires at a lesser cost. Once the oil price rebounds, this could lead to a return to capacity issues in the sector, and rising rates.

Field development is also suffering: Oil & Gas UK estimates that capex on new and existing UK fields fell from a peak of £5.6 billion ($8.2 billion) in 2006 to just under £5 billion ($7.38 billion) last year, despite the oil price surge. And the current scarcity of capital means that new investment is secured only for the most attractive projects – on current trends, capex could drop to £2.5-4 billion ($3.7-5.9 billion) in 2010.

Oil & Gas UK has held regular meetings with the UK government pleading for tax breaks, so far to little avail. Recently, representatives of Subsea UK also met with government officials to discuss the impact of banks curtailing or canceling debt facilities. This has led some independent operators such as Antrim Energy to re-think the scope of their subsea developments, many of which are prolonging the life of aging platforms that otherwise would have to be dismantled. In one extreme case, withdrawal of credit put Oilexco North Sea out of business, although its assets look set to be transferred to Premier Oil.

Another Canadian company, Ithaca Energy, hit problems financing its Jacky oil project in the Moray Firth before drafting in Dyas of the Netherlands as partner. The perseverance paid off, as Jacky recently came onstream via a minimal platform exporting to the refurbished Beatrice Bravo facility. The latter had been shut in by previous owner Talisman Energy due to pipeline integrity issues. Ithaca replaced the pipeline and installed a new water injection line to improve oil recovery from the northern leg of the Beatrice field.

Independents also are sustaining exploration on the UK shelf. Among these, Dana has discovered a series of oil accumulations in the Rinnes area in the northern North Sea, while Canada’s Nexen has a growing cluster of oil finds north of its Buzzard complex in the central sector, the latest named Hobby.

British Gas’ parent company Centrica embarked on a series of acquisitions in the southern gas basin including operating interests in Hess’ York fields, said to be the UK’s largest undeveloped resource in this region. York is close to Rough, the UK’s largest offshore gas storage facility. Centrica hopes to convert the Bains gas field in the east Irish Sea to another storage site, connected to an unmanned platform and new processing facilities at the South Morecambe terminal in northwest England.

West of the Shetlands, various stranded gas fields could further ease the UK’s energy worries. The problem is year-round, severe metocean conditions. Total has been working on a subsea-to-shore scheme for its Laggan and Tormore fields, the gas landing on the main Shetland Island before being piped to Aberdeen.

Chevron has taken a drillship from Stena on a long-term contract to appraise its promising Rosebank/Lochnagar oil discoveries in the same region. These and other nearby successes prompted a scramble of applications for licenses in the area under the UK’s 25th Seaward round, many of which went to groups of independents.

Across the median line, the Faroes government awarded blocks covering a total area of 6,505 sq km (2,512 sq mi) to six companies last December, under the islands’ third licensing round. StatoilHydro was by far the biggest taker.

Deepwater promotion

Last November,Ireland invited bids for new exploration licenses in the deepwater Rockall basin off the west coast, covering an area of 117,200 sq km (42,252 sq mi). Applications were due by April 22. More license options have been issued in recent months to indigenous companies, particularly in the Celtic Sea. Lansdowne Oil & Gas gained an option covering parts of four shallow water blocks where it plans to target oil in Jurassic sands.

To the north, Petronas subsidiary Star Energy has assumed ownership from Marathon of the Kinsale Head offshore gas production facilities. Star also has been studying locations offshore Ireland for gas storage, including one site close to Dublin.

In theNetherlands, the government has taken small steps towards stimulating investment in E&P. The Ministry of Economic Affairs has proposed amending the country’s Mining Act to allow companies to deduct an extra 25% of capital costs from their profits for exploration and development of marginal fields.

Qualification would depend on reservoir size, anticipated production rates, and distance to existing infrastructure. How these criteria would be applied is unclear, according to the Dutch operators association Nogepa, which has started dialogue with the Ministry over the proposals. But the changes could be in place by the start of 2010.

In anticipation, the Shell/ExxonMobil joint venture NAM recently contracted Swift Drilling for exploration and production drilling in the southern North Sea. The rig, due to be in service late in 2010, is a relatively small jackup custom-designed for low-cost operations on marginal accumulations in this region.

Last year, Nogepa counted 10 offshore exploration wells on the Dutch shelf, up from six in 2007, with at least three discoveries for GDF Suez, NAM, and Petro-Canada in the G, P, and L quadrants. It was also a busy time for wheeler-dealing: GDF Suez acquired a package of interests held by NAM along the route of the Nogat gas trunkline, while Total bought Talisman’s entire Dutch North Sea interests. Among the growing upstream contingent, Dutch utility Nuon snapped up the assets formerly owned by Burlington.

This year, one of the sector’s more active newcomers, Canadian company Cirrus Energy, has made a further gas find with the L11-13 well, drilled directionally from the L11b-A production platform. Total recently contracted HSM in Schiedam for a platform for its K/5 CU satellite development in block K/5. The same fabricator should shortly deliver a four-deck platform to GDF Suez, for use on the 2.5 bcm (88 bcf) E17a-A gas field.

The normally dormantGermany offshore sector sparked to life in February, with London-based Hansa Hydrocarbons agreeing to farm in to nine blocks operated by Wintershall in the H and L quadrants. Hansa’s immediate priority is to revive work on the L-1 Alpha Rotliegendes gas discovery. There are other known accumulations in the blocks, but high associated levels of nitrogen deterred further exploration.

Exploration drilling offDenmark has trickled to a halt of late, with the sector’s main stalwarts, Maersk and DONG, channeling their energies into incremental production. Last June, the Danish Energy Agency (DEA) approved Maersk’s $1.1 billion plan for a fourth-phase development of its Halfdan field in the North Sea, designed to recover 95 MMbbl of oil and 6.3 bcm (222 bcf) of gas. The centerpiece will be a new processing platform, awarded to Sembawang Corp, processing 80,000 b/d of oil with gas separation capacity of 6.7 MMcm/d (237 MMcf/d).

DONG should start production this fall from Nini East, a DKK2.1 billion ($378 million) scheme involving a new platform linked to the incumbent installation on the Nini field via multiphase flow, gas-lift, and water injection lines. DONG also has taken the opportunity to replace the corroded Nini-Siri water injection line with a new 32-km (19.9-mi) line to be installed this summer by Acergy.

Later this year, according to ScanBoss, DONG may select a concept for Hejre, an HP/HT oil and gas field which is Denmark’s largest undeveloped offshore resource. The company has turned to Ramboll to help manage propane and butane in the natural gas liquids – one option could be a tieback to a new processing platform at the Arne South field center.

The government ofIceland has opened waters northeast of the island (the Dreki area) for exploration and production. Seismic and other geophysical surveys suggest potential for producible quantities of oil and gas, according to the Ministry of Industry.

In the section of the Barents Sea belonging toRussia, the Shtokman partners have issued further contracts. In February a consortium comprising Aker Solutions, SBM Offshore, and Technip France was awarded concept definition and front-end engineering design studies for a floating production platform for the Phase 1 development.

Earlier, Vyborg Shipyard engaged Dockwise Shipping for the same project to transport two giant topsides from Korea to the Barents Sea, followed by installations on semisubmersible hulls in 2010-11. Next year, Saipem is due to start laying pipelines in the Baltic Sea for the Nord Stream project, taking fresh supplies of Russian gas to northern Europe. Recent reports suggest Gazprom is now considering funneling future phases of Shtokman’s gas.

In southern Europe, Tullow Oil is nearing completion of geological studies and seismic data/interpretation in acreage in the Alentejo basin offshore southwestPortugal. If results look encouraging, the company could drill a well by 2011. Off southeast Spain, the Saipem 7000 recently wrapped up installation of the deepwater section of the Medgaz pipeline, which will take gas from Beni Saf on the Algerian coast 210 km (130 mi) across the Mediterranean Sea to Almeria. Following hydraulic tests, first gas exports should start later this year.

Another consortium, Galsi, has outlined plans for a new gas export trunkline in the central Mediterranean, stretching from Algeria to Sardinia before making landfall on the Tuscany coast. But various other consortia hopes to prove Italy has offshore hydrocarbons of its own – particularly close to Sicily and in the Sicily Channel adjoining Tunisian waters. They include Northern Petroleum and Shell Italia, which have just acquired over 2,460 km (1,528 mi) of 2D seismic across licenses in the West Sicily thrust belt using Bergen Oilfield’sBOS Angler.

In the Adriatic Sea, Eni should take delivery shortly of the Annamaria B platform from Sardinian fabricator Intermare Sarda. Farther east offGreece, Aegean Energy has contracted Northern Offshore’s jackup Energy Exerter for three wells, the first a sidetrack from an existing well drilled from the Prinos A platform offshore Kavala.

Finally, UK company Melrose Resources is set to become operator of the Doina and Ana gas field developments in the Black Sea, offshoreRomania. Sterling will remain operator for exploration of other prospects in the associated Midia and Pelican blocks.