Life in the North Sea appears comfortable - on the surface. Oil production in Norway and the UK is maintaining record levels. Germany is joining the ranks of offshore gas producers. Denmark is attracting new players, and the disputed Faroese/UK waters are finally open for exploration.
However, drilling remains generally slack, despite low rig day rates and numerous "cheap well" initiatives - an acknowledgement of the sector's overly high operating costs. If anything, the surge of initiatives is a sign of mounting desperation. The North Sea's glamor is fading fast, it may soon be beyond a routine face-lift.
United Kingdom sector
Stability used to be the UKCS' major selling point, until drilling action shifted to war-torn Africa. This is reflected in the number of rigs engaged in UK exploration at the end of June - a grand total of four. Similar lows were last recorded in the early 1970s.
Most of the exploration wells of late have been routine appraisals, either of extensions to producing reservoirs or of modest discoveries in the Central or Southern North Sea. Mobil was a little bolder, launching this year's first wildcat west of Shetland. Others are thought to be keen to follow, but are either on the waiting list for deepwater semisubmersibles or weighed down by documents from environmental objectors.
Those that do manage to drill in this sector, and then discover gas, may be disincentivized by the failure so far to commercialize West of Shetland stranded gas. The Aurora operators study team investigating options was recently disbanded, due to lack of progress.
Elsewhere on the UKCS, other collectives are holding together, if not flourishing. The South Halibut Basin Operators Forum is still deliberating over joint solutions for their unattached fields in the Outer Moray Firth. However, another infrastructure-sharing study for the southern gas basin - Arco/Mobil's Avalon - has fizzled out, following the BP Amoco and Exxon takeovers.
In the North Sea, the powers behind the new mega-mergers have shareholders on their minds. In the post-accountancy phase, there is little indication of renewed field activity. However, the sell-off of some core holdings could benefit the UKCS as a whole.
Entrepreneurial independents have proven their ability to move in and work wonders on neglected assets. Burlington Resources, for instance, is revitalizing the UK side of the Irish Sea with fast-track developments of its newly acquired fields.
Others could do a similar job. Analysts Wood Mackenzie reported recently that most UKCS production remained economic during the oil price plunge. The exceptions were declining mature fields in the Northern and Central North Sea with big platforms, where OPEX is outstripping production revenue. Now that the oil price is rebounding, revenues are recovering - up 27% to a daily average of $43 million, according to a recent report from the Royal Bank of Scotland.
In the short term, the development picture appears fairly bright. Britain's Department of Industry forecasts spending on new UKCS projects of over $30 billion between 1998-2003, although the final year figure tails off to just over $2.5 billion. Wood Mackenzie anticipates 39 probable oil and gas developments in that period. However, not too many are on a grand scale, beyond Texaco's Captain B. Shell's Brigantine, Burlington's Millom West, Phillips' Jade, and Conoco's E-Plus require modest unmanned platforms - most of the rest are subsea jobs.
Investment planning is not helped by the government's stance. It shifts. In March, Energy and Industry Minister John Battle announced measures to supposedly re-ignite exploration and development, including:
- Annual licensing rounds, with each round covering half of available unlicensed acreage
- More flexibility from the government over license extensions and timing of work programs
- Allowance for exploration to be deferred on "fallow" acreage (undrilled for six years), to encourage trading in licence interests concerned.
However, this announcement coincided with the government's annual budget, which included a provision to stop oil companies minimizing tax liabilities through sale and lease back of their North Sea assets.
Earlier, an Oil and Gas Industry Task Force was established to identify further scope to cut North Sea costs. Then the Government issued its Consultation Paper on a proposed Climate Change levy, which will likely raise beachhead gas prices by 40-45%, according to the UK Offshore Operators Association. They described the levy as "an energy, not carbon, tax that hits 'clean' fuels as much as carbon-intensive ones" - without really impacting emissions at all.
A few months previously, the government had antagonized UKOOA by halting further gas-fired power station planning in order to protect the beleaguered UK coal industry. It did, though, make an exception for one gas-fired scheme in Wales shortly afterwards (involving many new jobs), just prior to the national elections for the first Welsh Assembly.
Aggressive heckling may be UKOOA's best option. In May, it urged extension of Capital Gains Tax rollover relief to trading of North Sea production assets. The Government duly complied in July.
Norway sector
The Norwegian sector has been dominated, though not yet shaken up, by Statoil/Norsk Hydro's joint takeover of troubled Saga Petroleum. Elf's alternative offer was frowned on by the government - no big surprise, given its earlier veto of Gaz de France's attempted stake in the Visund Field. While the rest of the world opens up to international oil companies, Norway's offshore remains a closed shop.
At some point, however, the government may have to yield. According to a survey by Norway's Central Bureau of Statistics, oil and gas spending on the Norwegian continental shelf (CS) this year will drop by NKr17
Investment might be revived by re-addressing the country's punitive carbon dioxide tax on field production. Norway's opposition Labor party has proposed halving this tax on future developments to help safeguard jobs, particularly in the country's fabrication yards. Fears over under-capacity have led Kværner and Aker to discuss a merger in this regard.
The field inventory is hardly running low. Norwegian exploration continues to generate "world class" discoveries, but they are not necessarily the easiest to develop. Tore Sandvold, Director-General of the Ministry of Petroleum and Energy's Oil and Gas Division, said recently: "We have to ask ourselves whether all available resources were mobilized in such developments as Åsgard or Visund, or whether it is appropriate that the operator alone should pursue such a project.
"When developing the Ormen Lange (deepwater) area of the Norwegian Sea, for instance, bringing in a larger constellation, broader expertise, and expanded responsibilities should perhaps be a condition for such a demanding venture."
Sandvold claimed that the Norwegian Sea was the most attractive to international companies, in exploration terms. But the only new deepwater well here is the Saga-operated Gjallar Ridge, in 1,350 meters water depth in an unexplored part of the Voering Plateau.
The government is also anxious to maintain the conveyor belt of smaller North Sea projects, most of which would be led by Hydro or Statoil. The State will not relinquish its stake in promising licences, but under new measures, it will withdraw from licences with lower resource potential.
Oil and gas pipeline tariffs are also being reviewed. This may become an issue in areas where new infrastructure hubs are emerging, such as the new Åsgard Transport gas trunkline serving Åsgard and other Mid-Norwegian fields. In the North Sea, Hydro plans a new 33-km line called Vesterled which would run from the Heimdal riser platform to the Norway-UK Frigg line. This would provide an outlet for numerous untapped discoveries close to Heimdal. Among major new developments likely to go forward are:
- Kvitebjoern, a 1.65 tcf field near Gullfaks, which would cost $1.1 billion, assuming a platform and associated pipeline
- Kristin, a large gas-condensate discovery in the southern Halten Bank. The numerous design reviews to date have been tempered by Saga's financial struggles
- Grane, a heavy oilfield with reserves of 630 million bbl. According to London-based field analysts ScanBoss, operator Hydro is inviting bids for a large platform with topsides weighing around 25,000 tons. Required injection gas may come from Esso's nearby Balder Field
- Sogn Area, a combined development of the Fram and Gjoea oil and gas fields, close to Troll, likely involving a production floater and intelligent completions. Scanboss estimates a $1.9 billion outlay, but planning may be impacted by the outcome of the nearby Aurora well, spudded recently by BP Amoco.
Denmark sector
Prior to May 1998, all fields in the Danish CS had been developed and produced by the DUC consortium. However, a new open door approach by the government has led since to Sirri and Lulita coming onstream under Statoil's command.
South Arne, an old discovery reactivated by Amerada Hess, was also due to start production this summer, but may be delayed due to problems with the platform's GBS installation, plus an accident affecting the new 300-km offshore gas export trunkline from the field to Nybro in Denmark.
The Environment and Energy Ministry has attracted more newcomers of late under its open licensing procedure, which relates to areas on the shelf east of the heavily explored Central Graben. New block sets were awarded this year to Agip, Gustavson, Anschutz Overseas Corp, and most recently, to Amerada Hess (in behalf of the Odin II group). They have acreage east of Jutland in a barely explored portion of the Danish-Norwegian Basin.
Last year, 17 new E&P licences were also granted under Denmark's 5th licensing round pertaining to waters further west. The Danish Energy Agency claims that related commitments should generate exploration spending of DKr1.7 billion over the next six years, with 13 unconditional and eight conditional wells plus 3,500 km of new 3D seismic.
Of the new wells off Denmark in 1998, the most important was MFF-19C, drilled by Maersk from the Dan Field complex. The well, drilled 7,650 meters to the northwest, in order to appraise a chalk reservoir zone, featured the world's longest horizontal section, at 6,117 meters.
Oil saturation was good over the entire length. The well was brought onstream shortly afterwards, and Maersk followed up by drilling this year another prospect 1.1 km further north-west, named Nana. This proved the continuation of the oil-bearing formation.
Flow rates were not disclosed, but were large enough for Maersk to alert fabricators of plans for a wellhead platform, weighing up to 5,000 tons, plus associated risers and pipelines ranging from 6 in. to 16-in. Scanboss suggests that processing capability may also be added to the platform.
The Faroes, Ireland
This spring, the Faroese and UK governments finally resolved their differences over the continental shelf boundary between the two nations. That should lead to the long-delayed first Faroese licensing round going forward this fall, with licenses duly awarded next summer.
Most of the nominated blocks lie on the south-east margin of the Faroese CS. The disputed White Zone acreage will not be auctioned this time. This area borders BP's Foinaven and Schiehallion discoveries on the UK side. It also contains a block awarded contentiously by Britain to Arco in 1997, which is thought to house an extension of BP's undeveloped Suilven oilfield.
Ireland is undergoing a flurry of development activity. Marathon is upgrading compression on its Kinsale Head installations, offshore Cork, to take gas from a new subsea satellite, Southwest Kinsale. Dublin-based Providence Resources is aiming to develop three oil and gas discoveries in the same area, all up to 60 km offshore, in 240 ft water depths.
In Dublin, a new gas-fired power station is being built by Statoil and Irish electricity generator ESB. Statoil's Alliance Gas subsidiary will supply gas to the plant. Statoil is involved in 10 exploration licences off Ireland, one of which contains the Corrib gas discovery in the Slyne Trough. Operator Enterprise Oil recently drilled an appraisal well on the southern part of the field, thought to be targeting a separate compartment to the Triassic Sherwood Sandstone reservoir. Marathon also farmed into the license this year.
Corrib's gas is sweet and the reservoir geology is relatively simple, although seismic interpretation is hampered by the overlying salt layer. Prior to the latest well, Wood Mackenzie sized reserves at 1.2 tcf. As a possible outlet for the gas, Marathon may have in mind another new gas-fired plant it is proposing currently for a site in County Louth. The timing looks right, given the current liberalization of the Irish gas market.;
Dutch operators face changing market
In the Dutch North Sea, operators continue to announce small discoveries which are then developed fast track using ultra-low-cost unmanned platforms. HSM in Gouda has been working on two such platforms this year for Elf's L/4-PN and K/4B-E projects. Wintershall has invited bids for a 4,000-ton platform for L/8-P4. Clyde will likely follow suit once its Lower Cretaceous gas discovery Q/4-8 has been appraised.
According to analysts Wood Mackenzie, these and other new Dutch developments are profitable even below $3/bbl, making them the most economic in North West Europe. One reason is the abundance of processing and export infrastructure throughout the Dutch sector. This will be expanded further through the addition of a new trunkline bringing gas from Wintershall's A6/B4 development (the first offshore Germany) to the Dutch mainland - also tying in other discoveries en route in the northern Dutch North Sea.
The impact of the government's liberalization plans remains to be seen. Gasunie (50% owned by Shell and Exxon) is the Netherlands' dominant gas purchaser, distributor, and marketer, but under a European Union directive, will have to open its domestic markets shortly to competition.
Imports of UK gas (previously limited to Lasmo's Markham Field straddling the Dutch/UK median line) have been stepped up following 10 months in service of the Bacton-Zeebrugge Interconnector trunkline.
However, tariffs for access to Gasunie's Dutch transmission network have coincidentally risen, drawing accusations of anti-competitiveness. As further tie-ins are effected between trunklines stretching from Norway to the UK and to the northern European mainland, The Netherlands could emerge as the focus for trading in European gas markets. In anticipation, Gasunie has been toying with a second Interconnector from Den Helder to Bacton, via Shell's Corvette gasfield. The resultant access to new supply sources might, however, rebound on small field developers on the Dutch shelf.
The answer, says Wood Mackenzie, may be for the dominant players such as Shell to exploit the liberalization by expanding downstream. NAM continues to discover new volumes of offshore gas, which could be sold to the mainland in future by a new Shell-owned marketing division.
