Rising oil prices have so far had little impact on North Sea activity. Exploration drilling remains depressed in all sectors, while development in the UK is virtually dormant. However, governments across the region are attempting to break the impasse through more favorable licensing and trading conditions. - Artist's impression of the Grane platform, a rare new giant in the Norwegian North Sea.
Change is on the way in Norway. A number of important policy initiatives have been proposed in a white paper issued by the Labor government in June, which are expected to be approved by the Störting, the country's parliament, before the end of the year. The following are among the proposals:
- Störting approval will be required only for field development projects involving a capital investment of NKr 10 billion, rather than the current NKr 5 billion. This will mean that more projects will require only ministry approval, leading to faster approval times.
- Licensing rounds for acreage in the Norwegian Sea, which still offers exciting exploration potential, will be held every two years; an annual round for acreage in the mature North Sea is already held annually. Applicants will be able to form their own groups, instead of being allocated to groups by the ministry.
- A pre-qualification system for license applications will be established to lessen the documentation required in each application.
- A wider range of companies will be allowed to apply for license interests. At present, such interests may be held only by companies fulfilling strict qualifications concerning their upstream status.
- Procedures for trading and exchanging license interests will be eased.
"The measures will strengthen competitiveness on the continental shelf such that oil companies will still find it attractive in the future to develop new fields in Norway," said Oil and Energy Minister Olav Akselsen. "The main message in the white paper is that this is an industry we wish to commit ourselves to, and which has a future. The government will create the conditions for further developing the valuable expertise that has been generated in Norway's oil sector, and secure work and jobs in the supply industry."
The measures put forward in the white paper have been widely welcomed by the industry, which has long called for substantial change if Norway's offshore sector is to remain attractive to foreign investment. Some concrete steps have already been taken. The government has approved Danish company Dong's acquisition of Statoil's stake in the Trym Field, having previously turned down such applications. It is also considering the first license application from a contractor, Aker Maritime, which jointly with German oil company RWE-DEA has applied for Block 35/3. The block contains the Agat gas find. - Shell's ultra-minimal Skiff platform at Lowestoft Port prior to its recent delivery to the southern North Sea. More low-cost platforms this size are expected to feature in the coming years.
What is state's role?
What is lacking in the white paper, however, is any discussion of the most important issue - the prominent role played by the state in the country's oil and gas sector. The government had intended to propose that state-owned Statoil be partly privatized, and that some of the state's direct financial interest (SDFI) be sold off. But at the last moment, opposition in the Labor Party's own ranks forced it to stay its hand until the party debates the matter at its national conference in October.
The issue is one which has clearly split the party, between the free market advocates which dominate the government and the supporters of a traditional state interventionist line. It had been presumed that the "progressives" held the upper hand, but the sudden upswell of opposition in May has muddied the waters. Even so, it will be surprising if some measure of privatization is not developed.
As Prime Minister Jens Stoltenberg was quick to point out, matters may not be delayed by more than a couple of months, as the Storting would anyway not have begun debating the issue before it reconvenes in October. Any delay was to be regretted, in the view of Statoil's Chairman, Ole Lund, and its Chief Executive, Olav Fjell, who strongly favor privatization, and also would like to take over as much of the SDFI as possible.
Fjell claimed recently in London that the merged company would be a top 10 major, similar in size to ENI and with total reserves exceeding those held by TotalFinaElf (although the bulk would be on the Norwegian shelf). "I think we should get 100% of the SDFI's assets," he said, while admitting that a 100% merger would be highly unlikely. Whatever happens, he added, the SDFI shares should be put to commercial use.
Ramco Energy has been awarded licensing options for prospective acreage in Ireland's Donegal and Celtic Sea basins.
"Average ownership in Norwegian licenses is 16%, compared with 40% on the UKCS. On Troll, we are operators, but with a 12% stake only. If we manage to save NKr100 million on operating costs, the state takes 78% in tax. The rest gets distributed to our field partners, so we end up with just NKr3 million. However, if the operator had 40%, and the other partners also had bigger shares [at the state's expense], we could take more actions towards running our assets more efficiently. Ultimately, it's more important that SDFI's assets get commercialized than that Statoil gets them all."
Tax system
Meanwhile, adjustments to the tax system have been proposed by a commission set up by the finance ministry. These include changes in allowance provisions to prevent companies subsidizing uneconomic investments, and better financial incentives for new entrants to Norway's offshore sector. The proposals were criticized by oil companies, which would like to see the abolition of the 50% special tax to which the offshore sector is subject.
An important indication of changing attitudes in Oslo came in April with the award of new licenses in the 16th round. These were made by the previous centrist party coalition government, but in terms of general oil policy, there is not a lot of difference to be perceived between the two governments. Of the 14 new operatorships, four went to BP Amoco, three to Norsk Hydro, two to Statoil, and one each to Agip, Chevron, TotalFinaElf, ExxonMobil and Shell. There were certainly no claims of favoritism towards Statoil, which let it be known it was disappointed. The "hot" block, 6406/5, which holds the promise of substantial gas/condensate reserves, went to Shell. The SDFI's share in the round was fairly modest - it was given stakes in eight licenses, for the most part of 20-30%.
Exhausting lease potential
Oil and Energy Minister Olav Akselsen proposes changes to maintain the Norwegian continental shelf's attraction for oil companies.
All the 16th round acreage is in the Norwegian Sea, some of it in water depths up to 1,800 meters. Exploration success is vital, as most companies have exhausted the potential of their existing licenses, and there are only a few large fields in the future development portfolio, notably Halten Bank South and Ormen Lange.
The hiatus in new development projects occasioned by the 12-month freeze imposed by the previous government in 1998, just as oil prices were about to collapse, came to an end this year. Five projects are underway, ranging from Norsk Hydro's NKr 15 billion development of the 704 million bbl Grane Field to BP Amoco's NKr 800 million development of Tambar (40 million bbl). The others are Statoil's Kvitebjørnørn, ExxonMobil's Ringhorne, and BP Amoco's Valhall water injection project.
All require fixed platforms, a matter of some relief to the work-starved fabrication yards. By mid-year, contracts had been awarded to Kværner (Grane process module, Tambar platform), Umoe (Kvitebjørnørn deck), Aker Verdal (Kvitebjørnørn jacket), and Leirvik Sveis (Kvitebjørnørn living quarters), and more were in the pipeline. Once all this work has been placed, the fabrication sector will be working to about 70% of its capacity. Demand in the longer term is only moderate, so it remains to be seen whether all the yards can survive in their present form.
The latest forecasts from Statistics Norway, which are based on consultation with oil companies, do not make cheerful reading. Overall investment in the offshore sector in 2001 is estimated at NKr 33.6 billion, down from NKr 51 billion this year. In 1999 the figure was NKr 69.1 billion. All forms of activity - exploration, field development, production operations, onshore operations, and pipeline transport - are heading for a decline in expenditure. But worst hit is field development, where the spending is forecast to fall to NKr 13.6 billion from this year's NKr 22.7 billion. Production operations, with a spending of NKr 16.1 billion, will become the leading investment area, a sign of the Norwegian continental shelf's growing maturity.
The plunge in field development spending is partly a reflection of the fact that a number of projects have been, or will soon be, completed. This autumn, gas production gets underway on Statoil's Åsgard Field in the Norwegian Sea, where last year saw the start of oil production. Cost overruns on Åsgard have regularly drawn sharp criticism in the Störting and the country's media, but oil production of around 200,000 b/d and gas exports of some 10 bcm/yr should soon make the project very profitable.
Also in the Norwegian Sea, a large expansion program on Statoil's Heidrun Field will be in place this year, and gas from Heidrun, Statoil's Norne and Norske Shell's Draugen will start being exported through the Åsgard Transport System. Shell is to implement a NKr 3 billion investment program at Draugen, involving two small subsea tiebacks and further development of the main field.
In the North Sea, Norsk Hydro brought the second stage of development of the Troll oil reserves on stream late last year. Troll, whose thin oil layers were once thought to be unproducible, is now the single largest oil producer in the Norwegian sector, with output in excess of 300,000 b/d, as well as the largest gas producer. Later this year, Hydro's Oseberg South platform will come on stream, and in October the main Oseberg Field is due to start exporting gas. The subsea development of the satellite Tune Field is underway, with startup due in 2002.
Developments are also taking place around the other main North Sea fields. At Statfjord, where Statoil last year brought on stream the northern flank, the Sygna Field is due to start up in August - both are subsea tiebacks. And at Statoil's Gulfaks South, where oil production began last year, preparations for gas production next year are proceeding. These projects involve subsea facilities tied back to the main field. Also in the Gulfaks area, Statoil is developing the Huldra Field with a wellhead platform, from which gas will be sent to Hydro's Heimdal platform for processing when startup takes place next summer.
Development activity also remains high at ExxonMobil. Having brought onstream its two floating production, storage, and offloading (FPSO) vessel projects, Balder and Jotun last year, the company is now preparing to tie Ringhorne back to Balder. In the southern North Sea, Phillips has implemented a waterflood project to increase oil recovery on the Eldfisk Field, while in the Tampen area, the Snorre North project continues on track for startup next summer with a floating production platform. The field is now operated by Hydro, Saga Petroleum's name having vanished from the North Sea this year.
Slow UK revival
Exploration drilling on the UK continental shelf last year sank to its lowest level since 1965, according to the latest review from the Department of Trade and Industry (DTI). Only 16 exploratory wells were started, compared with 47 in 1998. Analysts Wood Mackenzie foresee an upswing this year in both exploration and appraisal drilling, but only to 75% of 1997-98 levels.
Corporate gamesmanship may be partly to blame. Around 44% of licensed UKCS blocks are held by the big four oil companies, Wood Mackenzie points out, three of which have undergone mergers. As a result, significant tranches of their acreage have effectively been removed from the partner approval process. This iron grip frees them to focus on larger geological structures elsewhere in the world. The same also applies to other prospective North Sea areas, where various independents' drilling ambitions are also being thwarted.
Most new UK wells this year have been drilled in the play-safe, infrastructure-intensive plays of the Central North Sea. Six operators have chanced their arm with deepwater wells west of Shetland, but results so far are not encouraging.
There is no indication, however, of the long-threatened pull-out by the establishment. BP Amoco and Shell have re-affirmed their commitment to sustaining their UKCS production levels. Exxon-Mobil was thought to be bartering the Beryl production complex, but a major new subsea scheme has just been approved to develop the Skene Field to the south, via a manifold linked to the Beryl A platform.
A survey of 22 member companies by the UK Offshore Operators Association (UKOOA) suggests a slight increase in UK development spending this year to £3.5 billion (still way below the £5.1 billion invested in 1998). However, the picture brightens over the next three years, with UKOOA anticipating up to 25 new production platforms, half being minimal southern gas basin facilities. There could also be 68 new subsea tieback clusters over the same period, it adds, but only one FPSO (this may be overly pessimistic).
Scottish Enterprise is a little more upbeat, predicting total spending on exploration, appraisal, development, production and decommissioning on the UKCS of £42.4 billion over the next six years. Its forecast is based on a constant $16 oil price scenario, modeled using newly developed software. Half the total capital spending outlay will go towards development drilling, it predicts, with higher expenditure on well servicing.
Field development has slowed most notably in the southern gas basin, coinciding with curbs on new gas-fired power stations. These were imposed by the incoming Labor government in 1997, which was concerned at the potentially detrimental impact of gas on Britain's coal industry. Only two of 10 new gas-fired schemes have been approved of late - one for industrial South Wales happened to coincide with Welsh Assembly elections.
The government has now decided to lift its 'stricter consents policy', although the change may not come into effect before April. A blitz on applications has already started - Wood Mackenzie believes that three to five projects totaling 2.3 GW capacity may be put forward for an immediate start. These could raise North Sea gas demand by 250-375 MMcf/d. The irony is that recent oil price indexation by gas traders has lifted UK spot prices to standard European levels at around 2.2 p/kWh. So while field developers may be inclined to put in more platforms, the utilities may be harder-pushed to sell the economics of the new schemes. Indexation, which is routine in other parts of the world, could also defeat European Union plans to liberalize the continent's gas markets. According to London-based analysts Primark, the producers could enforce a price stranglehold which the EU could do little to break.
Independents raise stakes
Wood Mackenzie estimates in another study that there are 246 UK fields in production or under development with remaining reserves totaling over 13.7 billion boe. In addition, there are 34 probable developments totaling 7.2 billion boe, plus around 270 technical reserves.
Mature acreage across the North Sea continues to attract the smaller players. In Norway, this year, DNO has acquired stakes in Statoil's Glitne and BP Amoco's Tor developments, while Pelican picked up 15% of BP Amoco's Tambar, soon to be exploited through the declining Ula Field facilities. Both these independents eye operating roles on the Norwegian shelf, outsourcing production management duties to contractors such as PGS or Brovig.
On the UKCS, Wintershall is to sell its southern gas basin portfolio to a new specialist in this area called Highland Energy. The package includes a 6% operated interest in Windermere, which produces through a wellhead tower exporting to Lasmo's Markham platform. Highland is also negotiating for Statoil's southern sector interests, which include a stake in Conoco's Victor.
This May, Aberdeen-based Venture Petroleum assumed its first North Sea operating role when it acquired Lasmo's Trees fields interests. Venture plans to boost production at Birch and Larch (both tiebacks to third party platforms) and to review options for five other 'stranded' prospects shelved by the previous regime.
The newest entrant in the UK North Sea is Westoil, a Glasgow-based company backed by local investment groups. Its portfolio at present comprises the UKCS assets of Cultus Petroleum, acquired this April from Cultus' parent company OMV. The key component is a 6.7% share of the Kerr-McGee operated Hutton Field, plus the adjoining oilfield Q West. The net monthly yield to Westoil is around 20,000 bbl.
Hutton has been in production through a TLP since 1984. Output peaked at 75,000 b/d, but now stands at 10,000 b/d. Ongoing life extension measures may prove futile beyond 2003 - in anticipation, the partners are looking to sell or lease the field for use elsewhere. There have been enquiries from various parts of the world according to Westoil Director Laurence Grainger - "it's an extremely heavily engineered structure," he points out.
Westoil brought in Alan Mathison, ex-Mobil, to handle all oilfield planning issues alone. Technical services are outsourced as and when required. The operation run by Cultus was based in large offices near London with high overheads. Westoil has cut these by 65% through the move to Glasgow.
The company has no pretensions to become an operator, Grainger says, although it is looking for further farm-in opportunities. "Our objective is to achieve profitability, cash flow, and expansion - but not at the expense of our shareholders. A lot of small oil companies have gone wrong by getting themselves onto a growth roller-coaster - once on, they can't get off. They bring in too many people with too many aspirations, so the only way forward is to grow. But there are times when consolidation should take place.
"We could work with other oil companies regularly in the North Sea, but for smaller companies our size, there should be a far greater impetus to keep production going. The North Sea can be a profitable are for smaller companies for many years to come, as long as they stay small and don't acquire big company overheads."
Dutch tracking northwards
Drilling last year in the Dutch North Sea led to seven gas discoveries, according to the Energy Ministry. One, operated by Wintershall in northern block A15, tested 24 MMcf/d from shallow sand horizons. It is thought to be the sector's biggest gas find for 20 years, although appraisal is being hampered by overlapping acreage considerations.
The ideal outlet for the gas would be the new NOGAT trunkline extension heading north from F3 to German block A6, to carry supplies from A6/B4 (Germany's first offshore gas development). Another beneficiary of this line could be the G17-4 discovery, drilled last winter by TransCanada and Gulf Canada, which tested 40 MMcf/d from a Bunter formation. The gas could alternatively be evacuated through the NGT trunkline, which TransCanada operates - the snag being that TransCanada wants to exit the Dutch sector. Another independent will likely take on TransCanada's assets - probably an established player, rather than Vanco Energy, which this year declared its intention to operate in the Dutch North Sea for the first time. To this end, it has set up offices in Delft, headed by Piet Velzeboer as Managing Director.
Vanco has participated in the Dutch offshore sector since 1973, when it acquired 25% of Tenneco's interests on the shelf. Its intention this time is to concentrate on development of small marginal prospects, perhaps including fields already in production. "Some oil companies consider anything less than 50 million bbl stock tank oil in place as their cut-off point," says Velzeboer. "Our profitability threshold is 10-15 million bbl recoverable.
"Our philosophy is to minimize our overheads and staff, using consultants to fill skills gaps. But the contracting industry must also get used to a low cost, innovative approach.
"Our view is that small field work in the Dutch sector will have to be incentivized. You can't expect the contractor to take on the major risk with little incentive. But we could also align with companies like PGS, Schlumberger or Halliburton and make up the operation expertise.
"The challenge with marginal field developments is that if you make one mistake, you can quickly go broke. Our philosophy is that you need to go for tried and trusted methods, both in the drilling and production of wells. We're thinking in terms of reusable platforms with a field life-span of three to five years to develop two prospects in sequence. In this regard, we are talking to companies with platforms about to be "released." The difficulty is, you never know exactly when. We would like to end up with a portfolio of six fields developed sequentially - as you also have to allow for the fact that one field may not perform."
Vanco is formulating a five-year plan to see what is available not just in the Dutch sector, but also the rest of the North Sea.
The company has designs on two license areas in open Dutch blocks. It was formerly a partner in the drilling program for one of these structures, which means it has access to key data. Vanco is attracted by the beneficial tax position for overseas companies in The Netherlands, Velzeboer says. "The government here encourages the development of marginal fields - otherwise, you must relinquish them." - Map shows location of Danish North Sea discovery/appraisal wells in 1999.
Ireland's Corrib at standby
In Ireland, Statoil has committed to invest in a new gas-fired power plant in Dublin Bay, and is also a partner in the Corrib gasfield, 70 km off the island of Achill in Western Ireland. This 1 tcf-plus prospect, still undergoing appraisal, will shortly become Ireland's first offshore gas development since Marathon's Kinsale Head in the 1970s. Liberalization of Ireland's gas market is driving the project.
A further flurry of development activity is possible in the North Celtic Sea. Semisubmersible Diamond Offshore is currently appraising the Helvick reservoir for new operator Providence Resources. In the same basin, Ramco Oil & Gas has a licensing option for blocks including two prospective discoveries, Seven Heads and Galley Head. Both lie within striking distance of the Kinsale Head infrastructure.
Galley Head is a gas discovery drilled by BP in 1985. Seven Heads, discovered by Esso in 1974, contains reserves estimated at 5 million bbl and 100 bcf, but Ramco's new seismic gathering/re-evaluation program could identify much larger volumes from this faulted reservoir. Ramco has also taken up an option for blocks in the Donegal Basin off north-west Ireland, thought to contain a potential gas play.
Faroese prospects
Further out into the Atlantic Margin, the best prospects may lie in Faroese waters. These will be opened for exploration for the first time in September, when the Faroese Ministry of Petroleum issues awards relating to February's licensing round, for which 17 companies submitted bids. There were some high-profile abstainers, notably Exxon-Mobil, Shell, TotalFinaElf and Maersk.
Licensing had to be delayed for several years until a dispute over the UK/Faroese median line could be resolved. The blocks and part-blocks most in demand lie close to this line, across from BP Amoco's producing oilfields west of Shetland.
In the Danish sector, oil production last year set a new record of 17.36 MMcm. The total in 2000 should climb further to 21.7 MMcm, according to the Danish Energy Agency, as water injection boosts output from the South Arne Field.
Halfdan, the major Danish oil and gas discovery of the past two years, is currently under development via a wellhead platform with nine wells, exporting through the Gorm/Dan complexes. Halfdan's oil is contained in porous chalk layers, but the oil zone is not a structural closure, unlike the neighboring Dan and Skjold fields.
1999 also yielded successful appraisal wells for Maersk on Tyra South East (oil) and Igor (gas), while to the west of Igor, and exploratory well on the Sif prospect established the presence of gas in the chalk. Applications have been lodged to develop Sif, Tyra South East and and another oil/gas field west of Skjold named Lola.
The high discovery rate has not been sustained this year, but the sector retains its appeal, particularly for small American independents. Last year, acquisition of 3D seismic over Danish waters hit an all-time high, with major programs over the Ringkoebing-Fyn High.
