OFFSHORE EUROPE: Future UK gas demand growth roiling waters for North Sea development

Map shows Thames area producing fields and undeveloped discoveries.

Britain's changing energy supply mix is creating incentives for natural gas field developers in and outside UK waters. Over the past decade, growth in gas-fired power throughout Britain has coincided with a decline in nuclear and coal-fired power. But existing gas production will not cover future needs.

A recent government report predicted that by 2006-2007, the UK would import up to 15% of its gas, compared with 2% at present. In anticipation, Statoil has signed an accord with BP UK Gas and Power to supply 1.6 bcm annually from Norwegian fields. Supplies will feed through the UK offshore transportation system from various sources, including the soon to be opened, Norsk Hydro-operated Vesterled trunkline.

Danish Oil and Natural Gas (DONG) has also held discussions with the UK government about supplying 2 bcm/yr through a new trans-North Sea pipeline from the Danish sector. In a further development, the owners of the Interconnector gas trunkline between Bacton, UK and Zeebrugge, Belgium are considering raising the current 8.5 bcm/yr import capacity to 20 bcm/yr, through installation of extra compression in Zeebrugge.

The UK government is partly to blame for the looming shortfall. One of the early acts after the administration entering office in 1997 was to rescind new applications for gas-fired power stations, in deference to supporters of Britain's beleaguered coal industry. That had the effect of stalling potential field developments in the southern North Sea, the most readily available supply source.

Brake on activity

Beta/Orca are located on the UK/Dutch median line.

Coincidentally, the oil price was tumbling, and BP, Amoco, ARCO, Exxon and Mobil - five of the sector's eight major players - were also merging and rationalizing their worldwide operations. That also put a brake on new field activity. A further blow, though not unexpected, came when the Aurora project team admitted defeat in their attempts to harness stranded gas in fields west of the Shetlands.

More positive recent developments include the emergence of a new production center for high pressure, high temperature gasfields in the central North Sea. Much of that gas, however, is heading out of the UK through the Interconnector.

Also, liberalization of Europe's gas markets has had the unintended effect of raising gas prices, rendering development more profitable. This is causing the southern sector camp to re-examine their dormant gas accumulations, backed by independent newcomers.

The most obvious example is the $294 million CMS III, launched by Conoco in June. Conoco's partners in this development are Gaz de France and Tullow Oil, both new entrants in the UK offshore sector. This project will harness 500 bcf of gas from the Boulton H, Hawksley, McAdam, Murdoch and Watt reservoirs via subsea wellheads and flowlines connected to the Murdoch Field processing platform. From there, the gas will move through the Caister Murdoch System (CMS) pipeline 115 miles to the Theddlethorpe gas terminal in Lincolnshire.

A separate accommodation platform and an additional compression module will also be built, the latter to be installed on the existing CMS complex. The enhanced compression will provide capacity for a future round of gas developments in the area. First CMS III gas is due to move late in 2002.

London-based Tullow Oil gained access to this development in February, as part of a £201 million package negotiated with BP. This also included southern sector assets in the Thames-Hewett area formerly held by Arco. The main attraction for Tullow was the highly cash generative producing assets combined with upside potential from appraisal and exploration opportunities, such as CMS III.

Other production

The Conoco-operated CMS interests includes 34% of the Murdoch Field and its associated infrastructure, which came onstream in 1993. Additionally, it gained 9.5% of Boulton, which produces through a single well from a minimal facilities jacket, tied to the Murdoch installation via a 10-in. flowline. Thirdly, Tullow secured 17% of the CMS trunkline system handling gas from the CMS fields plus Shell's Ketch and Schooner fields to the south.

Last month, a horizontal well was due to be drilled from the Boulton platform to appraise the deeper-lying, gas-bearing Carboniferous sands encountered on an earlier well on the Boulton F structure. If successful, that well could be onstream by October. There are further exploration prospects in the area, which could ultimately form the basis for a possible CMSIV development.

Development activity is slowly picking up across the southern sector, with BG preparing for a second, multi-field project in its ECA Catchment Area, and BP commissioning a platform on Hoton following an anonymous spell as operator in this region. In Conoco's case, having two new ambitious partners probably helped in getting CMS III off the ground, according to Tullow's Finance Director Tom Hickey. "We came in as highly supportive of CMS III, and believe it is an example of the type of opportunities that will arise in this area over the coming years."

According to John Lander, Managing Director of Tullow Exploration, "Our view of the southern gas basin as a whole is that in the years leading up to 2000, gas prices were consistently low, at around 10p/therm, so there was no incentive to explore. In Arco British's particular case, they also had no budget because of the uncertainty over the company's future direction. This has meant that the area has been underexplored in recent years."

Sub-salt picture

However, perceptions are changing, he claimed, following the application of high definition 3D seismic over the basin to provide a clearer, sub-salt picture. This has improved the success rate of discoveries within the key Rotliegendes and Carboniferous horizons, mostly in the range of 80-100 bcf. "But I wouldn't rule out future larger discoveries - particularly in the Carboniferous, which needs more exploration."

Tullow sees strong exploration potential across its new Thames-Hewett acreage, spread across 13 separate licenses. This includes the Phillips-operated Hewett complex, the Thames group of fields, six undeveloped discoveries and numerous other exploration leads. "Hewett has been in production since 1967," Lander says, "producing from the most typical reservoirs you'd expect in the southern gas basin - except the Carboniferous. There is potential, however, for Carboniferous discoveries in the area."

Phillips, the Hewitt fields operator, had adopted a low-key approach to this area in the past, but it will drill a new development well shortly to tap possible undrained gas in the Little Dotty satellite identified by the latest seismic technology. This data has been available for a couple of years, but no one looked at it, Lander claims, because gas prices were low. "There are other potential exploration targets in several geologic formations showing up on the seismic in the Hewett area, with another interesting feature that could be drilled as early as the end of this year."

Tullow will be 80% operator of block 48/23a to the northwest of Hewett, which includes Arco's Rotliegendes Blythe discovery from the early 1990s. "This was one of the first horizontal wells drilled by Arco, but it didn't produce any more gas than the vertical well, suggesting formation damage. In-place gas looks to be 70-100 bcf. But there is also complex overburden in this area, which has made structural definition at the reservoir level difficult to ascertain in the past. Hopefully the new seismic will clear this up." If developed, the gas could be piped to Hewett or to infrastructure to the north of the field.

Lander sees key enabling techniques for marginal southern gas basin developments as advanced 3D seismic processing, and well completion technology, such as under-balanced drilling to avoid reservoir damage and fracturing of horizontal wells. "We also want to import the latest logging techniques to help identify any reservoir problems."

Tullow had hoped to operate the entire Thames complex, but the vote among the other partners went in favor of ExxonMobil, presumably on the basis that it was better equipped to operate as an already established operator in the southern North Sea.

Tullow did secure operatorship of block 49/29c, adjacent to the Thames Field, and of 53/4a, containing the Wissey discovery. It also gained equity in Enterprise-operated blocks housing the Rotliegendes Horne and Wren discoveries - "we need to get after these," says Lander. Tullow will also look at the high carbon dioxide content discovery in block 50/26b. One option could be to pipe the gas to one of the Dutch sector platforms, close to the UK median line, which are better equipped to treat carbon dioxide.

Another new company considering cross-border development is Consort Resources, formed in July 2000, when it acquired TotalFinaElf's 49% interest in the Caister and Hunter gas fields, 24.5% interest in CMS and a subsequently discovered 12.25% interest in Murdoch K, which Consort has recently sold to Conoco, GDF, and Tullow in order to facilitate the CMS III development. Last December, Consort bought TotalFinaElf's and TXU Europe's operating interests in the Orca and Beta discoveries straddling the UK/Dutch median line. Earlier this year, Consort acquired all of TXU Europe Upstream, including its 64.20% operated interest in the Johnston gas field in blocks 43/26a and 43/27a. That deal also included various other interests in producing fields, plus 30% of the Esmond/EAGLES Transportation System.

According to Consort's Group Managing Director Jonathan Legg, "Unlike the other independents new to this area, which are exploration and production companies, we are purely a gas company. We are focused specifically on the southern gas basin, because it offers the securest and lowest cost source of gas for Western Europe ellipse where we see continued growth in demand, especially for gas-fired power. Also, the Consort team has a great deal of experience in this region. John Willis and I worked for Conoco for 15 years."

Cheaper locally

Compared with planned schemes to import Russian, North African, and Norwegian gas, southern basin gas is cheaper in terms of the supply chain, he claims. "The Interconnector pipeline is the motorway to Europe. Also, it was an initiative of our co-founder, ex-UK Energy Minister Colin Moynihan. Post-Interconnector, we believe there is a lot of scope for further interconnections to UK and Continental systems from existing North Sea infrastructure."

Orca and Beta were discovered in the early 1990s, with Beta situated 10 km to the north. It is also 10 km west of the NAM-operated D/15a-FA development in the Dutch sector. Orca is also believed to extend across the median line. Both are Carboniferous reservoirs, with combined recoverable reserves estimated at 466 bcf.

Between them, they overlap three UK and two Dutch blocks, and this has hindered development until now. "There were a lot of partners," says Legg, "and it was difficult to get progress. Over the last year, through various transactions, we've succeeded in whittling down the number of partners by half, and we now expect the project to be onstream in late 2003." The latest to leave was Petrobras, which recently sold its UKCS interests to Enterprise Oil.

Both fields could be developed through conventional minimum facilities platforms with horizontal wells, or there could be one platform on Beta with a subsea tieback to Orca. Offtake options remain open. Given the location, the traditional approach would be to put in a single pipeline for both fields, Legg says, or to lay a line to Lasmo's Markham processing complex. "But given where the gas is, and the opportunities in Europe, we have other plans."

Gas could be sent both to the UK, through a connection to the CMS system 20 km away (Consort has a 24.5% stake in this system) and to D15a-FA 15 km to the east for export through the GDF-operated NGT trunkline that lands at Uithuizen on the Dutch/German border. "We could also create a new hub in this area linking to fields in the Dutch, Danish and Norwegian sectors."

Equities in the UK blocks have been agreed, with Consort holding 25.92%. Now Consort is aiming for similar closure on the Dutch blocks. No end-users are lined up for the gas. This is the responsibility of Dynegy Europe, which recently agreed to handle downstream marketing of all Consort's gas and liquids production. "We're not fixed on customers - we will sell the gas when the fields are onstream," Legg claims. "Vast amounts of gas in the southern North Sea have been developed over the past seven years without long-term contracts.

"Once development is sanctioned, we would expect first gas 18 months later. One field will probably come onstream before the other." Plateau production will probably be 160 MMcf/d. There are also several exploration prospects that could be drilled - "once the hub is in place, there will be every incentive to exploit them," he says.

Venture diversifying

A third new southern sector operator is Aberdeen-based Venture Production Company, which last December bought Phillips' equity in three blocks containing the producing Audrey, Ann, and Alison fields. In February, it also acquired TotalFinaElf's interests in this area, leading to operatorships of acreage including Ann and Alison.

Venture's previous UK North Sea acquisition was Lasmo's operated interest in the Trees blocks, containing the Birch and Larch fields, both subsea tiebacks to the Brae complex. Venture proved its expertise as an operator here through drilling a new water injection well and completing a major workover on the Larch production well. Prior to the A-fields deal, its worldwide portfolio was effectively 95% oil, according to Finance Director Mike Wagstaff. "We had very little exposure to contracted gas production - we wanted diversity, for reasons of economic hedging. Also, in the North Sea we were dependent on a small number of wells and one processing/transportation system. The A-fields give us more wells and a diversified asset base. They also give us significant current production and cash flow, and longer-term infield and satellite production potential."

Audrey has been developed through the 12-slot steel 'A' platform to the south of the field and the six-slot 'B' wellhead platform, three miles to the northwest. Both platforms are controlled from Conoco's V-fields complex. Gas from Audrey is piped 16 km to the Valiant North platform before feeding into the Loggs export system. Ann employs a subsea template controlled via an 18 km umbilical from Audrey B, with two production wells, while Alison features a single tri-lateral subsea well tied to the pipeline connecting Ann's gas with the Loggs riser platform. The three fields' combined production will likely average 70 MMcf/d this year, according to Wood Mackenzie.

Wagstaff says there is undrilled potential on Audrey, but adds that it is not unusual for companies to sit on their acreage in the southern sector, due to the market's recent history. "Until 10 years ago, there was only one gas buyer, British Gas, that was driving the development of new fields. Then there was little interest in developing smaller discoveries. As the gas market has opened up, it's only in the last two years that people have seen a future scenario of surplus demand."

Field viability

Currently, Audrey is scheduled to stay in production through 2006-2007, based on managing the current decline (with no added investment). Ann and Alison would also be abandoned at the same time. "The clock is ticking, and it's a finite runway for new investment," Wagstaff says. "We would rather do the life-extension work sooner than later. Phillips hasn't done a lot of work on these assets of late, but there are a number of commercial factors which have precluded investment."

"There is potential to sidetrack existing wells, with recompletions." Annabel in block 49/11a, operated by Agip, offers the greatest potential from Venture's point of view. "We plan to drill an appraisal well here later this year - there was a discovery on an adjacent Conoco-held block which we think extends into ours. The problem - as always with the Audrey area - is seismic imaging below the salt." The field has potential to contain several hundred bcf, he says, with Loggs as one of the possible export options. If Annabel is to be developed, it could be as part of a cluster including Amy and Conoco's Argo in 48/9a.

"We don't have better technology than the majors," he says. "We appropriate the technology that's most cost-effective. For example, there's no point putting down equipment designed to last for 30 years if the field only produces for two to three years." Venture is not interested in owning transportation infrastructure - "we're upstream, not midstream. We want to sell production as close to the wellhead as possible."

But it is interested in further acquisitions in both the central and southern North Sea. "We're trying to put together an inventory of short, mid-term, and long-term drilling prospects. Ideally, we would like an inventory that would keep at least one rig drilling full time, because that is the most effective way to drill. Having said that, the North Sea market is a lot tougher to make acquistions than it was two years ago, with most companies buyers, rather than sellers."