Ranks of North Sea producers lured by productivity gains

Chevron/Conoco's Britannia 21,000-ton substructure prior to towout from the Dragados yard, Cadiz via the Intermac 627. After this project, Chevron UK sees its future more in Norway. [22,040 bytes] S7000 installing the jacket for Saga's Varg development, one of the platform/floater combos currently in vogue in the Norwegian sector. [61,872 bytes] BP's ETAP central platform jacket under construction at Barmac, Ardersier in Scotland is one of several major new UK Central North Sea

New development technology, asset management boost prospects

Jeremy Beckman
Editor, Europe
Deepwater exploration may be the answer to the looming world oil shortfall, but in northern Europe of late, the impact has been slight. The one new province proven up this year, in Mid-Norway's Voering Basin, looks heavily gas-prone.

With an already huge backlog of Norwegian gasfield developments to clear, this is good news for Albanian plans for gas-fired power circa 2013. For oil watchers, it knocks another hole in the North Sea's supposedly shrinking mystique.

Yet for all the disappointments, only one major player, Unocal, has departed the sector this year. In its place have come a host of bit-part players from North America and Japan seeking swift entry into ageing and minor oilfield properties.

At the upper end of the scale, acreage trading has been white-hot as the majors realign their barrel interests in the Norwegian and UK sectors. The whirl of activity is having a positive impact on field developments, with many projects going forward that might otherwise have festered.

Asset managment

June brought a flurry of deals, most involving Statoil. The Norwegian giant swapped acreage with six oil companies to strengthen its position in its five declared core areas in Norway, as well as building its presence in promising UK fields. An exchange with Texaco, for instance, yielded Statoil further equity in the potentially large Bressay heavy oil accumulation east of Shetland.

Chevron, the operator of Bressay, meantime dealt Statoil 12% of its UK North Sea Alba oilfield, equivalent to 36 million bbl. Phase IIb of this development, boosting fluids handling capacity by 60%, has since been approved. In return, Chevron regained access to the Norwegian sector, which it had exited in the late 1980s. Chevron received interests in five exploration licences, four in Mid-Norway, plus over 7.5% of Norske Shell's productive Draugen oilfield.

Ceding a piece of Alba was a wrench for Chevron, this being one of its two core assets in the UKCS. But it needed growth prospects elsewhere, hence the gamble. Chevron now plans to spend $33 million annually in Norway. Statoil's other swaps with Elf Norge, Norsk Hydro and BP have netted it bigger stakes in its core development areas around Sleipner, Gullfaks and Statfjord. It has also fortified its toehold in the UK gas market through a higher percentage of Conoco's Jupiter gasfields.

As analysts Wood Mackenzie point out, despite these transactions, Statoil appears little nearer its goal of achieving worldwide production of 1 million boe per year by 2005 - in fact it shed 40,000boe (prior to the Texaco deal) in exchange for 20,000 boe. But there is potential now for adding much higher gas reserves. It is better placed, for instance, to advance development of its Kvitebjoern prospect through the Gullfaks infrastructure.

Bartering on a lesser scale has also become commonplace among the UK sector leading lights. The upshot is that some shelved field discoveries such as Amoco's Halley (1981) and BHP's Babbage (1989) could at last go forward as subsea tiebacks to platform complexes, respectively Shell's Fulmar and BHP's Johnston.

A common theme of these changeovers is that money does not talk. For some minor North Sea players, this can be frustrating. Ranger Oil UK, for instance, is known for its Anglia Southern Gas Basin stronghold. The firm had been looking to strike out as an operator further north, and had an opportunity as a stakeholder in the Pierce FPSO-based development when BP decided to sell. However, Enterprise Oil had more attractive acreage to offer BP, and thereby emerged the winner.

Cash on a vast scale will not be turned down. Saga is thought to have paid somewhat over the odds to land Santa Fe's North Sea assets. But the range of exploration acreage it gained along the Atlantic Margin will, in Saga's view, best advance its prospects of joining the major ranks.

Another route into the North Sea for first-timers is to buy up promising independents, as Gulf Canada did this year with Clyde Petroleum, which had a tidy portfolio of small oil and gasfields in the Dutch and UK sectors. The other approach is to take over management of tail-end projects from want-away operators, as Oryx did with Chevron's Ninian. The new owner is deriving some short-term value from the Ninian complex via successful infill drilling.

Trending to FPSOs

Generating cash from production is still acceptable, and floating production is viewed increasingly as the way to do it. British analysts Infield Consultants have identified over 40 possible/probable such developments in the North Sea (see accompanying table in this article).

Methodology differs markedly in the two main continental shelves. In the UK, fast bucks from short-term production are favored, normally via an FPSO. To cut costs, this will preferably be a converted tanker, owned and also managed out in the field by the contractor. The latter can then be penalized if production targets aren't reached. With conversion timescales increasingly tight (less than a year), these targets are getting easier to miss.

Some contractors are taking the view that the clauses are too restrictive. Others welcome the opportunity to sell their vessel on to another buyer after six years or so service on one field. PGS is taking the process a step further by adding reservoir monitoring for the Banff Field, in addition to its Ramform FPSO.

The danger is that as natural field life dwindles, the contractor is left with a loss-making pile of over-sized, underused process capacity on the vessel. PGS and Conoco are planning for this eventuality by already arranging third-party tie-ins, possibly from Ranger's Kyle prospect, as Banff comes off plateau. Going the other way, some designers are leaving room to step up processing on the vessel to meet the needs of a phased devlopment. Texaco's Captain FPSO, for instance, may move from 60,000 b/d to 100,000 b/d when a new area of the reservoir is exploited shortly.

Several oil companies are now testing the waters for FPSOs, such as Talisman (Ross) and Enterprise (Pierce). However, this solution is not to everyone's liking, even among pioneers of these units. Amerada Hess, for instance, is keen on a floater for a recent oil find that extends into acreage owned by Shell - hence the current dual name of Abbot/Razorbill. Shell, however, would prefer a new bridge-linked platform to its Gannet A facilities. In other instances, field partners have clashed over the economic merits of a floater versus a subsea tieback.

New FPSOs in Norway tend to be for much larger oil and gas fields, and consequently have longer lead-times for construction. This has not stopped delays in delivery from the building sites in the Far East, impinging costs of Esso's Balder FPSO and others. Topsides installation times seem to have been underestimated.

Perhaps for this reason, Esso is having the Jotun FPSO built by Kvaerner Masa-Yards in Finland, with the topsides to be installed by Kverner Rosenberg in Norway. Statoil's Norne FPSO turret and process facilities have been transferred to Aker Stord, also in Norway.

Jotun is a three-field development with estimated oil of 195-275 million bbl and over 65 bcf of gas. In this case, a fixed wellhead platform with 19 wells will handle production, with the 600,000 bbl storage vessel providing processing at a rate of 90,000 b/d. Saga's Varg is also large enough to warrant a platform linked to its FPSO.

The production semisubmersible too is making a comeback, even though most North Sea operators prefer onboard storage. Norsk Hydro got round the problem with a dedicated floating storage unit on its Njord development. Giant new semis are under construction for the Aasgard and Troll C developments, while in the UK, Texaco is converting the semi Emerald Producer for duty on its much smaller Galley project.

Drilling prospects

In line with world trends, drilling activity across NorthWest Europe is buoyant. According to Arthur Andersen, appraisal drilling during the first half of 1997 in the region was 64% up on the corresponding period last year. That gain offset a 14% decline in exploration wells over the same period, while still yielding at least 10 new discoveries.

In the UK, the line was led by British Gas' oil find in Moray Firth block 13/24 which could contain 100-200 million bbl. But most efforts have been targeted close to existing infrastructure. Marathon's oil strike west of Brae has not been officially sized, while Total's hit south of Alwyn North tested nearly 18 MMcf/d of gas and 1,000 b/d of condensate.

BP Norge's recent campaign in the deepwater Nyk High area of the Voering Basin, north of Trondheim, led to a methane-rich gas discovery in Upper Cretaceous sandstones. Pre-drilling seismic had suggested the possibility of oil below the gas column. BP may return with another well to ascertain whether the oil has migrated, and will also drill a prospect next year in the Moere Basin, further south.

Next month, Statoil will explore the Vema Dome prospect which is adjacent to the Nyk Ridge, an area characterized by salt diapirs. The semisubmersible Ocean Alliance is to drill the well in 1,240 meters of water, targeting Cretaceous sands 5,000 meters down. High resolution surveys at the drilling site, and recently interpreted 3D seismic, indicate good quality reservoir sands, without any real proof that oil is in the system.

That was not the case in Esso's campaign close to Balder, which yielded two new oil finds. The largest, named Hanz, flowed 4,230 b/d from Jurassic sandstones.

More and more metric records are being set, or claimed. Saga has drilled its longest-ever extended reach horizontal well, 7,028 meters from the Snorre platform to a total depth of 2,637 meters. Over 4,000 meters of the P-23 well maintained an angle of more than 80 degrees. The well also employed a new technique that involves setting a 9 5/8-in. liner rather than casing down to the uppermost reservoir at 5,694 meters. A 7-in. liner was then set to 6,563 meters and a 5-in. liner to 7,000 meters.

Other new techniques tried in this operation were friction-reducing subs on the drillstring, and turbine and thruster drilling to put weight on the drill bit on the horizontal section.

Elsewhere in the North Sea, BP is attempting its usual record for ER drilling at Wytch Farm on/offshore southern England, with a 10 km stepout planned to the end of the Sherwood Reservoir into Poole Bay.

Interest in deviated wells is mounting across the North Sea. In complex reservoirs such as Norsk Hydro's Troll C, 54 horizontal wells, including 12 multilaterals, will be drilled to access over 1 billion bbl from the oil layers within the Troll C gas province. At the other end of the development scale, new unmanned platforms in the Southern Gas Basin routinely include spare well slots to fast-track small discoveries at a later date through low-cost, enhanced recovery wells.

Coiled tubing drilling is gaining acceptance as another tool for accessing awkward oil pockets from major production installations, such as Snorre and Brent Delta. In terms of multilateral numbers, Shell UK Expro may be leading the way, having completed five on North Sea fields by early 1997 with a further 19 planned elsewhere.

Statoil has just drilled a multilateral well using Baker Hughes Inteq's new Autotrack rotatable system. This involves rotating the whole drillstring even during horizontal operations, with well direction computer-controlled from the platform without interruption. A total of 4,770 meters was drilled at a maximum deviation of 88 degrees. Over the final 1,200 meters, average drilling speed was 40 meters/hr - twice the normal rate. The well never veered more than 15 cm off course during drilling.

Recovery boost

In production processing, major advances are occurring in the Norwegian sector, where deepwater developments are most frequent. To enhance oil recovery from Troll C, where water depths are 340 meters, Norsk Hydro is employing riser base gas lift and also Subsis, the world's first combined subsea separation and water injection plant. The system, designed by ABB Offshore Technology, should be completed and installed on the seabed early in 1999.

Troll C's production medium will be a steel semisubmersible. Other established platform complexes are undergoing water injection upgrades to hike oil recovery. Statfjord C, for instance, will receive a new turbine-driven, low NOx pump for its existing system in an attempt to squeeze out an extra 6 million bbl of oil. Phillips plans an entirely new water injection platform for Eldfisk.

The various schemes have helped the Norwegian Petroleum Directorate (NPD) upgrade remaining reserves off Norway by almost 1 billion bbl above the 1996 estimate. Biggest contributor was Norsk Hydro's Hermod heavy oilfield, where oil in place predictions have risen sharply following last year's extended well test.

NPD added that Norwegian oil output will slide after 2001 if further large discoveries are not made soon. However, Norway's Energy Ministry will not launch its next full licensing round, the 16th, until after 2000. It has just completed awards under the Barents Sea round. Here seven licences were issued to 10 oil companies covering a broad swathe of the sea's southern zone.

The two westernmost licences, A and B, are on the Atlantic Margin and have plays potentially analogous to the west of Shetland and the Voering/Moere basins. The other five licences are further east in areas reasonably well explored to date.

NPD estimates 1.6 billion bbl of oil and 20 tcf of gas are out there to be discovered, but oil will be the main target with no gas market of consequence in sight on the sparsely populated northern mainland. However, one know Barents gasfield, Snohvit, could go forward for development soon if Statoil finds a way to exploit its thin oil layers.

Gas is more highly regarded in the burgeoning Haltenbanken area, where Saga is currently evaluating development options for its Kristin and Lavrans gas condensate discoveries. These are the two major Norwegian finds of recent times, each containing around 700 million boe.

The new Aasgard gas transport pipeline will be an obvious medium for evacuation, but Saga must first gain assurances of allocations to continental Europe through the Norwegian Gas Supply Committee's trunkline network. The Energy Ministry has just announced that Statoil's Huldra, Heidrun, Norne and Gullfaks field satellites will be next in line to meet contracted deliveries from 1999-2000.

On the median line with the UK, the Frigg pipeline treaty has finally been renegotiated after several years of stalled talks, allowing fresh supplies of Norwegian gas to move through the Frigg system to St Fergus, Scotland. Conveniently situated candidate fields include Kvitebjoern and Oseberg. But there is also the possibility of some shelved gas developments going forward, now that Norsk Hydro has assumed operatorship from Elf of the Heimdal platform. This may now become a gas transportation hub in the area, with gas perhaps funneled to the Frigg system through a new pipeline.

UK's eco-problems

In UK waters, the big question is `what happens next'? The oil industry-courting Conservative regime has been replaced by a New Labor government whose long-term intentions are unclear. Its first budget, last month, removed a levy on North Sea gasfields, making gas cheaper for consumers. However, more significant changes will come following a planned fundamental review of the UK's oil and gas taxation system.

A recent report by a British academic suggested that oil companies on the UKCS were making almost indecent returns on their investments. Labor may be tempted to gnaw at this apparent comfort zone, having promised the elctorate not to raise revenue through higher income tax.

This leads on to the question of Atlantic Margin exploration. Greenpeace has staged a series of stunts for the new administration, including occupation of Britain's westernmost outpost, a rock called Rockall. The aim is to block new frontier activity in the Atlantic (recently extended as far as Rockall), backed by injunctions issued through the European courts.

In Labor's current populist mood, the influence of such eco-friendly actions cannot be dismissed. Energy Minister John Battle recently issued draft regulations which would supposedly ease public access to the environmental impact of oil company projects.

Although Labor ignored protests against building of a second airport runway in Manchester this spring, it is believed to be considering eco-taxes on gasoline plus a tax of up to $640 on anyone driving a car in London. It is also launching another review of UKCS platform decommissioning, with wholesale removal of large installations likely favored over dumping at sea. If this is the future, Greenpeace's investment in its worldwide Brent Spar campaign would be vindicated.

Whatever extra impositions arrive, the industry in the UK is still striving to trim its own costs. To this end, the Cost Reduction in the New Era (Crine) committee has finally agreed on a batch of standard contracts relating to construction, design, offshore services, and well services. These should cut out inefficiencies arising from repeated drafting and reviewing of contracts.

On the development front, more high pressure/high temperature projects are going through now that xmas tree, flowline and other designers have successfully adapted their equipment. Shearwater and Elgin/Franklin, both HP/HT gas condensate reservoirs, are two of the major new UK field projects.

They may be joined soon by BP's Clair, an outstanding giant-size old discovery west of Shetland. Production flow rates from an extended well test last years have encouraged hopes of a development concept being concluded next year, possibly a fixed platform. But recovery would likely be phased and slow.

Another big platform was forecast for the latest phase of Chevron's Alba project, but the operator has just decided instead to retrofit additional separation and water injection facilities to the existing platform.

Other shelf action

Denmark's Energy Agency is to offer all available acreage in the Danish Central Graben area for a forthcoming 5th licensing round. Currently an open-door plociy operates whereby companies can apply for any Danish licences apart from areas in the western Central Graben.

Relaxation of state participation, introduced in the 4th round, will continue to apply. The improved terms, which apply to production as well as exploration, have paid off, with Amerada Hess becoming the second foreign oil company, after Statoil, to launch a development in Danish waters. This is South Arne, a DKr1.8 billion project which will be based around a platform processing 50,000 b/d of oil and 2 million cu meters/d of gas, with a concrete gravity base substructure offering storage of 550,000 bbl. Gas will be piped to Nybro on the Danish west coast via a new 13 million cu meters/d pipeline.

Things may also be stirring offshore Germany. Brigitta Erdgas und Erdoel has just been awarded an exploration licence covering 14 blocks on the Schill Grund High, where three wells have been drilled since 1965. Brigitta shot 220 km of seismic over the acreage this March, when RWE-DEA also gained eight German offshore blocks. Last drilling of any sort in the German North Sea occurred in 1992. Wintershall, meanwhile, may finally advance development of its A/6-B/4 gas discovery.

The Netherlands' first new offshore oilfield for a while will be developed, announced operator RWE-DEA, after completing a successful appraisal well F2-6. There may be around 30 million bbl recoverable from the various oil layers in Upper Cretaceous chalk at a depth of 1,650 meters. Development will likely be through NAM's nearby F3-FB-1 production platform, which offloads to shuttle tankers.

Off western Ireland, odd deepwater wells are being drilled this year, but more concerted drilling is not expected until 1999 when licence commitments filter through. That same year, Wood Mackenzie predicts that up to 15 wells could be spudded off the Faroe Islands, following awards from the islands' upcoming first licensing round.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.

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