Norway's Development Prospect List Grows Through Old Field Reworkings And New Finds

Aug. 17, 1998
Norwegian field developments: 1998-2003 [127,365 bytes] The list of Norwegian offshore fields under development or lined up for development has grown considerably in the last year. Wood Mackenzie Consultants Ltd., Edinburgh, says fields likely to be brought on stream in the next 5 years have total reserves of 6.4 billion bbl of oil and 25.7 tcf of gas (see table).
The Transocean Arctic semisubmersible rig tests the Kristin discovery in the Haltenbanken area of the Norwegian Sea for operator Saga Petroleum. The find will be developed as part of a four-field project known as Haltenbanken South, comprising a tension leg platform development and three subsea satellites. Photo courtesy of Saga.
The list of Norwegian offshore fields under development or lined up for development has grown considerably in the last year.

Wood Mackenzie Consultants Ltd., Edinburgh, says fields likely to be brought on stream in the next 5 years have total reserves of 6.4 billion bbl of oil and 25.7 tcf of gas (see table).

The analyst attributes growth in the developments list to several factors: development delays on current projects due to construction or technical problems; delays forced on operators by the Norwegian government; the award of a number of gas sales allocations by the GFU (Gas Negotiating Committee); the planned exploitation of older finds previously considered uncommercial for technical or logistical reasons; and the continuing normal progression of discoveries through to the development stage following a sustained period of successful exploration.

Statfjord upside

A major contributor to Norway's development log-jam is operators' continual upgrading of reserves in existing fields.

Statoil AS is operator of aging oil giant Statfjord, one of the North Sea's largest oil producers since production began in 1979. The company sees considerable upside potential.

Statfjord, on Block 33/9, was developed with three large platforms: Statfjord A, which was brought on stream in 1979; Statfjord B, which was started up in 1982; and Statfjord C, which began production in 1985.

Erik Åbø , improved oil recovery pilot project manager for Statfjord, said that the field is now estimated to have had 1 billion cu m of oil equivalent in place but that recoverable reserves have been raised down the years.

In 1988, Statoil thought 482 million cu m of oil equivalent was recoverable; more than 500 million cu m have been produced, and the latest estimate of total reserves is 700 million cu m.

"We originally thought Statoil would stay in production until 2015," said Åbø , "but now with reserves upgraded to 700 million cu m we are looking to extend the field life to 2020." Åbø said the operator is looking to achieve 70% recovery of oil in place through a combination of advanced seismic techniques, late production technology, smart wells, and gas-based drainage methods.

"The Statfjord license expires in 2009," said Åbø , "but we intend to get a new deal with the authorities."

Åbø said the oil pilot project is intended to add 60 million cu m of oil equivalent to reserves, 50 million cu m in Statfjord field and 10 million cu m through about half a dozen nearby exploration prospects.

"We had intended to close down Statfjord A platform in 2003," said Åbø . "Now we are looking to keep it in production until 2009 because we will need the platform's processing capacity and well slots.

"The enhanced oil recovery will be driven by rig activity-no fancy chemicals, just hard work by the drilling teams. We are going to use water-alternating-gas injection from 2000. From then there will be no physical exports of gas from Statfjord-all gas will be used to improve oil recovery."

Oseberg upside

Like Statoil, Norsk Hydro is looking to squeeze more oil out of an aging giant field-Oseberg on North Sea Blocks 30/6 and 30/9.

Torgeir Kyland, Hydro's vice-president for exploration and production, Oseberg area, said the field was brought on stream in 1988, while nearby Brage satellite produced first oil in 1993. Oseberg has recently been Norway's largest producer, yielding almost 450,000 b/d of oil this year. In 1983, Hydro estimated Oseberg reserves at 159 million cu m of oil equivalent, and in 1997 the total was pegged at 319 million cu m.

"The upgrade was because of the injection of gas from Troll oil field," said Kyland. "The revised drive mechanism was one of the most important decisions in Oseberg. Originally we used waterflood, but instead we installed a subsea template in Troll field to provide gas for injection in Oseberg."

Kyland said Oseberg and Brage production is now coming off plateau, but Hydro aims to develop new reserves nearby to extend plateau production to 2005.

The operator's ambition for improved oil recovery is to raise Oseberg total reserves to 355 million cu m of oil equivalent, which would require 66% recovery, and Brage reserves to 63 million cu m, which would require 44% recovery.

Kyland said Hydro intends to spend 7 billion kroner ($1 billion) on development of Oseberg East field, Oseberg gas reserves, Oseberg South field, and upgrading the Sture onshore terminal.

Later this year Oseberg East platform will be installed, enabling Hydro to produce an anticipated 23 million cu m of oil. In late 1999 Oseberg D platform, with capacity to produce 32 million cu m/day of gas, will be installed in the main field to produce its gas reserves, estimated at 110 billion cu m.

In 2000 Hydro intends to install Oseberg South platform, giving access to a further 53.5 million cu m of oil. Kyland said there are thought to be more oil reserves still to be found in the Oseberg South area. He envisages about six subsea satellites, which have not been evaluated, to be developed during 2005-2010.

Development delays

In 1997 several developments were delayed through problems with Far Eastern shipyards being unfamiliar with application of offshore production technology to ships.

Mostly the delays were attributable to aggressive commissioning schedules that the construction yards were unable to meet, said Wood Mackenzie.

In March Oslo announced that capital investments in 12 offshore projects would be postponed for 12 months. This was an attempt by government to cool the Norwegian economy.

Most of these projects were small subsea satellites, but four-Grane, Frame, Gullfaks Satellites Phase 2, and Snorre 2-were major projects. Snorre 2 was subsequently reprieved by the Storting (Norway's parliament).

In March, the Norwegian Petroleum Directorate also said that there were 129 discoveries off Norway which had not been brought forward for development. More than a dozen of the projects under development or likely by 2003 were discovered in the 1980s, and several were found in the 1970s.

Exploration targets

Among exploration targets lined up for drilling offshore Norway is the Helland Hansen prospect, where Norske Shell AS is operator of the six blocks on which it lies.

Tony Evans, deepwater exploration team leader at Norske Shell, said the company plans to drill a well into the structure on Block 6505/10, where water depth is 685 m, using the Ocean Alliance semisubmersible rig.

Shell has acquired 1,600 sq km of 3D seismic data over the prospect and plans to drill to a vertical depth of 5,000 m. Evans said the objective is in an Upper Cretaceous formation at a depth of 3,400-3,900 m.

Evans reckons that the likelihood of finding hydrocarbons is about 10% and that the structure is more likely to contain gas than oil or condensate. The target is attractive because of its size: It could hold 4-20 tcf of gas.

Norsk Hydro AS plans to drill two wells in the Ormen Lange prospect this year, with the aim of fixing estimated reserves and determining if it is a dry gas discovery or if oil is present.

So far, Hydro has proven 100 billion cu m of gas in Ormen Lange, and estimates reserves eventually will reach 365 billion cu m of gas on the basis of drilling to date. Ormen Lange lies on Block 6305/5 in water depths of 700-1,000 m.

Thor Tangen, Hydro's vice-president, exploration and production, Troll area, said the company plans to drill this year near the Gj a discovery on North Sea Block 35/9 and 36/7.

Water depth in Gj a is 380 m, and Hydro's appraisal drilling to date has proved reserves amounting to 28 million cu m of oil and condensate and 35 billion cu m of gas.

Hydro has sketched out a development concept requiring a minimum of six production wells and three injectors and reckons it could have the find on stream in 2002.

Tangen said Gj a is likely to be developed with a semisubmersible production platform with drilling facilities, with up to 15 producers tied back through a subsea manifold.

Also earmarked for production start-up in 2002 is the Fram discovery on Block 35/11, northeast of Troll field. Hydro has proved up reserves estimated at 36 million cu m of oil and 15 billion cu m of gas in Fram.

Hydro hopes this year's Fram appraisal well will boost oil reserves to 50 million cu m. Tangen envisages a semisubmersible production, drilling, and quarters platform development.

The Fram platform would have capacity to process 15,000 cu m/day of oil and 23,000 cu m/day of condensate, said Tangen, plus 9 million cu m/day of gas. A total of 17 wells is envisaged, including 11 producers and the remainder gas or water injectors.

Frank Pedersen, Hydro's vice-president for exploration and production, Heimdal area, said the Block 25/11 Grane discovery is a heavy oil accumulation in 130 m of water.

Hydro estimates Grane reserves at 100 million cu m of 19? gravity oil if gas injection is used. A number of small finds have also been made nearby, which could be developed as subsea satellites of Grane.

Pedersen said the Grane development base case is for a production and quarters platform plus a drilling platform, with oil exports by a 170 km pipeline to shore or with a floating storage unit and shuttle tankers.

Grane processing platform capacity is expected to be 34,000 cu m/day of oil and 11 million cu m/day of gas. More than 40 production wells are envisaged, all horizontal, plus 10 vertical gas injectors. Development cost is estimated to be 12-15 billion kroner ($1.8-2.2 billion).

"We are looking for production start-up in 2001," said Pedersen, "but we don't expect to get government's blessing. The indications are that government wants to delay start-up by 1 year, but we are looking to submit a plan for development and operation this autumn.

"We have already delayed the project voluntarily by 1 year because of Norway's overstretched contracting market. Though we don't like delays, we could get some benefit on price and through reducing risk in development in the meantime."

Development portfolio

Among the older finds that have recently become feasible, Wood Mackenzie cites Balder, which was made worthwhile by improved reservoir characterization and new production technology.

Haltenbanken South is a group of four gas-condensate and oil fields-Kristin, Lavrans, Tyrihans Nord, and Tyrihans S r-which became viable because of development of export infrastructure for other projects nearby, and through synergies with combined development.

The analyst also lists four potential field developments that might be brought on stream by 2003 but for which development plans are uncertain: the 1/3-3 discovery, with estimated reserves of 10 million bbl of oil; Heidrun North, with estimated reserves of 30 million bbl of oil; Dagny, with estimated reserves of 10 million bbl of oil and 200 bcf of gas; and Sn hvit, with estimated reserves of 170 million bbl of oil and 8.7 tcf of gas.

The first three of these are expected to be subsea satellite developments, but Sn hvit is anticipated to be a massive subsea development linked to a floater or shallow-water platform.

Because of its remoteness from any markets-Sn hvit is the largest find in the undeveloped Norwegian Barents Sea area-Sn hvit is expected to be developed only in conjunction with a liquefied natural gas export plant.

"There are some 35 projects that could potentially be developed and brought on stream in Norway by the year 2003," said Wood Mackenzie, "twenty-five of which have yet to receive development approval.

"This is a high level of development activity, and there must be some question as to whether there is sufficient contracting capacity in the Norwegian industry to service such a level of activity.

"In addition, the oil companies themselves may decide to delay some of the gas-producing new developments until the implications for Norwegian producers of the recently approved European Gas Directive and its effect upon offshore investments are better understood.

"Given these considerations, and the current government's inclination towards regulation of the industry in order to prevent overheating of the economy, it would seem likely that several of the probable field developments will be delayed beyond the dates currently envisaged."

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