North Sea

Jeremy Beckman London The NorFra gas line to Dunkerque, otherwise known as Zeepipe IV - one of five gas pipeline projects planned from Norwegian fields. Statoil looks to have made an interesting oil discovery west of its giant Gullfaks Field. Semisub Deep Sea Bergen, drilling vertically into Middle Jurassic sandstones, found light oil at 2,850 meters below sea level. Oil produced from the exploration well is being stored onboard test ship Crystal Sea.

May 1st, 1995

Jeremy Beckman
London

Probe proves further oil off Gullfaks

Statoil looks to have made an interesting oil discovery west of its giant Gullfaks Field. Semisub Deep Sea Bergen, drilling vertically into Middle Jurassic sandstones, found light oil at 2,850 meters below sea level. Oil produced from the exploration well is being stored onboard test ship Crystal Sea.

The probed structure could be sizeable, according to the Norwegian Petroleum Directorate (NPD). Well 34/10-37 lies north of the Rimfaks oilfield which Statoil plans to develop jointly with oil from the Gullfaks South reservoir.

Gullfaks itself has been hit by lower production levels than expected in recent months, due partly to problems with hydraulic control systems on three subsea wells tied back to Gullfaks A. And first production from the Heidrun Field, where Statoil is due to assume operatorship from Conoco, now looks likely to be held up well beyond the target date of August 1, with more work still to be done on the platform modules.

Saga adds fuel to Haltenbanken debate

South of Smoerbukk Field in Norway's Haltenbanken, Saga Petroleum has made a gas/condensate find which could be on a par with the biggest fields located in the Norwegian Sea to date, according to NPD. The exploration well, in block 6406/2, was drilled to 5,300 meters by Ross Rig in 278 meters of water.

No comment has been issued yet on how this would affect proposals by Statoil and Saga for a joint development of the Smoerbukk, Smoerbukk South and Midgard fields. They are suggesting a two-platform field center on Smoerbukk, either in the form of two adjacent concrete platforms, one concrete structure combined with a floating production unit, or two production floaters. All three options are based on the conclusion that topsides equipment would be too heavy for one central platform to support.

Estimated cost for this project is NKr35-40 billion. Recently, all eight licensees in the three fields signed a unitization agreement giving each an identical share in the fields. It's hoped that this equalization of commercial interests will speed progress toward a development solution. This August, the chosen scheme will be submitted to Norway's Gas Supply Committee (GFU) which will decide whether to recommend the Haltenbanken fields or those in the northern North Sea to meet Norway's new gas sales commitments.

Over 2,500km of gas pipelines are due to be laid between Norwegian gasfields and mainland Europe in the next five years. Allseas' new large diameter pipelayer Solitaire is understood to be installing the Europipe II link to Germany - its first booking - with McDermott-ETPM West responsible for the Zeepipe IIB line from Kollsnes to North Sea block 16/11, and the planned 860km, 40in. NorFra line extending to Dunkerque, France.

Limited export potential for UK-Belgium link?

While demand for Norwegian gas powers ahead, merits of the UK's solitary planned gas link to the continent continue to be questioned. A report from Edinburgh consultants Wood Mackenzie suggests that by the time the new Interconnector pipeline from Bacton to Zeebrugge is operable (thought likely to be 1998), most outstanding gas contracts in west and southern Europe will have been sourced elsewhere. This would lead to the Interconnector operating well below its 20bcm capacity.

Wood Mackenzie sees a gas supply/demand gap in west Europe of only 1bcm in 2000, perhaps increased to just 4bcm in 2005. Although there might be more of a market for UK gas in central Europe, there is at present no route to these countries from Zeebrugge.

The analyst adds that current beach prices make UK gas uncompetitive with that from mainland Europe suppliers. It does not believe that the UK is equipped to offer long-term supply contracts to the European market.

UK still tops for venturers

For the second year running, the UK tops the list as the most popular place for E&P new ventures outside North America, according to Simon Petroleum Technology. The Wales-based consultant questioned 92 oil companies over exploration opportunities in 1995 plans: the UK was most favored, ahead of Venezuela and Indonesia. Reasons cited were Britain's relatively low petroleum tax offtake; build-up of infrastructure in the North Sea rendering previously marginal fields economic; and emergence of a new province west of the Shetlands.

Proof that these findings were not entirely jingoistic came in an announcement from Britain's Industry and Energy Ministry. This stated that nominations for 691 blocks had been received from oil companies for the UK's 17th offshore licensing round, the highest for some time. Most interest centered on the west of Shetland area.

The southern gas basin, however, remains the hotbed for fast-track developments. The latest batch includes Wintershall's Windermere gasfield in block 49/9b, previously known as Avalon. Production from this 100-125bcf field could start in 1996-97, assuming Annex B approval late this year. ABB Global Engineering is examining options for exporting the gas through existing infrastructure.

Mobil's Galahad Field could be onstream in just six months, assuming government sanction has been granted. The 153bcf reserves will likely be developed through an unmanned facilities platform, tied back to sister Mobil field Lancelot. Mobil has also announced a successful double-sidetrack appraisal of its Kyle Field, which tested oil and gas through probes into a fractured chalk reservoir and Paleocene sandstone. But there may be little rush to develop here, with infrastructure in the vicinity being patchy.

Much further north, BP is to commit the Miller Field to the UK's first full-scale incremental oil recovery scheme using water alternating gas technology. The aim is to boost production from the current daily rate of 150,000bbl, and extend the field's life by up to two years. Work will involve installing a new compressor.

Six of the platform's wells will be converted, two to gas lift and four to water alternating gas injection. An average of 60mcf/d will be reinjected into the reservoir: currently Miller exports 250mcf/d. Gas reinjection is due to start early in 1997.

Worse news, finally, from Lasmo, which has decided to permanently shut off production from Staffa, an oilfield satellite of Ninian. Staffa came onstream in March 1992 as Lasmo's first operated North Sea development, but ran into problems caused by hydrate build-up in 1993 which has plagued the 8 MM bbl development ever since. With just 2 MM bbl left to produce, the partners have decided that further repairs are not worthwhile.

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