Field development surge revives ailing UK sector
Following a long period of deathly silence, the UK field development scene burst to life over the New Year, with six new schemes off the blocks. Most are subsea, but will still be savored by the local fabrication sector, which otherwise faced oblivion.
The happiest yards were Heerema Hartlepool and Kvaerner Oil and Gas in Methil, selected respectively for the 2,100-ton topsides and 2,700-ton jacket for Phillips' Jade platform. Jade, discovered in central UK North Sea block 30/2c in 1996, was always seen as a satellite to Phillips' Judy gas-condensate production complex 12 miles to the south. The new platform, due to be operational in late 2001, will be normally unmanned and controlled remotely from Judy.
AMEC, which built the Judy facilities, is designing the Jade installation to produce at up to 210 MMcf/d of gas and 22,700 b/d of oil, all of which will be transported through a 16-in. multiphase pipeline to Judy for processing. These figures are higher than those issued by Phillips for plateau output, suggesting that space has been left to tie in production from other fields.
At one point, BG International's 1997 oilfield discovery, Blake, was another platform candidate. But following a downgrade of reserves to 50-75 million bbl, BG has opted instead for Talisman's Bleo Holm FPSO as the host processing center. Bleo Holm currently serves the Talisman-operated Ross Field in the Outer Moray Firth, and Talisman is also a partner in Blake. Eight development wells will be drilled, starting in April, with the wellstream transported via flowlines to a subsea production manifold, and then onto the FPSO through 10-in. and 12-in. production lines. The development cost is projected at UKP158 million.
Another FPSO, the PGS-owned and managed Petrojarl 1, will likely be moved from ARCO's dwindling Blenheim Field to Kyle, operated by Ranger. Subject to government approval, it will perform an extended 4-5 month test on Kyle's 29/2c-12z well from late May, at an anticipated rate of 10,000 bbl plus. Kyle was scheduled to be developed last year through PGS' Banff Field Ramform, where the operator is Conoco. But the tie-in had to be postponed, due to continuing technical hitches besetting the vessel.
Major projects set to resume off Norway
Two major Norwegian North Sea developments are set for sanction this year. In both cases, progress had been halted by the government, which had been concerned about overheating of Norway's oil and gas sector (this was prior to last year's global field development slump, which threatened to decimate the country's fabrication industry).
Norsk Hydro has submitted a NKr15 billion plan for the Grane heavy oil field project. The proposed accommodation, process, and drilling platform is easily the largest North Sea installation pending, with planned oil production of 214,000 b/d from 26 wells by 2005. Oil will be piped to the terminal at Sture, with gas imported to Grane for power use. Kvaerner is handling engineering, with construction awards due this fall.
Kvitebjorn's case also looks sound, provided the field makes it onto the next round of Norwegian gas sales allocations. Statoil and its partners are thinking in terms of another steel jacket production platform, including full drilling capabilities, which could be installed by spring 2003. As well as exporting 20 MMcm/d of gas to Kollsnes and 62,500 b/d of condensate (via a new pipeline connecting to the Troll Oil II line to Mongstad), the platform could be configured to accept oil and gas from other small fields nearby.
Norsk Hydro's NKr2.6 billion subsea development of the Tune gas/condensate field has been cleared by Norway's Oil and Energy Ministry. Gas production of 3 bcm annually is scheduled to start in 2002. Initially, four subsea wells drilled from a template will be tied back to the Oseberg D platform to the east via two 10-km, 12-in. pipelines. More wells could be added later on. DSND will install the pipelines, with Umoe building the 8-900 ton reception module for the platform. Kvaerner Oilfield |Products will likely construct the 300-ton template.
Discoveries herald possible drilling upturn
One of Saga Petroleum's final acts as an operator was a new discovery, named Erlend, in Norway's Halten Bank. Wildcat 6406/2-7, drilled in 293 meters of water by the Transocean Arctic semisubmersible, was appraising the E-structure west of the Kristin Field. HP/HT gas and condensate were encountered in lower Jurassic reservoirs.
The discovery swells the backlog of fields in the western Halten Terrace awaiting a joint dev elop ment solution. Earlier attempts foundered, due mainly to Saga's crippling financial problems. A TLP on Kristin was vetoed, but this field is still viewed as the central production location. Statoil, which now operates following the transfer of Saga's assets, is thought to be considering a phased approach, tying together initially the Erlend, Kristin, Lavrans, and Ragnfrid fields, with separation handled potentially at the Asgard complex. Tyrihans and Trestakk in the eastern Halten Bank would be tackled at a later date.
In the Norwegian Sea, semisubmersible Byford Dolphin has completed appraisal drilling on the southern flank of the Mikkel gas field, discovered by Statoil in 1985. Analysis suggests a development would be justified, according to Mikkel team leader Kjetil Ohm. One option under review is a 3-subsea-well tieback to the Asgard B production platform, recovering 16 bcm of gas at an estimated cost of NKr1.7 billion. The alternative, costing NKr2.5 billion, could derive 50% more gas via a subsea link to Shell's Draugen facilities. In either case, the gas would be piped to Kaarstoe on the mainland through the Asgard Transport trunkline. Mikel straddles licenses PL 092 and 121.
Portents are generally better for Norwegian sector drilling this year. A new survey of oil company spending plans by Statistics Norway predicts a near NKr2 billion increase to NKr7.1 billion in 2000 - higher oil prices and upcoming frontier acreage awards are contributory factors.
Gas activity resumes, despite power ban
The BG-operated ECA project is bringing new gas supplies to the Yorkshire coast via newly installed platforms on Neptune and Cleeton.
On the UK mainland, an application to build a new gas-fired power station in the south-west has become the 15th to be vetoed by the government since October 1998 - equivalent to over 5,800 MW of rejected new gas-fired capacity. This might explain the sudden slowdown in UK southern gas basin activity, although one fairly major new project there has recently started up - the UKP150 million Easington Catchment Area Phase 1, operated by BG International.
A 1,325-ton unmanned platform was installed on the Neptune Field, linked to subsea facilities on the Mercury Field by a 26 km, 12-in. pipeline. The fields have combined reserves of 370 bcf, and the aim is to sustain plateau output of 250 MMcf/d for over three years. All produced gas is exported to a new 1,260-ton riser platform within BP Amoco's Cleeton complex, before being routed to the Dimlington terminal on the Yorkshire coast.