Troll leads North Sea upgrades
Equinor has initiated life extension programs at three of its largest fields in the North Sea. Work is already under way on the NOK7.8-billion ($913-million) Troll Phase 3 development following sanction by Norway’s Ministry of Petroleum and Energy. The project involves recovering gas from the western part of the Troll field, 25 km (15.5 mi) northwest of the Troll A platform, via eight new production wells connected to two subsea templates, a 36-in. pipeline and a new processing module on Troll A and powered from the shore. The facilities should prolong the field’s productive lifespan beyond 2050: Equinor believes this could be one of its most profitable offshore investments to date, with a projected breakeven cost of less than $10/bbl. Subsea contracts have gone out so far to Allseas, DeepOcean, IKM, Marubeni and Nexans, with Aker Solutions responsible for the topsides campaign.
Lowering of a subsea template at Vigdis North East. (Courtesy Equinor/André Osmundsen)
Front-end engineering design is under way for the Gudrun Phase 2 water injection scheme at Aibel’s offices in Haugesund and Stavanger. Aibel is assessing integration and hookup needs, the aim of the project being to extend and increase recovery from the Gudrun field’s reservoir. On completion of the study this June, Aibel will likely be awarded the implementation contract. Equinor and its partners have also committed to improve recovery from the subsea Vigdis field which has produced over 400 MMbbl through the Snorre A facilities over the past two decades. A subsea boosting station will be connected to the pipeline to enhance throughput, also allowing wellhead pressure to be lowered which should increase flow from the wells. Estimated cost of the program, which also entails modifications to Snorre A and B (the latter supplying power to the boosting station’s umbilical) is around NOK1.4 billion ($164 million). OneSubsea will supply the boosting system and associated subsea template.
North Sea, Baltic gas lines move ahead
Polish and Danish gas transport operators Gaz-System and Energinet have committed to the Baltic Pipe, which will take gas from Norwegian fields to Denmark via a connection to the Europipe II pipeline. Another new line will extend the transmission of gas from eastern Denmark through the Baltic Sea to Poland. Norwegian trunklines operator Gassco will be responsible for the tie-ins – Baltic Pipe will have an overall length of 900 km (559 mi) and will also cross part of Sweden.
In the UK central North Sea, Shell and partners ExxonMobil and BP plan a new pipeline export route for gas-liquids production from the fixed platform serving the HP/HT Shearwater field and various Shell/third-party-operated satellite tiebacks sanctioned over the past year. At present, dry gas produced by the platform, 140 mi (225 km) east of Aberdeen, flows south through the Shearwater Elgin Area Line (SEAL) to the Bacton terminal in eastern England. Under the new scheme, Shell will modify the platform and install a new 23-mi (37-km) line from a connection point in the Fulmar Gas Line system to Shearwater. This will allow wet gas to flow into the Shell Esso Gas and Associated Liquids pipeline to St Fergus, near Aberdeen. SEAL will continue to transport gas from the HP/HT Elgin field for processing at Bacon.
The Clipper South platform. (Courtesy INEOS)
In the UK’s southern gas basin, production from INEOS’ unmanned Clipper South platform has begun heading through another new pipeline to Shell’s Clipper hub in the Sole Pit area. The change had to be made after ConocoPhillips decided to shut down the LOGGS pipeline system and the Theddlethorpe terminal that previously received the platform’s gas. Production from Clipper is sent to Bacton, where Shell and ExxonMobil completed a £300-million ($379-million) overhaul in 2017, allowing the facility to handle more gas from offshore fields in the area.
UK well decommissioning costs down
Oil & Gas UK forecasts annual decommissioning expenditure for UK fields of around £1.5 billion ($1.9 billion) over the next decade. This is 20% lower than its previous report in 2017, and lower well decommissioning costs are a major factor. Among the latest findings, 1,465 wells are set to be decommissioned over the next 10 years, representing around one-fifth of the UK’s total well stock. For some projects, average time spent on well decommissioning has halved throughout its life cycle. •