|
Field name
|
Type
|
Text
|
NPDID field
|
Date updated
|
Date sync NPD
|
|---|---|---|---|---|---|
|
ALBUSKJELL
|
Reservoir
|
Albuskjell produced gas and condensate from Maastrichtian and lower Paleocene chalk. The deposit is located above a salt dome. The main reservoir is in the Upper Cretaceous Tor Formation, at a depth of 3,200 metres. The overlying Ekofisk Formation has poorer reservoir quality and has hardly been drained. There are significant remaining resources.
|
43437
|
28.02.2023
|
22.03.2023
|
|
ALBUSKJELL
|
Recovery strategy
|
The field was produced by pressure depletion.
|
43437
|
28.02.2023
|
22.03.2023
|
|
ALBUSKJELL
|
Transport
|
The well stream was transported via pipeline to the Ekofisk Complex for export.
|
43437
|
28.02.2023
|
22.03.2023
|
|
ALBUSKJELL
|
Development
|
Albuskjell is a field in the southern part of the Norwegian sector in the North Sea, 20 kilometres west of the Ekofisk field. The water depth is 70 metres. Albuskjell was discovered in 1972, and the plan for development and operation (PDO) was approved in 1975. The field was developed with two steel installations for drilling and production. Production started in 1979.
|
43437
|
28.02.2023
|
22.03.2023
|
|
ALBUSKJELL
|
Status
|
The field was shut down in 1998 and the platforms were removed in 2011 and 2013. Any redevelopment of the field must be viewed in combination with other decommissioned fields in the area.
|
43437
|
28.02.2023
|
22.03.2023
|
|
ALVE
|
Recovery strategy
|
The field is produced by pressure depletion.
|
4444332
|
28.02.2023
|
22.03.2023
|
|
ALVE
|
Transport
|
The oil is offloaded from the Norne FPSO and the gas is transported via the Norne pipeline to the Åsgard Transport System (ÅTS) and further to the Kårstø terminal for export.
|
4444332
|
28.02.2023
|
22.03.2023
|
|
ALVE
|
Status
|
Production from Alve is constrained by the commercial agreement with the Norne licence and the gas handling capacity on the Norne FPSO. Excess capacity on the FPSO in recent years has made it possible to process larger volumes of gas from Alve. The long-term activity on the field is to optimise production.
|
4444332
|
28.02.2023
|
22.03.2023
|
|
ALVE
|
Reservoir
|
Alve produces oil and gas from sandstone of Early and Middle Jurassic age in the Tilje, Not and Garn Formations. The reservoir lies at a depth of 3,600 metres and has moderate to good quality.
|
4444332
|
28.02.2023
|
22.03.2023
|
|
ALVE
|
Development
|
Alve is a field in the Norwegian Sea, 16 kilometres southwest of the Norne field. The water depth is 370 metres. Alve was discovered in 1990, and the plan for development and operation (PDO) was approved in 2007. The development concept is a standard subsea template with four production wells. Alve is tied to the Norne production, storage and offloading vessel (FPSO) by a pipeline. Production started in 2009.
|
4444332
|
28.02.2023
|
22.03.2023
|
|
ALVHEIM
|
Development
|
Alvheim is a field in the central part of the North Sea, ten kilometres west of the Heimdal field and near the border to the UK sector. The field includes the six discoveries Kameleon, Boa, Kneler, Viper, Kobra and Gekko. Boa lies partly in the UK sector. The water depth is 120-130 metres. Alvheim was discovered in 1998, and the plan for development and operation (PDO) was approved in 2004. The field is developed with subsea wells tied to a production, storage and offloading vessel, Alvheim FPSO. Production started in 2008. The Vilje, Volund, Bøyla and Skogul fields are tied-back to the Alvheim FPSO. Frosk, Trell and Trine are new tie-backs that are under development.
|
2845712
|
28.02.2023
|
22.03.2023
|
|
ALVHEIM
|
Transport
|
The oil is stabilised and stored on the Alvheim FPSO before it is exported by tankers. Processed rich gas is transported by pipeline from Alvheim to the Scottish Area Gas Evacuation (SAGE) pipeline on the UK continental shelf.
|
2845712
|
28.02.2023
|
22.03.2023
|
|
ALVHEIM
|
Reservoir
|
Alvheim produces oil and gas from Paleocene sandstone in the Hermod and Heimdal Formations. The reservoirs are located in submarine fan deposits and injectites, mostly at depths of 2,100 to 2,200 metres. The reservoir quality is good.
|
2845712
|
28.02.2023
|
22.03.2023
|
|
ALVHEIM
|
Status
|
Due to greater in-place volumes and longer infill wells, Alvheim has seen a significant increase in the estimated recoverable volumes of oil and gas since the PDO. The capacity of the Alvheim gas compressor is limited due to further development of the Boa deposit. Measures including reducing gas lift and choking back or shutting in of wells were taken to maximise the overall production. Alvheim production has been better than anticipated. Alvheim is a hub in the area, and Kobra East Gekko (KEG), Frosk, Trell and Trine are under development as tied-backs to the Alvheim FPSO.
|
2845712
|
28.02.2023
|
22.03.2023
|
|
ALVHEIM
|
Recovery strategy
|
The field is produced by natural water drive from an underlying aquifer.
|
2845712
|
28.02.2023
|
22.03.2023
|
|
ATLA
|
Recovery strategy
|
The field has been produced by pressure depletion.
|
21106284
|
28.02.2023
|
22.03.2023
|
|
ATLA
|
Development
|
Atla is a field in the central part of the North Sea, 20 kilometres northeast of the Heimdal field. The water depth is 120 metres. Atla was discovered in 2010, and the plan for development and operation (PDO) was approved in 2011. The field has been developed with one production well which is connected to a subsea facility, and is tied-back to Heimdal via the Skirne field. Production started in 2012.
|
21106284
|
28.02.2023
|
22.03.2023
|
|
ATLA
|
Status
|
Atla is in its tail phase and continuous production ceased in 2016 due to low reservoir pressure. The field has produced intermittently after pressure build-up in recent years. Atla produced for only a few days in 2022. A joint decommissioning plan for the Atla and Skirne fields was submitted to the authorities in 2015.
|
21106284
|
28.02.2023
|
22.03.2023
|
|
ATLA
|
Transport
|
The well stream is transported via the Skirne/Byggve subsea facility to Heimdal for processing and export.
|
21106284
|
28.02.2023
|
22.03.2023
|
|
ATLA
|
Reservoir
|
Atla produces gas from Middle Jurassic sandstone in the Brent Group. The reservoir lies at a depth of 2,700 metres and has good quality.
|
21106284
|
28.02.2023
|
22.03.2023
|
|
BALDER
|
Recovery strategy
|
Balder and Ringhorne produce primarily by natural aquifer drive, but reinjection of produced water is used for pressure support, especially into the Ringhorne Jurassic reservoir. Excess water is injected into the Utsira Formation. Gas is also reinjected if the gas export system is down.
|
43562
|
28.02.2023
|
22.03.2023
|
|
BALDER
|
Reservoir
|
Balder, including Ringhorne, produces oil from several separate deposits in sandstone of Jurassic, Paleocene and Eocene age. Balder produces from the Heimdal and Hermod Formations as well as from the injected sand complex above them. Ringhorne produces from the Hugin, Ty and Hermod Formations. The reservoirs are of good to very good quality. The Balder reservoir lies at a depth of 1,700 metres and the Ringhorne reservoir at a depth of 1,900 metres.
|
43562
|
28.02.2023
|
22.03.2023
|
|
BALDER
|
Transport
|
The oil is transported by tankers. Excess gas from Balder and Ringhorne is exported from the Jotun FPSO through the Statpipe system to Kårstø and from there on to continental Europe.
|
43562
|
28.02.2023
|
22.03.2023
|
|
BALDER
|
Status
|
A revised PDO for Balder and Ringhorne was approved in 2020. The development plan includes lifetime extension and relocation of the Jotun FPSO, and drilling of new subsea wells. The FPSO is currently at a shipyard undergoing maintenance and upgrades. It is scheduled to be back on the field in 2024.
|
43562
|
28.02.2023
|
22.03.2023
|
|
BALDER
|
Development
|
Balder is a field in the central part of the North Sea, just west of the Grane field. The water depth is 125 metres. Balder was discovered in 1967, and the initial plan for development and operation (PDO) was approved in 1996. Production started in 1999. The field has been developed with subsea wells tied-back to the Balder production, storage and offloading vessel (FPSO). The Ringhorne deposit, located nine kilometres north of the Balder FPSO, is included in the Balder complex. Ringhorne is developed with a combined accommodation, drilling and wellhead facility, tied-back to the Balder FPSO and Jotun FPSO for processing, crude oil storage and gas export. The nearby field Ringhorne Øst is also tied-back to Balder via the Ringhorne platform. The PDO for Ringhorne Jura was approved in 2000 and production started in 2003. The Ringhorne Vest PDO exemption was approved in 2003 and production started in 2004. An amended PDO for Ringhorne was approved in 2007.
|
43562
|
28.02.2023
|
22.03.2023
|
|
BAUGE
|
Development
|
Bauge is a field on the Halten bank in the southern Norwegian Sea, 15 kilometres east of the Njord field. The water depth is 280 metres. Bauge was discovered in 2013, and the plan for development and operation (PDO) was approved in June 2017. The field will be developed with two production wells tied-back to the Njord A facility. A water injection well will be drilled from the existing subsea template on the Hyme field.
|
29446221
|
28.02.2023
|
22.03.2023
|
|
BAUGE
|
Transport
|
The well stream will be transported to the Njord A platform for processing. Produced oil will be transported by pipeline to the storage vessel Njord B, and further by tankers to the market. Gas from the field is exported through a 40-kilometre pipeline connected to the Åsgard Transport System (ÅTS) and further to the Kårstø terminal.
|
29446221
|
28.02.2023
|
22.03.2023
|
|
BAUGE
|
Recovery strategy
|
The field will be produced by partial pressure maintenance from phased water injection, which will commence a few years after production start-up.
|
29446221
|
28.02.2023
|
22.03.2023
|
|
BAUGE
|
Reservoir
|
The main reservoirs contain oil in Lower and Middle Jurassic sandstone in the Tilje and Ile Formations, at a depth of 2,700 metres. The reservoirs are segmented and have moderate quality.
|
29446221
|
28.02.2023
|
22.03.2023
|
|
BAUGE
|
Status
|
The field is under development and the production is planned to start in late 2022.
|
29446221
|
28.02.2023
|
22.03.2023
|
|
BLANE
|
Transport
|
The well stream is transported by pipeline to the Ula field for processing. The oil is exported further to Teesside in the UK.
|
3437650
|
28.02.2023
|
22.03.2023
|
|
BLANE
|
Status
|
Production from the field has generally been good, but the water cut is increasing. The production is restricted by oil-in-water limits.
|
3437650
|
28.02.2023
|
22.03.2023
|
|
BLANE
|
Recovery strategy
|
Until 2019, the field was produced with pressure support from injection of produced water from the Blane, Tambar and Ula fields. The field is now produced by pressure depletion. In addition, gas lift is used in the wells.
|
3437650
|
28.02.2023
|
22.03.2023
|
|
BLANE
|
Reservoir
|
Blane produces oil from Paleocene sandstone in the Forties Formation. The reservoir is of moderate to good quality and lies at a depth of 3,100 metres.
|
3437650
|
28.02.2023
|
22.03.2023
|
|
BLANE
|
Development
|
Blane is a field in the southern part of the Norwegian sector in the North Sea, 35 kilometres southwest of the Ula field. The field is located on the border to the UK sector and the Norwegian share of the field is 18 per cent. The water depth is 70 metres. Blane was discovered in 1989, and the plan for development and operation (PDO) was approved in 2005. The field has been developed with a subsea facility on the British continental shelf with two horizontal production wells tied-back to the Ula field. Production started in 2007.
|
3437650
|
28.02.2023
|
22.03.2023
|
|
BRAGE
|
Recovery strategy
|
The recovery strategy in Statfjord and Fensfjord is water injection. In the Brent Group, the production strategy is water alternating gas (WAG) injection, and the Sognefjord Formation is produced by depletion and by pressure support from the aquifer.
|
43651
|
28.02.2023
|
22.03.2023
|
|
BRAGE
|
Transport
|
The oil is transported by pipeline to the Oseberg field and further through the Oseberg Transport System (OTS) pipeline to the Sture terminal. A gas pipeline is tied-back to Statpipe.
|
43651
|
28.02.2023
|
22.03.2023
|
|
BRAGE
|
Reservoir
|
Brage produces oil from sandstone of Early Jurassic age in the Statfjord Group, and sandstone of Middle Jurassic age in the Brent Group and the Fensfjord Formation. There is also oil and gas in Upper Jurassic sandstone in the Sognefjord Formation. The reservoirs lie at a depth of 2,000-2,300 metres. The reservoir quality varies from poor to excellent.
|
43651
|
28.02.2023
|
22.03.2023
|
|
BRAGE
|
Development
|
Brage is a field in the northern part of the North Sea, ten kilometres east of the Oseberg field. The water depth is 140 metres. Brage was discovered in 1980, and the plan for development and operation (PDO) was approved in 1990. The field has been developed with an integrated production, drilling and accommodation facility with a steel jacket. Production started in 1993. A PDO for Brage Sognefjord was approved in 1998. The authorities granted PDO exemptions for the Brent Ness and Bowmore Brent deposits in 2004 and 2007, respectively.
|
43651
|
28.02.2023
|
22.03.2023
|
|
BRAGE
|
Status
|
Brage has been producing for a long time, and work is still ongoing to find new ways of increasing recovery from the field. New wells are being drilled.
|
43651
|
28.02.2023
|
22.03.2023
|
|
BREIDABLIKK
|
Status
|
The field is under development and production is planned to start in 2024.
|
38702206
|
28.02.2023
|
22.03.2023
|
|
BREIDABLIKK
|
Reservoir
|
The main reservoirs contain oil in Paleocene sandstone in the Heimdal Formation, at a depth of 1700 metres. The reservoirs have good quality, with little variation in reservoir properties. Above the Heimdal Formation, oil is present in a sand injectite complex in shales of Paleocene and Eocene age in the Lista, Sele and Balder Formations.
|
38702206
|
28.02.2023
|
22.03.2023
|
|
BREIDABLIKK
|
Transport
|
The oil will be transported from Grane to the onshore terminal at Sture for storage and export.
|
38702206
|
28.02.2023
|
22.03.2023
|
|
BREIDABLIKK
|
Development
|
Breidablikk is a field in the central part of the North Sea, ten kilometers northeast of the Grane field. The water depth is 130 metres. Breidablikk includes two discoveries, D-structure and F-structure, discovered in 1992 and 2013, respectively. The plan for development and operation (PDO) was approved in 2021. The field is being developed with four subsea templates tied-back to the Grane platform.
|
38702206
|
28.02.2023
|
22.03.2023
|
|
BREIDABLIKK
|
Recovery strategy
|
The field will be produced by pressure depletion, assisted by gas lift in the production wells which will be placed close to the top of the structures.
|
38702206
|
28.02.2023
|
22.03.2023
|
|
BRYNHILD
|
Reservoir
|
Brynhild produced oil from sandstone of Late Jurassic age in the Ula Formation. The reservoir lies at a depth of 3,300 metres, and the reservoir conditions are close to high pressure, high temperature (HPHT) conditions.
|
21123063
|
28.02.2023
|
22.03.2023
|
|
BRYNHILD
|
Status
|
Production from Brynhild ceased in 2018 and the subsea template was removed in 2021.
|
21123063
|
28.02.2023
|
22.03.2023
|
|
BRYNHILD
|
Development
|
Brynhild is a field in the southern part of the Norwegian sector in the North Sea, 10 kilometres from the UK sector and 55 kilometres northwest of the Ula field. The water depth is 80 metres. Brynhild was discovered in 1992, and the plan for development and operation (PDO) was approved in 2011. The development concept was a subsea template including four wells, tied-in to the Haewene Brim production, storage and offloading vessel (FPSO) located on the Pierce field in the British sector. Production started in 2014.
|
21123063
|
28.02.2023
|
22.03.2023
|
|
BRYNHILD
|
Recovery strategy
|
The field was produced by pressure support from water injection. Water for injection was supplied from the Pierce field.
|
21123063
|
28.02.2023
|
22.03.2023
|
|
BRYNHILD
|
Transport
|
The well stream was transported by pipeline to the Haewene Brim FPSO for processing. The processed oil was exported by shuttle tankers to the market, and gas was reinjected into the Pierce field.
|
21123063
|
28.02.2023
|
22.03.2023
|
|
BYRDING
|
Development
|
Byrding is a field in the northern part of the North Sea, four kilometres north of the Fram H-Nord field and 30 kilometres north of the Troll C facility. The water depth is 360 metres. Byrding was discovered in 2005, and the plan for development and operation (PDO) was approved in 2017. The development concept is a two-branch multilateral (MLT) well drilled from the Fram H-Nord template. Production started in 2017.
|
28975067
|
28.02.2023
|
22.03.2023
|
|
BYRDING
|
Reservoir
|
Byrding produces oil and gas from turbiditic sandstone of Late Jurassic age in the Heather Formation. The reservoir lies at a depth of 3,050 metres. It is structurally complex and has good reservoir quality.
|
28975067
|
28.02.2023
|
22.03.2023
|
|
BYRDING
|
Recovery strategy
|
The field is produced by pressure depletion.
|
28975067
|
28.02.2023
|
22.03.2023
|
|
BYRDING
|
Status
|
The field has been shut-in for a period in 2022, but is now producing again after a light well intervention operation.
|
28975067
|
28.02.2023
|
22.03.2023
|
|
BYRDING
|
Transport
|
The well stream is routed through Fram Vest to Troll C for processing. The oil is transported further in the Troll Oil Pipeline II to the Mongstad terminal and the gas is exported via Troll A to the Kollsnes terminal.
|
28975067
|
28.02.2023
|
22.03.2023
|
|
BØYLA
|
Reservoir
|
Bøyla produces oil from sandstone of late Paleocene to early Eocene age in the Hermod Formation. The reservoir has good quality and lies in a channelised submarine fan system at depth of 2,100 metres.
|
22492497
|
28.02.2023
|
22.03.2023
|
|
BØYLA
|
Recovery strategy
|
The field is produced with pressure support from water injection. Gas lift is also necessary to support flow in the wells.
|
22492497
|
28.02.2023
|
22.03.2023
|
|
BØYLA
|
Development
|
Bøyla is a field in the central part of the North Sea, 28 kilometres south of the Alvheim field. The water depth is 120 metres. Bøyla was discovered in 2009, and the plan for development and operation (PDO) was approved in 2012. The field is developed with a subsea template including two horizontal production wells and one water injection well. The field is tied-back to the Alvheim production, storage and offloading vessel (FPSO). Production started in 2015.
|
22492497
|
28.02.2023
|
22.03.2023
|
|
BØYLA
|
Status
|
Test production from the nearby discovery 24/9-12 S (Frosk) started in 2019 and provided the basis for the PDO for Frosk that was approved in 2022. Frosk is included in the Bøyla field, which is periodically shut-in because of the production of Frosk.
|
22492497
|
28.02.2023
|
22.03.2023
|
|
BØYLA
|
Transport
|
The well stream is transported by pipeline to the Alvheim FPSO, where the oil is stabilised and stored before it is exported by tankers. Processed rich gas is transported by pipeline from Alvheim to the Scottish Area Gas Evacuation (SAGE) pipeline on the UK continental shelf.
|
22492497
|
28.02.2023
|
22.03.2023
|
|
COD
|
Development
|
Cod is a field in the southern part of the Norwegian sector in the North Sea, 75 kilometres northwest of the Ekofisk field. The water depth is 75 metres. Cod was discovered in 1968, and the plan for development and operation (PDO) was approved in 1973. The field was developed with a combined drilling, production and accommodation facility and started production in 1977.
|
43785
|
28.02.2023
|
22.03.2023
|
|
COD
|
Status
|
The field was shut down in 1998 and the facility was removed in 2013. Any redevelopment of the field must be viewed in combination with other decommissioned fields in the area.
|
43785
|
28.02.2023
|
22.03.2023
|
|
COD
|
Transport
|
The well stream was sent via pipeline to the Ekofisk Complex for export.
|
43785
|
28.02.2023
|
22.03.2023
|
|
COD
|
Recovery strategy
|
The field was produced by pressure depletion.
|
43785
|
28.02.2023
|
22.03.2023
|
|
COD
|
Reservoir
|
The Cod field produced gas and condensate from deep-marine turbiditic sandstone of Paleocene age in the Forties Formation. The deposit has a complex structure with several separate reservoirs at a depth of 3,000 metres.
|
43785
|
28.02.2023
|
22.03.2023
|
|
DRAUGEN
|
Status
|
With declining oil production, volumes of associated gas will not be sufficient for power generation, and alternative solutions are therefore being evaluated, including power from shore. The gas discovery 6407/9-9 (Hasselmus) is under development for subsea tie-back to the Draugen platform. Identification and maturing of infill targets are ongoing in order to increase the recovery from the field. A lifetime extension for the facility is required to maintain the forecasted production profile.
|
43758
|
28.02.2023
|
22.03.2023
|
|
DRAUGEN
|
Transport
|
The oil is offloaded via a floating loading-buoy and exported by tankers. The associated gas was earlier transported via the Åsgard Transport System (ÅTS) to the Kårstø terminal, but is now used for power generation on the platform.
|
43758
|
28.02.2023
|
22.03.2023
|
|
DRAUGEN
|
Reservoir
|
Draugen produces oil from two formations. The main reservoir is in sandstone of Late Jurassic age in the Rogn Formation. The western part of the field also produces from sandstone of Middle Jurassic age in the Garn Formation. The reservoirs lie at a depth of 1,600 metres. They are relatively homogeneous, with good reservoir quality.
|
43758
|
28.02.2023
|
22.03.2023
|
|
DRAUGEN
|
Development
|
Draugen is a field in the southern part of the Norwegian Sea. The water depth is 250 metres. Draugen was discovered in 1984, and the plan for development and production (PDO) was approved in 1988. The field has been developed with a concrete fixed facility and integrated topside, and has both platform and subsea wells. Stabilised oil is stored in tanks at the base of the facility. Two pipelines connect the facility to a floating loading-buoy. Production started in 1993.
|
43758
|
28.02.2023
|
22.03.2023
|
|
DRAUGEN
|
Recovery strategy
|
The field is produced by pressure maintenance from water injection and by aquifer support.
|
43758
|
28.02.2023
|
22.03.2023
|
|
DUVA
|
Transport
|
The well stream is routed to the Gjøa platform for processing and export. The oil is transported further through the Troll Oil Pipeline II to the Mongstad terminal, and the gas is exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus in the UK.
|
34833026
|
28.02.2023
|
22.03.2023
|
|
DUVA
|
Recovery strategy
|
The Field is produced by pressure depletion and gas expansion in the gas cap.
|
34833026
|
28.02.2023
|
22.03.2023
|
|
DUVA
|
Development
|
Duva is a field in the northern part of the North Sea, six kilometres northeast of the Gjøa field. The water depth is 350 metres. Duva was discovered in 2016, and the plan for development and operation (PDO) was approved in 2019. Duva is developed with a 4-slot subsea template including three oil production wells and one gas production well tied-back to the Gjøa platform.
|
34833026
|
28.02.2023
|
22.03.2023
|
|
DUVA
|
Reservoir
|
The reservoir contains oil and gas in turbiditic sandstone of Early Cretaceous age in the Agat Formation. It is a stratigraphic trap at a depth of 2,200 metres. The reservoir quality is good.
|
34833026
|
28.02.2023
|
22.03.2023
|
|
DUVA
|
Status
|
Production from Duva started in August 2021.
|
34833026
|
28.02.2023
|
22.03.2023
|
|
DVALIN
|
Recovery strategy
|
The field is produced by pressure depletion.
|
29393934
|
28.02.2023
|
22.03.2023
|
|
DVALIN
|
Development
|
Dvalin is a field in the central part of the Norwegian Sea, 15 kilometres northwest of the Heidrun field. It consists of two separate structures that are 3.5 kilometres apart. Dvalin East was proven in 2010 and Dvalin West was proven in 2012. The water depth is 340 and 400 metres, respectively. The plan for development and production (PDO) was approved in 2017. The development concept is a subsea template with four production wells tied-back to the Heidrun platform. Production started in 2020.
|
29393934
|
28.02.2023
|
22.03.2023
|
|
DVALIN
|
Status
|
Production from Dvalin is currently put on hold until a mercury removal solution is in place, with expected startup in 2023.
|
29393934
|
28.02.2023
|
22.03.2023
|
|
DVALIN
|
Transport
|
The well stream is transported via pipeline to Heidrun for processing at a dedicated gas processing module. The gas is then transported via Polarled to Nyhamna for further processing before being exported as dry gas via Gassled to the market.
|
29393934
|
28.02.2023
|
22.03.2023
|
|
DVALIN
|
Reservoir
|
Both Dvalin East and Dvalin West contain gas in Middle Jurassic sandstone in the Ile and Garn Formations. The reservoirs lie at a depth of 4,500 metres and have high pressure and high temperature (HPHT). The homogeneous shallow marine Garn sandstone has good reservoir quality, while the more heterogeneous and fine-grained Ile sandstone has less favourable reservoir properties.
|
29393934
|
28.02.2023
|
22.03.2023
|
|
EDDA
|
Reservoir
|
Edda produced oil from Maastrichtian and lower Paleocene chalk. The main reservoir is in the Upper Cretaceous Tor Formation, at a depth of approximately 3,100 metres.
|
43541
|
28.02.2023
|
22.03.2023
|
|
EDDA
|
Status
|
The field was shut down in 1998 and the facility removed in 2012. Any redevelopment of the field must be viewed in combination with other decommissioned fields in the area.
|
43541
|
28.02.2023
|
22.03.2023
|
|
EDDA
|
Recovery strategy
|
The field was produced with pressure depletion. Starting in 1988, gas from the Tommeliten Gamma field was transported to Edda and used for gas lift in the wells.
|
43541
|
28.02.2023
|
22.03.2023
|
|
EDDA
|
Transport
|
The well stream was sent via pipeline to the Ekofisk Complex for export.
|
43541
|
28.02.2023
|
22.03.2023
|
|
EDDA
|
Development
|
Edda is a field in the southern part of the Norwegian sector in the North Sea, 12 kilometres southwest of the Ekofisk field. The water depth is 70 metres. Edda was discovered in 1972, and the plan for development and operation (PDO) was approved in 1975. The field was developed with a manned wellhead and production facility and started production in 1979.
|
43541
|
28.02.2023
|
22.03.2023
|
|
EDVARD GRIEG
|
Reservoir
|
Edvard Grieg produces undersaturated oil from alluvial, aeolian and shallow marine sandstone and conglomerate of Late Triassic to Early Cretaceous age. Reservoir quality varies from moderate to very good in marine and aeolian sandstone, while the quality is poorer in alluvial sandstone and conglomerate. Oil is also proven in the underlying basement. The reservoir is at a depth of 1,900 metres.
|
21675433
|
28.02.2023
|
22.03.2023
|
|
EDVARD GRIEG
|
Transport
|
The oil is exported by pipeline to the Grane Oil Pipeline, which is connected to the Sture terminal. The gas is exported in a separate pipeline to the Scottish Area Gas Evacuation (SAGE) system in the UK.
|
21675433
|
28.02.2023
|
22.03.2023
|
|
EDVARD GRIEG
|
Status
|
The field has been producing better than expected and recoverable volumes have increased significantly since the PDO due to excellent reservoir performance. Production is still in its plateau phase, and several new producers may come on stream in 2023. Test production from Rolvsnes started in 2021 and will continue in 2023.
|
21675433
|
28.02.2023
|
22.03.2023
|
|
EDVARD GRIEG
|
Recovery strategy
|
The field is produced by pressure support from water injection.
|
21675433
|
28.02.2023
|
22.03.2023
|
|
EDVARD GRIEG
|
Development
|
Edvard Grieg is a field in the Utsira High area in the central North Sea, 35 kilometres south of the Grane and Balder fields. The water depth is 110 metres. Edvard Grieg was discovered in 2007, and the plan for development and operation (PDO) was approved in 2012. The field is developed with a fixed installation with a steel jacket and full process facility, and it utilises a jack-up rig for drilling and completion of wells. Production started in 2015. The Edvard Grieg installation supplies power to the Ivar Aasen field and processes the well stream from Ivar Aasen. Solveig and Rolvsnes are tied-back to Edvard Grieg.
|
21675433
|
28.02.2023
|
22.03.2023
|
|
EKOFISK
|
Reservoir
|
Ekofisk produces oil from naturally fractured chalk of Late Cretaceous age in the Tor Formation and early Paleocene age in the Ekofisk Formation. The reservoir rock has high porosity, but low permeability. The reservoir has an oil column of more than 300 metres and lies at 3,000 metres depth.
|
43506
|
28.02.2023
|
22.03.2023
|
|
EKOFISK
|
Recovery strategy
|
Ekofisk was originally produced by pressure depletion and had an expected recovery factor of 17 per cent. Since then, comprehensive water injection has contributed to a substantial increase in oil recovery. Large-scale water injection started in 1987, and in subsequent years, the area for water injection has been extended in several phases. Experience has proven that water displaces the oil much more effectively than anticipated, and the expected final recovery factor for Ekofisk is now estimated to be over 50 per cent. In addition to the water injection, compaction of the soft chalk provides extra force to drainage of the field. The reservoir compaction has resulted in about 10 metres subsidence of the seabed, especially in the central part of the field. It is expected that the subsidence will continue, but at a much lower rate.
|
43506
|
28.02.2023
|
22.03.2023
|
|
EKOFISK
|
Status
|
Production from Ekofisk is maintained at a high level through continuous water injection, drilling of production and injection wells, and well interventions. Key challenges are identifying the remaining oil pockets in a mature, waterflooded reservoir, as well as handling the increasing volumes of produced water. Ekofisk Life of Field Seismic (LoFS) provides data for monitoring of waterflood and dynamic changes in the overburden for use in reservoir management. First phase drilling on Ekofisk Z was completed in 2020. Infill drilling on Ekofisk is expected to continue throughout the lifetime of the field. Water injection is extended in the southern part of the field by the installation of a new subsea template, Ekofisk VC. In 2022, the production licence 018, which includes the Ekofisk field, was extended until 2048.
|
43506
|
28.02.2023
|
22.03.2023
|
|
EKOFISK
|
Development
|
Ekofisk is a field in the southern part of the Norwegian sector in the North Sea. The water depth is 70 metres. Ekofisk was discovered in 1969, and the initial plan for development and operation (PDO) was approved in 1972. Test production was initiated in 1971 and ordinary production started in 1972. Production was initially routed to tankships until a concrete storage tank was installed in 1973. Since then, the field has been further developed with many facilities, including facilities for associated fields and export pipelines. Several of the initial facilities have already been removed or are awaiting decommissioning. The initial field development started with three production platforms: Ekofisk A, Ekofisk B and Ekofisk C. Wellhead platform Ekofisk X and process platform Ekofisk J were installed in 1996 and 1998, respectively, as part of the Ekofisk II project. In 2005, wellhead platform Ekofisk M was installed as part of the Ekofisk Growth Project. A plan for water injection at Ekofisk was approved in 1983. Ekofisk K, which is the main injection facility, started water injection in 1987 and is still in operation. There had also been water injection at Ekofisk W from 1989 until 2009, when Ekofisk W was shut down and replaced by a subsea template, Ekofisk VA. A PDO for the development of Ekofisk South was approved in 2011. The project included two new installations in the southern part of the field: production platform Ekofisk Z and a subsea template for water injection, Ekofisk VB. Injection from Ekofisk VB and production from Ekofisk Z started in 2013. The accommodation facilities Ekofisk H and Ekofisk Q were replaced by Ekofisk L in 2014. An amended PDO for an additional water injection template, Ekofisk VC, was approved in 2017.
|
43506
|
28.02.2023
|
22.03.2023
|
|
EKOFISK
|
Transport
|
Oil and gas are routed to export pipelines via the processing facility at Ekofisk J. Gas from the Ekofisk area is transported via the Norpipe gas pipeline to Emden in Germany, while the oil is sent via the Norpipe oil pipeline to Teesside in the UK.
|
43506
|
28.02.2023
|
22.03.2023
|
|
ELDFISK
|
Transport
|
Oil and gas are sent to the export pipelines via the Ekofisk Centre. Gas from the Ekofisk area is transported via the Norpipe gas pipeline to Emden in Germany, while the oil is sent via the Norpipe oil pipeline to Teesside in the UK.
|
43527
|
28.02.2023
|
22.03.2023
|
|
ELDFISK
|
Recovery strategy
|
Eldfisk was originally produced by pressure depletion. In 1999, water injection was implemented through horizontal injection wells. Pressure depletion and the water weakening effect have caused reservoir compaction, which in turn has resulted in several metres of seabed subsidence. The Eldfisk II project extends waterflooding on the field.
|
43527
|
28.02.2023
|
22.03.2023
|
|
ELDFISK
|
Status
|
Further development of Eldfisk Bravo is ongoing. In 2022, an amended PDO for this development was submitted, and the production licence 018, which includes the Eldfisk field, was extended until 2048. Even though the drilling campaign in the Eldfisk II project was completed in 2022, additional wells are planned to be drilled. Drilling targets are also being matured in the eastern structure, Eldfisk Øst.
|
43527
|
28.02.2023
|
22.03.2023
|
|
ELDFISK
|
Reservoir
|
Eldfisk produces oil from chalk of Late Cretaceous and early Paleocene age in the Hod, Tor and Ekofisk Formations. The reservoir rock has high porosity, but low permeability. Natural fracturing allows the reservoir fluids to flow more easily. The field consists of three structures: Alpha, Bravo and Eldfisk Øst. The reservoirs lie at depths of 2,700-2,900 metres.
|
43527
|
28.02.2023
|
22.03.2023
|
|
ELDFISK
|
Development
|
Eldfisk is a field in the southern part of the Norwegian sector in the North Sea, 10 kilometres south of the Ekofisk field. The water depth is 70 metres. Eldfisk was discovered in 1970, and the plan for development and operation (PDO) was approved in 1975. The initial development consisted of three facilities: Eldfisk B (a combined drilling, wellhead and process facility), and Eldfisk A and Eldfisk FTP (wellhead and process facilities). Production started in 1979. A PDO for water injection was approved in 1997, and the injection facility Eldfisk E was installed in 1999. This facility also provides some the water to Ekofisk K for injection on the Ekofisk field. A PDO for Eldfisk II was approved in 2011, and included a new integrated facility, Eldfisk S, connected by bridge to Eldfisk E. Production from Eldfisk S started in 2015. This facility replaces several functions of Eldfisk A and Eldfisk FTP. Eldfisk A is converted into a wellhead platform and Eldfisk FTP is used as bridge-support facility. The Embla field, located south of Eldfisk, is tied to Eldfisk S.
|
43527
|
28.02.2023
|
22.03.2023
|
|
EMBLA
|
Transport
|
Oil and gas are transported by pipeline to the Eldfisk S facility for processing, and further to the Ekofisk Centre for export. Gas from the Ekofisk area is transported via the Norpipe gas pipeline to Emden in Germany, while the oil is sent via the Norpipe oil pipeline to Teesside in the UK.
|
43534
|
28.02.2023
|
22.03.2023
|
|
EMBLA
|
Development
|
Embla is a field in the southern part of the Norwegian sector in the North Sea, just south of the Eldfisk field. The water depth is 70 metres. Embla was discovered in 1988, and the plan for development and operation (PDO) was approved in 1990. The field has been developed with an unmanned wellhead facility, which is remotely controlled from Eldfisk. Production started in 1993. In 1995, an amended PDO for Embla was approved.
|
43534
|
28.02.2023
|
22.03.2023
|
|
EMBLA
|
Status
|
As part of the Eldfisk II development project, Embla was tied to the Eldfisk S facility, extending the lifetime for Embla. Currently, there are four producers. Because of the complexity of the reservoir, there are no plans other than optimising the existing production wells. In 2022, the production licence 018, which includes the Embla field, was extended until 2048.
|
43534
|
28.02.2023
|
22.03.2023
|
|
EMBLA
|
Recovery strategy
|
The field is produced by pressure depletion.
|
43534
|
28.02.2023
|
22.03.2023
|
|
EMBLA
|
Reservoir
|
Embla produces oil and gas from segmented sandstone and conglomerate of Devonian and Permian age. The reservoir lies at a depth of more than 4,000 metres and has high pressure and high temperature (HPHT). It has a complex, highly faulted structure.
|
43534
|
28.02.2023
|
22.03.2023
|
|
ENOCH
|
Status
|
The field is in its late tail phase. Cease of profitable production is currently estimated for the end of 2024.
|
3437659
|
28.02.2023
|
22.03.2023
|
|
ENOCH
|
Reservoir
|
Enoch produces oil from Forties sandstone of Paleocene age. The reservoir lies at a depth of 2,100 metres and has variable quality.
|
3437659
|
28.02.2023
|
22.03.2023
|
|
ENOCH
|
Recovery strategy
|
The field is produced by pressure depletion.
|
3437659
|
28.02.2023
|
22.03.2023
|
|
ENOCH
|
Development
|
Enoch is a field in the central part of the North Sea on the border to the British sector, ten kilometres northwest of the Gina Krog field. The Norwegian share of the field is 20 per cent. Enoch was proven in 1985, and the plan for development and operation (PDO) was approved in 2005. The field has been developed with one horizontal production well tied to the British Brae field. Production started in 2007.
|
3437659
|
28.02.2023
|
22.03.2023
|
|
ENOCH
|
Transport
|
The well stream from Enoch is transported to the Brae A facility for processing and further transport by pipeline to Cruden Bay in the UK. The gas is sold to Brae.
|
3437659
|
28.02.2023
|
22.03.2023
|
|
FENJA
|
Status
|
The field is under development and the production is planned to start in 2023.
|
31164879
|
28.02.2023
|
22.03.2023
|
|
FENJA
|
Transport
|
The well stream will be routed by pipeline to the Njord A facility for processing. The oil will be stored at the Njord B facility and transferred to shuttle tankers. The reinjected gas will be produced at the end of the oil production period. The gas will be exported via Åsgard Transport System (ÅTS).
|
31164879
|
28.02.2023
|
22.03.2023
|
|
FENJA
|
Recovery strategy
|
The field will be produced by pressure support from water and gas injection. Produced gas will be reinjected into the reservoir.
|
31164879
|
28.02.2023
|
22.03.2023
|
|
FENJA
|
Development
|
Fenja is a field in the Norwegian Sea, 35 kilometres southwest of the Njord field. The water depth is 325 metres. The field also includes the discovery 6406/12-3 A (Bue). Fenja was discovered in 2014, and the plan for development and operation (PDO) was approved in 2018. The field will be developed with two subsea templates with a total of six wells, tied-back to the Njord A facility.
|
31164879
|
28.02.2023
|
22.03.2023
|
|
FENJA
|
Reservoir
|
The reservoirs contain oil and gas in sandstone of Late Jurassic age in the Melke Formation, and oil in Upper Jurassic sandstone in the Rogn Formation. The reservoirs are in a fan system at a depth of 3,200-3,500 metres, and they have variable Properties.
|
31164879
|
28.02.2023
|
22.03.2023
|
|
FLYNDRE
|
Status
|
Production has been lower than expected since start-up. The main challenge is a more rapid pressure decline than anticipated.
|
24635035
|
28.02.2023
|
22.03.2023
|
|
FLYNDRE
|
Recovery strategy
|
The field is produced by pressure depletion. Only the Balmoral reservoir is developed.
|
24635035
|
28.02.2023
|
22.03.2023
|
|
FLYNDRE
|
Development
|
Flyndre is a field in the southern part of the Norwegian sector in the North Sea, straddling the border between the Norwegian and UK sectors. The Norwegian share of the field is seven per cent. Flyndre is located 35 kilometres northwest of the Ekofisk field. The water depth is 70 metres. Flyndre was discovered in 1974, and the plan for development and operation (PDO) was approved in 2014. The development includes a subsea horizontal well tied-back to the Clyde platform on the UK continental shelf. Production started in 2017.
|
24635035
|
28.02.2023
|
22.03.2023
|
|
FLYNDRE
|
Transport
|
The well stream is processed on the Clyde field. Liquids are transported to the Fulmar platform and further to Teesside in the UK via Norpipe. Some of the gas is used offshore for fuel and flare on the Clyde and Fulmar fields, with the remainder going to the terminal of the Shell-Esso Gas and Liquids (SEGAL) system at St Fergus in the UK.
|
24635035
|
28.02.2023
|
22.03.2023
|
|
FLYNDRE
|
Reservoir
|
Flyndre produces oil and associated gas from Balmoral sandstone of Paleocene age. The reservoir lies at a depth of 3,000 metres and has moderate to good quality. There is also oil in Upper Cretaceous chalk with poor reservoir quality at a depth of 3,100 metres.
|
24635035
|
28.02.2023
|
22.03.2023
|
|
FRAM
|
Status
|
An extra gas module dedicated to Fram on the Troll C platform started operation in 2020. Production from the Fram area is optimised within the available capacities at Troll C. Active exploration is ongoing in the area.
|
1578840
|
28.02.2023
|
22.03.2023
|
|
FRAM
|
Reservoir
|
Fram produces oil and associated gas from sandstone of Middle Jurassic age in the Brent Group, and from Upper Jurassic sandstone in a marine fan system in the Draupne Formation and the shallow marine Sognefjord Formation. The reservoirs have a gas cap and lie in several isolated, rotated fault blocks at 2,300-2,500 metres depth. The reservoir in Fram Vest is complex. The reservoirs in Fram Øst are generally of good quality.
|
1578840
|
28.02.2023
|
22.03.2023
|
|
FRAM
|
Transport
|
The well stream is transported to the Troll C platform for processing. The oil is transported further through the Troll Oil Pipeline II to the Mongstad terminal, and the gas is exported via the Troll A platform to the Kollsnes terminal.
|
1578840
|
28.02.2023
|
22.03.2023
|
|
FRAM
|
Recovery strategy
|
The Fram Øst deposit in the Sognefjord Formation is produced by injection of produced water as pressure support, in addition to natural aquifer drive. The Brent reservoirs in Fram Øst are produced by pressure support from natural aquifer drive. Gas lift is used in the wells. Oil production from Fram is restricted by the gas processing capacity at the Troll C facility.
|
1578840
|
28.02.2023
|
22.03.2023
|
|
FRAM
|
Development
|
Fram is a field in the northern part of the North Sea, 20 kilometres north of the Troll field. The water depth is 350 metres. Fram was discovered in 1990 and comprises two main structures, Fram Vest and Fram Øst, with several deposits. The plan for development and operation (PDO) for Fram Vest was approved in 2001, and production started in 2003. The PDO for Fram Øst was approved in 2005, and production started in 2006. Both structures are developed with two subsea templates each, tied-back to the Troll C platform. A PDO exemption for Fram C-Øst was approved in 2016; the development included a long oil producer drilled from the B2-template on Fram Øst. Another PDO exemption was granted in 2018 for two wells in the Fram-Øst Brent reservoir, drilled from one of the existing templates on Fram Øst. Both Byrding and Fram H-Nord are producing through the Fram infrastructure.
|
1578840
|
28.02.2023
|
22.03.2023
|
|
FRAM H-NORD
|
Recovery strategy
|
The field is produced by pressure depletion.
|
23410947
|
28.02.2023
|
22.03.2023
|
|
FRAM H-NORD
|
Status
|
Fram H-Nord has produced below expectations and has been shut-in for a while because of severe problems with the well stream (slugging). Slugging is manageable at present, and production started again in August 2022.
|
23410947
|
28.02.2023
|
22.03.2023
|
|
FRAM H-NORD
|
Reservoir
|
Fram H-Nord produces oil and gas from turbiditic sandstone of Late Jurassic age in the Heather Formation. The reservoir lies at a depth of 2,950 metres and has good quality.
|
23410947
|
28.02.2023
|
22.03.2023
|
|
FRAM H-NORD
|
Transport
|
The well stream is routed through a template on Fram Vest and further to the Troll C facility for processing. The oil is transported further by the Troll Oil Pipeline II to the Mongstad terminal, and the gas is exported via the Troll A platform to the Kollsnes terminal.
|
23410947
|
28.02.2023
|
22.03.2023
|
|
FRAM H-NORD
|
Development
|
Fram H-Nord is a field just north of the Fram field in the northern part of the North Sea. The water depth is 360 metres. Fram H-Nord was discovered in 2007, and the authorities granted an exemption from the plan for development and operation (PDO) requirement in 2013. The field is developed with a two-branch multilateral (MLT) well from a 4-slot template. Production started in 2014. The Byrding field is also drilled from the Fram H-Nord template.
|
23410947
|
28.02.2023
|
22.03.2023
|
|
FRIGG
|
Reservoir
|
Frigg produced gas from deep marine, turbiditic sandstone of Eocene age in the Frigg Formation, at a depth of 1,900 metres.
|
43555
|
28.02.2023
|
22.03.2023
|
|
FRIGG
|
Development
|
Frigg is a field in the central part of the North Sea, straddling the border between the UK and Norwegian sectors. The water depth is 100 metres. Frigg was discovered in 1971, and the plan for development and operation (PDO) was approved in 1974. The field was developed with a living quarters facility (QP), two process facilities (TP1 and TCP2) and two drilling facilities (DP2 and CDP1). TP1, CDP1 and TCP2 had concrete substructures and steel frame topsides. The two other facilities had steel jackets. CDP1, TP1 and QP were on the UK part of the field. The facilities on the field also treated oil and gas from the fields Frøy, Nord Øst Frigg, Øst-Frigg, Lille-Frigg and Odin. Production started in 1977.
|
43555
|
28.02.2023
|
22.03.2023
|
|
FRIGG
|
Status
|
The field was shut down in 2004 and final disposal of the facilities was completed in 2010. An appraisal well was drilled on Frigg in 2019. The planned development of the area between the Oseberg and Alvheim fields might lead to a future redevelopment of the field.
|
43555
|
28.02.2023
|
22.03.2023
|
|
FRIGG
|
Transport
|
The gas was transported via a 180-kilometre pipeline to the Shell-Esso Gas and Liquids (SEGAL) terminal at St Fergus in the UK.
|
43555
|
28.02.2023
|
22.03.2023
|
|
FRIGG
|
Recovery strategy
|
The field was produced by pressure depletion.
|
43555
|
28.02.2023
|
22.03.2023
|
|
FRØY
|
Recovery strategy
|
The field was produced by pressure support from water injection.
|
43597
|
28.02.2023
|
22.03.2023
|
|
FRØY
|
Development
|
Frøy is a field in the central part of the North Sea, 22 kilometres northeast of the Heimdal field. The water depth is 120 metres. Frøy was discovered in 1987, and the plan for development and operation (PDO) was approved in 1992. The field was developed with a wellhead facility with 15 well slots. Production started in 1995.
|
43597
|
28.02.2023
|
22.03.2023
|
|
FRØY
|
Reservoir
|
Frøy produced oil from Jurassic sandstone in the Brent Group at a depth of 3,200-3,300 metres.
|
43597
|
28.02.2023
|
22.03.2023
|
|
FRØY
|
Transport
|
The well stream was transported by pipeline to the Frigg field for treatment and metering, and transported further via pipeline to the terminal of the Shell-Esso Gas and Liquids (SEGAL) system at St Fergus in the UK.
|
43597
|
28.02.2023
|
22.03.2023
|
|
FRØY
|
Status
|
The field was shut down in 2001 and the facility was removed in 2002. Frøy is planned to be redeveloped with a normally unmanned platform as part of the development of the area between the Oseberg and Alvheim fields. A PDO for the area was submitted in December 2022.
|
43597
|
28.02.2023
|
22.03.2023
|
|
GAUPE
|
Reservoir
|
Gaupe produced oil and gas from two structures, Gaupe South and Gaupe North. Most of the resources were in sandstone in the Triassic Skagerrak Formation, while some were in Middle Jurassic sandstone. The reservoirs lie at a depth of 3,000 metres. The two structures had a gas cap overlying an oil zone. Due to segmentation, the vertical and lateral connectivity in the field is poor.
|
18161341
|
28.02.2023
|
22.03.2023
|
|
GAUPE
|
Status
|
Production from Gaupe ceased in 2018. According to the formal removal resolution, decommissioning must be completed by the end of 2026.
|
18161341
|
28.02.2023
|
22.03.2023
|
|
GAUPE
|
Development
|
Gaupe is a field in the central part of the North Sea close to the border to the UK sector, about 35 kilometres south of the Sleipner Øst field. The water depth is 90 metres. Gaupe was discovered in 1985, and the plan for development and operation (PDO) was approved in 2010. The development concept was two single horizontal subsea wells tied to the Armada installation on the UK continental shelf. Production started in 2012.
|
18161341
|
28.02.2023
|
22.03.2023
|
|
GAUPE
|
Recovery strategy
|
The field was produced by pressure depletion.
|
18161341
|
28.02.2023
|
22.03.2023
|
|
GAUPE
|
Transport
|
The well stream was processed at the Armada installation for export to the UK. The rich gas was transported via the Central Area Transmission System (CATS) pipeline to Teesside in the UK, and liquids were transported via the Forties pipeline to Cruden Bay in the UK.
|
18161341
|
28.02.2023
|
22.03.2023
|
|
GIMLE
|
Reservoir
|
Gimle produces oil from sandstone of Middle Jurassic age in the Brent Group. The main reservoir is in a downfaulted structure northeast of the Gullfaks field at a depth of 2,900 metres. Reservoir quality is generally good. There is also oil in sandstone of Late Triassic and Early Jurassic age.
|
4005142
|
28.02.2023
|
22.03.2023
|
|
GIMLE
|
Development
|
Gimle is a field in the northern part of the North Sea, just northeast of the Gullfaks field. The water depth is 220 metres. Gimle was discovered in 2004, and was granted exemption from the plan for development and operation (PDO) requirement in 2006. The field is developed with three production wells and one water injection well drilled from the Gullfaks C facility. Production started in 2006.
|
4005142
|
28.02.2023
|
22.03.2023
|
|
GIMLE
|
Recovery strategy
|
The field is produced by partial pressure support from water injection. Injection is temporarily stopped due to production shut down.
|
4005142
|
28.02.2023
|
22.03.2023
|
|
GIMLE
|
Transport
|
The production from Gimle is processed on the Gullfaks C facility and transported together with oil and gas from the Gullfaks field.
|
4005142
|
28.02.2023
|
22.03.2023
|
|
GIMLE
|
Status
|
Gimle is temporarily shut down due to low reservoir pressure. A new well is planned to be drilled in 2023 in the area between Gimle and Sindre fields. Gimle and Sindre have recently been merged into a unit called Brime.
|
4005142
|
28.02.2023
|
22.03.2023
|
|
GINA KROG
|
Reservoir
|
Gina Krog produces oil and gas from sandstone of Middle Jurassic age in the Hugin Formation. The field is complex and segmented, and the reservoirs lie depths of 3,300-3,900 metres. Reservoir thickness and quality are varying.
|
23384544
|
28.02.2023
|
22.03.2023
|
|
GINA KROG
|
Recovery strategy
|
The field has earlier been produced by gas injection in most reservoir segments. Since 2021, all segments are produced by pressure depletion.
|
23384544
|
28.02.2023
|
22.03.2023
|
|
GINA KROG
|
Status
|
In 2022, the production has been stable and according to plan. A new drilling campaign using a jack-up rig is planned for 2023. Randgrid FSO will be replaced by an oil export pipeline to Sleipner A with anticipated start-up in 2024. The Eirin discovery is being considered for tie-in to Gina Krog.
|
23384544
|
28.02.2023
|
22.03.2023
|
|
GINA KROG
|
Transport
|
Stabilised oil and condensate are transported to a floating storage and offloading vessel (Randgrid FSO), and then offloaded to shuttle tankers for further transport. Rich gas is exported to the Sleipner A facility for further processing. Sales gas is exported from Sleipner A via Gassled (Area D) to the market, while unstable condensate is exported to the Kårstø terminal.
|
23384544
|
28.02.2023
|
22.03.2023
|
|
GINA KROG
|
Development
|
Gina Krog is a field on the Utsira High in the central part of the North Sea, just north of the Sleipner Vest field. The water depth is 120 metres. Gina Krog was discovered in 1978, and the plan for development and operation (PDO) was approved in 2013. The field is developed with a fixed platform with living quarters and processing facilities. Production started in 2017. From 2023, Gina Krog will be supplied with power from shore, as part of the electrification of the Utsira High area.
|
23384544
|
28.02.2023
|
22.03.2023
|
|
GJØA
|
Recovery strategy
|
The field is produced by pressure depletion. In the southern segments, oil production was prioritised in the first years. Gas blow-down, production of the gas cap, started in 2015. Low pressure production was implemented in 2017.
|
4467574
|
28.02.2023
|
22.03.2023
|
|
GJØA
|
Transport
|
Stabilised oil is exported by pipeline connected to Troll Oil Pipeline II, for further transport to the Mongstad terminal. Rich gas is exported via the Far North Liquids and Associated Gas System (FLAGS) on the UK continental shelf, for further processing at the St Fergus terminal in the UK.
|
4467574
|
28.02.2023
|
22.03.2023
|
|
GJØA
|
Development
|
Gjøa is a field in the northern part of the North Sea, 50 kilometres northeast of the Troll field. The water depth is 360 metres. Gjøa was discovered in 1989, and the plan for development and operation (PDO) was approved in 2007. The field comprises several segments. Gjøa is developed with a semi-submersible production facility and includes five 4-slot templates. The field is partly supplied with power from shore. Production started in 2010. In 2019, Gjøa was granted a PDO exemption for the redevelopment of the P1 segment, including a 4-slot template. The Vega, Duva and Nova fields are tied-back to Gjøa for processing and further export.
|
4467574
|
28.02.2023
|
22.03.2023
|
|
GJØA
|
Status
|
Production from the new wells in the P1 segment was started in early 2021. The Nova field started producing via the Gjøa platform in July 2022.
|
4467574
|
28.02.2023
|
22.03.2023
|
|
GJØA
|
Reservoir
|
The reservoirs contain gas above a relatively thin oil zone in sandstone of Jurassic age in the Dunlin, Brent and Viking Groups. The field comprises several tilted fault segments with partly uncertain communication and variable reservoir quality. The reservoir depth is 2,200 metres.
|
4467574
|
28.02.2023
|
22.03.2023
|
|
GLITNE
|
Transport
|
Oil from Glitne was processed and stored on the production vessel and exported by tankers. Excess gas was injected into the Utsira Formation.
|
1272071
|
28.02.2023
|
22.03.2023
|
|
GLITNE
|
Status
|
The field was shut down in 2013, and decommissioning was completed in 2015.
|
1272071
|
28.02.2023
|
22.03.2023
|
|
GLITNE
|
Recovery strategy
|
The field was produced with pressure support from a large natural aquifer in the Heimdal Formation. Associated gas was used for gas lift in the horizontal wells until 2012.
|
1272071
|
28.02.2023
|
22.03.2023
|
|
GLITNE
|
Reservoir
|
Glitne produced oil from sandstone of Paleocene age in the upper part of the Heimdal Formation. The reservoir is in a deep marine fan system at a depth of 2,150 metres.
|
1272071
|
28.02.2023
|
22.03.2023
|
|
GLITNE
|
Development
|
Glitne is a field in the central part of the North Sea, 40 kilometres north of the Sleipner area. The water depth is 110 metres. Glitne was discovered in 1995, and the plan for development and operation (PDO) was approved in 2000. The field was developed with six horizontal production wells and one water injection well, tied-back to the production and storage vessel "Petrojarl 1". Production started in 2001.
|
1272071
|
28.02.2023
|
22.03.2023
|
|
GOLIAT
|
Reservoir
|
Goliat produces oil from sandstone of Triassic age in the Kobbe and Snadd Formations, and in the Kapp Toscana Group (Realgrunnen subgroup) of Triassic to Jurassic age. The reservoirs have thin gas caps and lie in a complex and segmented structure at depths of 1,100-1,800 metres.
|
5774394
|
28.02.2023
|
22.03.2023
|
|
GOLIAT
|
Development
|
Goliat is a field in the Barents Sea, 50 kilometres southeast of the Snøhvit field. The water depth is 360-420 metres. Goliat was discovered in 2000, and the plan for development and operation (PDO) was approved in 2009. The field is developed with a cylindrical floating production, storage and offloading facility (Sevan 1000 FPSO). Eight subsea templates with a total of 32 well slots are tied-back to the FPSO. Production started in 2016. Goliat was granted a PDO exemption for the Snadd reservoir in 2017 and the Goliat West reservoir in 2020. Production from these reservoirs started in 2017 and 2021 respectively.
|
5774394
|
28.02.2023
|
22.03.2023
|
|
GOLIAT
|
Status
|
Production regularity has been below expectation since production start-up. Continuous maintenance and modification work along with several revision stops have resulted in a gradually improved regularity of the facility. Several infill wells have been drilled since start up. In 2021, the Rødhette discovery (7122/6-3 S) was made in the area north of the Goliat field. More infill and exploration wells are planned in the coming years.
|
5774394
|
28.02.2023
|
22.03.2023
|
|
GOLIAT
|
Transport
|
The oil is offloaded to shuttle tankers for transport to the market. Future gas export is pending an export solution.
|
5774394
|
28.02.2023
|
22.03.2023
|
|
GOLIAT
|
Recovery strategy
|
The field is produced using water injection as pressure support. Additional pressure support results from reinjection of produced gas.
|
5774394
|
28.02.2023
|
22.03.2023
|
|
GRANE
|
Status
|
The recoverable volumes have increased since the initial PDO estimates. A permanent reservoir monitoring system installed on the seabed provides more detailed seismic data for improved reservoir management. Several wells have been drilled, and new wells are being planned, most of them as multilateral wells. The Breidablikk field is under development as a tie-back to the Grane platform.
|
1035937
|
28.02.2023
|
22.03.2023
|
|
GRANE
|
Transport
|
Oil from Grane is transported by pipeline to the Sture terminal for storage and export.
|
1035937
|
28.02.2023
|
22.03.2023
|
|
GRANE
|
Recovery strategy
|
The field is produced by gas injection at the top of the structure, and horizontal production wells at the bottom of the oil zone. In 2010, Grane terminated gas import from the Heimdal gas centre, and only produced gas was reinjected into the reservoir. Gas import started up again in 2014. Grane has limited water injection. Oil recovery is maintained by gas injection and drilling of new wells, including sidetracks from existing producers.
|
1035937
|
28.02.2023
|
22.03.2023
|
|
GRANE
|
Reservoir
|
Grane produces oil with high viscosity mostly from Paleocene sandstone in the Heimdal Formation with very good reservoir properties. The field comprises a main structure and some additional segments with full communication. The reservoir depth is 1,700 metres.
|
1035937
|
28.02.2023
|
22.03.2023
|
|
GRANE
|
Development
|
Grane is a field in the central part of the North Sea, just east of the Balder field. The water depth is 130 metres. Grane was discovered in 1991, and the plan for development and operation (PDO) was approved in 2000. The field has been developed with an integrated accommodation, drilling and processing facility with a steel jacket. The facility has 40 well slots. Production started in 2003. The Svalin field is tied-back to Grane platform.
|
1035937
|
28.02.2023
|
22.03.2023
|
|
GUDRUN
|
Development
|
Gudrun is a field in the central part of the North Sea, 50 kilometres north of the Sleipner Øst field. The water depth is 110 metres. Gudrun was discovered in 1975, and the plan for development and operation (PDO) was approved in 2010. The field is developed with a steel jacket and a topside with process facility and living quarters. Gudrun is tied-back to the Sleipner A facility with two pipelines, one for oil and one for wet gas. A PDO exemption was granted for the discovery 15/3-9 in 2013.Production started in 2014.
|
18116481
|
28.02.2023
|
22.03.2023
|
|
GUDRUN
|
Status
|
Production from Gudrun has started to decline. Work is ongoing to maximise recovery from the field by infill drilling, and additional infill targets are being matured. The facility will be operated with power from shore starting in 2023, as part of the electrification of the Utsira High area. Nearby discoveries and prospects may prove sufficient resources for development and tie-in to Gudrun.
|
18116481
|
28.02.2023
|
22.03.2023
|
|
GUDRUN
|
Reservoir
|
Gudrun produces oil and gas from sandstone in the Upper Jurassic Draupne Formation and the Middle Jurassic Hugin Formation. The reservoir quality in the Draupe Formation, which constitutes the main recoverable resources, is in general good. The Hugin Formation has larger variation in reservoir quality. The reservoirs lie at depths of 4,000-4,700 metres.
|
18116481
|
28.02.2023
|
22.03.2023
|
|
GUDRUN
|
Transport
|
Unstable oil and rich gas are transported in separate pipelines to the Sleipner A facility for further processing. Dry gas is exported via Gassled (Area D) to the market, while oil is transported to the Kårstø terminal.
|
18116481
|
28.02.2023
|
22.03.2023
|
|
GUDRUN
|
Recovery strategy
|
The field is mainly produced by pressure depletion. In 2022, water injection started in part of the field.
|
18116481
|
28.02.2023
|
22.03.2023
|
|
GULLFAKS
|
Development
|
Gullfaks is a field in the Tampen area in the northern part of the North Sea. The water depth is 130-220 metres. Gullfaks was discovered in 1978, and the plan for development and operation (PDO) for Gullfaks Phase I was approved in 1981. A PDO for Gullfaks Phase II was approved in 1985. Production started in 1986. The field has been developed with three integrated processing, drilling and accommodation facilities with concrete bases (Gullfaks A, B and C). Gullfaks B has a simplified processing plant with first stage separation. Gullfaks A and C receive and process oil and gas from Gullfaks Sør and Visund Sør. The Gullfaks facilities are also involved in production and transport from the Tordis, Vigdis and Visund fields. Production from Tordis is processed in a separate facility on Gullfaks C. PDO for Gullfaks Vest was approved in 1993, and for recovery from the Lunde Formation in 1995. An amended PDO for the Gullfaks field, covering prospects and small discoveries, which could be drilled and produced from existing facilities, was approved in 2005. Amendments to the Gullfaks PDO, covering Phase I and Phase II production from the Shetland/Lista deposit, were approved in 2015 and 2019, respectively. In 2020, an amended PDO for the development of the Hywind Tampen wind farm was approved. The wind farm consists of 11 floating turbines which supply electricity to the Gullfaks and Snorre platforms. These fields are the first in the world receiving power from a floating wind farm.
|
43686
|
28.02.2023
|
22.03.2023
|
|
GULLFAKS
|
Status
|
Drilling of new wells on Gullfaks has been challenging for many years due to overpressured areas in the Shetland/Lista interval. Production from the Shetland/Lista reservoirs has gradually contributed to reduced overpressures and improved drillability. Additional wells are being drilled continuously from all platforms. Hywind Tampen started power production in November 2022.
|
43686
|
28.02.2023
|
22.03.2023
|
|
GULLFAKS
|
Recovery strategy
|
The drive mechanism for the main reservoirs is primarily water injection, with gas injection and water alternating gas injection (WAG) in some areas. Initially, the drainage strategy for the Shetland/Lista reservoir was depletion, but pressure support by water injection has now been implemented.
|
43686
|
28.02.2023
|
22.03.2023
|
|
GULLFAKS
|
Transport
|
Oil is exported from Gullfaks A and Gullfaks C via loading buoys onto tankers. Rich gas is transported by Statpipe for further processing at the Kårstø terminal.
|
43686
|
28.02.2023
|
22.03.2023
|
|
GULLFAKS
|
Reservoir
|
Gullfaks produces oil from Middle Jurassic sandstone in the Brent Group, and from Lower Jurassic and Upper Triassic sandstone in the Statfjord Group and Cook and Lunde Formations. Recoverable oil is also present in fractured carbonate and shale in the overlying Shetland Group and Lista Formation. The reservoirs lie at a depth of 1,700-2,000 metres in rotated fault blocks in the west and a structural horst (raised fault block) in the east, with a highly faulted area in between. Reservoir quality is generally good to very good in the Jurassic reservoirs within each fault compartment, but poor reservoir communication is a challenge for pressure maintenance.
|
43686
|
28.02.2023
|
22.03.2023
|
|
GULLFAKS SØR
|
Reservoir
|
The Gullfaks Sør deposits produce oil and gas from Middle Jurassic sandstone in the Brent Group and from Lower Jurassic and Upper Triassic sandstone in the Statfjord Group and Cook and Lunde Formations. The reservoirs lie at a depth of 2,400-3,400 metres in several rotated fault blocks. The reservoirs in the Gullfaks Sør deposit are heavily segmented, with many internal faults and challenging flow characteristics, especially in the Statfjord Group and Lunde Formation. The other deposits in the Gullfaks Sør area have generally good reservoir quality.
|
43699
|
28.02.2023
|
22.03.2023
|
|
GULLFAKS SØR
|
Transport
|
The oil is transported to the Gullfaks A facility for processing, storage and further transport by tankers. Rich gas is processed on Gullfaks C and exported through Statpipe to the Kårstø-terminal.
|
43699
|
28.02.2023
|
22.03.2023
|
|
GULLFAKS SØR
|
Status
|
Gullfaks Sør oil production is on decline, but the field has large remaining gas volumes. New wells are continuously drilled in the Gullfaks Sør area with a licence-owned rig.
|
43699
|
28.02.2023
|
22.03.2023
|
|
GULLFAKS SØR
|
Recovery strategy
|
The Brent reservoir in Gullfaks Sør is produced by pressure depletion after gas injection ceased in 2009. The Statfjord Group and Lunde Formation in Gullfaks Sør are produced with pressure support from gas injection. Gas export from Rimfaks started in 2015, but limited gas injection was maintained in the Brent Group until 2018. The Gullveig, Gulltopp and Rutil deposits are produced by pressure depletion and partial aquifer drive. The Skinfaks deposit is produced with gas lift. The Rutil and Opal deposits are produced by pressure depletion.
|
43699
|
28.02.2023
|
22.03.2023
|
|
GULLFAKS SØR
|
Development
|
Gullfaks Sør is a field in the northern part of the North Sea, just south of the Gullfaks field. The water depth is 130-220 metres. Gullfaks Sør was discovered in 1978, but comprises several discoveries made in later years. The Gullfaks Sør deposits have been developed with a total of 13 subsea templates tied-back to the Gullfaks A and Gullfaks C facilities. The initial plan for development and operation (PDO) for Gullfaks Sør Phase I was approved in 1996 and included production of oil and condensate from the Gullfaks Sør, Rimfaks and Gullveig deposits. Production started in 1998. The PDO for Phase II was approved in 1998 and included production of gas from the Brent Group in the Gullfaks Sør deposit. In 2004, the Gulltopp discovery was included in Gullfaks Sør. Gulltopp is produced through an extended reach production well from the Gullfaks A facility. A PDO for the Skinfaks discovery and Rimfaks IOR was approved in 2005. An amended PDO for the redevelopment of Gullfaks Sør Statfjord Formation with two new subsea templates was approved in 2012. A PDO for Gullfaks Rimfaksdalen, which includes the Rutil and Opal deposits, was approved in 2015. It consists of a new subsea template and four production wells. Since 2017, gas production is increased by two subsea wet gas compressors, tied-back to the Gullfaks C platform. A PDO exemption for some prospects and small discoveries, which can be drilled and produced from existing Gullfaks Sør facilities, was granted in 2018. A PDO exemption for the Opal Sør deposit was granted in 2019.
|
43699
|
28.02.2023
|
22.03.2023
|
|
GUNGNE
|
Development
|
Gungne is a field in the Sleipner area in the central part of the North Sea. The water depth is 85 metres. Gungne was discovered in 1982, and the plan for development and operation (PDO) was approved in 1995. The field has been developed by three wells drilled from the Sleipner A installation, and production started in 1996. A PDO exemption was granted for the Skagerrak and Hod Formations in 2000, and for a well to the Gamma High structure in 2007.
|
43464
|
28.02.2023
|
22.03.2023
|
|
GUNGNE
|
Status
|
Gungne is in its late tail production phase. Only one well is currently on production, and there is limited or no production from the well on the Gamma High structure.
|
43464
|
28.02.2023
|
22.03.2023
|
|
GUNGNE
|
Transport
|
The well stream from Gungne is processed at the Sleipner A facility. Sales gas is exported from Sleipner A via Gassled (Area D) to the market. Unstable condensate is transported in a pipeline to the Kårstø terminal.
|
43464
|
28.02.2023
|
22.03.2023
|
|
GUNGNE
|
Recovery strategy
|
The field is produced by pressure depletion.
|
43464
|
28.02.2023
|
22.03.2023
|
|
GUNGNE
|
Reservoir
|
Gungne produces gas and condensate mainly from sandstone in the Triassic Skagerrak Formation, with some contribution from Middle Jurassic sandstone in the Hugin Formation and Paleogene sandstone in Ty Formation. The Skagerrak Formation has generally poorer reservoir quality than the Hugin and Ty Formations. The reservoirs lie at a depth of 2,800 metres.
|
43464
|
28.02.2023
|
22.03.2023
|
|
GYDA
|
Status
|
The field was shut down in 2020 and the facility was removed in 2022.
|
43492
|
28.02.2023
|
22.03.2023
|
|
GYDA
|
Reservoir
|
Gyda produced oil from three reservoirs in Upper Jurassic sandstone in the Ula Formation. The reservoir depth is 4,000 metres.
|
43492
|
28.02.2023
|
22.03.2023
|
|
GYDA
|
Transport
|
The oil was transported to the Ekofisk field via the oil pipeline from Ula, and further via Norpipe to Teesside in the UK. The gas was transported in a dedicated pipeline to Ekofisk for further transport via Norpipe to Emden in Germany. Gas export ceased in 2016.
|
43492
|
28.02.2023
|
22.03.2023
|
|
GYDA
|
Recovery strategy
|
The field was produced by water injection, as well as by pressure support from both gas cap and aquifer in parts of the field.
|
43492
|
28.02.2023
|
22.03.2023
|
|
GYDA
|
Development
|
Gyda is a field in the southern part of the Norwegian sector in the North Sea, between the Ula and Ekofisk fields. The water depth is 65 metres. Gyda was discovered in 1980, and the plan for development and operation (PDO) was approved in 1987. The field was developed with a combined drilling, accommodation and processing facility with a steel jacket. Production started in 1990. A PDO for Gyda Sør was approved in 1993.
|
43492
|
28.02.2023
|
22.03.2023
|
|
HANZ
|
Recovery strategy
|
The field will be produced by pressure support from water injection.
|
25307278
|
28.02.2023
|
22.03.2023
|
|
HANZ
|
Reservoir
|
The reservoir contains oil with a minor gas cap. It is in the Draupne Formation of Late Jurassic age at a depth of 2,350 metres. The reservoir is in presumably deep marine sandstone with good reservoir Properties.
|
25307278
|
28.02.2023
|
22.03.2023
|
|
HANZ
|
Transport
|
After initial processing on the Ivar Aasen field, the well stream will be transported to the Edvard Grieg field for final processing and export.
|
25307278
|
28.02.2023
|
22.03.2023
|
|
HANZ
|
Status
|
The field is under development and the production is planned to start in 2024.
|
25307278
|
28.02.2023
|
22.03.2023
|
|
HANZ
|
Development
|
Hanz is a field in the North Sea, 12 kilometres north of the Ivar Aasen field. The water depth is 115 metres. Hanz was discovered in 1997 and the plan for development and operation (PDO) was approved in 2013. The field will be developed with subsea templates tied-back to Ivar Aasen.
|
25307278
|
28.02.2023
|
22.03.2023
|
|
HEIDRUN
|
Status
|
Production from Heidrun is maintained at a relatively high level through continuous water and gas injection and drilling of new production and injection wells. Several methods are being evaluated to improve recovery and prolong the lifetime of the field, including infill wells, new drilling technology and methods for enhanced oil recovery (EOR). Production from the Alpha Horst segment started in 2022.
|
43771
|
28.02.2023
|
22.03.2023
|
|
HEIDRUN
|
Development
|
Heidrun is a field on Haltenbanken in the Norwegian Sea, 30 kilometres northeast of the Åsgard field. The water depth is 350 metres. Heidrun was discovered in 1985, and the plan for development and operation (PDO) was approved in 1991. The field has been developed with the world's first ever floating concrete tension-leg platform (TLP), installed over a large subsea template with 56 well slots. Six subsea templates in the southern and northern areas are additionally tied-back to the TLP. Production started in 1995. The floating storage unit (FSU) Heidrun B is permanently moored at the Heidrun platform since 2015. The PDO for the Heidrun northern flank was approved in 2000. The Maria field receives water for injection from Heidrun. The Dvalin field has a dedicated gas processing plant on the Heidrun platform.
|
43771
|
28.02.2023
|
22.03.2023
|
|
HEIDRUN
|
Reservoir
|
Heidrun produces oil and gas from Lower and Middle Jurassic sandstone in the Åre, Tilje, Ile and Garn Formations. The reservoir lies at a depth of 2,300 metres and is heavily faulted and segmented. The Ile and Garn Formations have good reservoir quality, while the Åre and Tilje Formations are more complex.
|
43771
|
28.02.2023
|
22.03.2023
|
|
HEIDRUN
|
Transport
|
The oil is exported via the Heidrun B FSU onto tankers and shipped to the market. The gas is transported by pipeline to the terminal at Tjeldbergodden and/or via the Åsgard Transport System (ÅTS) to the Kårstø terminal. The Dvalin gas is transported by pipeline via Polarled to the Nyhamna terminal.
|
43771
|
28.02.2023
|
22.03.2023
|
|
HEIDRUN
|
Recovery strategy
|
The field is produced with pressure maintenance using water and gas injection in the Ile and Garn Formations. In the more complex parts of the reservoir, in the Åre and Tilje Formations, the main recovery strategy is water injection. Some segments are also produced by pressure depletion.
|
43771
|
28.02.2023
|
22.03.2023
|
|
HEIMDAL
|
Transport
|
Originally, gas from Heimdal was transported in Statpipe via the Draupner and Ekofisk fields to continental Europe. When the Heimdal Gas Centre was established, a new gas pipeline was connected to the existing gas pipeline from the Frigg field to St Fergus in the UK. Gas can now also be transported via Vesterled to St Fergus. A gas pipeline was laid from Heimdal to the Grane field for gas injection at Grane. Condensate is transported by pipeline to the Brae field in the UK sector and further to Cruden Bay in the UK.
|
43590
|
28.02.2023
|
22.03.2023
|
|
HEIMDAL
|
Recovery strategy
|
The field was produced by pressure depletion.
|
43590
|
28.02.2023
|
22.03.2023
|
|
HEIMDAL
|
Development
|
Heimdal is a field in the central part of the North Sea. The water depth is 120 metres. Heimdal was discovered in 1972, and the plan for development and operation (PDO) was approved in 1981. The field was developed with an integrated drilling, production and accommodation facility with a steel jacket (HMP1). Production started in 1985. The PDO for Heimdal Jurassic was approved in 1992. The PDO for the Heimdal Gas Centre was approved in 1999, and included a new riser facility, connected by a bridge to HMP1. Heimdal is now a processing centre for other fields, presently Atla, Skirne, Vale and Valemon, and for Huldra until production ceased in 2014. The Huldra pipeline to Heimdal is now used for transport of rich gas from Valemon. Heimdal also serves as a hub for rich gas transported from Oseberg to continental Europe via the Draupner platforms.
|
43590
|
28.02.2023
|
22.03.2023
|
|
HEIMDAL
|
Status
|
Most of the wells were permanently plugged in 2015, and production from Heimdal ceased in 2020. Heimdal is used as a gas processing centre for tied-in fields until 2023. Work is ongoing to prepare for cease of gas processing at the Heimdal platform. A decommissioning plan for Heimdal was submitted in 2020 and according to the formal removal resolution, decommissioning must be completed by the end of 2028.
|
43590
|
28.02.2023
|
22.03.2023
|
|
HEIMDAL
|
Reservoir
|
Heimdal produced gas and some condensate from sandstone of Paleocene age in the Heimdal Formation. The reservoir lies in a massive turbidite system at a depth of 2,100 metres and has good quality.
|
43590
|
28.02.2023
|
22.03.2023
|
|
HOD
|
Transport
|
Oil and gas are transported in a shared pipeline to the Valhall field for further processing. Transport of oil and NGL from Valhall is routed via pipeline to the Ekofisk Centre and further to Teesside in the UK. Gas from Valhall is sent via Norpipe to Emden in Germany.
|
43485
|
28.02.2023
|
22.03.2023
|
|
HOD
|
Status
|
In April 2022, production started from Hod B. The Hod Saddle area is being produced through wells drilled from the Valhall field. The original Hod platform awaits decommissioning within 2026.
|
43485
|
28.02.2023
|
22.03.2023
|
|
HOD
|
Development
|
Hod is a field in the southern part of the Norwegian sector in the North Sea, about 13 kilometres south of the Valhall field. The water depth is 72 metres. Hod was discovered in 1974, and the plan for development and operation (PDO) was approved in 1988. The field was originally developed with an unmanned wellhead platform, remotely controlled from Valhall. Production started in 1990. A PDO for Hod Saddle was approved in 1994. Production from the original platform ceased in 2013. A PDO for the redevelopment of Hod with a new unmanned wellhead platform (Hod B) tied in to the Valhall field centre was approved in 2020.
|
43485
|
28.02.2023
|
22.03.2023
|
|
HOD
|
Recovery strategy
|
The field is produced by pressure depletion. Gas lift has been used in some wells to increase production.
|
43485
|
28.02.2023
|
22.03.2023
|
|
HOD
|
Reservoir
|
Hod produces oil from chalk in the Upper Cretaceous Tor and Hod Formations and the lower Paleocene Ekofisk Formation. The Tor Formation chalk is fine-grained and soft. Considerable fracturing allows oil and water to flow more easily than in the underlying Hod Formation. The reservoir depth is 2,700 metres. The field consists of three structures: Hod West, Hod East and Hod Saddle.
|
43485
|
28.02.2023
|
22.03.2023
|
|
HULDRA
|
Recovery strategy
|
The field was produced by pressure depletion and with low pressure production after 2007.
|
97002
|
28.02.2023
|
22.03.2023
|
|
HULDRA
|
Reservoir
|
Huldra produced gas and condensate from sandstone of Middle Jurassic age in the Brent Group. The reservoir is in a rotated fault block at a depth of 3,500-3,900 metres, and initially had high pressure and high temperature (HPHT). There are many small faults in the field and two main segments without pressure communication.
|
97002
|
28.02.2023
|
22.03.2023
|
|
HULDRA
|
Transport
|
The wet gas was transported to the Heimdal field and the condensate to Veslefrikk for processing and export. The Huldrapipe to Heimdal is now being used by the Valemon field.
|
97002
|
28.02.2023
|
22.03.2023
|
|
HULDRA
|
Development
|
Huldra is a field in the northern part of the North Sea, 16 kilometres west of the Veslefrikk field. The water depth is 125 metres. Huldra was discovered in 1982, and the plan for development and operation (PDO) was approved in 1999. The field was developed with a wellhead facility, including a simple process facility, and remotely operated from Veslefrikk B. Production started in 2001.
|
97002
|
28.02.2023
|
22.03.2023
|
|
HULDRA
|
Status
|
Production ceased in 2014, and the facility was removed in 2019.
|
97002
|
28.02.2023
|
22.03.2023
|
|
HYME
|
Development
|
Hyme is a field in the southern part of the Norwegian Sea, 19 kilometres northeast of the Njord field. The water depth is 250 metres. Hyme was discovered in 2009, and the plan for development and operation (PDO) was approved in 2011. The field is developed with a subsea template including one production well and one water injection well. Hyme is connected to the Njord A facility. Production started in 2013.
|
20474183
|
28.02.2023
|
22.03.2023
|
|
HYME
|
Status
|
Production stopped temporarily in 2016 when the Njord A facility was shut down and towed to land for reinforcement and modifications. Hyme is expected to resume production late 2022, when the Njord facility is in place again.
|
20474183
|
28.02.2023
|
22.03.2023
|
|
HYME
|
Reservoir
|
Hyme produces oil and gas from sandstone of Early and Middle Jurassic age in the Tilje and Ile Formations. The reservoir lies at a depth of 2,150 metres and has good quality.
|
20474183
|
28.02.2023
|
22.03.2023
|
|
HYME
|
Recovery strategy
|
The field is produced with pressure support from seawater injection. The production well is equipped with gas lift.
|
20474183
|
28.02.2023
|
22.03.2023
|
|
HYME
|
Transport
|
The well stream is transported to the Njord field and processed on the Njord A platform. The Njord facilities are used for both oil and gas export.
|
20474183
|
28.02.2023
|
22.03.2023
|
|
ISLAY
|
Status
|
The well is producing cyclically at a low rate.
|
21105675
|
28.02.2023
|
22.03.2023
|
|
ISLAY
|
Transport
|
Production is routed via the Forvie-Alwyn pipeline to the British Alwyn field for separation. The gas is exported via the Frigg UK Pipeline (FUKA) to the Shell-Esso Gas and Liquids (SEGAL) terminal at St Fergus in the UK, whereas the liquids are exported to the Sullom Voe terminal in the Shetland Islands.
|
21105675
|
28.02.2023
|
22.03.2023
|
|
ISLAY
|
Development
|
Islay is a field on the boundary to the UK sector in the northern part of the North Sea, 55 kilometres west of the Oseberg field. The Norwegian share of the field is 5.51 per cent. The water depth is 120 metres. Islay was discovered in 2008, and production started in 2012. The field is developed with one well tied to the Forvie manifold in the UK sector.
|
21105675
|
28.02.2023
|
22.03.2023
|
|
ISLAY
|
Reservoir
|
Islay produces gas from Middle Jurassic sandstone in the Brent Formation. The reservoir depth is 3,700-3,900 metres.
|
21105675
|
28.02.2023
|
22.03.2023
|
|
ISLAY
|
Recovery strategy
|
The field is produced by pressure depletion.
|
21105675
|
28.02.2023
|
22.03.2023
|
|
IVAR AASEN
|
Recovery strategy
|
The Ivar Aasen reservoir is produced by pressure support from water injection. The West Cable reservoir is produced by pressure depletion.
|
23384520
|
28.02.2023
|
22.03.2023
|
|
IVAR AASEN
|
Transport
|
Oil and gas are transported to the Edvard Grieg platform for final processing. The oil is exported by pipeline to the Grane Oil Pipeline, which is connected to the Sture terminal. The gas is exported in a separate pipeline to the Scottish Area Gas Evacuation (SAGE) system in the UK.
|
23384520
|
28.02.2023
|
22.03.2023
|
|
IVAR AASEN
|
Reservoir
|
Ivar Aasen produces oil from sandstone reservoirs. The field consists of the 16/1-9 Ivar Aasen discovery and the small 16/1-7 (West Cable) discovery. The reservoir in the Ivar Aasen discovery consists of fluvial sandstone of Late Triassic to Middle Jurassic age in the Skagerrak and Sleipner Formations and shallow marine sandstone in the Middle Jurassic Hugin Formation. The reservoir lies at a depth of 2,400 metres. It is compartmentalised and has moderate to good quality. Parts of the reservoir have an overlying gas cap. The reservoir in the West Cable discovery is in fluvial sandstone in the Middle Jurassic Sleipner Formation. It lies at a depth of 2,950 metres and has moderate quality.
|
23384520
|
28.02.2023
|
22.03.2023
|
|
IVAR AASEN
|
Development
|
Ivar Aasen is a field in the northern part of the North Sea, 30 kilometres south of the Grane and Balder fields. The water depth is 110 metres. Ivar Aasen was discovered in 2008, and the plan for development and operation (PDO) was approved in 2013. The development comprises a production, drilling and quarters (PDQ) platform with a steel jacket and a separate jack-up rig for drilling and completion. Production started in 2016. The platform is equipped for tie-in of a subsea template planned for the development of the Hanz field, and for possible development of other nearby discoveries. First stage processing is carried out on the Ivar Aasen platform, and the partly processed fluids are transported to the Edvard Grieg platform for final processing and export. From 2023, Ivar Aasen will be supplied with power from shore, as part of the electrification of the Utsira High area.
|
23384520
|
28.02.2023
|
22.03.2023
|
|
IVAR AASEN
|
Status
|
Since production start-up, additional injection and production wells have been drilled. Ivar Aasen production is on decline. The Hanz field and the discovery 16/1-29 S (Lille Prinsen) are planned to be tied-back to Ivar Aasen.
|
23384520
|
28.02.2023
|
22.03.2023
|
|
JETTE
|
Reservoir
|
Jette produced oil from sandstone of late Paleocene age in the Heimdal Formation. The reservoir is in a marine fan system at a depth of 2,200 metres.
|
21613906
|
28.02.2023
|
22.03.2023
|
|
JETTE
|
Transport
|
The well stream was transported to Jotun B and further to Jotun A for processing and loading.
|
21613906
|
28.02.2023
|
22.03.2023
|
|
JETTE
|
Development
|
Jette is a field in the central part of the North Sea, six kilometres south of the Jotun field. The water depth is 127 metres. Jette was discovered in 2009, and the plan for development and operation (PDO) was approved in 2012. The field was developed with a subsea template with two production wells tied-in to the Jotun A facility. Production started in 2013.
|
21613906
|
28.02.2023
|
22.03.2023
|
|
JETTE
|
Status
|
Production ceased in 2016, and the subsea template was removed in 2019.
|
21613906
|
28.02.2023
|
22.03.2023
|
|
JETTE
|
Recovery strategy
|
The field was produced with natural pressure support from the aquifer.
|
21613906
|
28.02.2023
|
22.03.2023
|
|
JOHAN CASTBERG
|
Reservoir
|
The reservoirs contain oil with gas caps in three separate sandstone deposits from Late Triassic to Middle Jurassic age in the Tubåen, Nordmela and Stø Formations. The reservoirs are located at depths of 1,350 to 1,900 metres. Reservoir properties in the Tubåen and Stø Formations are generally good; the Nordmela Formation is more heterogeneous with several lateral Barriers.
|
32017325
|
28.02.2023
|
22.03.2023
|
|
JOHAN CASTBERG
|
Status
|
The field is currently under development, and production is scheduled to start in 2024.
|
32017325
|
28.02.2023
|
22.03.2023
|
|
JOHAN CASTBERG
|
Transport
|
The oil will be offloaded to shuttle tankers and transported to the market.
|
32017325
|
28.02.2023
|
22.03.2023
|
|
JOHAN CASTBERG
|
Development
|
Johan Castberg is a field in the Barents Sea, 100 kilometres northwest of the Snøhvit field. The water depth is 370 metres. Johan Castberg consists of the three discoveries Skrugard, Havis and Drivis, proven between 2011 and 2013. The discoveries will be developed together, and the plan for development and operation (PDO) was approved in June 2018. The development concept is a production, storage and offloading vessel (FPSO) with additional subsea solutions including 18 horizontal production wells and 12 injection wells.
|
32017325
|
28.02.2023
|
22.03.2023
|
|
JOHAN CASTBERG
|
Recovery strategy
|
The field will be produced by pressure support from gas and water injection.
|
32017325
|
28.02.2023
|
22.03.2023
|
|
JOHAN SVERDRUP
|
Transport
|
Stabilised oil is exported from the riser platform through a new oil export pipeline that is connected to existing underground storage caverns at the Mongstad terminal. The gas is exported from the riser platform to the Kårstø terminal through a new pipeline connected to Statpipe.
|
26376286
|
28.02.2023
|
22.03.2023
|
|
JOHAN SVERDRUP
|
Recovery strategy
|
The field is produced by water injection as pressure support, as well as gas lift in the production wells. In the first development phase, production wells are placed centrally, high up in the thickest parts of the reservoirs. The water injection wells are placed near the oil-water contact. The distance between the production and injection wells is typically between four and five kilometres. In the second development phase, production and injection wells will be placed in the less central parts of the field.
|
26376286
|
28.02.2023
|
22.03.2023
|
|
JOHAN SVERDRUP
|
Reservoir
|
The main reservoir contains oil in Upper Jurassic intra-Draupne sandstone and lies at a depth of 1,900 metres. The quality of the main reservoir is excellent with very high permeability. The remaining oil resources are in sandstone in the Upper Triassic Statfjord Group and Middle to Upper Jurassic Vestland Group, as well as in spiculites in the Upper Jurassic Viking Group. Oil was also proven in Permian Zechstein carbonates.
|
26376286
|
28.02.2023
|
22.03.2023
|
|
JOHAN SVERDRUP
|
Development
|
Johan Sverdrup is a field on the Utsira High in the central part of the North Sea, 65 kilometres northeast of the Sleipner fields. The water depth is 115 metres. Johan Sverdrup was discovered in 2010 and the plan for development and operation (PDO) for Phase I was approved in 2015. The development solution for the first development phase is a field centre with four specialised platforms: living quarters, process, drilling and riser facilities. The four platforms are connected by bridges. The drilling platform has 48 well slots and is prepared for simultaneous drilling, well intervention and production. The field will be operated with power from shore throughout its lifetime. In 2019, production from Phase I started and the PDO for Phase II was approved. The plan comprises a process platform and five subsea templates, in addition to modifications on the riser platform.
|
26376286
|
28.02.2023
|
22.03.2023
|
|
JOHAN SVERDRUP
|
Status
|
The capacities for oil production and water injection in Phase I have been increased in 2021. Phase II started production in December 2022.
|
26376286
|
28.02.2023
|
22.03.2023
|
|
JOTUN
|
Transport
|
The Jotun FPSO is an integrated part of the Balder and Ringhorne facilities and is still in operation. It receives oil and gas from Ringhorne, and excess gas from Balder. Jotun processes and exports rich gas via Statpipe to Kårstø. The oil is exported via the production vessel at Jotun to tankers on the field.
|
43604
|
28.02.2023
|
22.03.2023
|
|
JOTUN
|
Development
|
Jotun is a field in the central part of the North Sea, 25 kilometres north of the Balder field. The water depth is 125 metres. Jotun was discovered in 1994, and the plan for development and operation (PDO) was approved in 1997. The field was developed with Jotun A, a combined production, storage and offloading vessel (FPSO), and Jotun B, a wellhead facility. Jotun is integrated with the Balder field. Production started in 1999.
|
43604
|
28.02.2023
|
22.03.2023
|
|
JOTUN
|
Reservoir
|
Jotun produced oil from sandstone of Paleocene age in the Heimdal Formation. The reservoir lies at 2,000 metres depth in a marine fan system and comprises three structures.
|
43604
|
28.02.2023
|
22.03.2023
|
|
JOTUN
|
Status
|
Production from the field ceased in 2016. Jotun B was removed in 2020, and the Jotun FPSO will be upgraded and relocated to continue operation for the Balder and Ringhorne Øst fields from 2024.
|
43604
|
28.02.2023
|
22.03.2023
|
|
JOTUN
|
Recovery strategy
|
The field was produced by pressure support from the aquifer and with gas lift. Produced water was injected into the Utsira Formation.
|
43604
|
28.02.2023
|
22.03.2023
|
|
KNARR
|
Development
|
Knarr is a field in the northern part of the North Sea, 50 kilometres northeast of the Snorre field. The water depth is 400 metres. Knarr was discovered in 2008, and the plan for development and operation (PDO) was approved in 2011. The Knarr field consists of two segments, Knarr West and Knarr Central. The development comprised a floating production, storage and offloading vessel (FPSO) and two subsea templates, including six production and injection wells. Production started in 2015.
|
20460988
|
28.02.2023
|
22.03.2023
|
|
KNARR
|
Reservoir
|
Knarr produced oil from Lower Jurassic sandstone in the Cook Formation. The reservoirs lie at a depth of 3,800 metres and have moderate to good quality.
|
20460988
|
28.02.2023
|
22.03.2023
|
|
KNARR
|
Recovery strategy
|
The field was produced with water injection for pressure maintenance.
|
20460988
|
28.02.2023
|
22.03.2023
|
|
KNARR
|
Transport
|
Oil was processed and stored on the Knarr FPSO and offloaded to shuttle tankers for export. Gas was exported via the Far North Liquids and Associated Gas System (FLAGS) to St Fergus in the UK.
|
20460988
|
28.02.2023
|
22.03.2023
|
|
KNARR
|
Status
|
Production from Knarr ceased in 2022. According to the formal removal resolution, decommissioning must be completed six years after cease of production.
|
20460988
|
28.02.2023
|
22.03.2023
|
|
KRISTIN
|
Transport
|
The well stream is processed at the Kristin platform and the rich gas is sent via the Åsgard Transport System (ÅTS) to the Kårstø terminal, where NGL and condensate is extracted. Light oil separated out on Kristin is transferred to the Åsgard C facility for storage and export.
|
1854729
|
28.02.2023
|
22.03.2023
|
|
KRISTIN
|
Reservoir
|
Kristin produces gas and condensate from Jurassic sandstone in the Garn, Ile and Tofte Formations. The reservoirs are at a depth of 4,600 metres and was initially at high pressure and high temperature (HPHT).
|
1854729
|
28.02.2023
|
22.03.2023
|
|
KRISTIN
|
Development
|
Development:Kristin is a field in the Norwegian Sea, a few kilometres southwest of the Åsgard field. The water depth is 370 metres. Kristin was discovered in 1997, and the plan for development and operation (PDO) was approved in 2001. The field is developed with four 4-slot subsea templates tied-back to a semi-submersible facility for processing. Production started in 2005. An amended PDO was approved in 2007. The Tyrihans and Maria fields are tied to the Kristin facility. A PDO for Kristin South, including development of the Kristin Q segment and Lavrans, was approved in 2022.
|
1854729
|
28.02.2023
|
22.03.2023
|
|
KRISTIN
|
Status
|
Kristin production is in the tail phase. The Kristin South development is ongoing and comprises development of the Kristin Q segment and the Lavrans field. Expected production start-up is in 2024.
|
1854729
|
28.02.2023
|
22.03.2023
|
|
KRISTIN
|
Recovery strategy
|
The field is produced by pressure depletion. Low pressure production was implemented in 2014.
|
1854729
|
28.02.2023
|
22.03.2023
|
|
KVITEBJØRN
|
Reservoir
|
Kvitebjørn produces gas and condensate from Middle Jurassic sandstone in the Brent Group. Secondary reservoirs are in the Lower Jurassic Cook Formation and Upper Triassic Statfjord Group. The reservoirs lie at a depth of 4,000 metres and initially had high pressure and high temperature (HPHT). The reservoir quality is good.
|
1036101
|
28.02.2023
|
22.03.2023
|
|
KVITEBJØRN
|
Status
|
The production on Kvitebjørn is declining. A drilling campaign for new production wells started in 2020, but the drilling program is now revised after experiencing many challenges in the new wells.
|
1036101
|
28.02.2023
|
22.03.2023
|
|
KVITEBJØRN
|
Transport
|
Rich gas is transported through the Kvitebjørn Gas Pipeline to the Kollsnes terminal, while condensate is transported in a pipeline tied to the Troll Oil Pipeline II and further to the Mongstad terminal.
|
1036101
|
28.02.2023
|
22.03.2023
|
|
KVITEBJØRN
|
Development
|
Kvitebjørn is a field in the Tampen area in the northern part of the North Sea, 15 kilometres southeast of the Gullfaks field. The water depth is 190 metres. Kvitebjørn was discovered in 1994, and the plan for development and operations (PDO) was approved in 2000. The field is developed with an integrated accommodation, drilling and processing facility with a steel jacket. Production started in 2004. An amended PDO including several deposits and prospects was approved in 2006.
|
1036101
|
28.02.2023
|
22.03.2023
|
|
KVITEBJØRN
|
Recovery strategy
|
The field is produced by pressure depletion. Gas pre-compression started in 2014 and has increased the gas recovery from the field.
|
1036101
|
28.02.2023
|
22.03.2023
|
|
LILLE-FRIGG
|
Development
|
Lille-Frigg is a field in the central part of the North Sea, 16 kilometres east of the Frigg field. The water depth is 110 metres. Lille-Frigg was discovered in 1975, and the plan for development and operation (PDO) was approved in 1991. The field was developed with a subsea installation with three production wells tied-back to the Frigg field. Production started in 1994.
|
43583
|
28.02.2023
|
22.03.2023
|
|
LILLE-FRIGG
|
Reservoir
|
The Lille-Frigg field produced gas and condensate from sandstone of Jurassic age in the Brent Group. The reservoir lies at a depth of 3,650 metres.
|
43583
|
28.02.2023
|
22.03.2023
|
|
LILLE-FRIGG
|
Recovery strategy
|
The field was produced by pressure depletion.
|
43583
|
28.02.2023
|
22.03.2023
|
|
LILLE-FRIGG
|
Status
|
The field was shut down in 1999 and the installation was removed in 2001. Lille-Frigg is planned to be redeveloped as a subsea tie-back to a new production platform as part of the Fulla development. A PDO for Fulla was submitted in December 2022.
|
43583
|
28.02.2023
|
22.03.2023
|
|
LILLE-FRIGG
|
Transport
|
The well stream was transported directly to the Frigg field for processing. The gas was transported via pipeline to St Fergus in the UK. Stabilised condensate was transported via Frostpipe to the Oseberg field and onward to the Sture terminal.
|
43583
|
28.02.2023
|
22.03.2023
|
|
MARIA
|
Recovery strategy
|
The field is produced by water injection for pressure support. The wells are equipped with gas lift.
|
26465170
|
28.02.2023
|
22.03.2023
|
|
MARIA
|
Reservoir
|
Maria produces oil and gas from massive sandstone with shale layers in the Middle Jurassic Garn Formation. The reservoir is at a depth of 3,800 metres.
|
26465170
|
28.02.2023
|
22.03.2023
|
|
MARIA
|
Development
|
Maria is a field on Haltenbanken in the Norwegian Sea, 25 kilometres east of the Kristin field. The water depth is 300 metres. Maria was discovered in 2010, and the plan for development and production (PDO) was approved in 2015. The field is developed as a subsea tie-back with two templates. There are five producers and two water injectors on the field. Gas for gas lift is supplied from the Åsgard B facility via the Tyrihans D template. Sulphate-reduced water for injection is supplied from Heidrun. Production started in 2017. A PDO for Maria phase 2 was submitted in November 2022.
|
26465170
|
28.02.2023
|
22.03.2023
|
|
MARIA
|
Status
|
Production has been lower than forecasted since start-up due to limited vertical reservoir communication. Several measures have been taken to increase production from upper and lower Garn. The PDO for Maria phase 2 which comprises drilling of more wells will increase the recovery from mid Garn. Total recovery from the field is still expected to be lower than the original PDO estimates.
|
26465170
|
28.02.2023
|
22.03.2023
|
|
MARIA
|
Transport
|
The well stream is routed to the Kristin platform for processing and further export together with the gas and oil from the Kristin and Tyrihans fields. Stabilised oil is transported from Kristin to Åsgard C and further offloaded to shuttle tankers. The rich gas is sent via the Åsgard Transport System (ÅTS) to the Kårstø terminal, where NGL and condensate is extracted.
|
26465170
|
28.02.2023
|
22.03.2023
|
|
MARTIN LINGE
|
Recovery strategy
|
The gas is produced by pressure depletion. Oil from the Frigg reservoir is produced by natural aquifer drive and gas lift. Some produced water is reinjected.
|
21675447
|
28.02.2023
|
22.03.2023
|
|
MARTIN LINGE
|
Reservoir
|
Martin Linge produces mainly gas and condensate from sandstone of Middle Jurassic age in the Brent Group. The reservoirs are structurally complex with high pressure and high temperature (HPHT) at depths of 3,700-4,400 metres. In addition, there is oil in the Frigg Formation of Eocene age. The Frigg reservoir is at a depth of 1,750 metres and has good quality.
|
21675447
|
28.02.2023
|
22.03.2023
|
|
MARTIN LINGE
|
Status
|
The platform jacket was installed on the field in 2014, and the topside modules in 2018. Production started in June 2021.
|
21675447
|
28.02.2023
|
22.03.2023
|
|
MARTIN LINGE
|
Transport
|
Rich gas is transported to the Frigg UK pipeline (FUKA), and on to the Shell-Esso Gas and Liquid (SEGAL) terminal at St Fergus in the UK. Oil and condensate are exported via tankers from the FSO.
|
21675447
|
28.02.2023
|
22.03.2023
|
|
MARTIN LINGE
|
Development
|
Martin Linge is a field near the border to the UK sector in the northern part of the North Sea, 42 kilometres west of the Oseberg field. The water depth is 115 metres. Martin Linge was discovered in 1978, and the plan for development and operation (PDO) was approved in 2012. The development concept is a fully integrated fixed production platform and a floating storage and offloading unit (FSO) for oil storage. The installation is supplied with power from shore. A PDO exemption for the Herja discovery and the Hervor prospect was granted in 2017.
|
21675447
|
28.02.2023
|
22.03.2023
|
|
MARULK
|
Transport
|
The well stream is sent to the Norne FPSO for processing. The gas is then transported via the Åsgard Transport System (ÅTS) to the Kårstø terminal.
|
18212090
|
28.02.2023
|
22.03.2023
|
|
MARULK
|
Status
|
Marulk production is in the decline phase. Production from Marulk is limited by the commercial agreement with the Norne licensees and the gas handling capacity on the Norne FPSO. Marulk has been able to produce above the forecasted volumes for 2022 because of excess capacity available on Norne.
|
18212090
|
28.02.2023
|
22.03.2023
|
|
MARULK
|
Recovery strategy
|
The field is produced by pressure depletion.
|
18212090
|
28.02.2023
|
22.03.2023
|
|
MARULK
|
Development
|
Marulk is a field in the Norwegian Sea, 25 kilometres southwest of the Norne field. The water depth is 370 metres. Marulk was discovered in 1992, and the plan for development and operation (PDO) was approved in 2010. The field is developed with a subsea template tied-back to the production, storage and offloading vessel (FPSO) Norne. Production started in 2012.
|
18212090
|
28.02.2023
|
22.03.2023
|
|
MARULK
|
Reservoir
|
Marulk produces gas from Cretaceous sandstone in the Lysing- and Lange Formations. The reservoirs are located at a depth of 2,800-2,850 metres. Both reservoirs are in turbidite fans and have moderate to good quality.
|
18212090
|
28.02.2023
|
22.03.2023
|
|
MIKKEL
|
Status
|
The pressure decline in the reservoir has been less than anticipated. This has resulted in increased recoverable volumes compared to PDO estimates. Installation of the Åsgard subsea gas compressor (ÅSC) in 2015/2016 has accelerated and prolonged gas production from the field. The ÅSC Phase II development is ongoing. A stable supply of gas with low CO2 content from the Mikkel field is important for dilution of gas with high CO2 content from the Kristin field in the Åsgard Transport System.
|
1630514
|
28.02.2023
|
22.03.2023
|
|
MIKKEL
|
Recovery strategy
|
The field is produced by pressure depletion.
|
1630514
|
28.02.2023
|
22.03.2023
|
|
MIKKEL
|
Transport
|
The well stream from Mikkel is combined with the well stream from the Midgard deposit and routed to the Åsgard B facility for processing. The condensate is separated from the gas and stabilised before being shipped together with condensate from the Åsgard field. The condensate is sold as oil. The rich gas is transported via the Åsgard Transport System (ÅTS) to the Kårstø terminal for separation of the natural gas liquids (NGL). The dry gas is transported from Kårstø to continental Europe via the Europipe II pipeline.
|
1630514
|
28.02.2023
|
22.03.2023
|
|
MIKKEL
|
Reservoir
|
Mikkel produces gas and condensate from Jurassic sandstone in the Garn, Ile and Tofte Formations. The field consists of six structures separated by faults, all with good reservoir quality. It has a 300-metre-thick gas/condensate column and a thin underlying oil zone. The reservoir depth is 2,500 metres.
|
1630514
|
28.02.2023
|
22.03.2023
|
|
MIKKEL
|
Development
|
Mikkel is a field in the eastern part of the Norwegian Sea, 30 kilometres north of the Draugen field. The water depth is 220 metres. Mikkel was discovered in 1987, and the plan for development and operation (PDO) was approved in 2001. The field is developed with two subsea templates tied-back to the Åsgard B facility. Production started in 2003.
|
1630514
|
28.02.2023
|
22.03.2023
|
|
MIME
|
Reservoir
|
Mime produced oil from sandstone of Late Jurassic age in the Ula Formation. The reservoir depth is 4,200 metres.
|
43792
|
28.02.2023
|
22.03.2023
|
|
MIME
|
Development
|
Mime is a field in the southern part of the Norwegian sector in the North Sea, six kilometres northeast of the Cod field. The water depth is 80 metres. Mime was discovered in 1982, and the plan for development and operation (PDO) was approved in 1992. The field was developed with a subsea well tied to the Cod facility. Production started 1993.
|
43792
|
28.02.2023
|
22.03.2023
|
|
MIME
|
Status
|
The field was shut down in 1993 and the facility was removed in 1999. Currently, there are no plans to recover the remaining resources.
|
43792
|
28.02.2023
|
22.03.2023
|
|
MIME
|
Recovery strategy
|
The filed was produced by pressure depletion.
|
43792
|
28.02.2023
|
22.03.2023
|
|
MIME
|
Transport
|
The well stream from Mime was mixed with gas and condensate from the Cod field and transported to the Ekofisk Complex. The oil was transported further to Teesside in the UK, whereas the gas was used at the Ekofisk Complex.
|
43792
|
28.02.2023
|
22.03.2023
|
|
MORVIN
|
Recovery strategy
|
The field is produced by pressure depletion.
|
4966234
|
28.02.2023
|
22.03.2023
|
|
MORVIN
|
Transport
|
The well stream from Morvin is transported by a heated, 20-kilometre pipeline to the Åsgard B facility for processing and further transport.
|
4966234
|
28.02.2023
|
22.03.2023
|
|
MORVIN
|
Development
|
Morvin is a field in the Norwegian Sea, 15 kilometres west of the Åsgard field. The water depth is 360 metres. Morvin was discovered in 2001, and the plan for development and production (PDO) was approved in 2008. The field is developed with two 4-slot subsea templates, tied to the Åsgard B facility. Production started in 2010.
|
4966234
|
28.02.2023
|
22.03.2023
|
|
MORVIN
|
Reservoir
|
Morvin produces gas and oil from Jurassic sandstone in the Tilje, Tofte, Ile, Garn and Spekk Formations. The reservoirs lie in a rotated and tilted fault block at a depth of 4,500-4,700 metres. They have high pressure and high temperature (HPHT).
|
4966234
|
28.02.2023
|
22.03.2023
|
|
MORVIN
|
Status
|
Drilling of new wells on Morvin is challenging. Well intervention in existing wells is planned for 2023.
|
4966234
|
28.02.2023
|
22.03.2023
|
|
MURCHISON
|
Reservoir
|
Murchison produced oil from sandstone of Middle Jurassic age in the Brent Group.
|
43665
|
28.02.2023
|
22.03.2023
|
|
MURCHISON
|
Recovery strategy
|
The field was produced with pressure support from water injection.
|
43665
|
28.02.2023
|
22.03.2023
|
|
MURCHISON
|
Transport
|
The well stream was sent through the Brent Pipeline System to Sullom Voe in the Shetland Islands in the UK.
|
43665
|
28.02.2023
|
22.03.2023
|
|
MURCHISON
|
Status
|
Production ceased in 2014, and the platform was removed in 2017.
|
43665
|
28.02.2023
|
22.03.2023
|
|
MURCHISON
|
Development
|
Murchison is a field in the Tampen area in the northern part of the North Sea, on the border between the Norwegian and UK sectors. The Norwegian share of the field was 22.2 per cent. Murchison was discovered in 1975, and the plan for development and operation was approved in 1976. The field was developed in the UK sector with a combined drilling, accommodation and production facility. The British and Norwegian licensees and authorities entered into an agreement in 1979 concerning common exploitation of the resources on the Murchison field. Production started in 1980.
|
43665
|
28.02.2023
|
22.03.2023
|
|
NJORD
|
Recovery strategy
|
Initial production strategy was gas injection for pressure support in parts of the reservoir and pressure depletion in the rest of the reservoir. After gas export started in 2007, only minor volumes of gas have been injected. Due to the complex reservoir with many faults, the field has a relatively low recovery factor.
|
43751
|
28.02.2023
|
22.03.2023
|
|
NJORD
|
Development
|
Njord is a field in the Norwegian Sea, 30 kilometres west of the Draugen field. The water depth is 330 metres. The Njord field was discovered in 1986, and the plan for development and operation (PDO) was approved in 1995. Njord is developed with a floating steel platform unit, Njord A, containing drilling and processing facilities, and a storage vessel, Njord Bravo. Production started in 1997. An amended PDO was approved in 2017. The Hyme field is tied to the Njord facility.
|
43751
|
28.02.2023
|
22.03.2023
|
|
NJORD
|
Reservoir
|
The pressure decline in the reservoir has been less than anticipated. This has resulted in increased recoverable volumes compared to PDO estimates. Installation of the Åsgard subsea gas compressor has accelerated and prolonged gas production from the field. A stable supply of gas with low CO2 content from the Mikkel field is important for dilution of gas with high CO2 content from the Kristin field in the Åsgard Transport System.
|
43751
|
28.02.2023
|
22.03.2023
|
|
NJORD
|
Transport
|
Produced oil is transported by pipeline to the storage vessel Njord Bravo, and further by tankers to the market. Gas from the field is exported through a 40-kilometre pipeline connected to the Åsgard Transport System (ÅTS) and further to the Kårstø terminal.
|
43751
|
28.02.2023
|
22.03.2023
|
|
NJORD
|
Status
|
The field resumed production in December 2022 after a temporarily shut down since 2016 due to Njord A structural integrity. Njord installations had been upgraded and prepared for tie-in of the Bauge and Fenja fields. It is planned for Njord to receive power from shore via the Draugen platform in a few years and thus be partially electrified.
|
43751
|
28.02.2023
|
22.03.2023
|
|
NORDØST FRIGG
|
Reservoir
|
Nordøst Frigg produced gas from sandstone of Eocene age in the Frigg Formation. The reservoir lies at a depth of 1,950 metres. It has pressure communication with the reservoir on the Frigg field via the aquifer.
|
43568
|
28.02.2023
|
22.03.2023
|
|
NORDØST FRIGG
|
Transport
|
The well stream was sent via pipeline to Frigg (TCP2) for further processing before export through the Frigg Norwegian Pipeline to St Fergus in the UK.
|
43568
|
28.02.2023
|
22.03.2023
|
|
NORDØST FRIGG
|
Recovery strategy
|
The field was produced by pressure depletion.
|
43568
|
28.02.2023
|
22.03.2023
|
|
NORDØST FRIGG
|
Development
|
Nordøst Frigg is a field in the central part of the North Sea. The water depth is 110 metres. The field was discovered in 1974, and the plan for development and operation (PDO) was approved in 1980. Nordøst-Frigg was developed with a seabed template with six wells and was remotely operated from the Frigg field using a control tower. The control tower consisted of a deck and a 126-metre-high steel structure attached to a concrete foundation. Production started in 1983.
|
43568
|
28.02.2023
|
22.03.2023
|
|
NORDØST FRIGG
|
Status
|
The field was shut down in 1993 and the facility was removed in 1996. The planned development of the area between the Oseberg and Alvheim fields might lead to a future redevelopment of the field.
|
43568
|
28.02.2023
|
22.03.2023
|
|
NORNE
|
Status
|
Norne production is in the decline phase. Production challenges are related to reservoir souring, increasing water cut, scale and well integrity due to aging facilities. The key activities include identifying new well targets and optimising the water injection strategy. The discoveries 6608/10-17 S Verdande and 6507/3-8 Andvare are planned as new tie-ins to the Norne FPSO.
|
43778
|
28.02.2023
|
22.03.2023
|
|
NORNE
|
Development
|
Norne is a field in the Norwegian Sea, 80 kilometres north of the Heidrun field. The water depth is 380 metres. Norne was discovered in 1992, and the plan for development and operation (PDO) was approved in 1995. The field has been developed with a production, storage and offloading vessel (FPSO), connected to seven subsea templates. Production started in 1997. An amended PDO for several deposits in the area around the Norne and Urd fields was approved in 2008. The Alve, Urd, Skuld and Marulk fields are tied-back to the Norne FPSO.
|
43778
|
28.02.2023
|
22.03.2023
|
|
NORNE
|
Transport
|
The oil is loaded to tankers for export. Gas export started in 2001 through a dedicated pipeline to the Åsgard field and via Åsgard Transport System (ÅTS) to the Kårstø terminal.
|
43778
|
28.02.2023
|
22.03.2023
|
|
NORNE
|
Recovery strategy
|
The field is produced by water injection as the drive mechanism. Gas injection ceased in 2005 and all gas is exported.
|
43778
|
28.02.2023
|
22.03.2023
|
|
NORNE
|
Reservoir
|
Norne produces oil and gas from Jurassic sandstone. Oil is mainly found in the Ile and Tofte Formations, and gas in the Not Formation. The reservoir lies at a depth of 2,500 metres and has good quality.
|
43778
|
28.02.2023
|
22.03.2023
|
|
NOVA
|
Development
|
Nova is a field in the northern part of the North Sea, 17 kilometres southwest of the Gjøa field. The water depth is 370 metres. Nova was proven in 2012, and the plan for development and operation (PDO) was approved in 2018. The development consists of two 4-slot subsea templates, one with three oil producers and one with three water injectors, tied-back to the Gjøa platform.
|
33197696
|
28.02.2023
|
22.03.2023
|
|
NOVA
|
Status
|
Nova started production in July 2022.
|
33197696
|
28.02.2023
|
22.03.2023
|
|
NOVA
|
Reservoir
|
The reservoir contains oil with a gas cap in sandstone of Late Jurassic age in the Heather Formation of the Viking Group, at a depth of 2,500 metres. The reservoir quality is good.
|
33197696
|
28.02.2023
|
22.03.2023
|
|
NOVA
|
Recovery strategy
|
The field is produced by pressure support from water injection and with gas lift.
|
33197696
|
28.02.2023
|
22.03.2023
|
|
NOVA
|
Transport
|
The well stream is routed to the Gjøa platform for processing and export. The oil is transported further through the Troll Oil Pipeline II to the Mongstad terminal, and the gas is exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus in the UK.
|
33197696
|
28.02.2023
|
22.03.2023
|
|
ODA
|
Reservoir
|
Oda produces oil from sandstone of Late Jurassic age. The main reservoir is in the Ula Formation at a depth of 2,900 metres. The reservoir is steeply dipping and has good quality.
|
29412516
|
28.02.2023
|
22.03.2023
|
|
ODA
|
Development
|
Oda is a field in the southern part of the Norwegian sector in the North Sea, 14 kilometres east of the Ula field. The water depth is 65 metres. Oda was discovered in 2011, and the plan for development and operation (PDO) was approved in 2017. Oda is developed with one subsea template with two production wells and one injection well tied-back to the Ula field. Production started in 2019.
|
29412516
|
28.02.2023
|
22.03.2023
|
|
ODA
|
Status
|
Drilling of the production wells has shown that the reservoir is more complex and smaller than anticipated. Consequently, the estimated recoverable volumes have been decreased. In 2022, a sidetrack was drilled from one of the production wells.
|
29412516
|
28.02.2023
|
22.03.2023
|
|
ODA
|
Transport
|
The well stream is transported by pipeline to the Ula field for processing. The oil is exported to Ekofisk and then onward in Norpipe to the Teesside terminal in the UK. The gas is sold to Ula for injection into the reservoir to increase oil recovery from the Ula field.
|
29412516
|
28.02.2023
|
22.03.2023
|
|
ODA
|
Recovery strategy
|
The field is produced by pressure support from water injection.
|
29412516
|
28.02.2023
|
22.03.2023
|
|
ODIN
|
Transport
|
The gas was sent via pipeline to Frigg (TCP2) for further processing before export through the Frigg Norwegian Pipeline to the Shell-Esso Gas and Liquids (SEGAL) terminal at St Fergus in the UK.
|
43610
|
28.02.2023
|
22.03.2023
|
|
ODIN
|
Recovery strategy
|
The field was produced by pressure depletion. The reservoir had limited water drive compared with the other fields in the Frigg area.
|
43610
|
28.02.2023
|
22.03.2023
|
|
ODIN
|
Reservoir
|
Odin produced gas from sandstone of Eocene age in the Frigg Formation. The reservoir lies at a depth of 2,000 metres. It has pressure communication with the Frigg reservoir via the aquifer.
|
43610
|
28.02.2023
|
22.03.2023
|
|
ODIN
|
Development
|
Odin is a field in the central part of the North Sea, eight kilometres northeast of the Frigg field. The water depth is 100 metres. Odin was discovered in 1974, and the plan for development and operation (PDO) was approved in 1980. The development solution was a facility with simplified drilling and processing equipment and living quarters. Production started in 1984.
|
43610
|
28.02.2023
|
22.03.2023
|
|
ODIN
|
Status
|
The field was shut down in 1994 and the facility removed in 1997. The planned development of the area between the Oseberg and Alvheim fields might lead to a future redevelopment of the field.
|
43610
|
28.02.2023
|
22.03.2023
|
|
ORMEN LANGE
|
Transport
|
The well stream is transported in two multiphase pipelines to the Nyhamna terminal for processing and is exported in the Langeled pipeline via Sleipner to Easington in the UK.
|
2762452
|
28.02.2023
|
22.03.2023
|
|
ORMEN LANGE
|
Status
|
Ormen Lange production is declining, and reservoir monitoring is a key focus. Work is ongoing to increase recovery from the field. Land-based gas compression at the Nyhamna terminal started operation in 2017. Subsea gas compression is currently being installed.
|
2762452
|
28.02.2023
|
22.03.2023
|
|
ORMEN LANGE
|
Development
|
Ormen Lange is a field in the southern part of the Norwegian Sea, 120 kilometres west-northwest of the Nyhamna processing plant. The water depth varies from 800 to more than 1,100 metres. Ormen Lange was discovered in 1997, and the plan for development and operation (PDO) was approved in 2004. Deep water and seabed conditions made the development very challenging and triggered development of new technology. The field has been developed in several phases. The development comprises four 8-slot subsea templates with a total of 24 production wells. Production started in 2007 from two subsea templates in the central part of the field. In 2009 and 2011, two additional templates were installed in the southern and northern parts of the field, respectively. An amended PDO for subsea gas compression was approved in 2022.
|
2762452
|
28.02.2023
|
22.03.2023
|
|
ORMEN LANGE
|
Reservoir
|
Ormen Lange produces very dry gas and small amounts of condensate from Paleocene sandstone in the Egga Formation. The reservoir lies at a depth of 2,700-2,900 metres below sea level and has excellent quality.
|
2762452
|
28.02.2023
|
22.03.2023
|
|
ORMEN LANGE
|
Recovery strategy
|
The field is produced by pressure depletion.
|
2762452
|
28.02.2023
|
22.03.2023
|
|
OSEBERG
|
Development
|
Oseberg is a field in the northern part of the North Sea. The water depth is 100 metres. Oseberg was discovered in 1979, and the plan for development and operation (PDO) was approved in 1984. The field was developed in multiple phases and production started in 1988. The Oseberg Field Centre in the south originally consisted of two facilities: the process and accommodation facility Oseberg A and the drilling and water injection facility Oseberg B. A PDO for Oseberg C was approved in 1988 and included an integrated production, drilling and quarters facility (PDQ) in the northern part of the field. A PDO for the gas phase was approved in 1996 and included a facility for gas processing, Oseberg D. A PDO for the western flank, Vestflanken, was approved in 2003 and included a subsea template tied-back to Oseberg B. A PDO for Oseberg Delta was approved in 2005 and included a subsea template tied-back to Oseberg D. A PDO for Oseberg Delta II was approved in 2013 and included two subsea templates tied-back to the Oseberg Field Centre. A PDO for Oseberg Vestflanken II was approved in 2016 and included an unmanned wellhead platform (UWP), Oseberg H, and new wells from the existing G4 template on the western flank. A PDO for Oseberg Field Centre low pressure gas production and power from shore was approved in 2022. The Oseberg Øst, Oseberg Sør and Tune fields are tied to the Oseberg Field Centre.
|
43625
|
28.02.2023
|
22.03.2023
|
|
OSEBERG
|
Reservoir
|
Oseberg produces oil and gas from sandstone of Middle Jurassic age in the Brent Group. The main reservoirs are in the Oseberg and Tarbert Formations, but there is also production from the Etive and Ness Formations. The reservoirs lie at a depth of 2,300-2,700 metres and have generally good reservoir quality. The field is divided into several structures. The satellite structures west of the main structure also produce from the Statfjord Group and Cook Formation.
|
43625
|
28.02.2023
|
22.03.2023
|
|
OSEBERG
|
Recovery strategy
|
The Oseberg field is produced by pressure maintenance using gas and water injection, as well as pressure depletion in some structures. Massive upflank gas injection in the main field has provided excellent oil displacement, and a large gas cap has developed. Injection gas was previously imported from Troll Øst (TOGI). Gas blowdown has gradually started in main parts of the field, while other parts are maintaining injection.
|
43625
|
28.02.2023
|
22.03.2023
|
|
OSEBERG
|
Transport
|
The oil is transported through the Oseberg Transport System (OTS) to the Sture terminal. Gas export began in 2000. The gas is transported to the market via the Oseberg Gas Transport (OGT) pipeline to the Heimdal Gas Centre and further in the Statpipe-system to continental Europe, and via the Vesterled pipeline to the UK.
|
43625
|
28.02.2023
|
22.03.2023
|
|
OSEBERG
|
Status
|
The strategy for the main Oseberg reservoirs is to balance oil production with increasing gas offtake. New production wells are continuously being drilled to enhance oil recovery. Gas blowdown from the Oseberg Delta structure started in 2022. In addition, a project to reduce the inlet pressure on the Oseberg C facility was initiated in 2022. This project will increase oil recovery from the northern part of the field.
|
43625
|
28.02.2023
|
22.03.2023
|
|
OSEBERG SØR
|
Transport
|
The oil is transported from the Oseberg Sør facility by pipeline to the Oseberg Field Centre, where it is processed. It is then transported through the Oseberg Transport System (OTS) to the Sture terminal. The gas is transported via the Omega Nord deposit to the Oseberg Field Centre for processing and then to the market through Oseberg Gas Transport (OGT), either to Statpipe or Vesterled.
|
43645
|
28.02.2023
|
22.03.2023
|
|
OSEBERG SØR
|
Development
|
Oseberg Sør is a field in the northern part of the North Sea, just south of the Oseberg field. The water depth is 100 metres. Oseberg Sør was discovered in 1984, and the plan for development and operation (PDO) was approved in 1997. The field has been developed with an integrated steel facility with accommodation, drilling module and first-stage oil/gas separation. Final processing of oil and gas takes place at the Oseberg Field Centre. Production started in 2000. In addition, several deposits on the field have been developed with subsea templates tied-back to the Oseberg Sør facility: the PDO for Oseberg Sør J was approved in 2003, a PDO exemption for the G-Central structure was granted in 2008, and the PDO for the Stjerne deposit was approved in 2011. A PDO for the Oseberg Field Centre low pressure gas production and power from shore was approved in 2022 which includes power from shore to the Oseberg Sør facility.
|
43645
|
28.02.2023
|
22.03.2023
|
|
OSEBERG SØR
|
Reservoir
|
Oseberg Sør produces oil and gas from several deposits in sandstone of Jurassic age. The main reservoirs are in the Tarbert and Heather Formations. The reservoirs lie at a depth of 2,200-2,800 metres and have moderate quality.
|
43645
|
28.02.2023
|
22.03.2023
|
|
OSEBERG SØR
|
Status
|
Further maturation of drilling targets is a focus area, but lack of available well slots is a challenge. Several projects are under evaluation to increase recovery from Oseberg Sør.
|
43645
|
28.02.2023
|
22.03.2023
|
|
OSEBERG SØR
|
Recovery strategy
|
The field is produced with water and gas injection. In parts of the field, water alternating gas (WAG) injection is being used. Water for injection is produced from the Utsira Formation.
|
43645
|
28.02.2023
|
22.03.2023
|
|
OSEBERG ØST
|
Development
|
Oseberg Øst is a field in the northern part of the North Sea, 15 kilometres east of the Oseberg field. The water depth is 160 metres. Oseberg Øst was discovered in 1981, and the plan for development and operation (PDO) was approved in 1996. The field has been developed with an integrated fixed facility with accommodation, drilling equipment and first-stage separation of oil, water, and gas. Production started in 1999. A PDO exemption for the Beta East segment was granted in 2004.
|
43639
|
28.02.2023
|
22.03.2023
|
|
OSEBERG ØST
|
Transport
|
The oil is sent by pipeline to the Oseberg Field Centre for further processing and transport through the Oseberg Transport System (OTS) to the Sture terminal. The gas is mainly used for injection, gas lift and fuel.
|
43639
|
28.02.2023
|
22.03.2023
|
|
OSEBERG ØST
|
Reservoir
|
Oseberg Øst produces oil from Middle Jurassic sandstone in the Brent Group. The field consists of two structures which are separated by a sealing fault. The structures contain several oil-bearing layers with variable reservoir characteristics. The reservoir lies at a depth of 2,700-3,100 metres.
|
43639
|
28.02.2023
|
22.03.2023
|
|
OSEBERG ØST
|
Recovery strategy
|
The field is produced by partial pressure support from both water injection and gas injection. Water for injection is produced from the Utsira Formation.
|
43639
|
28.02.2023
|
22.03.2023
|
|
OSEBERG ØST
|
Status
|
Oseberg Øst is at the tail end of its production phase and the main challenge is to maximise the oil recovery within the field lifetime. Maximising the gas production rate is also of importance, as the produced gas is used as fuel supply for the platform power generator. To increase production, the focus is on drainage strategy, including optimisation of injection, infill drilling and well interventions. In addition, measures that reduce and optimise the energy consumption topside will be implemented.
|
43639
|
28.02.2023
|
22.03.2023
|
|
OSELVAR
|
Recovery strategy
|
The field was produced by pressure depletion.
|
5506919
|
28.02.2023
|
22.03.2023
|
|
OSELVAR
|
Status
|
Oselvar was shut down in 2018 and the facility was removed in 2022.
|
5506919
|
28.02.2023
|
22.03.2023
|
|
OSELVAR
|
Transport
|
The well stream was transported by pipeline to the Ula field for processing. The gas was used for injection in Ula for improved recovery, while the oil was transported by pipeline to the Ekofisk field for further export.
|
5506919
|
28.02.2023
|
22.03.2023
|
|
OSELVAR
|
Development
|
Oselvar is a field in the southern part of the Norwegian sector in the North Sea, 20 kilometres southwest of the Ula field. The water depth is 70 metres. Oselvar was discovered in 1991, and the plan for development and operation (PDO) was approved in 2009. The development concept was a subsea template with three horizontal production wells tied to Ula. Production started in 2012.
|
5506919
|
28.02.2023
|
22.03.2023
|
|
OSELVAR
|
Reservoir
|
Oselvar produced oil and gas from sandstone of Paleocene age in the Forties Formation. The reservoir has a gas cap and lies at a depth of 2,900-3,250 metres.
|
5506919
|
28.02.2023
|
22.03.2023
|
|
REV
|
Reservoir
|
Rev produces gas and some condensate from intra-Heather sandstone of Late Jurassic age. The reservoir is a simple structure divided into two segments. It surrounds a salt structure at 3,000 metres depth. Reservoir quality is good. Measurements show that the reservoir is in pressure communication with the Varg field.
|
4467554
|
28.02.2023
|
22.03.2023
|
|
REV
|
Recovery strategy
|
The field is produced by pressure depletion.
|
4467554
|
28.02.2023
|
22.03.2023
|
|
REV
|
Development
|
Rev is a field close to the UK border in the southern part of the Norwegian sector in the North Sea, four kilometres south of the Varg field. The water depth is 90-110 metres. Rev was discovered in 2001, and the plan for development and operation (PDO) was approved in 2007. The field is developed with a subsea template including three production wells connected to the Armada field on the UK continental shelf. Production started in 2009.
|
4467554
|
28.02.2023
|
22.03.2023
|
|
REV
|
Status
|
The estimated volumes have been reduced since the PDO. The field has been producing with very short production periods and long pressure build-up periods since 2013. Changes in the cyclical production frequency have provided longer production forecast from Rev.
|
4467554
|
28.02.2023
|
22.03.2023
|
|
REV
|
Transport
|
The well stream is routed through a 10-kilometre pipeline to the Armada field in the UK sector and further to the Teesside terminal for final processing. The condensate is sold as stabilised crude oil.
|
4467554
|
28.02.2023
|
22.03.2023
|
|
RINGHORNE ØST
|
Reservoir
|
Ringhorne Øst produces oil with associated gas from Jurassic sandstone in the Statfjord Group. The reservoir lies at a depth of 1,940 metres and has very good quality.
|
3505505
|
28.02.2023
|
22.03.2023
|
|
RINGHORNE ØST
|
Development
|
Ringhorne Øst is a field in the central part of the North Sea, six kilometres northeast of the Balder field. The water depth is 130 metres. Ringhorne Øst was discovered in 2003, and the plan for development and operation (PDO) was approved in 2005. The field is developed with four production wells drilled from the Ringhorne wellhead platform. Production started in 2006.
|
3505505
|
28.02.2023
|
22.03.2023
|
|
RINGHORNE ØST
|
Recovery strategy
|
The field is produced by natural water drive from a regional aquifer to the north and east of the structure. The wells have gas lift to optimise production, and this will be expanded due to increasing water production.
|
3505505
|
28.02.2023
|
22.03.2023
|
|
RINGHORNE ØST
|
Transport
|
Production is routed from the Ringhorne wellhead platform to the Balder production, storage and offloading vessel (FPSO) for processing, storage and export. The oil is transported by tankers. Any surplus gas is sent to the Jotun FPSO for export via Statpipe to the Kårstø terminal.
|
3505505
|
28.02.2023
|
22.03.2023
|
|
RINGHORNE ØST
|
Status
|
The field is in its tail production phase. Several new infill wells are planned to be drilled in the coming years. Ringhorne Øst will also benefit from an amended PDO for Balder and Ringhorne that was approved in 2020. Field lifetime will be prolonged, and production can benefit from increased capacity in the area.
|
3505505
|
28.02.2023
|
22.03.2023
|
|
SIGYN
|
Transport
|
The well stream is sent through two pipelines to the Sleipner A facility. Sales gas is exported from Sleipner A via Gassled (Area D). Unstable oil is exported by pipeline to the Kårstø terminal for final processing.
|
1630100
|
28.02.2023
|
22.03.2023
|
|
SIGYN
|
Recovery strategy
|
Sigyn East is produced with pressure support from gas injection and Sigyn West is produced by pressure depletion.
|
1630100
|
28.02.2023
|
22.03.2023
|
|
SIGYN
|
Status
|
The field is in its late tail production phase. Production is limited by well performance and available flowlines. Currently, there is only production from Sigyn East. Production from Sigyn West is limited because the available flowlines are used to inject gas and produce oil from Sigyn East. An infill well was put on production on Sigyn East in 2022 and the existing producer was converted to a gas injector.
|
1630100
|
28.02.2023
|
22.03.2023
|
|
SIGYN
|
Development
|
Sigyn is a field in the central part of the North Sea, 12 kilometres southeast of the Sleipner Øst field. The water depth is 70 metres. Sigyn was discovered in 1982, and the plan for development and operation (PDO) was approved in 2001. The field is developed with a 4-slot subsea template tied-back to the Sleipner A facility. Production started in 2002.
|
1630100
|
28.02.2023
|
22.03.2023
|
|
SIGYN
|
Reservoir
|
The Sigyn field produces gas and condensate from two separate deposits, Sigyn West and Sigyn East. Sigyn West contains rich gas and condensate, while Sigyn East contains light oil. Both reservoirs are in Triassic sandstone in the Skagerrak Formation and lie at a depth of 2,700 metres.
|
1630100
|
28.02.2023
|
22.03.2023
|
|
SINDRE
|
Status
|
The field has been shut down for a long time due to low reservoir pressure. It has been possible to produce the well for a limited period at the end of 2022 after pressure build-up. A new well is planned to be drilled in 2023 in the area between Sindre and Gimle fields. Sindre and Gimle have recently been merged into a unit called Brime.
|
29401178
|
28.02.2023
|
22.03.2023
|
|
SINDRE
|
Development
|
Sindre is a field in the northern part of the North Sea, three kilometres northeast of the Gullfaks field. The water depth is 250 metres. Sindre was discovered and granted exemption from a plan for development and operation (PDO) in 2017. The field is developed with one production well drilled from the Gullfaks C platform. Production started in 2017.
|
29401178
|
28.02.2023
|
22.03.2023
|
|
SINDRE
|
Transport
|
The well stream from Sindre is processed together with the production from the Gimle field at the Gullfaks C facility, and transported further with oil and gas from the Gullfaks field.
|
29401178
|
28.02.2023
|
22.03.2023
|
|
SINDRE
|
Reservoir
|
Sindre contains oil in Upper Triassic to Lower Jurassic sandstone in the Lunde Formation, Statfjord Group and Dunlin Group. The main reservoir lies at a depth of 3,100 metres. The reservoir quality is good, but sealing faults reduce communication in the reservoir. Reservoir is also identified in Middle Jurassic sandstone in the Brent Group.
|
29401178
|
28.02.2023
|
22.03.2023
|
|
SINDRE
|
Recovery strategy
|
The field is produced by pressure depletion, but rapid pressure decline may necessitate pressure support.
|
29401178
|
28.02.2023
|
22.03.2023
|
|
SKARV
|
Reservoir
|
Skarv produces gas and oil from Lower and Middle Jurassic sandstone in the Tilje, Ile and Garn Formations. The Garn Formation has good reservoir quality, while the Tilje Formation has relatively poor quality. The reservoirs are divided into several fault segments and lie at a depth of 3,300-3,700 metres.
|
4704482
|
28.02.2023
|
22.03.2023
|
|
SKARV
|
Recovery strategy
|
The field is produced with pressure support by gas injection and gas lift.
|
4704482
|
28.02.2023
|
22.03.2023
|
|
SKARV
|
Development
|
Skarv is a field in the northern part of the Norwegian Sea, 35 kilometres southwest of the Norne field. The water depth is 350-450 metres. Skarv was discovered in 1998, and the plan for development and operation (PDO) was approved in 2007. Skarv is a joint development of the Skarv, Idun, Ærfugl and Gråsel deposits. The development concept is a production, storage and offloading vessel (FPSO) with five subsea templates. Production started in 2013.
|
4704482
|
28.02.2023
|
22.03.2023
|
|
SKARV
|
Status
|
Skarv oil production is declining, and gas injection is important for oil recovery. Gas blowdown has started in 2022 from parts of the reservoir and will continuously be evaluated. Work is ongoing to evaluate the potential of infill wells and prospects in the area.
|
4704482
|
28.02.2023
|
22.03.2023
|
|
SKARV
|
Transport
|
The oil is offloaded to shuttle tankers, while the gas is transported to the Kårstø terminal in an 80-kilometre pipeline connected to the Åsgard Transport System (ÅTS).
|
4704482
|
28.02.2023
|
22.03.2023
|
|
SKIRNE
|
Reservoir
|
Skirne and Byggve produce gas and condensate from Middle Jurassic sandstone in the Brent Group. The Skirne deposit lies at a depth of 2,370 metres and the Byggve deposit at 2,900 metres. The reservoir quality is good.
|
2138816
|
28.02.2023
|
22.03.2023
|
|
SKIRNE
|
Status
|
Skirne is now in its tail phase and continuous production ceased in 2021 due to water breakthrough. The field produced for only a few days in 2022. The Byggve reservoir is flooded by formation water, and there is no remaining recoverable gas. A joint decommissioning plan for the Skirne and Atla fields was submitted to the authorities in 2015.
|
2138816
|
28.02.2023
|
22.03.2023
|
|
SKIRNE
|
Development
|
Skirne, including the Byggve deposit, is a field in the central part of the North Sea, 20 kilometres east of the Heimdal field. The water depth is 120 metres. Skirne was discovered in 1990, and the plan for development and operation (PDO) was approved in 2002. The field has been developed with two subsea templates tied to the Heimdal facility. Production started in 2004. The Atla field was tied-back to Skirne in 2012.
|
2138816
|
28.02.2023
|
22.03.2023
|
|
SKIRNE
|
Recovery strategy
|
The field is produced by pressure depletion.
|
2138816
|
28.02.2023
|
22.03.2023
|
|
SKIRNE
|
Transport
|
The well stream from Skirne is transported in a pipeline to the Heimdal facility for processing. The gas is transported from Heimdal in the Vesterled pipeline to the St Fergus terminal in the UK. Gas was previously also sent through Statpipe to continental Europe. Condensate is transported to the Brae field in the UK sector and further via the Forties pipeline system to Cruden Bay in the UK.
|
2138816
|
28.02.2023
|
22.03.2023
|
|
SKOGUL
|
Transport
|
The well stream from Skogul is routed by pipeline via the Vilje field to the Alvheim FPSO.
|
31164600
|
28.02.2023
|
22.03.2023
|
|
SKOGUL
|
Development
|
Skogul is a field in the central part of the North Sea, 30 kilometres northeast of the Alvheim field. The water depth is 110 metres. Skogul was discovered in 2010, and the plan for development and operation (PDO) was approved in 2018. The development concept is a 2-slot subsea template, including one dual-lateral production well, tied to the Alvheim production, storage and offloading vessel (FPSO) via the Vilje field. Production started in 2020.
|
31164600
|
28.02.2023
|
22.03.2023
|
|
SKOGUL
|
Recovery strategy
|
Skogul is produced by depletion and natural aquifer support.
|
31164600
|
28.02.2023
|
22.03.2023
|
|
SKOGUL
|
Status
|
The production has been higher than anticipated, even though the oil production is steadily declining due to increasing water cut.
|
31164600
|
28.02.2023
|
22.03.2023
|
|
SKOGUL
|
Reservoir
|
The reservoir contains oil with a minor gas cap in reservoir belonging to the Odin Formation. It is located at a depth of 2,100 metres and has excellent Properties.
|
31164600
|
28.02.2023
|
22.03.2023
|
|
SKULD
|
Reservoir
|
Skuld produces oil from sandstone of Early to Middle Jurassic age in the Åre, Tofte and Ile Formations. The field consists of the two deposits Fossekall and Dompap. The reservoirs have small gas caps and lie at a depth of 2,400-2,600 metres. The reservoir quality is moderate to good.
|
21350124
|
28.02.2023
|
22.03.2023
|
|
SKULD
|
Status
|
Identification of new infill drilling targets and prevention of scale problems are the main focus areas for Skuld.
|
21350124
|
28.02.2023
|
22.03.2023
|
|
SKULD
|
Recovery strategy
|
The field is produced with pressure support by water injection. Some of the wells are additionally supplied with gas lift to produce at low reservoir pressure and high water cut.
|
21350124
|
28.02.2023
|
22.03.2023
|
|
SKULD
|
Transport
|
The well stream is sent to the Norne FPSO. The oil is offloaded to shuttle tankers together with the oil from the Norne field. The gas is transported by pipeline from the Norne vessel to the Åsgard field, and further via the Åsgard Transport System (ÅTS) to the Kårstø terminal.
|
21350124
|
28.02.2023
|
22.03.2023
|
|
SKULD
|
Development
|
Skuld is a field in the Norwegian Sea, 20 kilometres north of the Norne field. The water depth is 340 metres. Skuld was discovered in 2008, and the plan for development and operation (PDO) was approved in 2012. The field is developed with three subsea templates tied-back to the Norne production, storage and offloading vessel (FPSO). Production started in 2013.
|
21350124
|
28.02.2023
|
22.03.2023
|
|
SLEIPNER VEST
|
Development
|
Sleipner Vest is a field in the central part of the North Sea. The water depth is 110 metres. Sleipner Vest was discovered in 1974, and the plan for development and operation (PDO) was approved in 1992. The field is developed with the Sleipner B production/wellhead facility, which is remotely operated from the Sleipner A facility on the Sleipner Øst field. Production started in 1996.
|
43457
|
28.02.2023
|
22.03.2023
|
|
SLEIPNER VEST
|
Transport
|
The well stream is sent to the Sleipner A facility for processing. Sales gas is exported from Sleipner A via Gassled (Area D) to the market. Unstable condensate is transported in a pipeline to the Kårstø terminal.
|
43457
|
28.02.2023
|
22.03.2023
|
|
SLEIPNER VEST
|
Reservoir
|
Sleipner Vest produces gas and condensate mainly from Middle Jurassic sandstone in the Hugin Formation. Minor hydrocarbon volumes occur locally in the Sleipner Formation. The reservoir lies at a depth of 3,450 metres and is highly segmented. Faults in the field are generally not sealing and communication between the sand deposits is good.
|
43457
|
28.02.2023
|
22.03.2023
|
|
SLEIPNER VEST
|
Status
|
Sleipner Vest is in the middle of the tail production phase. A 4D seismic survey was acquired in 2020. Results are being used in planning future drilling campaigns as well as de-risking exploration targets.
|
43457
|
28.02.2023
|
22.03.2023
|
|
SLEIPNER VEST
|
Recovery strategy
|
The field is produced by pressure depletion.
|
43457
|
28.02.2023
|
22.03.2023
|
|
SLEIPNER ØST
|
Development
|
Sleipner Øst is a field in the central part of the North Sea. The water depth is 80 metres. Sleipner Øst was discovered in 1981, and the plan for development and operation (PDO) was approved in 1986. The field has been developed with Sleipner A, an integrated processing, drilling and accommodation facility with a concrete base structure. The development includes the Sleipner R riser facility, which connects Sleipner A to the pipelines for gas transport, and the Sleipner T facility for processing and CO2 removal. Production started in 1993. A PDO for Loke Heimdal was approved in 1991 and for Loke Triassic in 1995. Two subsea templates were installed, one for production from the northern part of Sleipner Øst and one for production from the Loke deposit. The Alpha Nord segment was developed in 2004 with a subsea template connected to Sleipner T. The Utgard field is tied-back to Sleipner T for processing and CO2 removal. The CO2 is injected into the Utsira Formation via a dedicated well at Sleipner A. The Sigyn, Gungne, Gudrun and Gina Krog fields are tied-back to Sleipner A.
|
43478
|
28.02.2023
|
22.03.2023
|
|
SLEIPNER ØST
|
Transport
|
Sales gas is exported from the Sleipner A facility via Gassled (Area D) to market. Unstable condensate is transported to the Kårstø terminal by pipeline.
|
43478
|
28.02.2023
|
22.03.2023
|
|
SLEIPNER ØST
|
Reservoir
|
Sleipner Øst produces gas and condensate. The Sleipner Øst and Loke reservoirs are in Paleocene turbidite sandstone in the Ty Formation, Middle Jurassic shallow marine sandstone in the Hugin Formation and in continental sandstone in the Triassic Skagerrak Formation. In addition, gas has been proven in the Heimdal Formation, overlying the Ty Formation. The Ty Formation has good reservoir quality, while the Skagerrak Formation generally has poorer reservoir quality than both Ty and Hugin Formations. The reservoirs are at a depth of 2,300 metres.
|
43478
|
28.02.2023
|
22.03.2023
|
|
SLEIPNER ØST
|
Recovery strategy
|
The Hugin Formation reservoir is produced by pressure depletion. The reservoir in the Ty Formation was produced by dry gas recycling until 2005, and production from the Ty reservoir stopped in 2012. To optimise production, wells are produced at a reduced inlet pressure.
|
43478
|
28.02.2023
|
22.03.2023
|
|
SLEIPNER ØST
|
Status
|
Sleipner Øst is in the late tail production phase. The main focus is on increasing reserves and decreasing production decline. It is expected that Sleipner Øst continues operation for tied-back fields after cease of own production. As a part of the electrification of the Utsira High area, the facilities are planned to be operated with power from shore with start-up in 2023.
|
43478
|
28.02.2023
|
22.03.2023
|
|
SNORRE
|
Status
|
The remaining Snorre Expansion wells started production in 2022. Several measures to increase oil recovery from Snorre are being considered. Possible third party tie-ins may lead to further development of the field. Hywind Tampen started power production in November 2022. Measures to further reduce emissions are also considered.
|
43718
|
28.02.2023
|
22.03.2023
|
|
SNORRE
|
Development
|
Snorre is a field in the Tampen area in the northern part of the North Sea. The water depth is 300-350 metres. Snorre was discovered in 1979, and the plan for development and operation (PDO) was approved in 1988. The field is developed with the facilities Snorre A, located in the southern part of the field, Snorre B in the northern part and two subsea systems tied-back to Snorre A (SPS and SEP). Snorre A is a floating tension-leg platform for accommodation, drilling and processing. There is also a separate process module on Snorre A for full stabilisation of the well stream from the Vigdis field. Production from Snorre A started in 1992. The subsea production system SPS was installed on the field in 1992. It consists of one template with 20 slots for production and injection wells. In 1998, a PDO was approved for Snorre B, a semi-submersible integrated drilling, processing and accommodation facility. Snorre B started production in 2001. An amended PDO for the Snorre Expansion Project (SEP) was approved in 2018. SEP consists of six subsea templates, each with four wells, and production from the first wells started in 2020. An amended PDO for the development of the Hywind Tampen wind farm was approved in 2020. The wind farm consists of 11 floating turbines which supply electricity to the Snorre and Gullfaks platforms. These fields are the first in the world receiving power from a floating wind farm.
|
43718
|
28.02.2023
|
22.03.2023
|
|
SNORRE
|
Recovery strategy
|
The field is produced with pressure support from water injection, gas injection and water alternating gas injection (WAG). From 2019, all gas is reinjected to increase oil recovery.
|
43718
|
28.02.2023
|
22.03.2023
|
|
SNORRE
|
Transport
|
Oil and gas are separated at the Snorre A platform. The oil is stabilised at the Vigdis process module on Snorre A, then exported through the Vigdis pipeline to Gullfaks A. The oil is stored and loaded onto shuttle tankers at the Gullfaks field. All gas from Snorre and Vigdis is reinjected into the Snorre field. Fully processed oil from Snorre B is transported by pipeline to Statfjord B for storage and loading onto shuttle tankers.
|
43718
|
28.02.2023
|
22.03.2023
|
|
SNORRE
|
Reservoir
|
Snorre produces oil from Triassic and Lower Jurassic sandstone in the Alke and Lunde Formations and the Statfjord Group. The field consists of several large fault blocks. The reservoir is at a depth of 2,000-2,700 metres and has a complex structure with both channels and flow barriers.
|
43718
|
28.02.2023
|
22.03.2023
|
|
SNØHVIT
|
Transport
|
The well stream, with natural gas, CO2, natural gas liquids (NGL) and condensate, is transported in a 160-kilometre pipeline to the liquid natural gas (LNG) processing facility at Melkøya near Hammerfest. The CO2 is separated and returned to the field by pipeline for injection into the aquifer (Stø reservoir). LNG, liquid petroleum gas (LPG) and condensate are shipped to the market.
|
2053062
|
28.02.2023
|
22.03.2023
|
|
SNØHVIT
|
Recovery strategy
|
The field is produced by pressure depletion.
|
2053062
|
28.02.2023
|
22.03.2023
|
|
SNØHVIT
|
Reservoir
|
Snøhvit produces gas with condensate from Lower and Middle Jurassic sandstone in the Nordmela and Stø Formations. The reservoirs lie at a depth of 2,300 metres and have moderate to good quality. Development of a thin oil zone underlying the gas at the Snøhvit structure is not included in the PDO.
|
2053062
|
28.02.2023
|
22.03.2023
|
|
SNØHVIT
|
Development
|
Snøhvit is a field in the central part of the Hammerfest Basin in the southern part of the Barents Sea. The water depth is 310-340 metres. Snøhvit was discovered in 1984, and the plan for development and operation (PDO) was approved in 2002. Snøhvit was the first field development in the Barents Sea. The field includes the Snøhvit, Albatross and Askeladd structures and has been developed in multiple phases. The development includes several subsea templates. Two well slots are used for CO2 injection. Production started in 2007. A PDO exemption for Snøhvit North was granted in 2015.
|
2053062
|
28.02.2023
|
22.03.2023
|
|
SNØHVIT
|
Status
|
Snøhvit production is in its plateau phase. Since production started, additional production wells have been drilled in different structures. Work is ongoing to evaluate future compression solutions, as well as measures for reducing CO2 emissions from the onshore facility at Melkøya. The Snøhvit production was shut-in after a fire at the LNG plant at Melkøya in 2020, but was resumed in June 2022 when the plant was fully operational again.
|
2053062
|
28.02.2023
|
22.03.2023
|
|
SOLVEIG
|
Recovery strategy
|
The field is produced by pressure support from water injection.
|
34833011
|
28.02.2023
|
22.03.2023
|
|
SOLVEIG
|
Reservoir
|
Solveig produces oil from sandstone and conglomerate of Triassic and presumably Devonian age. The main reservoir was formed in small basins along the southwestern flank of the South Utsira High. The reservoir contains oil with a small gas cap at a depth of 1,900 metres and has varying quality.
|
34833011
|
28.02.2023
|
22.03.2023
|
|
SOLVEIG
|
Transport
|
The well stream is transported via the Edvard Grieg field and onward by pipeline to the Sture terminal. The gas is exported via the Scottish Area Gas Evacuation (SAGE) infrastructure to the St Fergus terminal in the UK.
|
34833011
|
28.02.2023
|
22.03.2023
|
|
SOLVEIG
|
Status
|
Production from Solveig started in September 2021.
|
34833011
|
28.02.2023
|
22.03.2023
|
|
SOLVEIG
|
Development
|
Solveig is a field in the North Sea, 15 kilometres south of the Edvard Grieg field. The water depth is 100 metres. Solveig was discovered in 2013, and subsequently delineated by appraisal wells in 2014, 2015 and 2018. The plan for development and operation (PDO) was approved in 2019. Solveig is developed with five single wells, tied-back to the Edvard Grieg field.
|
34833011
|
28.02.2023
|
22.03.2023
|
|
STATFJORD
|
Recovery strategy
|
The field was originally produced by pressure support from water alternating gas injection (WAG), water injection and partially gas injection. Statfjord Late Life entails that all injection now has ceased. To release the solution gas from the remaining oil, depressurisation of the reservoirs started in 2007.
|
43658
|
28.02.2023
|
22.03.2023
|
|
STATFJORD
|
Status
|
Work is ongoing to extend the lifetime of the field. Plans include prolonging the lifetime of the platforms and drilling of many new wells in the years to come. Satellite fields tied-back to Statfjord as well as nearby discoveries will benefit from the lifetime extension.
|
43658
|
28.02.2023
|
22.03.2023
|
|
STATFJORD
|
Development
|
Statfjord is a field in the Tampen area in the northern part of the North Sea, on the border between the Norwegian and UK sectors. The Norwegian share of the field is 85.47 per cent. The water depth is 150 metres. Statfjord was discovered in 1974, and the plan for development and operation (PDO) was approved in 1976. The field has been developed with three fully integrated concrete facilities: Statfjord A, Statfjord B and Statfjord C. Statfjord A, centrally located on the field, came on stream in 1979. Statfjord B, in the southern part of the field, in 1982, and Statfjord C, in the northern part, in 1985. The satellite fields Statfjord Øst, Statfjord Nord and Sygna have a dedicated inlet separator on Statfjord C. A PDO for Statfjord Late Life was approved in 2005.
|
43658
|
28.02.2023
|
22.03.2023
|
|
STATFJORD
|
Reservoir
|
Statfjord produces oil and associated gas from Jurassic sandstone in the Brent and Statfjord Groups, and in the Cook Formation. The Brent and Statfjord Groups have excellent reservoir quality. The reservoirs lie at a depth of 2,500-3,000 metres in a large fault block tilted towards the west, and in several smaller blocks along the eastern flank.
|
43658
|
28.02.2023
|
22.03.2023
|
|
STATFJORD
|
Transport
|
Stabilised oil is stored in storage cells at each facility. Oil is loaded onto tankers from one of the two oil-loading systems on the field. Since 2007, gas is exported through Tampen Link, and routed via the Far North Liquids and Gas System (FLAGS) pipeline to the UK. The UK licensees route their share of the gas through the FLAGS pipeline from Statfjord B to St Fergus in the UK.
|
43658
|
28.02.2023
|
22.03.2023
|
|
STATFJORD NORD
|
Reservoir
|
Statfjord Nord produces oil from Middle Jurassic sandstone in the Brent Group and Upper Jurassic sandstone in the Munin Formation. The reservoirs lie at a depth of 2,600 metres and are of good quality.
|
43679
|
28.02.2023
|
22.03.2023
|
|
STATFJORD NORD
|
Recovery strategy
|
The field is produced with pressure maintenance from water injection.
|
43679
|
28.02.2023
|
22.03.2023
|
|
STATFJORD NORD
|
Development
|
Statfjord Nord is a field in the Tampen area in the northern part of the North Sea, 17 kilometres north of the Statfjord field. The water depth is 250-290 metres. Statfjord Nord was discovered in 1977, and the plan for development and operation (PDO) was approved in 1990. The field has been developed with two production templates and one water injection template tied-back to the Statfjord C facility. Production started in 1995.
|
43679
|
28.02.2023
|
22.03.2023
|
|
STATFJORD NORD
|
Status
|
Well intervention performed in 2019 has resulted in increased oil rates and reduced water cut. One new well was drilled in 2022. The lifetime extension of the Statfjord C facility could result in additional wells for the field.
|
43679
|
28.02.2023
|
22.03.2023
|
|
STATFJORD NORD
|
Transport
|
The well stream is transported in two pipelines to the Statfjord C facility for processing, storage and export. The fields Statfjord Nord, Statfjord Øst and Sygna have a shared process module on Statfjord C. Oil is loaded onto tankers and gas is exported through Tampen Link and the Far North Liquids and Gas System (FLAGS) pipeline to the UK.
|
43679
|
28.02.2023
|
22.03.2023
|
|
STATFJORD ØST
|
Recovery strategy
|
The field was originally produced with water injection but is now produced by pressure depletion.
|
43672
|
28.02.2023
|
22.03.2023
|
|
STATFJORD ØST
|
Transport
|
The well stream is transported in two pipelines to the Statfjord C facility for processing, storage and export. Statfjord Øst, Statfjord Nord and Sygna have a shared process module on Statfjord C. Oil is loaded onto tankers and gas is exported through Tampen Link and the Far North Liquids and Gas System (FLAGS) pipeline to the UK.
|
43672
|
28.02.2023
|
22.03.2023
|
|
STATFJORD ØST
|
Development
|
Statfjord Øst is a field in the Tampen area in the North Sea, seven kilometres northeast of the Statfjord field. The water depth is 150-190 metres. Statfjord Øst was discovered in 1976, and the plan for development and operation (PDO) was approved in 1990. The field has been developed with two subsea production templates and one water injection template, tied-back to the Statfjord C platform. In addition, two production wells have been drilled from Statfjord C. Production started in 1994.
|
43672
|
28.02.2023
|
22.03.2023
|
|
STATFJORD ØST
|
Status
|
The field is affected by pressure depletion due to depressurisation of the Statfjord field. The lifetime extension of the Statfjord C facility could result in additional wells and projects for Statfjord Øst. The main planned activity for Statfjord Øst is related to the gas lift project, which includes providing agas lift solution for both subsea production templates and drilling new wells capable of producing with gas lift.
|
43672
|
28.02.2023
|
22.03.2023
|
|
STATFJORD ØST
|
Reservoir
|
Statfjord Øst produces oil from Middle Jurassic sandstone in the Brent Group. The reservoir has good quality and lies at 2,400 metres depth.
|
43672
|
28.02.2023
|
22.03.2023
|
|
SVALIN
|
Recovery strategy
|
The field is produced by pressure depletion and with pressure support from a regional aquifer.
|
22507971
|
28.02.2023
|
22.03.2023
|
|
SVALIN
|
Development
|
Svalin is a field in the central part of the North Sea, six kilometres southwest of the Grane field. The water depth is 120 metres. Svalin was discovered in 1992, and the plan for development and operation (PDO) was approved in 2012. The field comprises two separate structures: Svalin C and Svalin M. Svalin C is developed with a subsea template tied-in to the Grane facility, and Svalin M is developed with a multilateral well drilled from Grane. Production started in 2014.
|
22507971
|
28.02.2023
|
22.03.2023
|
|
SVALIN
|
Status
|
Production has so far been lower than anticipated in the PDO and is declining due to increasing water cut.
|
22507971
|
28.02.2023
|
22.03.2023
|
|
SVALIN
|
Transport
|
The well stream is processed on the Grane field. The oil is transported by pipeline to the Sture terminal for storage and export, and the gas is injected into the Grane reservoir or used for fuel at the Grane platform.
|
22507971
|
28.02.2023
|
22.03.2023
|
|
SVALIN
|
Reservoir
|
Svalin produces oil and associated gas from massive sandstone of Paleocene to early Eocene age in the Heimdal and Balder Formations. The reservoirs are in marine fan deposits and have excellent quality. They lie at a depth of 1,750 metres.
|
22507971
|
28.02.2023
|
22.03.2023
|
|
SYGNA
|
Status
|
Production from Sygna is stable, and the strategy is to keep the reservoir pressure constant by water injection.
|
104718
|
28.02.2023
|
22.03.2023
|
|
SYGNA
|
Development
|
Sygna is a field in the Tampen area in the northern North Sea, just northeast of the Statfjord Nord field. The water depth is 300 metres. Sygna was discovered in 1996, and the plan for development and operation (PDO) was approved in 1999. The field has been developed with one subsea template with four well slots, connected to the Statfjord C facility. Three production wells have been drilled from the template. A long-reach water injection well was drilled from the Statfjord Nord template. Production started in 2000.
|
104718
|
28.02.2023
|
22.03.2023
|
|
SYGNA
|
Recovery strategy
|
The field is produced by pressure maintenance from water injection.
|
104718
|
28.02.2023
|
22.03.2023
|
|
SYGNA
|
Reservoir
|
Sygna produces oil from Middle Jurassic sandstone in the Brent Group. The reservoir lies at a depth of 2,650 metres and has good quality.
|
104718
|
28.02.2023
|
22.03.2023
|
|
SYGNA
|
Transport
|
The well stream is transported by pipeline to the Statfjord C facility for processing, storage and export. Sygna, Statfjord Nord og Statfjord Øst have a shared process module on Statfjord C. The oil is loaded onto tankers and the gas is exported through Tampen Link and the Far North Liquids and Gas System (FLAGS) pipeline to the UK.
|
104718
|
28.02.2023
|
22.03.2023
|
|
TAMBAR
|
Development
|
Tambar is a field in the southern part of the Norwegian sector in the North Sea, 16 kilometres southeast of the Ula field. The water depth is 70 metres. Tambar was discovered in 1983, and the plan for development and operation (PDO) was approved in 2000. The field has been developed with a remotely controlled wellhead platform tied-back to the Ula field. Production started in 2001.
|
1028599
|
28.02.2023
|
22.03.2023
|
|
TAMBAR
|
Transport
|
The oil is transported by pipeline to Ula. After processing at Ula, the oil is exported in the pipeline system via the Ekofisk field to Teesside in the UK, while the gas is injected into the Ula reservoir to improve oil recovery.
|
1028599
|
28.02.2023
|
22.03.2023
|
|
TAMBAR
|
Status
|
Production is declining due to decreased reservoir pressure and increased water cut.
|
1028599
|
28.02.2023
|
22.03.2023
|
|
TAMBAR
|
Recovery strategy
|
The field is produced by pressure depletion, with natural gas expansion combined with aquifer support. Gas lift is used to improve production performance.
|
1028599
|
28.02.2023
|
22.03.2023
|
|
TAMBAR
|
Reservoir
|
Tambar produces oil from Upper Jurassic shallow marine sandstone in the Ula Formation. The reservoir lies at a depth of 4100-4200 metres and has generally very good characteristics.
|
1028599
|
28.02.2023
|
22.03.2023
|
|
TAMBAR ØST
|
Transport
|
The oil is transported from the Tambar field to the Ula facility. After processing at Ula, the oil is exported in the existing pipeline system via the Ekofisk field to Teesside in the UK. The gas is used for gas injection in the Ula reservoir to improve oil recovery.
|
4999528
|
28.02.2023
|
22.03.2023
|
|
TAMBAR ØST
|
Development
|
Tambar Øst is a field in the southern part of the Norwegian sector in the North Sea, two kilometres east of the Tambar field. The water depth is 70 metres. Tambar Øst was discovered in 2007. In the same year, the authorities granted an exemption for the plan for development and operation (PDO) and the field started production. The field has been developed with one production well drilled from the Tambar facility.
|
4999528
|
28.02.2023
|
22.03.2023
|
|
TAMBAR ØST
|
Reservoir
|
Tambar Øst produces oil and some gas from shallow marine sandstone of Late Jurassic age in the Farsund Formation. The reservoir lies at a depth of 4,050-4,200 metres and has varying quality.
|
4999528
|
28.02.2023
|
22.03.2023
|
|
TAMBAR ØST
|
Recovery strategy
|
The field is produced by pressure depletion and limited aquifer drive.
|
4999528
|
28.02.2023
|
22.03.2023
|
|
TAMBAR ØST
|
Status
|
Production from Tambar Øst is shut down and the well is temporarily plugged. The flow line has been reused for an infill well on Tambar field. There will be no production from Tambar Øst until the reservoir pressure has been built up sufficiently and the Tambar pipeline pressure (back-pressure) is reduced to acceptable levels.
|
4999528
|
28.02.2023
|
22.03.2023
|
|
TOMMELITEN A
|
Transport
|
The well stream will be transported to Ekofisk Centre by pipelines. Oil and gas are routed to export pipelines via the processing facility at Ekofisk to Teesside in the UK and to Emden in Germany.
|
40867462
|
28.02.2023
|
22.03.2023
|
|
TOMMELITEN A
|
Development
|
Tommeliten A is a field in the southern part of the Norwegian sector in the North Sea, 25 kilometres southwest of the Ekofisk field. The field is located on the border to the UK sector and the Norwegian share of the field is 99.57 per cent. The water depth is 75 metres. Tommeliten A was proven in 1977 and the plan for development and operation (PDO) was approved in July 2022. The field is being developed with two subsea templates tied-back to the Ekofisk Comlpex, where a new processing module will be installed.
|
40867462
|
28.02.2023
|
22.03.2023
|
|
TOMMELITEN A
|
Recovery strategy
|
The field will be produced by pressure depletion.
|
40867462
|
28.02.2023
|
22.03.2023
|
|
TOMMELITEN A
|
Reservoir
|
The reservoir contains gas condensate and volatile oil in chalk in the Paleocene Ekofisk Formation and Upper Cretaceous Tor Formation at a depth of about 3000 metres. The reservoir qualities vary across both formations and are affected by faults and fractures.
|
40867462
|
28.02.2023
|
22.03.2023
|
|
TOMMELITEN A
|
Status
|
The field is under development and production is planned to start in 2024.
|
40867462
|
28.02.2023
|
22.03.2023
|
|
TOMMELITEN GAMMA
|
Reservoir
|
Tommeliten Gamma produced gas and condensate from fractured chalk of Late Cretaceous age in the Tor Formation and of early Paleocene age in the Ekofisk Formation. The reservoir lies at a depth of 3,500 metres.
|
43444
|
28.02.2023
|
22.03.2023
|
|
TOMMELITEN GAMMA
|
Transport
|
The well stream was sent via pipeline to the Edda field for first-stage separation, then to the Ekofisk Complex and further through Norpipe to Emden in Germany and Teesside in the UK. Some of the gas was used for gas lift on the Edda field.
|
43444
|
28.02.2023
|
22.03.2023
|
|
TOMMELITEN GAMMA
|
Status
|
The field was shut down in 1998 and the subsea template was removed in 2001. Any redevelopment of the field must be viewed in combination with other decommissioned fields in the area.
|
43444
|
28.02.2023
|
22.03.2023
|
|
TOMMELITEN GAMMA
|
Development
|
Tommeliten Gamma is a field in the southern part of the Norwegian sector in the North Sea, 12 kilometres west of the Edda field in the Ekofisk area. The water depth is 75 metres. Tommeliten Gamma was discovered in 1978, and the plan for development and operation (PDO) was approved in 1986. The field was developed with a subsea template including six production wells. Production started in 1988.
|
43444
|
28.02.2023
|
22.03.2023
|
|
TOMMELITEN GAMMA
|
Recovery strategy
|
The field was produced by pressure depletion.
|
43444
|
28.02.2023
|
22.03.2023
|
|
TOR
|
Status
|
Production from the field is according to plan. The original facility will be removed by the end of 2024.
|
43520
|
28.02.2023
|
22.03.2023
|
|
TOR
|
Development
|
Tor is a field in the southern part of the Norwegian sector in the North Sea, 13 kilometres northeast of the Ekofisk field. The water depth is 70 metres. Tor was discovered in 1970, and the plan for development and operation (PDO) was approved in 1973. The field was shut down in 2015. A new PDO for the redevelopment of Tor was approved in 2019. The development includes two subsea templates with eight horizontal production wells, tied-back to the Ekofisk Centre. Production started again in 2020.
|
43520
|
28.02.2023
|
22.03.2023
|
|
TOR
|
Reservoir
|
The reservoir contains oil and gas in fractured chalk of Late Cretaceous age in the Tor Formation and of early Paleocene age in the Ekofisk Formation. There are significant remaining resources in both formations. The reservoir depth is 3,200 metres.
|
43520
|
28.02.2023
|
22.03.2023
|
|
TOR
|
Transport
|
The well stream is transported by pipeline to the processing facility at the Ekofisk Centre and further to Teesside in the UK and Emden in Germany.
|
43520
|
28.02.2023
|
22.03.2023
|
|
TOR
|
Recovery strategy
|
The field is produced by natural pressure depletion.
|
43520
|
28.02.2023
|
22.03.2023
|
|
TORDIS
|
Status
|
Production is maintained through pressure support and well interventions. A better effectivity of water injection has contributed to increased production from the Tordis field in 2022. 4D seismic acquired in 2021 is being used to identify further infill drilling targets.
|
43725
|
28.02.2023
|
22.03.2023
|
|
TORDIS
|
Reservoir
|
Tordis produces oil from Jurassic sandstone. The reservoirs in Tordis and Tordis Øst are in the Brent and Statfjord Groups, and the reservoir in Borg is in Upper Jurassic intra-Draupne Formation sandstone. The reservoir in Tordis Sørøst is in the Brent Group and in Upper Jurassic sandstone. The reservoirs lie at a depth of 2000-2500 metres and the reservoir quality is good to excellent.
|
43725
|
28.02.2023
|
22.03.2023
|
|
TORDIS
|
Transport
|
The well stream from Tordis is transported via two pipelines to the Gullfaks C facility for processing. The oil is exported by tankers, while the gas is exported via Statpipe to the Kårstø terminal.
|
43725
|
28.02.2023
|
22.03.2023
|
|
TORDIS
|
Recovery strategy
|
The field is produced by pressure support from water injection and by natural aquifer drive.
|
43725
|
28.02.2023
|
22.03.2023
|
|
TORDIS
|
Development
|
Tordis is a field in the Tampen area in the northern part of the North Sea, between the Statfjord and Gullfaks fields. The water depth is 150-220 metres. Tordis was discovered in 1987, and the plan for development and operation (PDO) was approved in 1991. The field has been developed with a central subsea manifold tied-back to the Gullfaks C facility, which also supplies water for injection. Seven single-well satellites and two 4-slots subsea templates are tied-back to the manifold. Production started in 1994. Tordis comprises four structures: Tordis, Tordis Øst, Tordis Sørøst (34/7-25 S) and Borg. The PDO for Tordis Øst was approved in 1995 and for Borg in 1999. An amended PDO for Tordis was approved in 2005.
|
43725
|
28.02.2023
|
22.03.2023
|
|
TRESTAKK
|
Recovery strategy
|
The Field is produced by gas injection.
|
29396445
|
28.02.2023
|
22.03.2023
|
|
TRESTAKK
|
Status
|
In 2022, Trestakk has been producing with high regularity. In general, however, production from the field is lower than anticipated due to poorer reservoir properties than predicted and lower gas injection volumes. New infill targets are being evaluated.
|
29396445
|
28.02.2023
|
22.03.2023
|
|
TRESTAKK
|
Development
|
Trestakk is a field in the central part of the Norwegian Sea, 20 kilometres south of the Åsgard field. The water depth is 300 metres. Trestakk was proven in 1986 and the plan for development and operation (PDO) was approved in 2017. The development concept consists of one subsea template with four well slots and an additional satellite well. The subsea installation is tied-back to the Åsgard A facility for processing and gas injection. Production started in 2019.
|
29396445
|
28.02.2023
|
22.03.2023
|
|
TRESTAKK
|
Transport
|
The well stream is transported to the Åsgard A facility for processing. Oil and condensate are temporarily stored at Åsgard A, and then shipped to market by shuttle tankers. The gas is exported through the Åsgard Transport System (ÅTS) to the Kårstø terminal.
|
29396445
|
28.02.2023
|
22.03.2023
|
|
TRESTAKK
|
Reservoir
|
Trestakk produces oil from shallow marine sandstone of Middle Jurassic age in the Garn Formation. The reservoir lies at a depth of 3,900 metres and has moderate quality.
|
29396445
|
28.02.2023
|
22.03.2023
|
|
TROLL
|
Status
|
About 279 production wells, 605 branches and more than two million reservoir metres have been drilled on Troll. There is currently one drilling rig on the field, continuously drilling horizontal oil production wells from the subsea templates on Troll Vest. To produce the thin remaining oil columns on Troll, focus has been on developing and implementing new technology for cost effective drilling, more accurate well placement and technology for constraining water and gas production from the oil wells. To increase gas production and processing capacity for Troll and the tied-in Fram field, a new gas compressor module on the Troll C platform started operation in early 2020. The first step on Troll Phase III, which comprises 8 new gas wells on Troll Vest and a flowline to Troll A facility is developed and gas production started in 2021.
|
46437
|
28.02.2023
|
22.03.2023
|
|
TROLL
|
Transport
|
The gas from Troll Øst and Troll Vest is transported through three multiphase pipelines to the gas processing plant at Kollsnes. The condensate is separated from the gas and transported by pipeline to the Mongstad terminal. The dry gas is transported in Zeepipe II A and II B to Zeebrugge in Belgium. The oil from Troll B and Troll C is transported in the Troll Oil Pipelines I and II, respectively, to the oil terminal at Mongstad.
|
46437
|
28.02.2023
|
22.03.2023
|
|
TROLL
|
Recovery strategy
|
The gas in Troll Øst is recovered by pressure depletion through 39 wells drilled from Troll A. The oil in Troll Vest is produced from long horizontal wells, which penetrate the thin oil zone directly above the oil-water contact. The recovery strategy is based primarily on pressure depletion, but this is accompanied by a simultaneous expansion of both the gas cap above the oil zone and the underlying water zone. Some gas is also reinjected. Produced water was reinjected into the northern part of the Troll Vest oil province from 2000 to 2016.
|
46437
|
28.02.2023
|
22.03.2023
|
|
TROLL
|
Reservoir
|
Troll contains very large amounts of gas resources and is also one of the largest oil producing fields on the Norwegian continental shelf. The field has two main structures: Troll Øst and Troll Vest. About two-thirds of the recoverable gas reserves lie in Troll Øst. The gas and oil reservoirs in the Troll Øst and Troll Vest structures consist primarily of shallow marine sandstone of Late Jurassic age in the Sognefjord Formation. Part of the reservoir is also in the underlying Fensfjord Formation of Middle Jurassic age. The field consists of three relatively large rotated fault blocks. The eastern fault block constitutes Troll Øst. The reservoir depth at Troll Øst is 1,330 metres. Pressure communication between Troll Øst and Troll Vest has been proven. Originally, the oil column in Troll Øst was mapped to be 0-4 metres thick. A well drilled in 2007 proved an oil column of 6-9 metres in the Fensfjord Formation in the northern segment of Troll Øst. The Troll Vest oil province originally had a 22 to 26-metre-thick oil column under a small gas cap, located at a depth of 1,360 metres. The Troll Vest gas province originally had an oil column of 12-14 metres under a gas column of up to 200 metres. The oil column is now reduced to a thickness of only 1 to 5 metres. A significant volume of residual oil is encountered directly below the Troll Vest oil column.
|
46437
|
28.02.2023
|
22.03.2023
|
|
TROLL
|
Development
|
Troll is a field in the northern part of the North Sea. The water depth is 300-330 metres. Troll was discovered in 1979, and the initial plan for development and operation (PDO) was approved in 1986. The plan was updated in 1990 and involved the transfer of gas processing to the Kollsnes terminal. Production started in 1995. A phased development was pursued for the Troll field, with Phase I recovering gas reserves in Troll Øst and Phase II focusing on the oil reserves in Troll Vest. Troll Phase I has been developed with Troll A, which is a fixed wellhead and compression platform with a concrete substructure. Troll A receives power from shore. The gas compression capacity at Troll A was increased in 2004/2005, and again in 2015. Troll Phase II was developed with Troll B, a floating concrete accommodation and production platform, and Troll C, a semi-submersible accommodation and production steel platform. The oil is produced from several subsea templates tied-back to Troll B and Troll C by flowlines. Production from Troll C started in 1999. The Troll C platform is also utilised for production from the Fram field. Several PDO amendments were approved in connection with various subsea templates at Troll Vest. A PDO for Troll Phase III (gas production from Troll Vest) was approved in 2018 and production started in August 2021.
|
46437
|
28.02.2023
|
22.03.2023
|
|
TROLL BRENT B
|
Development
|
Troll Brent B is a field near the Troll field in the northern part of the North Sea. The water depth is 340 metres. Troll Brent B was discovered in 2005, and was granted an exemption from the plan for development and operation (PDO) in 2017. Troll Brent B was planned to be developed with one multilateral production well drilled from the O-template connected to Troll C.
|
29398828
|
28.02.2023
|
22.03.2023
|
|
TROLL BRENT B
|
Status
|
During drilling of the production well, oil reserves were proven to be significantly lower than originally assumed. It was therefore decided to be uneconomical to start production on the Troll Brent B field. The well was plugged, but the well slot is available to be used for potential new targets on Troll Vest.
|
29398828
|
28.02.2023
|
22.03.2023
|
|
TROLL BRENT B
|
Reservoir
|
The reservoir contains oil in sandstone of Middle Jurassic age in the Brent Group, stratigraphically underlying producing reservoirs on the Troll field. The reservoir lies at a depth of 1,900 metres.
|
29398828
|
28.02.2023
|
22.03.2023
|
|
TROLL BRENT B
|
Transport
|
There was no production from Troll Brent B.
|
29398828
|
28.02.2023
|
22.03.2023
|
|
TROLL BRENT B
|
Recovery strategy
|
The field was planned to be produced by pressure depletion.
|
29398828
|
28.02.2023
|
22.03.2023
|
|
TRYM
|
Reservoir
|
Trym produces gas and condensate from Middle Jurassic sandstone in the Sandnes Formation. The reservoir is located at a depth of 3,400 metres and has good quality.
|
18081500
|
28.02.2023
|
22.03.2023
|
|
TRYM
|
Recovery strategy
|
The field is produced by pressure depletion. A low-pressure project was started in 2017 and is expected to accelerate production, thus increasing final recovery.
|
18081500
|
28.02.2023
|
22.03.2023
|
|
TRYM
|
Transport
|
The well stream is processed on the Harald facility for further transport through the Danish pipeline system via the Tyra field.
|
18081500
|
28.02.2023
|
22.03.2023
|
|
TRYM
|
Development
|
Trym is a field in the southern part of the Norwegian sector in the North Sea, three kilometres from the border to the Danish sector. The water depth is 65 metres. Trym was discovered in 1990, and the plan for development and operation (PDO) was approved in 2010. The field is developed with a subsea template including two horizontal production wells, tied to the Harald facility in the Danish sector. Production started in 2011.
|
18081500
|
28.02.2023
|
22.03.2023
|
|
TRYM
|
Status
|
The production from Trym has been temporarily shut-in since September 2019, due to a major redevelopment project on the Tyra field in the Danish sector. Trym production is expected to restart in 2024, once the Tyra project is completed.
|
18081500
|
28.02.2023
|
22.03.2023
|
|
TUNE
|
Recovery strategy
|
The field is produced by pressure depletion. Low-pressure production has been implemented.
|
853376
|
28.02.2023
|
22.03.2023
|
|
TUNE
|
Development
|
Tune is a field in the northern part of the North Sea, ten kilometres west of the Oseberg field. The water depth is 95 metres. Tune was discovered in 1995, and the plan for development and operation (PDO) was approved in 1999. The field has been developed with a subsea template and a satellite well tied to the Oseberg Field Centre. Production started in 2002. A PDO exemption was granted for the development of the northern part of the field in 2004. A similar exemption was granted for the southern part of the field in 2005.
|
853376
|
28.02.2023
|
22.03.2023
|
|
TUNE
|
Transport
|
The well stream from Tune is transported in pipelines to the Oseberg Field Centre, where the condensate is separated and transported to the Sture terminal through the Oseberg Transport System (OTS). Gas from Tune is injected in the Oseberg field, while the licensees can export a corresponding volume of sales gas from Oseberg.
|
853376
|
28.02.2023
|
22.03.2023
|
|
TUNE
|
Reservoir
|
Tune produces gas and some condensate mainly from Middle Jurassic sandstone in the Tarbert Formation (Brent Group). The reservoir is divided into several inclined fault blocks and lies at a depth of 3,400 metres. Another reservoir is in the underlying Statfjord Formation.
|
853376
|
28.02.2023
|
22.03.2023
|
|
TUNE
|
Status
|
The Tune field is in its tail production phase and produces cyclically. However, since the inlet pressure for the Tune wells has been reduced in 2021, the field has had more continuous production.
|
853376
|
28.02.2023
|
22.03.2023
|
|
TYRIHANS
|
Transport
|
The well stream is sent to the Kristin platform for processing. Gas is exported from Kristin via the Åsgard Transport System (ÅTS) to the Kårstø terminal, while oil and condensate are transported by pipeline to the storage ship Åsgard C for export on shuttle tankers.
|
3960848
|
28.02.2023
|
22.03.2023
|
|
TYRIHANS
|
Reservoir
|
Tyrihans produces oil, gas and condensate from two deposits: Tyrihans Sør and Tyrihans Nord. Tyrihans Sør has an oil column with a condensate-rich gas cap. Tyrihans Nord contains gas and condensate with a thin oil zone. The main reservoir in both deposits is in the Middle Jurassic Garn Formation at a depth of 3500 metres. The reservoirs are homogenous and of good quality. In addition, one well produces oil from the Ile Formation.
|
3960848
|
28.02.2023
|
22.03.2023
|
|
TYRIHANS
|
Development
|
Tyrihans is a field in the Norwegian Sea, 25 kilometres southeast of the Åsgard field. The water depth is 270 metres. Tyrihans was discovered in 1983, and the plan for development and operation (PDO) was approved in 2005. The field is developed with five subsea templates tied-back to the Kristin platform, four templates for production and gas injection and one template for seawater injection. Gas for injection and gas lift is supplied from the Åsgard B platform. Production started in 2009.
|
3960848
|
28.02.2023
|
22.03.2023
|
|
TYRIHANS
|
Status
|
Oil production from Tyrihans is well above the PDO estimates, whereas gas production is in line with the PDO estimates. Water injection was stopped in 2017 but can be resumed if found necessary. Gas injection was stopped in 2018. A new production well targeting both Garn and Ile Formations was drilled in Tyrihans Nord early 2021.
|
3960848
|
28.02.2023
|
22.03.2023
|
|
TYRIHANS
|
Recovery strategy
|
Tyrihans has earlier been produced with pressure support by water and gas injection. The main recovery strategy now is pressure depletion and gas cap expansion.
|
3960848
|
28.02.2023
|
22.03.2023
|
|
ULA
|
Status
|
The current estimated reserves on Ula are more than three times higher than the original PDO estimates. All oil production from Ula is dependent on Enhanced Oil Recovery (EOR) measures. The positive effect of WAG injection resulted in the drilling of more WAG wells. Gas supply for WAG is currently challenging and production is declining.
|
43800
|
28.02.2023
|
22.03.2023
|
|
ULA
|
Development
|
Ula is a field in the southern part of the Norwegian sector in the North Sea. The water depth is 70 metres. Ula was discovered in 1976, and the plan for development and operation (PDO) was approved in 1980. The development consists of three facilities for production, drilling and accommodation, which are connected by bridges. Production started in 1986. The gas capacity at Ula was upgraded in 2008 with a new gas processing and gas injection module (UGU) that doubled the capacity. A PDO exemption for the Triassic reservoir was granted in 2015. Ula is the processing facility for the Tambar, Blane and Oda fields.
|
43800
|
28.02.2023
|
22.03.2023
|
|
ULA
|
Transport
|
The oil is transported by pipeline via the Ekofisk field to Teesside in the UK. All gas is reinjected into the reservoir to increase oil recovery.
|
43800
|
28.02.2023
|
22.03.2023
|
|
ULA
|
Recovery strategy
|
Oil was initially recovered by pressure depletion, but after some years water injection was implemented to improve recovery. Water alternating gas injection (WAG) started in 1998. The WAG program has been extended with gas from the tied-in Tambar, Blane and Oda fields. Gas lift is used in some of the wells.
|
43800
|
28.02.2023
|
22.03.2023
|
|
ULA
|
Reservoir
|
Ula produces oil mainly from sandstone in the Upper Jurassic Ula Formation. The reservoir lies at a depth of 3345 metres and consists of three units. There is also production from part of the underlying Triassic reservoir at a depth of 3450 metres. This is a tight sandstone reservoir with low effective permeability.
|
43800
|
28.02.2023
|
22.03.2023
|
|
URD
|
Reservoir
|
Urd produces oil from Lower to Middle Jurassic sandstone in the Åre, Tilje and Ile Formations. The field is structurally complex and segmented. The reservoirs lie at depths of 1,800-2,300 metres and have moderate to good quality.
|
2834734
|
28.02.2023
|
22.03.2023
|
|
URD
|
Status
|
Challenges for Urd are poor pressure support, increasing water cut, problems with the well stream (slugging) and sand control in production and injection wells. An infill production well was drilled in 2022. Work is ongoing to identify new well targets and evaluate the injection strategy.
|
2834734
|
28.02.2023
|
22.03.2023
|
|
URD
|
Transport
|
The well stream is processed on the Norne FPSO, and the oil is offloaded to shuttle tankers together with oil from the Norne field. The gas is sent from Norne to Åsgard, and then exported via the Åsgard Transport System (ÅTS) to the Kårstø terminal.
|
2834734
|
28.02.2023
|
22.03.2023
|
|
URD
|
Recovery strategy
|
The field is produced by water injection and gas lift.
|
2834734
|
28.02.2023
|
22.03.2023
|
|
URD
|
Development
|
Urd is a field in the Norwegian Sea, five kilometres northeast of the Norne field. The water depth is 380 metres. Urd was discovered in 2000, and the plan for development and operation (PDO) was approved in 2004. The field has three deposits: Svale, Svale North and Stær. The Urd field has been developed with subsea templates tied-back to the Norne production, storage and offloading vessel (FPSO). Production started in 2005 from Svale, from Stær in 2006 and from Svale North in 2016.
|
2834734
|
28.02.2023
|
22.03.2023
|
|
UTGARD
|
Development
|
Utgard is a field in the central part of the Norwegian sector in the North Sea, straddling the boundary between Norway and the UK. The Norwegian share of the field is 62 per cent. Utgard is located 20 kilometres west of the Sleipner area. The water depth is 110-120 metres. The field was discovered in 1982 and the plan for development and operation (PDO) was approved in 2017. The development concept is a 4-slot subsea template with two wells tied-back to the Sleipner T facility for processing and reduction of the CO2 level in the gas. The subsea template is located in the Norwegian sector. Production started in 2019.
|
28975098
|
28.02.2023
|
22.03.2023
|
|
UTGARD
|
Transport
|
The well stream from the Utgard field is processed at the Sleipner T facility. The sales gas is exported via Gassled (Area D). The unstable oil is transported by pipeline via Sleipner A to the Kårstø terminal for further processing and export.
|
28975098
|
28.02.2023
|
22.03.2023
|
|
UTGARD
|
Recovery strategy
|
Utgard is produced by pressure depletion.
|
28975098
|
28.02.2023
|
22.03.2023
|
|
UTGARD
|
Status
|
Production has been on decline due to early water breakthrough. Currently, one well is producing and the other well is watered out. Sidetracks and infill wells are being considered to increase recovery from the field.
|
28975098
|
28.02.2023
|
22.03.2023
|
|
UTGARD
|
Reservoir
|
Utgard produces gas with high CO2 content and some condensate mainly from sandstone of Middle Jurassic age in the Hugin Formation. Minor hydrocarbon volumes occur in the Sleipner Formation. The field consists of two main segments which are in pressure communication via the aquifer. The reservoir lies at a depth of 3,700 metres.
|
28975098
|
28.02.2023
|
22.03.2023
|
|
VALE
|
Development
|
Vale is a field in the central part of the North Sea, 16 kilometres north of the Heimdal field. The water depth is 115 metres. Vale was discovered in 1991, and the plan for development and operation (PDO) was approved in 2001. The field is developed with a subsea template including one horizontal production well with a single side track, tied-back to the Heimdal facility. Production started in 2002.
|
1578893
|
28.02.2023
|
22.03.2023
|
|
VALE
|
Status
|
Production from Vale stopped in 2018 because of processing problems at the Heimdal facility. After finding a technical solution, production started again in 2019. The Heimdal facility is available for tied-in fields until 2023. A decommissioning plan for Vale was submitted in 2020. According to the formal removal resolution, decommissioning must be completed by the end of 2028.
|
1578893
|
28.02.2023
|
22.03.2023
|
|
VALE
|
Recovery strategy
|
The field is produced by pressure depletion.
|
1578893
|
28.02.2023
|
22.03.2023
|
|
VALE
|
Transport
|
The well stream from Vale is routed to Heimdal for processing and export. Gas is transported via Vesterled to St Fergus in the UK. Condensate is transported by pipeline to the Brae field in the UK sector and further to Cruden Bay.
|
1578893
|
28.02.2023
|
22.03.2023
|
|
VALE
|
Reservoir
|
Vale produces gas and condensate from Middle Jurassic sandstone in the Brent Group. The reservoir lies at a depth of 3,700 metres and has low permeability. Measured in oil equivalents, the field produces relatively equal amounts of gas and condensate; however, gas production is expected to increase compared to condensate in the coming years.
|
1578893
|
28.02.2023
|
22.03.2023
|
|
VALEMON
|
Reservoir
|
Valemon produces gas and condensate from Lower Jurassic sandstone in the Cook Formation and Middle Jurassic sandstone in the Brent Group. The deposit has a complex structure with many fault blocks. The reservoirs lie at a depth of 3,900-4,200 metres and have high temperature and high pressure (HTHP).
|
20460969
|
28.02.2023
|
22.03.2023
|
|
VALEMON
|
Development
|
Valemon is a field in the northern part of the North Sea, just west of the Kvitebjørn field. The water depth is 135 metres. Valemon was discovered in 1985, and the plan for development and operation (PDO) was approved in 2011. The field is developed with a fixed production platform with a simplified separation process design. The platform is remotely controlled from an operations centre onshore. Production started in 2015.
|
20460969
|
28.02.2023
|
22.03.2023
|
|
VALEMON
|
Transport
|
The condensate is transported by pipeline to the Kvitebjørn field, and via the Kvitebjørn Oil Pipeline to Mongstad. The rich gas is exported via the previous Huldra pipeline to Heimdal for further export to the UK or continental Europe.
|
20460969
|
28.02.2023
|
22.03.2023
|
|
VALEMON
|
Status
|
Due to production experience and rapid pressure decline in the reservoirs, the estimated recoverable volumes have been significantly reduced since the PDO. A drilling campaign including four new production wells started in 2021, but the three first wells are delivering below expectation. Permanent rerouting of the Valemon gas export to Kollsnes terminal via Kvitebjørn is planned when the Heimdal facility closes in 2023.
|
20460969
|
28.02.2023
|
22.03.2023
|
|
VALEMON
|
Recovery strategy
|
The field is produced by pressure depletion.
|
20460969
|
28.02.2023
|
22.03.2023
|
|
VALHALL
|
Transport
|
Oil and NGL (Natural Gas Liquids) are routed via pipeline to the Ekofisk field and further to Teesside in the UK. Gas is sent via Norpipe to Emden in Germany.
|
43548
|
28.02.2023
|
22.03.2023
|
|
VALHALL
|
Status
|
The Valhall field has produced more than one billion barrels of oil equivalents, which is three times more than the original PDO estimate. The long-term strategy for the field has been updated. One well was drilled in 2022, and drilling will continue in the foreseeable future. Decommissioning plans were submitted in 2019 for the QP, PCP and DP facilities. According to the formal removal resolution, decommissioning must be completed by the end of 2026. Plugging and abandonment of the wells is completed on the DP facility.
|
43548
|
28.02.2023
|
22.03.2023
|
|
VALHALL
|
Recovery strategy
|
The field was initially produced with pressure depletion and compaction drive. Water injection in the centre of the field started in 2004. Chalk compaction as a result of pressure depletion and water weakening has led to seabed subsidence. Gas lift is used to optimise production in most of the production wells.
|
43548
|
28.02.2023
|
22.03.2023
|
|
VALHALL
|
Development
|
Valhall is a field in the southern part of the Norwegian sector in the North Sea. The water depth is 70 metres. Valhall was discovered in 1975, and the initial plan for development and operation (PDO) was approved in 1977. The field was originally developed with three facilities for accommodation (QP), drilling (DP), and processing and compression (PCP). Production started in 1982. A PDO for a wellhead facility (WP) was approved in 1995 and for a water injection platform (IP) in 2000. Bridges connect the platforms. A PDO for two wellhead platforms on the northern and southern flanks was approved in 2001. A PDO for Valhall Redevelopment was approved in 2007. The plan included an accommodation and processing platform (PH) to replace aging facilities on the field. The PH-platform is supplied with power from shore. A PDO for Valhall Flank West which included a normally unmanned wellhead platform was approved in 2018 and production started in 2019.
|
43548
|
28.02.2023
|
22.03.2023
|
|
VALHALL
|
Reservoir
|
Valhall produces oil from chalk in the Upper Cretaceous Hod and Tor Formations. Reservoir depth is 2400 metres. The Tor Formation chalk is fine-grained and has good reservoir quality. Considerable fracturing allows oil and water to flow more easily than in the underlying Hod Formation.
|
43548
|
28.02.2023
|
22.03.2023
|
|
VARG
|
Development
|
Varg is a field in the central part of the North Sea, south of the Sleipner Øst field. The water depth is 85 metres. Varg was discovered in 1984, and the plan for development and operation (PDO) was approved in 1996. The field was developed with the production vessel "Petrojarl Varg", which had integrated oil storage and was connected to the wellhead facility Varg A. Production started in 1998.
|
43451
|
28.02.2023
|
22.03.2023
|
|
VARG
|
Reservoir
|
Varg produced oil mainly from Upper Jurassic sandstone in the Ula Formation. The reservoir is at a depth of about 2,700 metres. The structure is segmented and includes several isolated compartments with varying reservoir properties.
|
43451
|
28.02.2023
|
22.03.2023
|
|
VARG
|
Transport
|
Oil was off-loaded from the production vessel onto tankers. All gas was reinjected until gas export started in 2014. A pipeline was installed between the Varg and Rev fields to export the gas to the UK via the Central Area Transmission System (CATS).
|
43451
|
28.02.2023
|
22.03.2023
|
|
VARG
|
Status
|
The decommissioning plan for Varg was approved in 2001. The plan then was to produce until summer 2002, but measures implemented on the field prolonged its lifetime. A new decommissioning plan was submitted in 2015. The field was shut down in 2016 and the facility was removed in 2018.
|
43451
|
28.02.2023
|
22.03.2023
|
|
VARG
|
Recovery strategy
|
The field was produced with pressure maintenance using water and gas injection. The smaller structures were produced by pressure depletion. All wells were produced with gas lift.
|
43451
|
28.02.2023
|
22.03.2023
|
|
VEGA
|
Transport
|
The well stream is sent to the Gjøa field for processing. Oil and condensate are transported from Gjøa to the Troll Oil Pipeline II for further transport to the Mongstad terminal. The rich gas is exported to the Far North Liquids and Associated Gas System (FLAGS) on the British continental shelf for further transport to St Fergus in the UK.
|
4467595
|
28.02.2023
|
22.03.2023
|
|
VEGA
|
Reservoir
|
Vega produces gas and condensate from Middle Jurassic shallow marine sandstone in the Brent Group. Vega Sør additionally has an oil zone overlying the gas/condensate deposit. The reservoirs lie at a depth of 3500 meters, and the quality varies from poor to medium across the field.
|
4467595
|
28.02.2023
|
22.03.2023
|
|
VEGA
|
Status
|
Vega production is currently limited by the gas production capacity rights at Gjøa platform.
|
4467595
|
28.02.2023
|
22.03.2023
|
|
VEGA
|
Development
|
Vega is a field in the northern part of the North Sea, 30 kilometres west of the Gjøa field. The water depth is 370 metres. Vega was discovered in 1981. The field consists of three separate structures: Vega Nord, Vega Sentral and Vega Sør. The plan for development and operation (PDO) for Vega Nord and Vega Sentral was approved in 2007. In 2011, the field was unitised with Vega Sør. The field has been developed with three 4-slot subsea templates, one on each structure. They are tied to the processing facility on the Gjøa platform. A total of nine production wells have been drilled. Production started in 2010.
|
4467595
|
28.02.2023
|
22.03.2023
|
|
VEGA
|
Recovery strategy
|
The field is produced by pressure depletion.
|
4467595
|
28.02.2023
|
22.03.2023
|
|
VESLEFRIKK
|
Development
|
Veslefrikk is a field in the northern part of the North Sea, 30 kilometres north of the Oseberg field. The water depth is 185 metres. Veslefrikk was discovered in 1981, and the plan for development and operation (PDO) was approved in 1987. The field was developed with two facilities, Veslefrikk A and Veslefrikk B. Veslefrikk A is a fixed steel wellhead facility with bridge connection to Veslefrikk B. Veslefrikk B is a semi-submersible facility for processing and accommodation. Production started in 1989. Several PDOs were approved in 1994: for the Statfjord reservoir and for the reservoirs in the Upper Brent and I-segment.
|
43618
|
28.02.2023
|
22.03.2023
|
|
VESLEFRIKK
|
Reservoir
|
Veslefrikk produced oil and some gas from Jurassic sandstone in the Statfjord, Dunlin and Brent Groups. The main reservoir was in the Brent Group. The reservoir depths are between 2800 and 3200 metres.
|
43618
|
28.02.2023
|
22.03.2023
|
|
VESLEFRIKK
|
Status
|
Production from Veslefrikk ceased in 2022. Permanent plugging of wells is ongoing. According to the formal removal resolution, decommissioning must be completed by the end of 2027.
|
43618
|
28.02.2023
|
22.03.2023
|
|
VESLEFRIKK
|
Transport
|
The oil was exported via the Oseberg Transport System (OTS) to the Sture terminal. The gas was exported through Statpipe to the Kårstø terminal.
|
43618
|
28.02.2023
|
22.03.2023
|
|
VESLEFRIKK
|
Recovery strategy
|
Veslefrikk had earlier been produced with pressure support from water alternating gas injection (WAG) in the Brent and Dunlin reservoirs and with gas recycling in the Statfjord reservoir. The field was subsequently produced by depletion until shut-in.
|
43618
|
28.02.2023
|
22.03.2023
|
|
VEST EKOFISK
|
Reservoir
|
Vest Ekofisk produced oil and gas from fractured chalk of Late Cretaceous age in the Tor Formation and of early Paleocene age in the Ekofisk Formation. The reservoir lies at a depth of 3,200 metres on a salt dome.
|
43513
|
28.02.2023
|
22.03.2023
|
|
VEST EKOFISK
|
Status
|
Production was shut down in 1998 and the facility was removed in 2012. Any redevelopment of the field must be viewed in combination with other decommissioned fields in the area.
|
43513
|
28.02.2023
|
22.03.2023
|
|
VEST EKOFISK
|
Recovery strategy
|
The field was produced by pressure depletion.
|
43513
|
28.02.2023
|
22.03.2023
|
|
VEST EKOFISK
|
Transport
|
The well stream was transported via pipeline to the Ekofisk Complex for further export to Emden in Germany and Teesside in the UK.
|
43513
|
28.02.2023
|
22.03.2023
|
|
VEST EKOFISK
|
Development
|
Vest Ekofisk is a field in the southern part of the Norwegian sector in the North Sea, five kilometres west of the Ekofisk field. The water depth is 70 metres. Vest Ekofisk was discovered in 1970, and the plan for development and operation (PDO) was approved in 1973. The field was developed with a combined drilling, production and living quarters facility. Production started in 1977. From 1994, the Vest Ekofisk 2/4 D facility was remotely controlled from Ekofisk 2/4 T.
|
43513
|
28.02.2023
|
22.03.2023
|
|
VIGDIS
|
Reservoir
|
Vigdis produces oil from sandstone in several deposits. The reservoir in the Vigdis Brent deposit is in the Middle Jurassic Brent Group, while the Vigdis Øst and Vigdis Nordøst deposits are in Upper Triassic and Lower Jurassic sandstone in the Statfjord Group. The Borg Nordvest deposit is in Upper Jurassic intra-Draupne sandstone. The reservoirs are at a depth of 2200-2600 metres and have generally good quality.
|
43732
|
28.02.2023
|
22.03.2023
|
|
VIGDIS
|
Status
|
Better effectivity of water injection has contributed to increased production from the Vigdis field in 2022. The strategy on Vigdis is to maintain reservoir pressure by water injection, while maximising production capacity and regularity. A subsea booster pump for accelerated and improved recovery was installed in 2020. New infill wells are planned for the coming years, and 4D-seismic acquired in 2021 may result in additional drilling targets.
|
43732
|
28.02.2023
|
22.03.2023
|
|
VIGDIS
|
Development
|
Vigdis is a field in the Tampen area in the northern part of the North Sea, between the Snorre, Statfjord and Gullfaks fields. The water depth is 280 metres. Vigdis was discovered in 1986, and the plan for development and operation (PDO) was approved in 1994. The field has been developed with seven subsea templates and two satellite wells connected to the Snorre A facility. Production started in 1997. Oil from Vigdis is processed in a dedicated processing module on Snorre A. Injection water is supplied from Snorre A and Statfjord C. A PDO for Vigdis Extension, including the discovery 34/7-23 S and adjoining deposits, was approved in 2002. The PDO for Vigdis Nordøst was approved in 2011. A PDO exemption was granted for the nearby Lomre deposit in 2022.
|
43732
|
28.02.2023
|
22.03.2023
|
|
VIGDIS
|
Transport
|
The well stream from Vigdis is routed to Snorre A through two flowlines. Stabilised oil is transported by pipeline from Snorre A to Gullfaks A for storage and export. All produced gas from Vigdis is reinjected into the Snorre reservoir.
|
43732
|
28.02.2023
|
22.03.2023
|
|
VIGDIS
|
Recovery strategy
|
The field is produced by pressure support using water injection. Some of the reservoirs are affected by pressure depletion on the Statfjord field.
|
43732
|
28.02.2023
|
22.03.2023
|
|
VILJE
|
Development
|
Vilje is a field in the central part of the North Sea, 20 kilometres northeast of the Alvheim field. The water depth is 120 metres. Vilje was discovered in 2003, and the plan for development for operation (PDO) was approved in 2005. The field is developed with three horizontal subsea wells tied-back to the Alvheim production, storage and offloading vessel (FPSO). Production started in 2008. The Skogul field is tied-back to the Alvheim FPSO via the Vilje template.
|
3392471
|
28.02.2023
|
22.03.2023
|
|
VILJE
|
Recovery strategy
|
The field is produced by natural water drive from the regional underlying Heimdal aquifer.
|
3392471
|
28.02.2023
|
22.03.2023
|
|
VILJE
|
Status
|
The recoverable volume estimates are significantly higher than in the PDO. However, production from the field is steadily declining due to increasing water cut.
|
3392471
|
28.02.2023
|
22.03.2023
|
|
VILJE
|
Reservoir
|
Vilje produces oil from turbidite sandstone of Paleocene age in the Heimdal Formation. The reservoir has good properties and lies in a fan system at a depth of 2,150 metres.
|
3392471
|
28.02.2023
|
22.03.2023
|
|
VILJE
|
Transport
|
The well stream is routed by pipeline to the Alvheim FPSO, where the oil is offloaded to shuttle tankers. The gas is transported by pipeline from Alvheim to the Scottish Area Gas Evacuation (SAGE) pipeline in the UK sector.
|
3392471
|
28.02.2023
|
22.03.2023
|
|
VISUND
|
Recovery strategy
|
The field is mainly produced by pressure depletion, and partly with pressure support from water injection. Gas has earlier also been injected in some segments, but increased gas export since 2015 has reduced gas available for injection. Gas injection has been terminated in 2021.
|
43745
|
28.02.2023
|
22.03.2023
|
|
VISUND
|
Transport
|
The oil is transported by pipeline to the Gullfaks A facility for storage and export via tankers. Gas is exported through the Kvitebjørn Gas Pipeline and on to the Kollsnes terminal, where the NGL is separated, and the dry gas is further exported to the market.
|
43745
|
28.02.2023
|
22.03.2023
|
|
VISUND
|
Status
|
The strategy for the Visund field is to maintain reservoir pressure within drilling limits and optimise oil recovery, while increasing gas exports. New production wells are being drilled continuously, some with exploration targets.
|
43745
|
28.02.2023
|
22.03.2023
|
|
VISUND
|
Development
|
Visund is a field in the northern part of the North Sea, northeast of the Gullfaks field. The water depth is 335 metres. Visund was discovered in 1986, and the plan for development and operation (PDO) was approved in 1996. The field is developed with a semi-submersible, integrated accommodation, drilling and processing facility (Visund A) and a subsea facility in the northern part of the field. Production started in 1999. A PDO for the gas phase was approved in 2002 and gas export started in 2005. A PDO exemption was granted in 2013 for the deposits Rhea and Titan east on Visund. The subsea facility north on Visund was replaced in 2013 due to problems with the original template. In 2017, a PDO exemption was granted for another subsea template north on Visund.
|
43745
|
28.02.2023
|
22.03.2023
|
|
VISUND
|
Reservoir
|
Visund produces oil and gas from sandstone of Late Triassic and Early Jurassic age in the Lunde Formation and Statfjord Group, and of Middle Jurassic age in the Brent Group. The reservoirs are in several tilted fault blocks with varying pressure and liquid systems. The reservoirs lie at a depth of 2,900-3,000 metres. Reservoir quality is generally good in the main reservoirs.
|
43745
|
28.02.2023
|
22.03.2023
|
|
VISUND SØR
|
Development
|
Visund Sør is a field in the northern part of the North Sea, 10 kilometres northeast of the Gullfaks C platform. The water depth is 290 metres. Visund Sør was discovered in 2008, and the plan for development and operation (PDO) was approved in 2011. The field is developed with a subsea template tied to Gullfaks C. Production started in 2012.
|
20461008
|
28.02.2023
|
22.03.2023
|
|
VISUND SØR
|
Transport
|
The well stream is transported to Gullfaks C for processing and export.
|
20461008
|
28.02.2023
|
22.03.2023
|
|
VISUND SØR
|
Status
|
Production has been shut down due to low reservoir presser and high water cut ratio.
|
20461008
|
28.02.2023
|
22.03.2023
|
|
VISUND SØR
|
Recovery strategy
|
The field is produced by pressure depletion.
|
20461008
|
28.02.2023
|
22.03.2023
|
|
VISUND SØR
|
Reservoir
|
Visund Sør produces oil and gas from Middle Jurassic sandstone in the Brent Group. The reservoir depth is 2,800-2,900 metres.
|
20461008
|
28.02.2023
|
22.03.2023
|
|
VOLUND
|
Recovery strategy
|
The field is produced with significant pressure support from the aquifer and with injection of produced water delivered from the Alvheim FPSO.
|
4380167
|
28.02.2023
|
22.03.2023
|
|
VOLUND
|
Reservoir
|
Volund produces oil from Paleocene sandstone in the Hermod Formation. The deposit is a unique injectite trap. The sand was remobilised in the early Eocene and injected into the overlying Balder Formation. The reservoir lies at a depth of 2,000 metres and has excellent quality.
|
4380167
|
28.02.2023
|
22.03.2023
|
|
VOLUND
|
Development
|
Volund is a field in the North Sea, 10 kilometres south of the Alvheim field. The water depth is 120 metres. Volund was discovered in 1994, and the plan for development and operation (PDO) was approved in 2007. The field was developed with a subsea template including four horizontal subsea production wells and one injection well tied to the Alvheim production, storage and offloading vessel (FPSO). Production started in 2009. An additional subsea template was installed later.
|
4380167
|
28.02.2023
|
22.03.2023
|
|
VOLUND
|
Status
|
The recoverable volume estimates are significantly higher than in the PDO, partly because of additional wells drilled on the field. However, production from Volund is now declining due to increasing water cut.
|
4380167
|
28.02.2023
|
22.03.2023
|
|
VOLUND
|
Transport
|
The well stream is routed by pipeline to the Alvheim FPSO. The oil is offloaded to shuttle tankers, and the associated gas is transported to the Scottish Area Gas Evacuation (SAGE) pipeline system and further to St Fergus in the UK.
|
4380167
|
28.02.2023
|
22.03.2023
|
|
VOLVE
|
Recovery strategy
|
The field was produced with water injection for pressure support.
|
3420717
|
28.02.2023
|
22.03.2023
|
|
VOLVE
|
Status
|
The field was shut down in 2016 and the facility was removed in 2018.
|
3420717
|
28.02.2023
|
22.03.2023
|
|
VOLVE
|
Transport
|
The oil was exported by tankers and the rich gas was transported to the Sleipner A facility for further export.
|
3420717
|
28.02.2023
|
22.03.2023
|
|
VOLVE
|
Reservoir
|
Volve produced oil from sandstone of Middle Jurassic age in the Hugin Formation. The reservoir is at a depth of 2,700-3,100 metres. The western part of the structure is heavily faulted and communication across the faults is uncertain.
|
3420717
|
28.02.2023
|
22.03.2023
|
|
VOLVE
|
Development
|
Volve is a field in the central part of the North Sea, five kilometres north of the Sleipner Øst field. The water depth is 80 metres. Volve was discovered in 1993, and the plan for development and operation (PDO) was approved in 2005. The field was developed with a jack-up processing and drilling facility. The vessel "Navion Saga" was used for storing stabilised oil. Production started in 2008.
|
3420717
|
28.02.2023
|
22.03.2023
|
|
YME
|
Reservoir
|
The reservoir contains oil in two separate main structures, Gamma and Beta. The structures comprise six deposits. The reservoirs are in sandstone of Middle Jurassic age in the Sandnes Formation, at a depth of 3,150 metres. They are heterogeneous and have variable reservoir Properties.
|
43807
|
28.02.2023
|
22.03.2023
|
|
YME
|
Transport
|
The oil is transported with tankers and the gas is reinjected.
|
43807
|
28.02.2023
|
22.03.2023
|
|
YME
|
Recovery strategy
|
The field is produced by pressure support from partial water injection and water alternating gas (WAG) injection.
|
43807
|
28.02.2023
|
22.03.2023
|
|
YME
|
Development
|
Yme is a field in the southeastern part of the Norwegian sector of the North Sea, 130 kilometres northeast of the Ula field. The water depth is 100 metres. The field comprises two separate main structures, Gamma and Beta, which are 12 kilometres apart. Yme was discovered in 1987, and the plan for development and operation (PDO) was approved in 1995. Yme was originally developed with a jack-up drilling and production platform on the Gamma structure and a storage vessel. The Beta structure was developed with a subsea template. Production started in 1996. In 2001, production ceased because operation of the field was no longer regarded as profitable. Yme was the first field on the Norwegian continental shelf to be considered for redevelopment after being shut down. The PDO for a redevelopment was approved in 2007. The development concept was a new mobile offshore production unit (MOPU). Due to structural deficiencies and the vast amount of outstanding work to complete the MOPU, it was decided to remove it from the field in 2013. The MOPU was removed in 2016 in accordance with the authorities' formal disposal resolution. In 2018, an amended PDO for the redevelopment of Yme was approved. The PDO includes a jack-up rig equipped with drilling and production facilities installed on the Gamma structure, a subsea template on the Beta structure, and reuse of existing facilities on the field.
|
43807
|
28.02.2023
|
22.03.2023
|
|
YME
|
Status
|
Production started again in October 2021.
|
43807
|
28.02.2023
|
22.03.2023
|
|
YTTERGRYTA
|
Development
|
Yttergryta is a field in the Norwegian Sea, 33 kilometres east of the Åsgard B platform. The water depth is 300 metres. Yttergryta was discovered in 2007, and the plan for development and operation (PDO) was approved in 2008. The field was developed with a subsea template connected to the Åsgard B platform via the Midgard X template. Production started in 2009.
|
4973114
|
28.02.2023
|
22.03.2023
|
|
YTTERGRYTA
|
Status
|
Production ceased in 2011 because of water breakthrough in the gas production well. An attempt to restart production in 2012 failed, and the field was shut down. The facility on Yttergryta is disconnected from the Midgard X template and will be decommissioned at the same time as the Åsgard facilities.
|
4973114
|
28.02.2023
|
22.03.2023
|
|
YTTERGRYTA
|
Reservoir
|
Yttergryta produced gas from sandstone of Middle Jurassic age in the Fangst Group. The reservoir is at a depth of 2,400-2,500 metres.
|
4973114
|
28.02.2023
|
22.03.2023
|
|
YTTERGRYTA
|
Transport
|
The gas was transported to the template Midgard X and further to the Åsgard B facility for processing. The gas from Yttergryta had a low CO2 content, making it suitable for dilution of CO2 in the Åsgard Transport System (ÅTS).
|
4973114
|
28.02.2023
|
22.03.2023
|
|
YTTERGRYTA
|
Recovery strategy
|
The field was produced by pressure depletion.
|
4973114
|
28.02.2023
|
22.03.2023
|
|
ÆRFUGL NORD
|
Recovery strategy
|
The field is produced by depletion.
|
38542241
|
28.02.2023
|
22.03.2023
|
|
ÆRFUGL NORD
|
Reservoir
|
The reservoir contains gas and condensate in sandstone of Cretaceous age in the Lysing Formation. It has good properties and lies at a depth of 2800 metres.
|
38542241
|
28.02.2023
|
22.03.2023
|
|
ÆRFUGL NORD
|
Transport
|
The well stream is transported to the Skarv FPSO for processing. The condensate is offloaded to shuttle tankers, while the gas is transported to the Kårstø terminal in an 80-kilometre pipeline connected to the Åsgard Transport System (ÅTS).
|
38542241
|
28.02.2023
|
22.03.2023
|
|
ÆRFUGL NORD
|
Status
|
Production started in November 2021, and the field produces according to plan.
|
38542241
|
28.02.2023
|
22.03.2023
|
|
ÆRFUGL NORD
|
Development
|
Ærfugl Nord is a field in the northern part of the Norwegian Sea, just west of the Skarv field. The water depth is 350-450 metres. Ærfugl Nord was discovered in 2012, and the plan for development and operation (PDO) was approved in 2018. The Ærfugl Nord development includes one production well tied-back to the Skarv production, storage and offloading vessel (FPSO).
|
38542241
|
28.02.2023
|
22.03.2023
|
|
ØST FRIGG
|
Transport
|
Gas was transported in a pipeline from the manifold to the Frigg field (TCP2) for processing, and further via pipeline the Shell-Esso Gas and Liquids (SEGAL) terminal at St Fergus in the UK.
|
43576
|
28.02.2023
|
22.03.2023
|
|
ØST FRIGG
|
Reservoir
|
Øst Frigg produced gas from sandstone of Eocene age in the Frigg Formation. The reservoir lies at a depth of 1900 metres and has excellent quality. The field contains two separate structures, which are part of the same pressure system as the Frigg field.
|
43576
|
28.02.2023
|
22.03.2023
|
|
ØST FRIGG
|
Development
|
Øst Frigg is a field in the central part of the North Sea, four kilometres east of the Frigg field. The water depth is 100 metres. Øst Frigg was discovered in 1973, and the plan for development and operation (PDO) was approved in 1984. The field was developed with two subsea templates and a central manifold station tied to the Frigg field. Production started in 1988.
|
43576
|
28.02.2023
|
22.03.2023
|
|
ØST FRIGG
|
Recovery strategy
|
The field was produced by pressure depletion.
|
43576
|
28.02.2023
|
22.03.2023
|
|
ØST FRIGG
|
Status
|
Production was shut down in 1997 and the subsea templates were removed in 2001. The planned development of the area between the Oseberg and Alvheim fields might lead to a future redevelopment of the field, depending on results from exploration and appraisal activities.
|
43576
|
28.02.2023
|
22.03.2023
|
|
ÅSGARD
|
Recovery strategy
|
Smørbukk is produced partly by pressure depletion and partly by injection of excess gas from the field. Smørbukk Sør is produced by pressure support from gas injection. Midgard is produced by pressure depletion.
|
43765
|
28.02.2023
|
22.03.2023
|
|
ÅSGARD
|
Status
|
Work is ongoing to increase the recovery from the field, with focus on further reduction of pressure on the facilities and identification of new targets for infill drilling. Challenges for Åsgard are avoiding minimum flow in the subsea flowlines and depleted reservoirs that impact the drilling window. Installation of the Åsgard subsea gas compressor (ÅSC) in 2015/2016 has accelerated and prolonged gas production from the field. The ÅSC Phase II development is ongoing. Avoiding minimum flow in the subsea flowlines is a challenge for Åsgard production. Third party tie-ins to Åsgard and identification of new resource potential can prolong the lifetime of the facilities.
|
43765
|
28.02.2023
|
22.03.2023
|
|
ÅSGARD
|
Development
|
Åsgard is a field in the central part of the Norwegian Sea. The water depth is 240-300 metres. Åsgard was discovered in 1981, and the plan for development and operation (PDO) was approved in 1996. The Åsgard field includes the deposits Smørbukk, Smørbukk Sør and Midgard. The field has been developed with subsea wells tied-back to a production, storage and offloading vessel (FPSO), Åsgard A. The development also includes Åsgard B, a floating, semi-submersible facility for gas and condensate processing. The gas centre is connected to a storage vessel for condensate, Åsgard C. Production started in 1999 and gas export started in 2000. The Åsgard facilities are an important part of the Norwegian Sea infrastructure. The Mikkel and Morvin fields are tied to Åsgard B for processing, and gas from Åsgard B is sent to the Tyrihans field for gas lift. The PDO for a gas compression facility at Midgard was approved in 2012. The Trestakk field is tied-in to Åsgard A.
|
43765
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28.02.2023
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22.03.2023
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ÅSGARD
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Reservoir
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Åsgard produces gas and considerable amounts of condensate from Jurassic sandstone at depths of as much as 4850 metres. The reservoir quality varies in the different formations, and there are large variations in the reservoir properties between the three deposits. The Smørbukk deposit is in a rotated fault block and contains gas, condensate and oil in the Åre, Tilje, Tofte, Ile and Garn Formations. The Smørbukk Sør deposit contains oil, gas and condensate in the Tilje, Ile and Garn Formations. The Midgard gas deposits are divided into four structural segments with the main reservoir in the Ile and Garn Formations.
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43765
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28.02.2023
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22.03.2023
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ÅSGARD
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Transport
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Oil and condensate are temporarily stored at Åsgard A, then shipped to land by tankers. The gas is exported through the Åsgard Transport System (ÅTS) to the terminal at Kårstø. The condensate from Åsgard is sold as oil.
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43765
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28.02.2023
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22.03.2023
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AASTA HANSTEEN
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Transport
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Gas from Aasta Hansteen is transported via the Polarled pipeline to the terminal at Nyhamna. Light oil is offloaded to shuttle tankers and transported to the market.
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23395946
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28.02.2023
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22.03.2023
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AASTA HANSTEEN
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Reservoir
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The main reservoirs contain gas in Upper Cretaceous sandstone in the Nise Formation, at a depth of 3000 metres. The reservoir quality is good.
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23395946
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28.02.2023
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22.03.2023
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AASTA HANSTEEN
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Development
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Aasta Hansteen is a field in the northern part of the Norwegian Sea, 120 kilometres northwest of the Norne field. The water depth is 1,270 metres. Aasta Hansteen was discovered in 1997, and the plan for development and production (PDO) was approved in 2013. The field initially comprised three separate deposits: Luva, Haklang and Snefrid Sør. A new deposit was discovered in 2015, Snefrid Nord. The field is developed with a spar platform, a floating installation with a cylindrical column moored to the seabed. The development also includes two subsea templates with four slots each and two subsea templates with one slot each (satellites). The templates are tied-back to the platform through pipelines and steel catenary risers. Aasta Hansteen was granted a PDO exemption for the development of the Snefrid Nord deposit in 2017. Production started in 2018.
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23395946
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28.02.2023
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22.03.2023
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AASTA HANSTEEN
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Recovery strategy
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The field is produced by pressure depletion and natural aquifer drive.
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23395946
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28.02.2023
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22.03.2023
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AASTA HANSTEEN
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Status
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The field is producing at plateau gas rate at present, and low pressure production is being planned for the future. Aasta Hansteen is considered a possible host for nearby discoveries after the field has gone off plateau production. A PDO for the tie-in of the Irpa discovery to Aasta Hansteen was submitted in 2022.
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23395946
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28.02.2023
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22.03.2023
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