Table – Description
|
Field name
|
Type
|
Text
|
NPDID field
|
Date updated
|
Date sync NPD
|
|---|---|---|---|---|---|
|
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
|
08.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
ALBUSKJELL
|
Recovery
|
The field was produced by pressure depletion.
|
43437
|
11.04.2017
|
28.02.2021
|
|
ALBUSKJELL
|
Transport
|
The well stream was transported via pipeline to the Ekofisk Complex for export.
|
43437
|
16.03.2018
|
28.02.2021
|
|
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
|
02.02.2021
|
28.02.2021
|
|
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 well slots and three production wells. Alve is tied to the Norne production, storage and offloading vessel (FPSO) by a pipeline. Production started in 2009.
|
4444332
|
12.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
ALVE
|
Recovery
|
The field is produced by pressure depletion.
|
4444332
|
16.03.2018
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
ALVE
|
Status
|
Production from Alve is constrained by the commercial agreement with the Norne licence and the gas handling capacity on the Norne FPSO. Alve can produce above volumes reserved in the commercial agreement if there is available capacity on the Norne FPSO.
|
4444332
|
12.02.2020
|
28.02.2021
|
|
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 24/6-2 (Kameleon), 24/6-4 (Boa), 25/4-7 (Kneler), 25/4-10 S (Viper), 25/7-5 (Kobra) and 25/4-3 (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 and Bøyla fields are tied-back to Alvheim. The Skogul discovery has been tied-back to the Alvheim FPSO via the Vilje field.
|
2845712
|
12.02.2020
|
28.02.2021
|
|
ALVHEIM
|
Reservoir
|
Alvheim produces oil and gas from Paleocene sandstone in the Hermod and Heimdal Formations. The reservoirs are in submarine fan deposits and lie mostly at depths of 2,100 to 2,200 metres. The reservoir quality is good.
|
2845712
|
25.04.2019
|
28.02.2021
|
|
ALVHEIM
|
Recovery
|
The field is produced by natural water drive from an underlying aquifer.
|
2845712
|
16.03.2018
|
28.02.2021
|
|
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
|
11.04.2017
|
28.02.2021
|
|
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 potential hub for more discoveries in the area, for example 25/4-2 (Trine) and 25/5-9 (Trell).
|
2845712
|
04.02.2021
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
ATLA
|
Recovery
|
The field is produced by pressure depletion.
|
21106284
|
16.03.2018
|
28.02.2021
|
|
ATLA
|
Transport
|
The well stream is transported via the Skirne/Byggve subsea facility to Heimdal for processing and export.
|
21106284
|
16.03.2018
|
28.02.2021
|
|
ATLA
|
Status
|
The field is in the tail phase and has produced intermittently after pressure build-up during the last few years. Atla was producing the first part of 2019, but no further commercial production is expected. A decommissioning plan was submitted to the authorities in 2015. According to the formal disposal decision, the facility must be removed by the end of 2021.
|
21106284
|
25.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
BALDER
|
Status
|
A revised PDO for Balder and Ringhorne was approved in June 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 2022.
|
43562
|
17.02.2021
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
BALDER
|
Recovery
|
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
|
11.04.2017
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
BAUGE
|
Development
|
Bauge is a field on Haltenbanken 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
|
26.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
BAUGE
|
Recovery strategy
|
The field will be produced by partial pressure maintenance from phased water injection, which will start a few years after production start-up.
|
29446221
|
16.03.2018
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
BAUGE
|
Status
|
The field is under development.
|
29446221
|
02.02.2021
|
28.02.2021
|
|
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 to Ula. Production started in 2007.
|
3437650
|
12.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
BLANE
|
Recovery
|
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
|
17.02.2021
|
28.02.2021
|
|
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, while the gas is sold to Ula for injection into the Ula reservoir.
|
3437650
|
16.03.2018
|
28.02.2021
|
|
BLANE
|
Status
|
Production from the field has generally been good. Water injection stopped because of a rupture in the flowline. The impact of water injection is currently being studied. In order to maximise recovery on Blane, an infill well is being evaluated.
|
3437650
|
17.02.2021
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
BRAGE
|
Recovery
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
08.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
BRYNHILD
|
Recovery
|
The field was produced by pressure support from water injection. Water for injection was supplied from the Pierce field.
|
21123063
|
25.04.2019
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
BRYNHILD
|
Status
|
Production from Brynhild ceased in 2018. According to the formal removal resolution, decommissioning must be completed by the end of June 2022.
|
21123063
|
02.02.2021
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
BYRDING
|
Recovery strategy
|
The field is produced by pressure depletion.
|
28975067
|
16.03.2018
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
BYRDING
|
Status
|
The field is producing with a higher gas/oil ratio (GOR) than expected.
|
28975067
|
25.04.2019
|
28.02.2021
|
|
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, which was drilled from the Fram H-Nord template. Production started in 2017.
|
28975067
|
12.02.2020
|
28.02.2021
|
|
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 installation 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
|
12.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
BØYLA
|
Recovery
|
The field is produced with pressure support from water injection. Gas lift is also necessary to support flow in the wells.
|
22492497
|
25.04.2019
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
BØYLA
|
Status
|
Test production from the nearby 24/9-12 S (Frosk) discovery is ongoing. This resulted in delayed production from Bøyla in 2019 and 2020. Production from the field will also be shut-in during production testing on Frosk in 2021.
|
22492497
|
17.02.2021
|
28.02.2021
|
|
COD
|
Recovery
|
The field was produced by pressure depletion.
|
43785
|
11.04.2017
|
28.02.2021
|
|
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
|
08.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
COD
|
Transport
|
The well stream was sent via pipeline to the Ekofisk Complex for export.
|
43785
|
16.03.2018
|
28.02.2021
|
|
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. Currently, there are no plans for recovering the remaining resources on Cod.
|
43785
|
08.02.2020
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
DRAUGEN
|
Recovery
|
The field is produced by pressure maintenance from water injection and by aquifer support.
|
43758
|
11.04.2017
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
DRAUGEN
|
Status
|
With declining oil production, sufficient volumes of associated gas will not be available for power generation, and alternative solutions are therefore being evaluated. The gas discovery 6407/9-9 (Hasselmus) is under evaluation for subsea tie-back to the Draugen platform. Identification and maturing of infill targets is 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
|
25.02.2020
|
28.02.2021
|
|
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
|
05.09.2019
|
28.02.2021
|
|
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 will be developed with a 4-slot subsea template with three oil production wells and one gas production well tied-back to the Gjøa platform.
|
34833026
|
02.02.2021
|
28.02.2021
|
|
DUVA
|
Recovery strategy
|
The field will be produced by pressure depletion and gas expansion in the gas cap.
|
34833026
|
05.09.2019
|
28.02.2021
|
|
DUVA
|
Transport
|
The well stream will be routed to the Gjøa platform for processing and export. The oil will be transported further through the Troll Oil Pipeline II to the Mongstad terminal, and the gas will be exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus in the UK.
|
34833026
|
26.02.2020
|
28.02.2021
|
|
DUVA
|
Status
|
The field is under development, and production is scheduled to start in 2021.
|
34833026
|
02.02.2021
|
28.02.2021
|
|
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.
|
29393934
|
26.02.2020
|
28.02.2021
|
|
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
|
17.12.2020
|
28.02.2021
|
|
DVALIN
|
Recovery strategy
|
The field is produced by pressure depletion.
|
29393934
|
17.12.2020
|
28.02.2021
|
|
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
|
17.12.2020
|
28.02.2021
|
|
DVALIN
|
Status
|
Production from Dvalin started in November 2020.
|
29393934
|
17.12.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
EDDA
|
Recovery
|
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
|
11.04.2017
|
28.02.2021
|
|
EDDA
|
Transport
|
The well stream was sent via pipeline to the Ekofisk Complex for export.
|
43541
|
16.03.2018
|
28.02.2021
|
|
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
|
02.02.2021
|
28.02.2021
|
|
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. The Edvard Grieg installation supplies power to the Ivar Aasen field and processes the well stream from Ivar Aasen. The installation is also equipped for possible tie-in of nearby discoveries. Production started in 2015.
|
21675433
|
12.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
EDVARD GRIEG
|
Recovery
|
The field is produced by pressure support from water injection.
|
21675433
|
11.04.2017
|
28.02.2021
|
|
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
|
11.04.2017
|
28.02.2021
|
|
EDVARD GRIEG
|
Status
|
The field has been producing better than expected and recoverable volumes have increased significantly since the PDO. All producers and injectors initially planned are now on stream.
|
21675433
|
04.02.2021
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
EKOFISK
|
Recovery
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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. Successive removal of obsolete[TA1] facilities included in the Ekofisk I decommissioning plan is ongoing.
|
43506
|
17.02.2021
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
ELDFISK
|
Recovery
|
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
|
11.04.2017
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
ELDFISK
|
Status
|
The drilling campaign in the Eldfisk II project started in 2014, and drilling of the remaining wells is expected to be completed in 2021. Drilling targets are also being matured in the eastern structure, Eldfisk Øst. A further development of the northern part of the field is being evaluated.
|
43527
|
17.02.2021
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
EMBLA
|
Recovery
|
The field is produced by pressure depletion.
|
43534
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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 active producers. Because of the complexity of the reservoir, there are no plans other than optimising the existing production wells.
|
43534
|
17.02.2021
|
28.02.2021
|
|
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 a subsea facility on the UK continental shelf and is tied to the British Brae field. Production started in 2007.
|
3437659
|
16.03.2018
|
28.02.2021
|
|
ENOCH
|
Recovery
|
The field is produced by pressure depletion.
|
3437659
|
11.04.2017
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
ENOCH
|
Status
|
The field is in the late tail phase. Cease of economic production is currently estimated for the end of 2022.
|
3437659
|
25.02.2020
|
28.02.2021
|
|
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 planned development consists of two subsea templates with a total of six wells tied-back to the Njord A facility.
|
31164879
|
18.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
18.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
FENJA
|
Status
|
Production is planned to start in 2021. The Bue discovery is included in the development as a potential upside. An appraisal well is planned to be drilled on Bue.
|
31164879
|
02.02.2021
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
FLYNDRE
|
Recovery
|
The field is produced by pressure depletion. Only the Balmoral reservoir is developed.
|
24635035
|
16.03.2018
|
28.02.2021
|
|
FLYNDRE
|
Status
|
Production has been lower than expected since start-up. The main challenge is a more rapid pressure decline than anticipated. Production from Flyndre is dependent on export via Fulmar; work is ongoing to clarify potential production on Flyndre beyond the expected lifetime of Fulmar.
|
24635035
|
25.04.2019
|
28.02.2021
|
|
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.
|
1578840
|
17.02.2021
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
FRAM
|
Recovery
|
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. The gas blow-down phase, production of the gas cap, has started at Fram Vest.
|
1578840
|
25.02.2020
|
28.02.2021
|
|
FRAM
|
Transport
|
The well stream is transported by pipeline to the Troll C platform 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.
|
1578840
|
17.02.2021
|
28.02.2021
|
|
FRAM
|
Status
|
A new gas module dedicated to Fram has been installed on Troll C and started operation early 2020. Two exploration wells near Fram are planned for 2021.
|
1578840
|
17.02.2021
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
FRAM H-NORD
|
Recovery
|
The field is produced by pressure depletion.
|
23410947
|
16.03.2018
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
FRAM H-NORD
|
Status
|
Fram H-Nord has produced below expectations. The field is currently not producing due to lower pressure compared with the Fram Vest production pipeline.
|
23410947
|
25.02.2020
|
28.02.2021
|
|
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
|
11.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
FRIGG
|
Recovery
|
The field was produced by pressure depletion.
|
43555
|
11.04.2017
|
28.02.2021
|
|
FRIGG
|
Status
|
The field was shut down in 2004 and final disposal of the facilities was completed in 2010. The concrete substructures TP1 and CDP1 on the British side and the substructure TCP2 on the Norwegian side were abandoned on-site. A production licence comprising the Frigg field was awarded in the Awards in Predefined Areas (APA) 2016 licensing round. The redevelopment of Frigg is planned as a subsea field development. It is being considered as part of a larger development in the area between the Oseberg and Alvheim fields. An appraisal well was drilled on Frigg in 2019.
|
43555
|
26.02.2020
|
28.02.2021
|
|
FRØY
|
Status
|
The field was shut down in 2001 and the facility was removed in 2002. Frøy is being considered as part of a larger development in the area between the Oseberg and Alvheim fields.
|
43597
|
26.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
FRØY
|
Reservoir
|
Frøy produced oil from Jurassic sandstone in the Brent Group at a depth of 3,200-3,300 metres.
|
43597
|
25.04.2019
|
28.02.2021
|
|
FRØY
|
Recovery
|
The field was produced by pressure support from water injection.
|
43597
|
16.03.2018
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
GAUPE
|
Status
|
A decommissioning plan was submitted in 2016. Production from Gaupe ceased in 2018.
|
18161341
|
11.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
GAUPE
|
Recovery
|
The field was produced by pressure depletion.
|
18161341
|
25.04.2019
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
11.02.2020
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
GIMLE
|
Recovery
|
The field is produced by partial pressure support from water injection. Injection is temporarily stopped due to production shut down.
|
4005142
|
25.02.2020
|
28.02.2021
|
|
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
|
28.02.2021
|
|
|
GIMLE
|
Status
|
Gimle is temporarily shut down due to low reservoir pressure. Drilling of a new production well from Gullfaks C is being evaluated to recover the remaining resources in Gimle.
|
4005142
|
25.02.2020
|
28.02.2021
|
|
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.
|
23384544
|
25.02.2020
|
28.02.2021
|
|
GINA KROG
|
Reservoir
|
Gina Krog produces oil and gas from sandstone of Middle Jurassic age in the Hugin Formation. The reservoir is complex and compartmentalised with poor to moderate quality, and lies at a depth of 3,700 metres.
|
23384544
|
25.04.2019
|
28.02.2021
|
|
GINA KROG
|
Recovery
|
The field is produced by gas injection. Gas is imported from Zeepipe 2A for gas injection and gas lift in the wells.
|
23384544
|
16.03.2018
|
28.02.2021
|
|
GINA KROG
|
Transport
|
Wet gas is exported by pipeline to the Sleipner A facility and stabilised. Sales gas is exported from Sleipner A via Gassled (Area D) to the market, while unstable condensate is exported to the Kårstø terminal. Oil is transported to a floating storage and offloading vessel (Randgrid FSO), and then offloaded to shuttle tankers for further transport.
|
23384544
|
30.11.2019
|
28.02.2021
|
|
GINA KROG
|
Status
|
The field is producing according to the plan. The primary drilling campaign was finalised in July 2019. Maturation of additional well targets for future drilling campaigns is ongoing. It is planned that the facility will be supplied with power from shore starting in 2022, as part of the electrification of the Utsira High area.
|
23384544
|
25.02.2020
|
28.02.2021
|
|
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 field is tied-back to Gjøa for processing and further export.
|
4467574
|
17.02.2021
|
28.02.2021
|
|
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
|
12.02.2020
|
28.02.2021
|
|
GJØA
|
Recovery
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
GJØA
|
Status
|
Production start-up of the new wells in the P1 segment is expected early 2021. The Duva and Nova fields are under development as tie-ins to the Gjøa platform and are expected to start production in late 2021 and early 2022, respectively.
|
4467574
|
17.02.2021
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
GLITNE
|
Recovery
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
11.02.2020
|
28.02.2021
|
|
GLITNE
|
Status
|
The field was shut down in 2013, and decommissioning was completed in 2015.
|
1272071
|
25.04.2019
|
28.02.2021
|
|
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 production started the same year.
|
5774394
|
13.02.2020
|
28.02.2021
|
|
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
|
13.02.2020
|
28.02.2021
|
|
GOLIAT
|
Recovery
|
The field is produced using water injection as pressure support. Additional pressure support results from reinjection of produced gas.
|
5774394
|
13.02.2020
|
28.02.2021
|
|
GOLIAT
|
Transport
|
The oil is offloaded to shuttle tankers for transport to the market. Future gas export is pending an export solution.
|
5774394
|
25.04.2019
|
28.02.2021
|
|
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. In 2018, production from two new infill wells started. Drilling of the Goliat Vest prospect in 2018 resulted in additional resources. More infill wells and exploration wells are planned.
|
5774394
|
25.02.2020
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
GRANE
|
Recovery
|
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
|
16.03.2018
|
28.02.2021
|
|
GRANE
|
Transport
|
Oil from Grane is transported by pipeline to the Sture terminal for storage and export.
|
1035937
|
28.02.2021
|
|
|
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 25/8-4 (D-struktur) and 25/11-27 (F-struktur) discoveries in the area are considered for tie-in to the Grane platform.
|
1035937
|
25.02.2020
|
28.02.2021
|
|
GUDRUN
|
Status
|
Plateau production has been short for both oil and gas, and production is now declining. Work is ongoing to maximise recovery from the field by water injection, infill drilling and additional increased oil recovery (IOR) measures. Water injection is planned to start in 2021. It is planned that the facility will be operated with power from shore starting in 2022, 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
|
04.02.2021
|
28.02.2021
|
|
GUDRUN
|
Transport
|
Wet gas and oil are transported in separate pipelines to the Sleipner A facility. Sales gas is transported from Sleipner A via Gassled (Area D) to the market, while oil is transported to the Kårstø terminal.
|
18116481
|
16.03.2018
|
28.02.2021
|
|
GUDRUN
|
Recovery
|
The field is produced by pressure depletion.
|
18116481
|
16.03.2018
|
28.02.2021
|
|
GUDRUN
|
Reservoir
|
Gudrun produces oil from sandstone in the Upper Jurassic Draupne Formation and gas from the Middle Jurassic Hugin Formation. The reservoirs are complex, and uncertainties are associated with sand distribution and connectivity, especially for the Draupne Formation. The reservoirs lie at a depth of 4,000-4,700 metres and have moderate quality.
|
18116481
|
25.04.2019
|
28.02.2021
|
|
GUDRUN
|
Development
|
Gudrun is a field in the central part of the North Sea, 50 kilometres north of the Sleipner field. The water depth is 110 metres. Gudrun was discovered in 1975, and the plan for development and operation (PDO) was approved in 2010. A PDO exemption for the discovery 15/3-9 was granted in 2013. The field is developed with a steel jacket and a topside first-stage process facility and living quarters. The field is tied-back to the Sleipner A facility with two pipelines, one for oil and one for wet gas. Production started in 2014.
|
18116481
|
13.02.2020
|
28.02.2021
|
|
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 will consist of 11 floating turbines which will supply electricity to the Snorre and Gullfaks fields. The Snorre and Gullfaks platforms will be the first platforms in the world to receive power from a floating wind farm.
|
43686
|
17.02.2021
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
GULLFAKS
|
Recovery
|
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
|
17.02.2021
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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 is scheduled for start-up at the end of 2022.
|
43686
|
17.02.2021
|
28.02.2021
|
|
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[HT1] , 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
|
25.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
GULLFAKS SØR
|
Recovery
|
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 currently not in production. The Rutil, Opal and Opal Sør deposits are produced by pressure depletion.
|
43699
|
25.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
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 Gammahøyden in 2007.
|
43464
|
13.02.2020
|
28.02.2021
|
|
GUNGNE
|
Reservoir
|
Gungne produces gas from Triassic sandstone in the Skagerrak Formation. The field additionally produces considerable amounts of condensate. The reservoir lies at a depth of 2,800 metres. The reservoir quality is generally good, but the reservoir is segmented, and lateral shale layers act as internal barriers.
|
43464
|
25.04.2019
|
28.02.2021
|
|
GUNGNE
|
Recovery
|
The field is produced by pressure depletion.
|
43464
|
25.04.2019
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
GUNGNE
|
Status
|
Gungne is in the late tail production phase. Injection of CO2 is being evaluated to increase recovery.
|
43464
|
13.02.2020
|
28.02.2021
|
|
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
|
18.03.2020
|
28.02.2021
|
|
GYDA
|
Reservoir
|
Gyda produced oil from three reservoirs in Upper Jurassic sandstone in the Ula Formation. The reservoir depth is 4,000 metres.
|
43492
|
18.03.2020
|
28.02.2021
|
|
GYDA
|
Recovery
|
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
|
18.03.2020
|
28.02.2021
|
|
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
|
18.03.2020
|
28.02.2021
|
|
GYDA
|
Status
|
Production from Gyda ceased in February 2020. Plugging and abandonment of wells is ongoing. According to the formal removal resolution, decommissioning must be completed by the end of 2023.
|
43492
|
18.03.2020
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
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 shallow marine sandstone with good properties.
|
25307278
|
25.04.2019
|
28.02.2021
|
|
HANZ
|
Recovery
|
The field will be produced by pressure support from water injection.
|
25307278
|
11.04.2017
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
HANZ
|
Status
|
The field is currently under development. The development schedule for production start-up depends on available processing capacities on Ivar Aasen.
|
25307278
|
18.02.2020
|
28.02.2021
|
|
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 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
|
17.02.2021
|
28.02.2021
|
|
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
|
13.02.2020
|
28.02.2021
|
|
HEIDRUN
|
Recovery
|
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
|
16.03.2018
|
28.02.2021
|
|
HEIDRUN
|
Transport
|
The oil is loaded onto tankers and shipped to either the Mongstad terminal or to Tetney in the UK. The gas is transported by pipeline to the terminal at Tjeldbergodden and/or via the Åsgard Transport System (ÅTS) to the Kårstø terminal.
|
43771
|
16.03.2018
|
28.02.2021
|
|
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). A water alternating gas (WAG) injection pilot was started in 2019 and continues injection in 2021. Development of the Alpha Horst discovery is being planned.
|
43771
|
17.02.2021
|
28.02.2021
|
|
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 mainly 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
|
13.02.2020
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
HEIMDAL
|
Recovery
|
The field was produced by pressure depletion.
|
43590
|
17.02.2021
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
HEIMDAL
|
Status
|
Most of the wells were permanently plugged in 2015 and production from Heimdal stopped in 2020. Heimdal is now used as a gas processing centre for tied-in fields. Gas from Valemon, the largest third-party user of Heimdal, is planned to be routed to the Kvitebjørn field from 2022 or 2023. A decommissioning plan for Heimdal was submitted in 2020.
|
43590
|
17.02.2021
|
28.02.2021
|
|
HOD
|
Recovery
|
The field is produced by pressure depletion. Gas lift has been used in some wells to increase production.
|
43485
|
11.04.2017
|
28.02.2021
|
|
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
|
11.04.2017
|
28.02.2021
|
|
HOD
|
Status
|
There has been no production from the Hod platform since 2013, and it awaits decommissioning. Production from the Hod Saddle area is ongoing through wells drilled from the Valhall field. Hod is currently being redeveloped by installing a new wellhead platform tied-in to the Valhall field centre.
|
43485
|
17.02.2021
|
28.02.2021
|
|
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 developed with an unmanned wellhead platform, remotely controlled from Valhall. Production started in 1990. A PDO for Hod Saddle was approved in 1994. A PDO for the redevelopment of Hod was approved in December 2020.
|
43485
|
17.02.2021
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
11.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
HULDRA
|
Recovery
|
The field was produced by pressure depletion and with low pressure production after 2007.
|
97002
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
HULDRA
|
Status
|
Production ceased in 2014, and the facility was removed in 2019.
|
97002
|
26.02.2020
|
28.02.2021
|
|
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
|
13.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
HYME
|
Recovery
|
The field is produced with pressure support from seawater injection. The production well is equipped with gas lift.
|
20474183
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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 in late 2021, when the Njord facility is in place again.
|
20474183
|
17.02.2021
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
ISLAY
|
Reservoir
|
Islay produces gas from Middle Jurassic sandstone in the Brent Formation. The reservoir depth is 3,700-3,900 metres.
|
21105675
|
16.03.2018
|
28.02.2021
|
|
ISLAY
|
Recovery
|
The field is produced by pressure depletion.
|
21105675
|
11.04.2017
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
ISLAY
|
Status
|
The well is producing cyclically at a low rate.
|
21105675
|
13.02.2020
|
28.02.2021
|
|
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.
|
23384520
|
16.03.2018
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
IVAR AASEN
|
Recovery
|
The Ivar Aasen reservoir is produced by pressure support from water injection. The West Cable reservoir is produced by pressure depletion.
|
23384520
|
13.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
IVAR AASEN
|
Status
|
Since production start-up, injection and production wells have been drilled and it is planned to drill new wells.
|
23384520
|
25.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
JETTE
|
Recovery
|
The field was produced with natural pressure support from the aquifer.
|
21613906
|
16.03.2018
|
28.02.2021
|
|
JETTE
|
Transport
|
The well stream was transported to Jotun B and further to Jotun A for processing and loading.
|
21613906
|
16.03.2018
|
28.02.2021
|
|
JETTE
|
Status
|
Production ceased in 2016, and the subsea template was removed in 2019.
|
21613906
|
26.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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 lie 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
|
26.02.2020
|
28.02.2021
|
|
JOHAN CASTBERG
|
Recovery strategy
|
The field will be produced by pressure support from gas and water injection.
|
32017325
|
25.04.2019
|
28.02.2021
|
|
JOHAN CASTBERG
|
Transport
|
The oil will be offloaded to shuttle tankers and transported to the market.
|
32017325
|
25.04.2019
|
28.02.2021
|
|
JOHAN CASTBERG
|
Status
|
The field is currently under development, and production is scheduled to start in late 2022.
|
32017325
|
29.11.2019
|
28.02.2021
|
|
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 development solution for the second phase comprises a process platform and five subsea templates. Modification work will in addition be performed on the riser platform.
|
26376286
|
17.02.2021
|
28.02.2021
|
|
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
|
06.10.2019
|
28.02.2021
|
|
JOHAN SVERDRUP
|
Recovery
|
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
|
06.10.2019
|
28.02.2021
|
|
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
|
13.02.2020
|
28.02.2021
|
|
JOHAN SVERDRUP
|
Status
|
Development of Phase II is ongoing and production is expected to start in 2022.
|
26376286
|
17.02.2021
|
28.02.2021
|
|
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
|
11.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
JOTUN
|
Recovery
|
The field was produced by pressure support from the aquifer and with gas lift. Produced water was injected into the Utsira Formation.
|
43604
|
11.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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 2022.
|
43604
|
02.02.2021
|
28.02.2021
|
|
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 comprises a floating production, storage and offloading vessel (FPSO) and two subsea templates, including six production and injection wells. Production started in 2015.
|
20460988
|
25.02.2020
|
28.02.2021
|
|
KNARR
|
Reservoir
|
Knarr produces 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
|
13.02.2020
|
28.02.2021
|
|
KNARR
|
Recovery
|
The field is produced with water injection for pressure maintenance.
|
20460988
|
16.03.2018
|
28.02.2021
|
|
KNARR
|
Transport
|
Oil is processed and stored on the Knarr FPSO and offloaded to shuttle tankers for export. Gas is exported via the Far North Liquids and Associated Gas System (FLAGS) to St Fergus in the UK.
|
20460988
|
16.03.2018
|
28.02.2021
|
|
KNARR
|
Status
|
The field is in tail phase and is producing with declining oil production and increasing water cut. A decommissioning plan was submitted to the authorities in 2020.
|
20460988
|
04.02.2021
|
28.02.2021
|
|
KRISTIN
|
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.
|
1854729
|
25.02.2020
|
28.02.2021
|
|
KRISTIN
|
Reservoir
|
Kristin produces gas and condensate from Jurassic sandstone in the Garn, Ile and Tofte Formations. The reservoirs lie at a depth of 4,600 metres and have high pressure and high temperature (HPHT). The reservoir quality is generally good, but low permeability in the Garn Formation and flow barriers in the Ile and Tofte Formations contribute to a rapid decline in reservoir pressure.
|
1854729
|
16.03.2018
|
28.02.2021
|
|
KRISTIN
|
Recovery
|
The field is produced by pressure depletion. Low pressure production from the reservoir was implemented in 2014.
|
1854729
|
25.02.2020
|
28.02.2021
|
|
KRISTIN
|
Transport
|
The well stream is processed at Kristin and the gas is transported via the Åsgard Transport System (ÅTS) to the Kårstø terminal. Light oil is transferred to the Åsgard C facility for storage and export. Condensate from Kristin is sold as oil.
|
1854729
|
03.06.2019
|
28.02.2021
|
|
KRISTIN
|
Status
|
Kristin production is in the tail phase. The reservoir pressure has decreased faster than expected, leading to challenges such as production of water and sand. Total recovery from the field is therefore expected to be lower than the PDO estimates. Kristin is considered a possible processing centre for several discoveries in the area.
|
1854729
|
25.02.2020
|
28.02.2021
|
|
KVITEBJØRN
|
Status
|
Drilling on Kvitebjørn is challenging because of low reservoir pressure. New drilling targets are time-critical. Evaluation of new technical concepts for drilling wells with high differential pressures will be a focus area. Work is ongoing to mature new drillings targets.
|
1036101
|
14.02.2020
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
KVITEBJØRN
|
Recovery
|
The field is produced by pressure depletion. Gas pre-compression started in 2014 and has increased the gas recovery from the field.
|
1036101
|
16.03.2018
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
LILLE-FRIGG
|
Status
|
The field was shut down in 1999 and the installation was removed in 2001.
|
43583
|
16.03.2018
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
LILLE-FRIGG
|
Recovery
|
The field was produced by pressure depletion.
|
43583
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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.
|
26465170
|
14.02.2020
|
28.02.2021
|
|
MARIA
|
Reservoir
|
Maria produces oil and gas from the Middle Jurassic Garn Formation. The formation is 90-100 metres thick and consists of massive sandstone with shale layers. The reservoir quality is best in the southern part of the deposit. The underlying Tilje and Ile Formations are aquiferous. The reservoir lies at a depth of 3,800 metres.
|
26465170
|
25.04.2019
|
28.02.2021
|
|
MARIA
|
Recovery
|
The field is produced by water injection for pressure support. The wells are equipped with gas lift.
|
26465170
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
MARIA
|
Status
|
Production has been lower than forecasted since start-up, due to limited reservoir communication and pressure support from the water injectors. Based on the production experience, total recovery from the field is expected to be lower than the PDO estimates. Work is ongoing to increase production, and drilling of more wells is being evaluated to increase recovery from the field.
|
26465170
|
25.02.2020
|
28.02.2021
|
|
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 operations (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. A mobile jack-up rig is utilised for the drilling of production wells. The installation will be supplied with power from shore. A PDO exemption for the Herja discovery and the Hervor prospect was granted in 2017.
|
21675447
|
18.02.2020
|
28.02.2021
|
|
MARTIN LINGE
|
Reservoir
|
The main reservoir contains gas and condensate at high pressure and high temperature (HPHT), and is structurally complex. Three reservoirs are in sandstone of Middle Jurassic age in the Brent Group, at depths of 3,700-4,400 metres. Oil also occurs in the Frigg Formation of Eocene age; the reservoir is at a depth of 1,750 metres and has good quality.
|
21675447
|
25.04.2019
|
28.02.2021
|
|
MARTIN LINGE
|
Recovery
|
The gas reservoir will be produced by pressure depletion. Oil production from the Eocene reservoir will be supported by natural aquifer drive and gas lift. Some produced water will be reinjected.
|
21675447
|
19.02.2021
|
28.02.2021
|
|
MARTIN LINGE
|
Transport
|
Rich gas will be 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 will be exported via tankers from the FSO.
|
21675447
|
16.03.2018
|
28.02.2021
|
|
MARTIN LINGE
|
Status
|
The field is under development. The platform jacket was installed on the field in 2014 and the topside modules in 2018. Production is planned to start in mid-2021.
|
21675447
|
19.02.2021
|
28.02.2021
|
|
MARULK
|
Status
|
Production from Marulk is limited by the commercial agreement with the Norne licensees and the gas handling capacity on the Norne FPSO. Excess capacity in recent years has made it possible to process larger volumes of gas from Marulk. In 2019, a new production well was drilled in the Lange Formation.
|
18212090
|
14.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
MARULK
|
Recovery
|
The field is produced by pressure depletion.
|
18212090
|
16.03.2018
|
28.02.2021
|
|
MARULK
|
Reservoir
|
Marulk produces gas from Cretaceous sandstone in the Lysing Formation. The reservoir lies at a depth of 2,800 metres. Gas is also present in Cretaceous sandstone in the Lange Formation. Both reservoirs are in turbidite fans and have moderate to good quality.
|
18212090
|
14.02.2020
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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 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.
|
1630514
|
17.02.2021
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
MIKKEL
|
Recovery
|
The field is produced by pressure depletion.
|
1630514
|
16.03.2018
|
28.02.2021
|
|
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
|
03.06.2019
|
28.02.2021
|
|
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
|
11.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
MIME
|
Reservoir
|
Mime produced oil from sandstone of Late Jurassic age in the Ula Formation. The reservoir depth is 4,200 metres.
|
43792
|
16.03.2018
|
28.02.2021
|
|
MIME
|
Recovery
|
The filed was produced by pressure depletion.
|
43792
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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). The Garn Formation is relatively homogeneous, while the Ile Formation is more heterogeneous. The Spekk Formation has good reservoir properties.
|
4966234
|
25.02.2020
|
28.02.2021
|
|
MORVIN
|
Recovery
|
The field is produced by pressure depletion.
|
4966234
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
MORVIN
|
Status
|
The main challenge on the Morvin field is drillability. The cost-benefit factor of drilling new wells is being compared with well intervention operations to regain production in existing wells.
|
4966234
|
25.02.2020
|
28.02.2021
|
|
MURCHISON
|
Reservoir
|
Murchison produced oil from sandstone of Middle Jurassic age in the Brent Group.
|
43665
|
16.03.2018
|
28.02.2021
|
|
MURCHISON
|
Recovery
|
The field was produced with pressure support from water injection.
|
43665
|
11.04.2017
|
28.02.2021
|
|
MURCHISON
|
Status
|
Production ceased in 2014, and the platform was removed in 2017.
|
43665
|
26.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
MURCHISON
|
Transport
|
The well stream was sent through the Brent Pipeline System to Sullom Voe in the Shetland Islands in the UK.
|
43665
|
25.04.2019
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
NJORD
|
Recovery
|
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
|
11.04.2017
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
NJORD
|
Status
|
Production from the Njord field and its satellite field Hyme was temporarily shut down in 2016 because of Njord A structural integrity issues. To extend the lifetime of the fields, Njord A and Njord Bravo were towed to land for upgrades and modifications. Production from the Njord and Hyme fields is expected to resume in late 2021. The Bauge and Fenja fields are under development and will also be tied to Njord.
|
43751
|
17.02.2021
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
NORDØST FRIGG
|
Recovery
|
The field was produced by pressure depletion.
|
43568
|
11.04.2017
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
NORDØST FRIGG
|
Status
|
The field was shut down in 1993 and the facility was removed in 1996. A production licence comprising the Nordøst Frigg field was awarded in the Awards in Predefined Areas (APA) 2016 licensing round. The redevelopment of the Nordøst Frigg field is planned as a subsea development. It is being considered as part of a larger development in the area between the Oseberg and Alvheim fields.
|
43568
|
25.04.2019
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
NORNE
|
Recovery
|
The field is produced by water injection as the drive mechanism. Gas injection ceased in 2005 and all gas is exported.
|
43778
|
11.04.2017
|
28.02.2021
|
|
NORNE
|
Transport
|
The oil is loaded onto 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
|
16.03.2018
|
28.02.2021
|
|
NORNE
|
Status
|
A lifetime extension granted for the Norne FPSO in 2018 will increase value creation from the Norne field and its satellites. Blowdown of the gas cap in the Not Formation was started in 2019. One new production well was drilled in the Ile Formation in 2020.
|
43778
|
17.02.2021
|
28.02.2021
|
|
NOVA
|
Recovery strategy
|
The field will be produced by pressure support from water injection and with gas lift.
|
33197696
|
18.02.2020
|
28.02.2021
|
|
NOVA
|
Transport
|
The well stream will be routed to the Gjøa platform for processing and export. The oil will be transported further through the Troll Oil Pipeline II to the Mongstad terminal, and the gas will be exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus in the UK.
|
33197696
|
18.02.2020
|
28.02.2021
|
|
NOVA
|
Reservoir
|
The reservoir contains oil with a gas cap in sandstone of Late Jurassic age in the Heather Formation in the Viking Group, at a depth of 2,500 metres. The reservoir quality is good.
|
33197696
|
02.02.2021
|
28.02.2021
|
|
NOVA
|
Status
|
Production is scheduled to start in early 2022.
|
33197696
|
02.02.2021
|
28.02.2021
|
|
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 planned 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
|
26.02.2020
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
ODA
|
Recovery strategy
|
The field is produced by pressure support from water injection.
|
29412516
|
17.02.2021
|
28.02.2021
|
|
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
|
27.02.2020
|
28.02.2021
|
|
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. Drilling of a sidetrack from one of the production wells is being evaluated.
|
29412516
|
17.02.2021
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
ODIN
|
Recovery
|
The field was produced by pressure depletion. The reservoir had limited water drive compared with the other fields in the Frigg area.
|
43610
|
11.04.2017
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
ODIN
|
Status
|
The field was shut down in 1994 and the facility removed in 1996/1997. A production licence comprising the Odin field was awarded in the Awards in Predefined Areas (APA) 2016 licensing round. The redevelopment of the Odin field is planned as a subsea development. It is being considered as part of a larger development in the area between the Oseberg and Alvheim fields.
|
43610
|
11.02.2020
|
28.02.2021
|
|
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.
|
2762452
|
25.02.2020
|
28.02.2021
|
|
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
|
27.02.2020
|
28.02.2021
|
|
ORMEN LANGE
|
Recovery
|
The field is produced by pressure depletion.
|
2762452
|
16.03.2018
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
ORMEN LANGE
|
Status
|
Ormen Lange production has gone off plateau and is declining. Reservoir monitoring is a key focus, and a new 4D seismic survey was acquired in 2019. Work is ongoing to increase recovery from the field. Land-based gas compression at the Nyhamna terminal started operation in 2017, and work is ongoing to implement subsea compression. The exploration potential near the field is being evaluated.
|
2762452
|
25.02.2020
|
28.02.2021
|
|
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. The Oseberg Øst, Oseberg Sør and Tune fields are tied to the Oseberg Field Centre.
|
43625
|
14.02.2020
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
OSEBERG
|
Recovery
|
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) and Oseberg Vest. Gas blowdown has gradually started in main parts of the field, while other parts are maintaining injection.
|
43625
|
25.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
OSEBERG
|
Status
|
The strategy for the main Oseberg reservoirs is to balance oil production with increasing gas offtake. New production and injection wells are continuously being drilled to enhance oil recovery.
|
43625
|
25.02.2020
|
28.02.2021
|
|
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.
|
43645
|
14.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
OSEBERG SØR
|
Recovery
|
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
|
16.03.2018
|
28.02.2021
|
|
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 Oseberg Gas Transport (OGT), either to Statpipe or Vesterled.
|
43645
|
16.03.2018
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
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 in the area 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
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
OSEBERG ØST
|
Recovery
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
29.11.2016
|
28.02.2021
|
|
OSEBERG ØST
|
Status
|
To increase production, work on the field focuseson the drainage strategy, including optimisation of injection, infill drilling and well interventions. A lifetime extension of the Oseberg Øst facility was approved in 2018.
|
43639
|
25.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
OSELVAR
|
Recovery
|
The field was produced by pressure depletion.
|
5506919
|
25.04.2019
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
OSELVAR
|
Status
|
The field was shut down in 2018. According to the formal disposal resolution, decommissioning must be completed by the end of 2022.
|
5506919
|
11.02.2020
|
28.02.2021
|
|
REV
|
Status
|
The estimated volumes have been reduced since the PDO. A negative pressure development starting from 2012 resulted in cessation of regular production in 2013. It has, however, been possible to produce the wells with very short production periods and long pressure build-up periods. It is expected that cyclic production will continue until decommissioning begins. According to the formal removal resolution, decommissioning must be completed by the end of 2023.
|
4467554
|
25.02.2020
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
REV
|
Recovery
|
The field is produced by pressure depletion.
|
4467554
|
25.04.2019
|
28.02.2021
|
|
REV
|
Transport
|
The well stream is routed through a 10-kilometre pipeline to the Armada field in the UK sector and further to the Teeside terminal for final processing. The condensate is sold as stabilised crude oil.
|
4467554
|
25.04.2019
|
28.02.2021
|
|
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
|
25.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
RINGHORNE ØST
|
Recovery
|
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
|
11.04.2017
|
28.02.2021
|
|
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
|
27.02.2020
|
28.02.2021
|
|
RINGHORNE ØST
|
Status
|
The field is in the tail 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 submitted in 2019. Field lifetime will be prolonged, and production can benefit from increased capacity in the area.
|
3505505
|
04.02.2021
|
28.02.2021
|
|
SIGYN
|
Status
|
The Sigyn field is in the tail phase, but production has been higher than expected. In 2017, a lifetime extension was granted until 2022. Gas injection is being evaluated in Sigyn West and Sigyn East to increase recovery.
|
1630100
|
25.04.2019
|
28.02.2021
|
|
SIGYN
|
Transport
|
The well stream is controlled from Sleipner Øst and is sent through two pipelines to the Sleipner A facility. Sales gas is exported from Sleipner A via Gassled (Area D) to the market, while unstable condensate is transported in a dedicated pipeline to the Kårstø terminal.
|
1630100
|
25.04.2019
|
28.02.2021
|
|
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 subsea template tied-back to Sleipner Øst. Production started in 2002.
|
1630100
|
14.02.2020
|
28.02.2021
|
|
SIGYN
|
Reservoir
|
The Sigyn field is in the late tail production phase. Production is cyclic and limited by capacity available at Sleipner A and decreasing reservoir pressure. Gas injection to increase recovery is being evaluated.
|
1630100
|
26.02.2020
|
28.02.2021
|
|
SIGYN
|
Recovery
|
The field is produced by pressure depletion.
|
1630100
|
11.04.2017
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
SINDRE
|
Recovery strategy
|
The field is produced by pressure depletion, but rapid pressure decline may necessitate pressure support.
|
29401178
|
14.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
SINDRE
|
Status
|
Due to pressure decline and low production, the well is temporarily shut in. There are no remaining recoverable resources in Sindre, and the focus is on developing resources in nearby deposits. New drainage strategies for the Sindre area are being evaluated.
|
29401178
|
26.02.2020
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
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 and Idun deposits. The development concept is a production, storage and offloading vessel (FPSO) with five subsea templates with fifteen wells. Production started in 2013. The Ærfugl field is being developed as a tie-in to the Skarv FPSO.
|
4704482
|
14.02.2020
|
28.02.2021
|
|
SKARV
|
Reservoir
|
Skarv produces gas and oil from Lower and Middle Jurassic sandstone in the Tilje, Ile and Garn Formations. There are also underlying oil zones in the Tilje 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
|
25.04.2019
|
28.02.2021
|
|
SKARV
|
Recovery
|
The field is produced with pressure support by gas injection and gas lift.
|
4704482
|
25.04.2019
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
SKARV
|
Status
|
Skarv oil production is declining, and gas injection is important for increased oil recovery. Optimal timing of gas blowdown is continuously being evaluated, and work is ongoing to evaluate the potential of infill wells and prospects in the area.
|
4704482
|
26.02.2020
|
28.02.2021
|
|
SKIRNE
|
Status
|
The field is now in the tail phase. The Byggve reservoir is flooded by formation water, and there is no more recoverable gas. Skirne production is optimised by maintaining a low inlet pressure on the Heimdal facility. Skirne can potentially produce as long as the Heimdal facility is available. A decommissioning plan for Skirne and Atla was already submitted in 2015.
|
2138816
|
26.02.2020
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
SKIRNE
|
Recovery
|
The field is produced by pressure depletion.
|
2138816
|
11.04.2017
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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.
|
31164600
|
26.02.2020
|
28.02.2021
|
|
SKOGUL
|
Reservoir
|
The reservoir contains oil with a minor gas cap in sandstone of Eocene age. It lies at a depth of 2,100 metres and has excellent properties.
|
31164600
|
26.02.2020
|
28.02.2021
|
|
SKOGUL
|
Recovery strategy
|
Skogul is produced by depletion and natural aquifer support.
|
31164600
|
28.03.2020
|
28.02.2021
|
|
SKOGUL
|
Transport
|
The well stream from Skogul is routed by pipeline via the Vilje field to the Alvheim FPSO.
|
31164600
|
28.03.2020
|
28.02.2021
|
|
SKOGUL
|
Status
|
Production from Skogul started in March 2020.
|
31164600
|
28.03.2020
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
SKULD
|
Recovery
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
SKULD
|
Status
|
Recoverable volume estimates were reduced compared to the PDO. Low productivity and increasing water cut are the main challenges. Focus is now on reservoir management and identification of the remaining potential of the field.
|
21350124
|
26.02.2020
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
SLEIPNER VEST
|
Reservoir
|
Sleipner Vest produces gas and condensate from Middle Jurassic sandstone in the Hugin and Sleipner Formations; most of the reserves are found in the Hugin 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
|
25.04.2019
|
28.02.2021
|
|
SLEIPNER VEST
|
Recovery
|
The field is produced by pressure depletion.
|
43457
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
SLEIPNER VEST
|
Status
|
Production is in the tail phase, but infill drilling and sidetracking of existing wells are being evaluated to reduce the production decline. The exploration potential near the field is being evaluated.
|
43457
|
27.02.2020
|
28.02.2021
|
|
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 tied-back to the Sleipner T with an 18-kilometre pipeline. 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
|
26.02.2020
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
SLEIPNER ØST
|
Recovery
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
SLEIPNER ØST
|
Status
|
Production is in the late tail phase. Work is ongoing to decrease the decline rate. Increased sand and water production due to pressure depletion of the reservoir is a challenge. CO2 injection in the Hugin reservoir is being evaluated to increase recovery. The exploration potential in the area and tie-in of nearby discoveries are being evaluated. It is planned that the facilities will be operated with power from shore starting in 2022, as part of the electrification of the Utsira High area.
|
43478
|
26.02.2020
|
28.02.2021
|
|
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, and Snorre UPA, located centrally on the field. Snorre A is a floating tension-leg platform for accommodation, drilling and processing. Snorre UPA is a subsea production facility tied-back to Snorre A. 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. In 1998, a PDO was approved for Snorre B, a semi-submersible integrated drilling, processing and accommodation facility located in the northern part of the field. Snorre B started production in 2001. In 2018, an amended PDO for the Snorre Expansion Project was approved. It includes six subsea templates, each with four wells tied-back to Snorre A. Production started in December 2020. In 2020, an amended PDO for the development of the Hywind Tampen wind farm was approved. The wind farm will consist of 11 floating turbines which will supply electricity to the Snorre and Gullfaks fields. The Snorre and Gullfaks platforms will be the first platforms in the world to receive power from a floating wind farm.
|
43718
|
17.02.2021
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
SNORRE
|
Recovery
|
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. Additional gas will be imported from Gullfaks for pressure support and improved reservoir drainage.
|
43718
|
17.02.2021
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
SNORRE
|
Status
|
Technical failure of a riser on the Snorre B platform resulted in reduced production in 2020. After retermination or replacement of all injection risers on Snorre B, production and injection have been reestablished. Several measures to increase oil recovery from Snorre are being considered. Requests from possible third party tie-ins may also lead to further development of the field. The Hywind Tampen wind farm is scheduled for start-up at the end of 2022.
|
43718
|
17.02.2021
|
28.02.2021
|
|
SNØHVIT
|
Status
|
Snøhvit production is in the 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.
|
2053062
|
17.02.2021
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
SNØHVIT
|
Recovery
|
The field is produced by pressure depletion.
|
2053062
|
16.03.2018
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
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 will be developed with five single wells, tied-back to the Edvard Grieg field.
|
34833011
|
26.02.2020
|
28.02.2021
|
|
SOLVEIG
|
Reservoir
|
Solveig will produce oil from sandstone and conglomerate of Permian and Triassic 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
|
29.11.2019
|
28.02.2021
|
|
SOLVEIG
|
Recovery strategy
|
The field will be produced by pressure support from water injection.
|
34833011
|
05.09.2019
|
28.02.2021
|
|
SOLVEIG
|
Transport
|
The well stream will be transported via the Edvard Grieg field and onward by pipeline to the Sture terminal. The gas will be exported via the Scottish Area Gas Evacuation (SAGE) infrastructure to the St Fergus terminal in the UK.
|
34833011
|
05.09.2019
|
28.02.2021
|
|
SOLVEIG
|
Status
|
The field is under development, and production is scheduled to start in 2021.
|
34833011
|
02.02.2021
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
STATFJORD
|
Recovery
|
The field was originally produced by pressure support from water alternating gas injection (WAG), water injection and partial 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
|
16.03.2018
|
28.02.2021
|
|
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
|
11.04.2017
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
STATFJORD NORD
|
Recovery
|
The field is produced with pressure maintenance from water injection.
|
43679
|
16.03.2018
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
STATFJORD NORD
|
Status
|
No new wells have been drilled since 2016, but a well intervention was performed in 2019 to increase oil rates and reduce water cut. New wells are possible because of a lifetime extension of the Statfjord C facility.
|
43679
|
26.02.2020
|
28.02.2021
|
|
STATFJORD ØST
|
Status
|
The field is affected by pressure depletion due to depressurisation of the Statfjord field. Current production is mainly from the one well with gas lift, drilled from Statfjord C. New wells and projects are possible because of a lifetime extension of the Statfjord C facility.
|
43672
|
26.02.2020
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
STATFJORD ØST
|
Recovery
|
The field was originally produced with water injection, but is now produced by pressure depletion and with gas lift in one well.
|
43672
|
14.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
SVALIN
|
Recovery
|
The field is produced by pressure depletion and with pressure support from a regional aquifer.
|
22507971
|
16.03.2018
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
SVALIN
|
Status
|
Production has so far been lower than anticipated in the PDO. There are currently no plans to drill more wells on Svalin.
|
22507971
|
26.02.2020
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
SYGNA
|
Recovery
|
The field is produced by pressure maintenance from water injection.
|
104718
|
16.03.2018
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
SYGNA
|
Status
|
Production from Sygna is stable, and the strategy is to keep reservoir pressure constant by water injection.
|
104718
|
26.02.2020
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
TAMBAR
|
Recovery
|
The field is produced by pressure depletion, with natural gas expansion combined with aquifer support. Gas lift is used to improve production performance.
|
1028599
|
17.02.2021
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
TAMBAR
|
Status
|
Production is steadily declining due to decreased reservoir pressure and increased water cut. A side-track from one of the existing wells is planned to be drilled in 2021. Studies are ongoing to evaluate water and/or gas injection to increase production.
|
1028599
|
17.02.2021
|
28.02.2021
|
|
TAMBAR ØST
|
Status
|
Production from Tambar Øst is temporarily shut down. There will be no production from the field until Tambar pipeline pressure (backpressure) is reduced to acceptable levels.
|
4999528
|
25.04.2019
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
TAMBAR ØST
|
Recovery
|
The field is produced by pressure depletion and limited aquifer drive.
|
4999528
|
11.04.2017
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
02.02.2021
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
TOMMELITEN GAMMA
|
Recovery
|
The field was produced by pressure depletion.
|
43444
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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 developed with a combined wellhead and processing facility tied-back to the Ekofisk field, and started producing in 1978. Tor was shut down in 2015, and the facility will be removed by the end of 2022. In November 2019, a new PDO for the redevelopment of the field was approved. The plan includes two subsea templates with eight horizontal production wells, tied-back to the Ekofisk Centre.
|
43520
|
18.02.2020
|
28.02.2021
|
|
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
|
25.11.2019
|
28.02.2021
|
|
TOR
|
Recovery
|
The field is produced by natural pressure depletion.
|
43520
|
05.12.2020
|
28.02.2021
|
|
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
|
05.12.2020
|
28.02.2021
|
|
TOR
|
Status
|
Production started again in December 2020.
|
43520
|
05.12.2020
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
TORDIS
|
Recovery
|
The field is produced by pressure support from water injection and by natural aquifer drive.
|
43725
|
17.02.2021
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
TORDIS
|
Status
|
Production is maintained through pressure support and well interventions. A production well drilled on Tordis in 2020, and a new well planned for 2021, will contribute to increased production. New 4D-seismic data to be acquired in 2021 will be used to map further infill drilling targets.
|
43725
|
17.02.2021
|
28.02.2021
|
|
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.
|
29396445
|
30.08.2019
|
28.02.2021
|
|
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
|
14.02.2020
|
28.02.2021
|
|
TRESTAKK
|
Recovery strategy
|
The Field is produced by gas injection.
|
29396445
|
30.08.2019
|
28.02.2021
|
|
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
|
30.08.2019
|
28.02.2021
|
|
TRESTAKK
|
Status
|
Production from Trestakk started in July 2019.
|
29396445
|
30.08.2019
|
28.02.2021
|
|
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 only 2 to 4 metres thickness. A significant volume of residual oil is encountered directly below the Troll Vest oil column. There is a minor oil discovery in the Middle Jurassic Brent Group, below the main oil reservoir.
|
46437
|
14.02.2020
|
28.02.2021
|
|
TROLL
|
Recovery
|
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 to increase oil production. Produced water was reinjected into the northern part of the Troll Vest oil province from 2000 to 2016.
|
46437
|
25.04.2019
|
28.02.2021
|
|
TROLL
|
Status
|
About 270 production wells, more than 570 sidetracks and more than two million reservoir metres have been drilled on Troll. There are currently three drilling rigs 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. Troll Phase III is under development and production is expected to start in 2021.
|
46437
|
17.02.2021
|
28.02.2021
|
|
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
|
11.04.2017
|
28.02.2021
|
|
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. In 2018, an amended PDO was approved to increase gas offtake from Troll Vest, Troll Phase III.
|
46437
|
17.02.2021
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
TROLL BRENT B
|
Recovery strategy
|
The field was planned to be produced by pressure depletion.
|
29398828
|
16.03.2018
|
28.02.2021
|
|
TROLL BRENT B
|
Transport
|
There was no production from Troll Brent B.
|
29398828
|
16.03.2018
|
28.02.2021
|
|
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
|
11.02.2020
|
28.02.2021
|
|
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 2022, once the Tyra project is completed.
|
18081500
|
26.02.2020
|
28.02.2021
|
|
TRYM
|
Transport
|
The well stream is processed on the Harald facility for further transport through the Danish pipeline system via the Tyra field.
|
18081500
|
16.03.2018
|
28.02.2021
|
|
TRYM
|
Recovery
|
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
|
16.03.2018
|
28.02.2021
|
|
TRYM
|
Reservoir
|
Trym produces gas and condensate from Middle and Upper Jurassic sandstone in the Bryne and Sandnes Formations. The reservoir is in the same salt structure as the Danish field Lulita. The deposits are presumably separated by a fault zone on the Norwegian side of the border, but there may be pressure communication in the water zone. The reservoir lies at a depth of 3,400 metres and has good quality.
|
18081500
|
25.04.2019
|
28.02.2021
|
|
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
|
18.02.2020
|
28.02.2021
|
|
TUNE
|
Status
|
Tune is in the tail production phase and produces cyclically. Due to technical issues, there has been longer periods with no production from the Field.
|
853376
|
04.02.2021
|
28.02.2021
|
|
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
|
18.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
TUNE
|
Recovery
|
The field is produced by pressure depletion. Low-pressure production has been implemented.
|
853376
|
11.04.2017
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
TYRIHANS
|
Recovery
|
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
|
17.02.2021
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
TYRIHANS
|
Status
|
The total oil production from Tyrihans, including important contributions from infill wells that have been drilled, is well above the PDO estimates. Total 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 gas production well with an exploration extension to the Ile Formation is planned to be drilled on Tyrihans Nord in 2021.
|
3960848
|
17.02.2021
|
28.02.2021
|
|
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
|
18.02.2020
|
28.02.2021
|
|
ULA
|
Reservoir
|
Ula produces oil mainly from sandstone in the Upper Jurassic Ula Formation. The reservoir lies at a depth of 3345 metres. It consists of three units, and two of them are producing well. 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
|
17.02.2021
|
28.02.2021
|
|
ULA
|
Recovery
|
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
|
17.02.2021
|
28.02.2021
|
|
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
|
11.04.2017
|
28.02.2021
|
|
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.
|
43800
|
17.02.2021
|
28.02.2021
|
|
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
|
18.02.2020
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
URD
|
Recovery
|
The field is produced by water injection and gas lift.
|
2834734
|
18.02.2020
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
URD
|
Status
|
Production performance has been close to expectation. Challenges for Urd are the structural complexity of the field, as well as poor pressure support and high water cut. Both production and injection wells have problems with slugging and sand control. There is currently no production or injection on Stær. New well targets are being evaluated.
|
2834734
|
26.02.2020
|
28.02.2021
|
|
UTGARD
|
Development
|
Utgard is a field in the North Sea, straddling the sector 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.
|
28975098
|
26.02.2020
|
28.02.2021
|
|
UTGARD
|
Reservoir
|
Utgard produces gas with high CO2 content and condensate from sandstone of Middle Jurassic age in the Hugin Formation. The reservoir possibly has a thin oil zone. The reservoir lies at a depth of 3,700 metres and has good quality.
|
28975098
|
26.02.2020
|
28.02.2021
|
|
UTGARD
|
Recovery strategy
|
Utgard is produced by pressure depletion.
|
28975098
|
24.09.2019
|
28.02.2021
|
|
UTGARD
|
Transport
|
The well stream from the Utgard field is processed at the Sleipner T facility. The gas is exported to the Gassled pipeline system. Unstable condensate is transported via the existing condensate pipeline to the Kårstø terminal for further processing and export.
|
28975098
|
18.02.2020
|
28.02.2021
|
|
UTGARD
|
Status
|
Production from Utgard started in September 2019.
|
28975098
|
18.02.2020
|
28.02.2021
|
|
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 October 2019. Vale can potentially produce as long as the Heimdal facility is available.
|
1578893
|
26.02.2020
|
28.02.2021
|
|
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
|
18.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
VALE
|
Recovery
|
The field is produced by pressure depletion.
|
1578893
|
11.04.2017
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
18.02.2020
|
28.02.2021
|
|
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
|
18.02.2020
|
28.02.2021
|
|
VALEMON
|
Recovery
|
The field is produced by pressure depletion.
|
20460969
|
16.03.2018
|
28.02.2021
|
|
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
|
18.02.2020
|
28.02.2021
|
|
VALEMON
|
Status
|
Due to production experience and rapid pressure decline in the reservoirs, [TA1] the estimated recoverable volumes have been significantly reduced since the PDO. No new wells have been drilled since 2018. However, new drilling targets have been identified after the acquisition of a new 4D seismic survey. Permanent rerouting of the gas export via Kvitebjørn is planned from late 2021.
|
20460969
|
26.02.2020
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
VALHALL
|
Recovery
|
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
|
11.04.2017
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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. Several wells were drilled in 2020, and drilling will continue in the foreseeable future. Decommissioning plans were submitted in 2019 for the QP, PCP and DP facilities. Plugging and abandonment of the wells is ongoing on the DP facility.
|
43548
|
17.02.2021
|
28.02.2021
|
|
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
|
11.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
VARG
|
Recovery
|
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
|
11.04.2017
|
28.02.2021
|
|
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
|
11.04.2017
|
28.02.2021
|
|
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
|
02.02.2021
|
28.02.2021
|
|
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 six production wells have been drilled. Production started in 2010.
|
4467595
|
18.02.2020
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
VEGA
|
Recovery
|
The field is produced by pressure depletion.
|
4467595
|
11.04.2017
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
VEGA
|
Status
|
Vega production is currently limited by the gas production capacity rights at Gjøa. It is planned to drill three new production wells on Vega Sentral and Vega Sør in 2021/2022.
|
4467595
|
17.02.2021
|
28.02.2021
|
|
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 is 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
|
18.02.2020
|
28.02.2021
|
|
VESLEFRIKK
|
Reservoir
|
Veslefrikk produces oil and some gas from Jurassic sandstone in the Statfjord, Dunlin and Brent Groups. The main reservoir is in the Brent Group and contained originally about 80 per cent of the reserves. The reservoir depths are between 2800 and 3200 metres, and the quality varies from moderate to excellent.
|
43618
|
17.02.2021
|
28.02.2021
|
|
VESLEFRIKK
|
Recovery
|
Veslefrikk has 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. Injection has ceased and the field is now being produced by depletion until shut-in.
|
43618
|
17.02.2021
|
28.02.2021
|
|
VESLEFRIKK
|
Transport
|
Oil is exported via the Oseberg Transport System (OTS) to the Sture terminal. Gas is exported through Statpipe to the terminal at Kårstø.
|
43618
|
17.02.2021
|
28.02.2021
|
|
VESLEFRIKK
|
Status
|
Veslefrikk production is maintained at a low rate. Well interventions and high production efficiency have contributed to a prolonged lifetime. A decommissioning plan was submitted in 2020 and plugging and abandonment of the wells is ongoing.
|
43618
|
17.02.2021
|
28.02.2021
|
|
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
|
02.02.2021
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
VEST EKOFISK
|
Recovery
|
The field was produced by pressure depletion.
|
43513
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
VIGDIS
|
Status
|
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 production wells were drilled in 2020, and the exploration well 34/7-E-4 AH proved the Lomre discovery. More infill wells are planned for the coming years. 4D-seismic data to be acquired in 2021 may result in additional drilling targets.
|
43732
|
17.02.2021
|
28.02.2021
|
|
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.
|
43732
|
18.02.2020
|
28.02.2021
|
|
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
|
17.02.2021
|
28.02.2021
|
|
VIGDIS
|
Recovery
|
The field is produced by pressure support using water injection. Some of the reservoirs are affected by pressure depletion on the Statfjord field.
|
43732
|
16.03.2018
|
28.02.2021
|
|
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
|
18.02.2020
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
VILJE
|
Recovery
|
The field is produced by natural water drive from the regional underlying Heimdal aquifer.
|
3392471
|
16.03.2018
|
28.02.2021
|
|
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
|
27.02.2020
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
VISUND
|
Recovery
|
Recovery strategy varies between the reservoirs at Visund. Oil in the Brent reservoirs is mainly produced by pressure maintenance from gas and water injection. The Statfjord reservoirs are partly produced by pressure depletion. Increased gas export since 2015 has reduced gas available for injection and reduced reservoir pressure in parts of the field.
|
43745
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
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 pilots. A new oil discovery was made on the east flank of Visund in 2019.
|
43745
|
26.02.2020
|
28.02.2021
|
|
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
|
18.02.2020
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
VISUND SØR
|
Recovery
|
The field is produced by pressure depletion.
|
20461008
|
16.03.2018
|
28.02.2021
|
|
VISUND SØR
|
Transport
|
The well stream is transported to Gullfaks C for processing and export.
|
20461008
|
16.03.2018
|
28.02.2021
|
|
VISUND SØR
|
Status
|
Production has been shut down due to low reservoir presser and high water cut ratio.
|
20461008
|
06.02.2021
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
VOLUND
|
Recovery
|
The field is produced with significant pressure support from the aquifer and with injection of produced water delivered from the Alvheim FPSO.
|
4380167
|
16.03.2018
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
VOLUND
|
Status
|
Additional wells drilled on the Volund field in 2017 and 2019 have resulted in significantly increased production. Water cut on the field is increasing.
|
4380167
|
26.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
VOLVE
|
Recovery
|
The field was produced with water injection for pressure support.
|
3420717
|
16.03.2018
|
28.02.2021
|
|
VOLVE
|
Transport
|
The oil was exported by tankers and the rich gas was transported to the Sleipner A facility for further export.
|
3420717
|
16.03.2018
|
28.02.2021
|
|
VOLVE
|
Status
|
The field was shut down in 2016 and the facility was removed in 2018.
|
3420717
|
11.02.2020
|
28.02.2021
|
|
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 March 2018, an amended PDO for the redevelopment of Yme was approved. The PDO includes a leased jack-up rig equipped with drilling and production facilities, a subsea template on the Beta structure, and reuse of existing facilities on the field. The plan is to reuse the nine wells pre-drilled in 2009-2010 and to drill seven additional wells.
|
43807
|
26.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
YME
|
Recovery
|
The field will be produced by pressure support from partial water injection and water alternating gas (WAG) injection.
|
43807
|
25.04.2019
|
28.02.2021
|
|
YME
|
Transport
|
The oil will be transported with tankers and the gas will be reinjected.
|
43807
|
25.04.2019
|
28.02.2021
|
|
YME
|
Status
|
The field is under redevelopment.
|
43807
|
09.07.2020
|
28.02.2021
|
|
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
|
11.02.2020
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
YTTERGRYTA
|
Recovery
|
The field was produced by pressure depletion.
|
4973114
|
11.04.2017
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
11.02.2020
|
28.02.2021
|
|
ÆRFUGL
|
Development
|
Ærfugl 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 was discovered in 2000, and the plan for development and operation (PDO) was approved in 2018. The development is planned to be completed in two phases, and includes a total of six new production wells in addition to the existing well, previously used for test production of the Ærfugl discovery. Ærfugl is tied to the Skarv production, storage and offloading vessel (FPSO).
|
33310197
|
19.02.2021
|
28.02.2021
|
|
ÆRFUGL
|
Reservoir
|
The reservoirs contain gas and condensate in sandstone of Cretaceous age in the Lysing Formation. They have good properties and lie at a depth of 2800 metres.
|
33310197
|
17.02.2021
|
28.02.2021
|
|
ÆRFUGL
|
Recovery strategy
|
The field is produced by depletion.
|
33310197
|
08.05.2020
|
28.02.2021
|
|
ÆRFUGL
|
Transport
|
The well stream is transported to the Skarv FPSO for processing. 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).
|
33310197
|
08.05.2020
|
28.02.2021
|
|
ÆRFUGL
|
Status
|
The field is under development. Test production has been ongoing since 2013. Production from the first of three wells in the second development phase was accelerated and started in April 2020. Production from the three wells in the first development phase started in November 2020. Production from the two remaining wells in the second phase is planned to start in late 2021. The northernmost of these production wells will produce the Ærfugl Nord field.
|
33310197
|
20.02.2021
|
28.02.2021
|
|
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
|
20.02.2021
|
28.02.2021
|
|
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
|
20.02.2021
|
28.02.2021
|
|
ÆRFUGL NORD
|
Recovery strategy
|
The field will be produced by depletion.
|
38542241
|
20.02.2021
|
28.02.2021
|
|
ÆRFUGL NORD
|
Transport
|
The well stream will be transported to the Skarv FPSO for processing. The condensate will be offloaded to shuttle tankers, while the gas will be transported to the Kårstø terminal in an 80-kilometre pipeline connected to the Åsgard Transport System (ÅTS).
|
38542241
|
20.02.2021
|
28.02.2021
|
|
ÆRFUGL NORD
|
Status
|
The field is under development. Production is planned to start in late 2021.
|
38542241
|
20.02.2021
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
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
|
25.04.2019
|
28.02.2021
|
|
ØST FRIGG
|
Recovery
|
The field was produced by pressure depletion.
|
43576
|
16.03.2018
|
28.02.2021
|
|
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
|
16.03.2018
|
28.02.2021
|
|
ØST FRIGG
|
Status
|
Production was shut down in 1997 and the subsea templates were removed in 2001.
|
43576
|
25.04.2019
|
28.02.2021
|
|
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
|
26.02.2020
|
28.02.2021
|
|
ÅSGARD
|
Reservoir
|
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.
|
43765
|
17.02.2021
|
28.02.2021
|
|
ÅSGARD
|
Recovery
|
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
|
11.04.2017
|
28.02.2021
|
|
ÅSGARD
|
Transport
|
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.
|
43765
|
27.02.2020
|
28.02.2021
|
|
ÅSGARD
|
Status
|
Work is ongoing to increase the recovery from the field. Conversion of gas injection wells to gas production wells at Smørbukk is ongoing, and it is possible to switch between injection and production. This maintains gas injection in Smørbukk and Smørbukk Sør, and gas export volumes from the Åsgard field. Third party tie-ins to Åsgard will prolong the lifetime of the facilities.
|
43765
|
17.02.2021
|
28.02.2021
|
|
AASTA HANSTEEN
|
Development
|
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.
|
23395946
|
26.02.2020
|
28.02.2021
|
|
AASTA HANSTEEN
|
Reservoir
|
The main reservoirs contain gas in Upper Cretaceous sandstone in the Nise Formation, at a depth of 3000 metres. The reservoir quality is good.
|
23395946
|
17.02.2021
|
28.02.2021
|
|
AASTA HANSTEEN
|
Recovery
|
The field is produced by pressure depletion and natural aquifer drive.
|
23395946
|
25.04.2019
|
28.02.2021
|
|
AASTA HANSTEEN
|
Transport
|
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.
|
23395946
|
27.02.2020
|
28.02.2021
|
|
AASTA HANSTEEN
|
Status
|
Production from Snefrid Nord started in 2019. Aasta Hansteen is considered a possible host for nearby discoveries after the field goes off plateau production. The Asterix discovery is currently being matured as a tie-in development to Aasta Hansteen.
|
23395946
|
17.02.2021
|
28.02.2021
|