The Tolmount Field, Block 42/28d, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 262-272 ◽  
Author(s):  
A. Miles ◽  
M. Allen ◽  
L. Fairweather ◽  
J. Hilton ◽  
H. Sloan ◽  
...  
Keyword(s):  
North Sea ◽  
Burial History ◽  
Reservoir Properties ◽  
Water Contact ◽  
Diagenetic Alteration ◽  
Reservoir Sandstones ◽  
Sandstone Formation ◽  
The Uk ◽  
Continental Basin ◽  
Gas Bearing

AbstractThe Tolmount Field is a lean gas condensate accumulation located in Block 42/28d of the UK Southern North Sea. The field was discovered in 2011 by well 42/28d-12, which encountered good-quality gas-bearing reservoir sandstones of the Permian Leman Sandstone Formation. The discovery was appraised in 2013 by wells 42/28d-13 and 42/28d-13Z, which logged the gas–water contact on the eastern flank of the field. The Tolmount structure is a four-way, dip-closed, faulted anticline, orientated NW to SE. The reservoir comprises mixed aeolian dune and fluvial sheetflood facies deposited within an arid continental basin. Dune sands display the best reservoir properties with porosities around 22% and permeabilities exceeding 100 mD. Only minor diagenetic alteration has occurred, primarily in the form of grain-coating illite. Superior reservoir quality is observed at Tolmount compared to adjacent areas, due to the preservation of dune facies, a hypothesized early gas emplacement and a relatively benign burial history. Current mapped gas initially-in-place estimates for the field are between 450 bcf and 800 bcf, with an estimated recovery factor between 70 and 90%. An initial four-well development is planned, with first gas expected in 2020.

scholarly journals Diagenesis influencing the porosity of Upper Jurassic reservoir sandstones, Danish North Sea

2008 ◽  
Vol 15 ◽  
pp. 9-12 ◽  
Author(s):  
Rikke Weibel ◽  
Nynke Keulen
Keyword(s):  
North Sea ◽  
Source Area ◽  
Upper Jurassic ◽  
Burial History ◽  
Reservoir Properties ◽  
Thin Sections ◽  
The North ◽  
Diagenetic Alteration ◽  
The North Sea ◽  
Reservoir Sandstones

Upper Jurassic quartz-rich sandstones in the North Sea Basin are important reservoir rocks for oil and gas, and one of the latest discoveries of oil in the Danish sector was made in the area of the Hejre wells that penetrated such sediments (Fig. 1). The reservoir properties of sandstones are strongly influenced by diagenetic alteration, i.e. the mineralogical changes that take place during burial of the sediments. The diagenetic features depend on the source area, depositional setting, facies architecture and burial history of the sediment. The major diagenetic features influencing porosity in Upper Jurassic reservoir sandstones are feldspar dissolution and precipitation, preci-pitation of illite, calcite and quartz, and quartz stylolite formation. With regard to the Upper Jurassic sandstones in the Danish sector of the North Sea, the important question is: how can porosity be preserved in sediments buried at depths of more than 5 km? The Hejre-2 well penetrated the Upper Jurassic sediments (Fig. 2) before reaching pre-Upper Jurassic volcaniclastic conglomerates. The diagenetic features were studied in thin sections of core samples with traditional petrographic techniques using transmitted light microscopy supplemented by scanning electron microscopy (SEM) of rock chips and thin sections.

The Cygnus Field, Blocks 44/11a and 44/12a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 151-162 ◽  
Author(s):  
Ian Dredge ◽  
Gary Marsden
Keyword(s):  
North Sea ◽  
Horizontal Wells ◽  
Third Party ◽  
Production Well ◽  
Field Development ◽  
Fault Block ◽  
Main Fault ◽  
Sandstone Formation ◽  
The Uk ◽  
Gas Bearing

AbstractThe Cygnus Field is located in Blocks 44/11a and 44/12a of the UK Southern North Sea. The field was first discovered in 1988 as a tight lower Leman Sandstone Formation gas discovery by well 44/12- 1. After the licences had sat idle for several years, GDF Britain (now Neptune E&P UK Ltd) appraised the field from 2006 to 2010. During the appraisal phase, the lower Leman Sandstone was found to be of better quality than first discovered and the gas-bearing lower Ketch Member reservoir was also encountered. The field development was sanctioned in 2012.The field has been developed from two wellhead platforms targeting Leman Sandstone and Ketch Member reservoirs. Five main fault blocks have been developed, with two wells in each fault block planned in the field development plan. The wells are long horizontal wells completed with stand-alone sand screens. At the time of writing, the production plateau is 320 MMscfgd (266 MMscfgd when third-party constraints apply), producing from nine wells with the final production well to be drilled.

The West Sole Field, Block 48/6, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 517-523 ◽  
Author(s):  
D. A. Winter ◽  
B. King
Keyword(s):  
Continental Shelf ◽  
North Sea ◽  
Gas Production ◽  
Permian Basin ◽  
The West ◽  
Depositional Facies ◽  
Reservoir Sandstones ◽  
Sandstone Formation ◽  
The Uk ◽  
Coal Measures

AbstractWest Sole is located in the Sole Pit area of the Southern North Sea Permian Basin in UK Block 48/6. The field was discovered in 1965 and was the first commercial discovery in the UK Continental Shelf. Gas Production commenced in 1967. Initial reserves are 1.873 TCF of which 1.335 TCF had been produced by the end of 1989. Gas is trapped in aeolian sandstones of the Permian Lower Leman Sandstone Formation. Three depositional facies are recognized, comprising aeolian dune, fluvial and sabkha. The aeolian dune facies form the principal reservoir sandstones, in units up to 40 m (131 ft) thick. However, permeability is reduced due to pervasive illite cementation, such that it averages 3 md in the dune sandstones. Productivity is enhanced in the southern part of the field by 'open' gas-filled fractures, generated during the Alpine inversion. The trap was also amplified at this stage and comprises a faulted inversion anticline trending NW-SE. The source rock is the Westphalian Coal Measures, lying directly beneath the reservoir.

The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 691-698
Author(s):  
M. J. Sarginson
Keyword(s):  
North Sea ◽  
Upper Permian ◽  
Lower Permian ◽  
Reservoir Properties ◽  
Gas Field ◽  
Field Development ◽  
Matrix Permeability ◽  
Recoverable Reserves ◽  
Reservoir Permeability ◽  
Sandstone Formation

AbstractThe Clipper Gas Field is a moderate-sized faulted anticlinal trap located in Blocks 48/19a, 48/19c and 48/20a within the Sole Pit area of the southern North Sea Gas Basin. The reservoir is formed by the Lower Permian Leman Sandstone Formation, lying between truncated Westphalian Coal Measures and the Upper Permian evaporitic Zechstein Group which form source and seal respectively. Reservoir permeability is very low, mainly as a result of compaction and diagenesis which accompanied deep burial of the Sole Pit Trough, a sub basin within the main gas basin. The Leman Sandstone Formation is on average about 715 ft thick, laterally heterogeneous and zoned vertically with the best reservoir properties located in the middle of the formation. Porosity is fair with a field average of 11.1%. Matrix permeability, however, is less than one millidarcy on average. Well productivity depends on intersecting open natural fractures or permeable streaks within aeolian dune slipface sandstones. Field development started in 1988. 24 development wells have been drilled to date. Expected recoverable reserves are 753 BCF.

The MacCulloch Field, Block 15/24b, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 453-466 ◽  
Author(s):  
C. Gunn ◽  
J. A. MacLeod ◽  
P. Salvador ◽  
J. Tomkinson
Keyword(s):  
North Sea ◽  
Water Contact ◽  
Northern Flank ◽  
Recoverable Reserves ◽  
Average Porosity ◽  
Oil Water ◽  
The Witch ◽  
The Uk ◽  
Clay Formation ◽  
Central North Sea

AbstractThe MacCulloch Field lies within Block 15/24b in the UK Central North Sea and is located on the northern flank of the Witch Ground Graben. It was discovered by Conoco well 15/24b-3 in 1990.MacCulloch Field is a four-way dip closure at Top Paleocene over a deeper Mesozoic structure. The reservoir consists of Upper Balmoral Sandstones containing 32-37° API oils derived from Kimmeridge Clay Formation shales and sealed by shales belonging to the Sele Formation. The field contains recoverable reserves of 60-90 MMBOE.Reservoir quality is generally very good, with an average porosity of 28% and core permeabilities (Kh) between 200 mD and 2D. AVO anomalies and a seismic flat spot are associated with oil filled reservoir and the oil-water contact in certain areas of the field.

The Hewett Field, Blocks 48/28a, 48/29a, 48/30a, 52/4a and 52/5a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 189-202 ◽  
Author(s):  
J. A. Hook
Keyword(s):  
Fault Zone ◽  
North Sea ◽  
Structural Evolution ◽  
Field Development ◽  
Southern North Sea ◽  
Sandstone Formation ◽  
The Uk ◽  
Basin Margin ◽  
Sour Gas

AbstractThe Hewett Field has been in production for some 50 years. Unusually for a Southern North Sea field in the UK Sector, there has been production from several different reservoirs and almost entirely from intervals younger than the principal Leman Sandstone Formation (LSF) reservoir in the basin. Some of these reservoirs are particular to the Hewett area. This reflects the location of the field at the basin margin bound by the Dowsing Fault Zone, which has influenced structural evolution, deposition and the migration of hydrocarbons. The principal reservoirs are the Permo-Triassic Hewett Sandstone (Lower Bunter), Triassic Bunter Sandstone Formation (BSF) (Upper Bunter) and Permian Zechsteinkalk Formation. There has also been minor production from the Permian Plattendolomit Formation and the LSF. Sour gas is present in the BSF only. Several phases of field development are recognized, ultimately comprising three wellhead platforms with production from 35 wells. Gas is exported onshore to Bacton, where the sour gas was also processed. Peak production was in 1976 and c. 3.5 tcf of gas has been recovered. Hewett has also provided the hub for six satellite fields which have produced a further 0.9 tcf of gas. It is expected that the asset will cease production in 2020.

The Osprey Field, Blocks 211/18a & 211/23a, UK North Sea*

1991 ◽  
Vol 14 (1) ◽  
pp. 183-189 ◽  
Author(s):  
John W. Erickson ◽  
C. D. Van Panhuys
Keyword(s):  
Crude Oil ◽  
North Sea ◽  
Water Depth ◽  
Middle Jurassic ◽  
Reservoir Quality ◽  
Shetland Islands ◽  
Delta System ◽  
Reservoir Sandstones ◽  
Northern North Sea ◽  
The Uk

AbstractThe Osprey Oilfield is located 180 km northeast of the Shetland Islands in Blocks 211/23a and 211/18a in the UK sector of the northern North Sea. The discovery well 211/23-3 was drilled in January 1974 in a water depth of 530 ft. The trap is defined at around 8500 ft TVSS by two dip and fault closed structures, the main 'Horst Block' and the satellite 'Western Pool'. The hydrocarbons are contained in reservoir sandstones belonging to the Middle Jurassic Brent Group which was deposited by a wave-dominated delta system in the East Shetlands Basin. The expected STOIIP and ultimate recovery are estimated at 158 MMBBL and 60 MMBBL of oil respectively, which represents a recovery factor of 38%. The 'Horst Block' contains 85% of the reserves with an OOWC about 150 ft shallower than in the 'Western Pool'. Reservoir quality is excellent, with average porosities varying from 23-26% and average permeabilities varying from 35-5300 md. The development plan envisages eleven satellite wells, six producers and five water injectors, closely clustered around two subsea manifolds. First production is expected in late 1990/early 1991. The wet crude oil will be piped to the Dunlin 'A' platform for processing and from there to the Cormorant Alpha platform into the Brent System pipeline for export to the Sullom Voe terminal.

The Gawain Field, Blocks 49/24, 49/29a, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 713-722
Author(s):  
R. A. Osbon ◽  
O. C. Werngren ◽  
A. Kyei ◽  
D. Manley ◽  
J. Six
Keyword(s):  
North Sea ◽  
Early Permian ◽  
Water Contact ◽  
Field Development ◽  
Dune Sands ◽  
Southern North Sea ◽  
Recoverable Reserves ◽  
Structural Relief ◽  
Sandstone Formation

AbstractThe Gawain Field is located on the Inde shelf in the Southern North Sea, 85 km NE of the Norfolk coast. Gawain was discovered in 1970 by well 49/29-1 and a total of nine wells have been drilled on the structure. Gas is produced from the Leman Sandstone Formation of Early Permian age. The reservoir section is comprised predominantly of stacked aeolian dune sands possessing excellent poroperm characteristics. The structure is a complex NW-SE trending horst block with a common gas-water contact at 8904 ft TVDss. Low structural relief has presented a major challenge to field development, which has utilized extended reach wells to maximize drainage potential. Initial gas-in-place is estimated at 289 BCF with recoverable reserves in the order of 196 BCF. The field came on production in September 1995 via a sub-sea tie back to the Thames infrastructure and has an expected field life of 10 years

The Guinevere Field, Block 48/17b, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 723-730 ◽  
Author(s):  
M. Lappin ◽  
D. J. Hendry ◽  
I. A. Saikia
Keyword(s):  
Fault Zone ◽  
North Sea ◽  
Production System ◽  
Early Permian ◽  
Gas Field ◽  
East Anglia ◽  
Southern North Sea ◽  
Fault Block ◽  
Sandstone Formation ◽  
The Uk

AbstractThe Guinevere Gas Field was discovered in January 1988 by the Mobil-operated well 48/17b-5. The field lies in the UK Sector of the Southern North Sea and occupies Block 48/17b. The field is located within the footwall of the Dowsing Fault Zone on the western flank of the Sole Pit Basin. Guinevere is a compressional northwesterly-trending fault block that comprises Early Permian Leman Sandstone Formation (Rotliegend Group) reservoir, sourced from the Carboniferous below and sealed by Later Permian Zechstein evaporates above.The Guinevere Gas Field is estimated to contain 90 BCF of recoverable gas reserves and was brought on-stream in June 1993 using a single not-normally-manned minimum facilities platform. Field life is predicted to be 13 years. Gas and condensate are evacuated though the Lancelot Area Production System (LAPS) to the onshore Bacton gas terminal in East Anglia.

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