bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Scott Field, Blocks 15/21a, 15/22, UK North Sea
Authors: Guscott Simon , Russell Ken , Thickpenny Andrew , Poddubiuk Robert 
Published: April 2008

Abstract
The Scott Field straddles Blocks 15/21 and 15/22 on the southern flanks of the Witch Ground Graben in the Outer Moray Firth Basin, UKCS. The oil field is developed in the highly productive Upper Jurassic Humber Group sandstones of Oxfordian to Kimmeridgian age. The field was discovered in 1983, sanctioned in 1990, and produced first oil in 1993.
The field structure, effectively a large southwards tilted fault block, is compartmentalized into a series of four main pressure isolated fault blocks by mid to late Jurassic faulting. The Kimmeridge Clay Formation provides both the top seal and the source of the trapped hydrocarbons. Fluid contact, overpressure and compositional trends suggest that the trap was filled primarily from the north. Some trap-defining faults were already active during the deposition of the reservoir intervals. Well data indicate that the development of accommodation space was technically controlled during this period, with subsidence occurring more rapidly in the western areas of the field.
The Scott Field reservoir consists of two major sand packages, the Scott Sandstone Member and the Piper Sandstone Member, bounded above and below by marine flooding surfaces. The late Oxfordian Scott Sandstone Member consists of a westwards prograding marine shoreface sandstone overlain by aggradational and retrogradational back-barrier deposits. Above this, the Mid Shale is a regionally extensive flooding event separating the Scott Sandstone Member from the overlying Piper Sandstone Member. The early Kimmeridgian Piper Sandstone Member consists of stacked mass flow sandstones, overlain by a shoreface/back-barrier system. Lateral facies changes and thickness variations significantly affect reservoir distribution in both Scott and Piper intervals.
The best reservoir quality occurs within the coarsest grained, highest energy facies, particularly the shoreface and proximal washover deposits. At the crest of the field, 10400 ft TVDss, multi-Darcy permeabilities and porosities of 20% are common. However, reservoir quality declines progressively downflank due to increased quartz cementation and compaction.
The Scott Field currently produces from 23 wells supported by 20 water injectors. Current modelling is aimed at targeting bypassed oil to increase ultimate recovery. The field has presently produced 300 MMSTB of oil from forecast reserves of 440 MMSTB with an estimated ultimate recovery factor of c. 46%.
The Banff Field, Blocks 22/27a, 29/2a, UK North Sea
Authors: Evans N. , MacLeod J. A. , Macmillan N. , Rorison P. , Salvador P. 
Published: April 2008

Abstract
The Banff Field is an oil field with a small gas cap containing an estimated 300 MMB0 oil-in place. The structure straddles the boundary between blocks 22/27a and 29/2a in the West Central Graben area of UK Central North Sea. The field was discovered by well 29/2a-6 in 1991. Banff Field is a Steeply dipping raft of fractured Late Cretaceous and Danian Chalk on the flank of a salt diapir. Paleocene sands draped over the raft provide addtional reservoir potential. A vertical oil column of over 3000 ft is present within the reservoir sourced from the underlying upper jurassic Kimmeridge Formation shales. Hydrocarbon migration into the trap is believed to have started in the Eocene.
The highest reservoir productivity occurs in the Late Cretaceous Tor Formation, which is expected to yield most of the field's reserves. Chalk porosity ranges from 15% to 35% but matrix permeabilities are generally less than 5 mD. Drainage is achieved through extensive faulting and fracturing
Initial uncertainties over reservoir performance and connectivity led to a phased development. Phase i comprised a six month Early Production System (EPS), during which time 5 MMBo were produced and the viability of the field was confirmed. Phase 2 Production is by means of a Floating Production System and Offtake (FPSO) Vessel Named the Ramform Banff. First oil production was achieved on 30 January 1999 and ultimate reserves are expected to be in excess of 75 MMBO.
The Curlew Field, Block 29/7, UK North Sea
Authors: Eneyok G. , Bussink P. , Maan A. 
Published: April 2008

abstract
In 1964, Block 29/7 was awarded as part of the first licencing round to Shell and Esso (UK). The Curlew area comprises a series of terraces that step down from the Western Platform into the West Central Graben. Exploration drilling started in 1977 but it wasn't until 1990 that well 29/7-4 successfully tested a 100 ft column of undersaturated volatile oil in the Upper Jurassic Fulmar Formation sandstones. Further exploration drillng, aided by 3D seismic data (acquired in 1991), yielded additional discoveries: Curlew C (1993, oil) and Curlew D (1994, condensate-rich gas). In Curlew D new technologies were succesfully applied to described and evaluate the isolated hanging wall compartment. Oil was discovered in what is now called Curlew D South in February 2000.
Hydrocarbon accumulations in the Curlew area occur in dip-closed faulted anticlinal structures. The producing Upper Jurassic Fulmar Formation is a heterogeneous mix of bioturbated shallow marine sandstones. barrier sandstones, and lagoonal/swamp deposits. The range in reservoir quality is reflected in the field porosity (5-27%) and permeability (0.001-800 mD). Reservoir compartments in the field (curlew B, D, and D South) are controlled by complex reservoir architecture, structure and fault geometry. Each reservoir compartment is characterized by a different fluid contact and a distinct fluid type. The reservoir heterogencity provieds potential for bypassed hydrocarbons in undrilled compartments, as was proven by the Curlew D South development.
Curlew B, D, and D South have since been developed. Evacuation of hydrocarbons from the Curlew area is via the Maersk Curlew FPSO, to which the producing wells have been tied back. Gas is fed nto the Fulmar Gas Line and oil is taken onshore by shuttle tankers. The initially-in-place volume in Curlew B at standard conditions is 24 MMSTB of oil and 25 BSCF of solution gas. Curlew B was developed via horizontal well 29/7-10y and came on stream in November 1997 at a rate of about 23 000 STB/D. The initially-in-place volume in Curlew D is 340 BSCF of gas and 100 MMSTB of condensate. Curlew D was developed via two vertical wells, 29/7-8z and 29/7-9, and started production in February 1998 with production rates up to 115 MMSCF/D of gas and 34 000 STB/D. Gas production from the field is constrained. however, by the facilities. Curlew D South is developed by the vertical well 29/7-11 which came on stream in March 2000 after a North Sea record-time tie back of the original appraisal well.
The Erskine Field, Block 23/26, UK North Sea
Authors: Coward R. N. 
Published: April 2008

Abstract
The Erskine Field is a high temperature, high pressure (HTHP), gas condensate accumulation located on the western margin of the East Central Graben. The field was discovered in 1981 by the 23/26a-3RE well and subsequently delineated by six appraisal wells. Development approval was granted in 1995 and to date five development wells have been drilled. In December 1997, Erskine Field became the first HTHP field in the UKCS to achieve production. Hydrocarbons are produced from three separate Jurassic reservoirs. In order of decreasing importance, these are: the Late Oxfordian Erskine Sandstone (Puffin Formation), the Middle Jurassic Pentland Reservoir, and the Late Oxfordian Heather Turbidite Reservoir.
The Erskine Sandstone is very fine to fine-grained highly bioturbated, shaley sandstone. The sandstones represent shallow marine progradational sequences, deposited predominantly in the offshore transition zone. Within the majority of the Erskine Sandstone, porosity is high (20-25%) but with relatively poor associated permeability (0.1-10mD). However, the tops of the coarsening upward sequences (E30 and E70 zones) have appreciably better permeability and are thought to be the major conduits for fluid flow. The E30 and E70 zones would not have been identified, had it not been for the extensive coring programme undertaken in the development wells.
The Pentland Reservoir is a regionally extensive sequence of interbedded sandstone, shales, coals and siltstones, deposited in a fluvial-lacustrine environment in a delta plain setting. Permeability in the Pentland reservoir (0.1 mD-1 D) is in general far superior to the values observed in the Erskine Sandstone. The main control on the observed variability in porosity and permeability characteristics is grain size, that in turn is controlled by facies.
The Heather Turbidite Reservoir occurs within two thin predominantly fine-grained turbidite sandstone beds in the Heather Shale Formation. This reservoir is restricted to the Alpha Terrace region in the SW of the field, and is drained by a single development well.

Total Erskine Field reserves are estimitated at approx
400 BCF
of gas and
66 MMBBL
of condensate.
The Fife and Fergus Fields, Block 31/26a, UK North Sea
Authors: Shepherd M. , MacGregor A. , Bush K. , Wakefield J. 
Published: April 2008

Abstract
The Fife Field and its smaller satellite the Fergus Field are the southernmost of the cluster of oil fields within the UK Central North Sea. The Fife Field lies at the intersection of four blocks, 31/26a, 31/27a, 39/la and 39/2a. It is a small to moderate size offshore field with reserves of 48.3 MMSTB and is produced by five sub-sea wells through a Floating, Production, Storage, Offloading (FPSO) vessel. The field was discovered in 1991 and the first oil was produced in 1995. The Fergus Field, located in Block 39/2a, is a satellite located 5 km SE of the Fife Field. It is produced by a single well tied-back by a sub-sea flowline to the Fife Field infrastructure. The Fergus Field was discovered in 1994 and first oil was produced in 1996. Reserves are estimated as 11.3 MMSTB
The main reservoir interval in both fields comprises fine-grained, heavily bioturbated, shallow marine shelf sandstones of Upper Jurassic age. Significant volumes of chert and carbonate cements, both banded and nodular, occlude porosity and impart reservoir layering within an otherwise thick sandy, mud deficient reservoir interval. Sandstone porosity is in the range 19-31%. Permeabilities are low in the Fife Field reservoir sandstones, typically less than lOOmD. By contrast, better permeabilities (average 500 mD) are seen in the Fergus Field, where a more proximal shelf sandstone facies is present within the oil leg. Two thin intervals of pebbly, very coarse-grained sandstone are intercalated with the shelf sandstones in the crest of the Fife Field. These may represent submarine toes of fan deltas sourced from an active fault system located to the north of the field. The pebbly sandstones show permeabilities in excess of a Darcy and have caused early water breakthrough problems in production wells
A subsidiary reservoir is present within the Tor Formation of the Chalk Group in the Fife Field, but is not oil bearing within the Fergus Field. This comprises white to grey, intensely bioturbated, stylolitized chalk with an average porosity of 24.5% and an average air permeability of slightly less than a millidarcy. Both the Fife and Fergus Fields are defined by simple four-way dip closure at top Jurassic. An episode of structural inversion at the end of the Jurassic created both structures. The overlying Chalk oil pool in the Fife Field has a trap defined by dip closure on three sides and a probable diagenetic trapping element to the south
The Forties and Brimmond Fields, Blocks 21/10, 22/6a, UK North Sea
Authors: Carter A. , Heale J. 
Published: April 2008

Abstract
This paper updates the earlier account of the Forties Field detailed in Geological Society Memoir 14 (Wills 1991), and gives a brief description of the Brimmond Field, a small Eocene accumulation overlying Forties (Fig. 1).
The Forties Field is located 180 km ENE of Aberdeen. It was discovered in 1970 by well 21/10-1 which encountered 119 m of oil bearing Paleocene sands at a depth of 2131 m sub-sea. A five well appraisal programme confirmed the presence of a major discovery including an extension into Block 22/6 to the southeast. Oil-in-place was estimated to be 4600 MMSTB with recoverable reserves of 1800 MM STB. The field was brought onto production in September 1975. Plateau production of 500 MBOD was reached in 1978, declining from 1981 to 77 MBOD in 1999.
In September 1992 a programme of infill drilling commenced, which continues today. The earlier infill targets were identified using 3D seismic acquired in 1988. Acquisition of a further 3D survey in 1996 has allowed the infill drilling programme to continue with new seismic imaging of lithology, fluids and saturation changes. The performance of the 1997 drilling showed that high step-out and new technology wells, including multi-lateral and horizontal wells, did not deliver significantly better targets than drilling in previous years.
In line with smaller targets, and in the current oil price environment, low cost technology is being developed through the 1999 drilling programme. Through Tubing Rotary Drilling (TTRD) is currently seen as the most promising way of achieving a step
The Fulmar Field, Blocks 30/16, 30/11b, UK North Sea
Authors: Kuhn O. , Smith S. W. , Van Noort K. , Loiseau B. 
Published: April 2008

Abstract
The Fulmar Field is located on the southwestern margin of the Central Graben in Blocks 30/16 and 30/11b of the UK sector of the North Sea. The Fulmar Field was discovered 1975 and began producing in 1982. Currently (2000) the field produces at a rate of 8000 BOPD at a watercut above 90% mainly through the process of rinsing of residual oil. Total STOIIP is 822 MMBBL and ultimate recovery is 567 MMBBL of oil and 342 BSCF of wet gas. As of the end of 1999, 547 MMSTB of oil and 325 BSCF of wet gas had been produced. The high recovery factor (69%) of the field is thought to be linked to the combination of well density, large length of reservoir perforated, excellent reservoir quality, sweep by water injection, good pressure support and oil stripping from a secondary gas cap formed early in field life.
The Fulmar Field is a small triangular, partly eroded domal anticline with steeply dipping flanks, located on a fault terrace within the western margin of the South West Central Graben at a depth between 9900 and 11 500 ft TVDss. The field has been shaped by three major tectonic processes: (1) halokinesis, (2) syndepositional reactivation of Caledonian basement faults; and (3) syndepositional through post-depositional displacements along the nearby Auk Horst Boundary Fault. The reservoir consists of thick Upper Jurassic, shallow marine, very bioturbated sandstones of the Fulmar Formation overlain by the deeper marine Ribble Sands interbedded within the Kimmeridge Clay Formation. Reservoir seal is provided by the Kimmeridge Clay in the west and Upper Cretaceous chalks which unconformably overlie the Fulmar Formation in the east. The reservoir section has been lithostratigraphically subdivided into six reservoir units and 24 sub-units. Integration of bio- and lithostratigraphic data has led to a sequence stratigraphic model of the Jurassic succession in the Fulmar Field. In total four depositional sequences are identified, which progressively onlap Triassic basement towards the southwest. The older Jurassic sequences are characterized by rapid progradation of shoreface sands, whereas aggradation of thick sediment packages is typical of the younger intervals. This change of depositional architecture is linked to syndepositional reactivation of basement faults. Major transgressive intervals form intra-reservoir barriers or baffles to flow. Facies changes (Mersey-Clyde Sands) from proximal to distal facies are abrupt and are also linked to basement faults.
The Maureen Field, Block 16/29a, UK Central North Sea
Authors: Chandler Peter M. , Dickinson Barbara 
Published: April 2008

abstract
The Maureen field comprises the Maureen, Mary and Morag Accumulations, the reservoirs being Palaeocene Sandstones, Upper Jurassic sandstones and Permian dolomites respectively. The field lies about 10 km NNE of the Moira Palaeocene field. Maureen was discovered in 1973, came on-stream in 1983 and produced 217.4 MMBBL (from an estimated STOIIP of 397 MMBBL). The field ceased production in October 1999. It is trapped in a four-way dip closure over a salt dome and scaled by the overlying Lista Formation mudstones. The reservoir is up to 450 ft gross thickness, with core porosity from 18-28% and good sand connectivity. Morag was discovered in 1979. came on-stream in 1991 and produced 2.6 MMBBL before being shut-in in 1994. It produced from clean fractured dolomites in a stratigraphic trap. Mary was discovered and came on-stream in 1991. The initial well died after 1 year. A later well was put on-stream in 1997. Mary produced 2.83 MMBBL before final shut-in in June 1999. Reservoir quality is reasonable, but sand distribution is problematic. All the oils are sourced from the Kimmeridge Clay formation on the adjacent Maureen Shelf area.
The Nelson Field, Blocks 22/11, 22/6a, 22/7, 22/12a, UK North Sea
Authors: Kunka J. M. , Williams G. , Cullen B. , Boyd-Gorst J. , Dyer G. R. , Garnham J. A. , Warnock A. , Wardell J. , Davis A. , Lynes P. 
Published: April 2008

Abstract

The Nelson Field is located in Blocks 22/11, 22/6a, 22/7 and 22/12a in the UK Central North Sea. Nelson is a simple dip closed structure and is one of a series of Palaeocene Forties Sandstone Member oil accumulations situated on the Forties-Montrose High. The first exploration well on the prospect, 22/11-1, was drilled by Gulf Oil in 1967. Although hydrocarbon shows were encountered in a heterolithic section of Forties Sandstone Member, the well failed to flow on test and was abandoned. 3D seismic data were first acquired in 1985 and led to the discovery of Nelson in 1988 when the 22/11-5 well was drilled by Enterprise Oil plc. Following appraisal drilling, Nelson was granted production consent and the field came on-stream in February 1994. The hydrocarbon type is a light 40° API crude with a GOR of 555 SCF/BBL and is believed to be sourced from the East Forties Basin. The Nelson Field is developed from a 36 slot minimum facilities platform. Currently there are 23 platform producers, four sub-sea producers and four platform water injectors. Oil export is via the Forties Pipeline System and gas export is via the Fulmar Gas System. Oil originally in place is estimated at 790 million barrels of oil (MMBBL). Up to end-1999, the field had produced 261 MMBBL. Since the field was described by Whyatt
et al.
(1992), a further 28 wells have been drilled resulting in the collection of a considerable amount of new geological and geophysical data. This now includes a total of 6500 ft of Palaeocene core and 4D seismic data. This has enabled a more detailed understanding of the structure and sequence stratigraphy of the Nelson Field. This paper illustrates the importance of seismic mapping, high resolution biostratigraphy and sedimentology in developing the Nelson Field model.
The Barque Field, Blocks 48/13a, 48/14, UK North Sea
Authors: Sarginson M. J. 
Published: April 2008

Abstract
The Barque Field is associated with some of the earliest gas discoveries in the southern North Sea. In the Sole Pit area the reservoir, the Rotliegend Group Leman Sandstone Formation of Lower Permian age, occurs between Carboniferous Coal Measures, which source the gas, and Zechstein evaporites which form an excellent seal. Primarily aeolian, the sandstone has generally very low permeability resulting from deep burial of the Sole Pit Trough. The deepest burial and hence the maximum diagenetic damage to the reservoir was achieved in the early Late Cretaceous prior to two phases of inversion in Late Cretaceous and Mid-Tertiary.
Compaction and diagenesis reduced reservoir permeability to such an extent that parts of the field would be non-productive were it not for the presence of effective natural fracture zones and well stimulation by hydraulic fracturing techniques. Though appraisal and evaluation have been relatively extensive, remaining uncertainties dictated a conservative development in conjunction with the adjacent Clipper Field. A selected initial area was developed for first gas in October 1990. Good reservoir performance from horizontal wells led to later development of the whole field.
The Corvette Field, Block 49/24, UK Southern North Sea
Authors: Hillier A. P. 
Published: April 2008

abstract
Corvette is a small prolific gas reservoir with reserves of 211 BSCF located on the Indefatigable Shelf in the Southern North Sea. The reservoir is the Permian Rotliegend aeolian sandstone, capped by Zechstein evaporites and sourced from the Carboniferous Coal Measures. The structure is a 'pop up' between the Gawain and Baird Fields. The field was discovered in 1996 and brought on production in 1999, with gas being evacuated via the Leman field to the Shell/Esso Bacton gas terminal.
The Guinevere Field, Block 48/17b, UK North Sea
Authors: Lappin M. , Hendry D. J. , Saikia I. A. 
Published: April 2008

Abstract
The 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.
The Johnston Gas Field, Blocks 43/26a, 43/27a, UK Southern North Sea
Authors: Lawton David E. , Roberson Paul P. 
Published: April 2008

abstract
The Johnston Field is a dry gas accumulation located within blocks 43/26a and 43/27a of the UK Southern North Sea. The discovery well was drilled in 1990 and after the drilling of one appraisal well in 1991, a development plan was submitted and approved in 1993. Initially two development wells were drilled from a four slot sub-sea template, with commercial production commencing in October 1994. A further horizontal development well was added to the field in 1997.
The field has a structural trap, fault bounded to the SW and dip-closed to the north, east and south. This field geometry has been established using high quality 3D seismic data, enhanced by seismic attribute analysis. The sandstone reservoir interval consists of the Early Permian, Lower Leman Sandstone Formation of the Upper Rotliegend Group. This reservoir consists of a series of interbedded aeolian dune, fluvial, and clastic sabkha lithofacies. The quality of the reservoir is variable and is principally controlled by the distribution of the various lithofacies. The top seal and fault bounding side seal are provided by the overlying clay stone of the Silverpit Shale Formation and the evaporite dominated Zechstein Supergroup.
The field has been developed using a phased development plan, with the acquisition of a 3D seismic survey allowing for the optimized drilling of a high deliverability horizontal well.
Current mapped gas initially-in-place estimates for the field are between 360 and 403 BCF, with an estimated recovery factor of between 60 and 75%.