bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Captain Field, Block 13/22a, UK North Sea
Authors: Pinnock S. J. , Clitheroe A. R. J. , Rose P. T. S. 
Published: April 2008

Abstract
The Captain Field is located in Block 13/22a in the Western Moray Firth Basin of the UK North Sea, 80 miles NE of Aberdeen in a water depth of 340 ft. Hydrocarbons are trapped in two geographical regions, the Main and Eastern closures, both with a significant stratigraphic pinchout component. The principal reservoirs consist of turbidite sandstones of Lower Cretaceous age which have been informally subdivided into two stratigraphic units comprising the Upper and Lower Captain Sandstones. At the base of the preserved Jurassic section the Heather Sandstone, Oxfordian in age, provides a secondary reservoir. Reservoir quality is uniformly excellent in the Lower Cretaceous with in situ, Klinkenberg corrected permeability averaging 7 Darcies and porosity in the range 28-34%. The reservoir is generally poorly consolidated sandstone with the depth to the crest of the field at -2700 ft TVDss. The reservoirs contain a total oil-in-place of 1000 MMBO. The Upper Captain Sandstone has a small associated gas cap containing 16 BCF gas-in-place. The oil is heavy, by North Sea standards, with oil gravity ranging from 19° to 21° API and has high in situ viscosity, 150 to 47 cP, at the mean reservoir temperature of 87°F. The fluid properties and offshore location necessitate the employment of innovative horizontal drilling methods, completion design and artificial lift technology in order to achieve an economically viable field development. Extended reach horizontal wells, with reservoir completion lengths of up to 8000 ft, are drilled for all oil producers and water injectors. Development risks were significantly reduced following two appraisal drilling campaigns in 1990 and 1993 culminating with the successful drilling and extended testing of a prototype horizontal field development well (13/22a-10). The field is being developed in two phases, Area A and Area B. First oil production commenced from the Captain platform in March 1997 from Area A and the field now produces at between 50000 and 70000 BOPD. Area B development is now underway with first oil planned for December 2000. Completion of this phase of the development will increase the plateau production rate to 85000 BOPD.
The Auk Field, Block 30/16, UK North Sea
Authors: Trewin Nigel H. , Fryberger Steven G. , Kreutz Helge 
Published: April 2008

Abstract

The Auk Field is located in Block 30/16 at the western margin of the Central Graben. Block 30/16 was awarded in June 1970 to Shell/Esso, and the discovery well 30/16-1 spudded in September 1970. The well found oil in a complex horst block sealed by Upper Cretaceous chalk and Tertiary claystones. The field contained an original oil column of up to 400 ft within Rotliegend sandstones, Zechstein dolomites, Lower Cretaceous breccia and Upper Cretaceous chalk. Production by natural aquifer drive commenced from a steel platform in 1976, initially from the Zechstein carbonates and now predominantly from the Rotliegend sandstone. Artificial lift was installed in 1988 helping to maintain production at economic levels past the year 2000. A complex reservoir architecture with cross flow between the Rotliegend and Zechstein reservoirs, a strong aquifer causing early water breakthrough via faults, and a limited seismic definition led to significant production variations from the initial forecasts. Equally important for the field, horizontal well technology opened up additional reserves and accelerated production from the complex Rotliegend reservoir; the most recent volumetric estimate for the total field predicts an ultimate recovery of 151
MMBBL
for the existing wells from a
STOIIP
of 795
MMBBL
. Full field reservoir simulation and 3D seismic data acquisition took place since mid 1980s but only recently resulted in a satisfactory understanding of the reservoir behaviour.

The field is situated about 270 km ESE from Aberdeen in 240-270 ft of water. It covers a tilted horst block with an area of 65 km
2
, located at the western margin of the Central Graben. The Auk horst is bounded on the west by a series of faults with throws of up to 1000 ft, the eastern boundary fault has a throw of 5000 ft in the north reducing in throw southwards. The best reservoir lithology in the Zechstein is a vuggy fractured dolomite, and in the Rotliegend dune slipface sandstones provide the majority of the production. Both reservoirs and the overlying Lower Cretaceous breccia shared a common FWL at 7750 ft TVDss. The 38° API oil with a GOR of 190 SCF/STB was sourced from organic-rich Kimmeridge Clay.
The Moira Field, Block 16/29a, UK Central North Sea
Authors: Chandler Peter M. , Dickinson Barbara 
Published: April 2008

Abstract
The Moira Field, discovered in 1988, lies on the Maureen Shelf, 10 km SSW of the Maureen Field. The reservoir comprises submarine fan sandstones in a four-way dip closure, draped over a Middle Jurassic fault block. The good quality reservoir (porosity 17-25%, permeability 80-400mD) flowed 5100 BOPD of 42° API oil in the discovery well. STOIIP was initially calculated as 20 MMBBL, but seismic pick and depth conversion uncertainites were revealed by later drilling. The most recent (1998) calculation yielded STOIIP of 12.4 MMBBL. Reserves of 4.2 MMBBL (34%), have been produced through a single deviated well tied-back to the Maureen platform. The field was shut-in in 1999.
The Montrose, Arbroath and Arkwright Fields, Blocks 22/17, 22/18, 22/23a, UK North Sea
Authors: Hogg A. J. C. 
Published: April 2008

Abstract

This paper updates the earlier account of the Montrose and Arbroath Fields by Crawford
et al.
detailed in
Geological Society Memoir
14
, and gives an additional description of the Arkwright Field, a satellite Paleocene accumulation some 7 miles SE of Arbroath.
The Boulton Field, Block 44/21a, UK North Sea
Authors: Conway A. M. , Valvatne C. 
Published: April 2008

Abstract
The Boulton Field was discovered in 1984 when gas was tested from the Lower Ketch Unit, Carboniferous Westphalian C/D, in well 44/21-2. Following appraisal drilling in 1990, the Boulton 'B' structure was delineated and a trap confirmed by a combination of up-dip seal against basal Permian shales, and salts and lateral seal against sealing faults and impermeable Westphalian C sediments. A second structure was drilled in the same year, Boulton 'F', with gas discovered in the deeper Murdoch Sand Interval of the Westphalian C/D. The two separate structures collectively form the Boulton Field.
Current deliverability from the 'B' structure, Lower Ketch Sands is approximately 100 MMSCFD from a single producer. Developed with a minimal platform facility, the gas is delivered to Theddlethorpe Gas Terminal via offshore compression at the nearby Murdoch Field. The reservoir in Boulton 'B' comprises a series of channel sands deposited in a braided stream complex flowing predominantly from north to south across an Upper Carboniferous alluvial plain. Sandbody connectivity within the complex fluvial architecture of the Westphalian C is a key control on gas production.
The Camelot Fields, Blocks 53/1a, 53/2, UK North Sea
Authors: Karasek R. M. , Hunt J. R. 
Published: April 2008

Abstract
The group of gas accumulations known as the Camelot Fields straddle Blocks 53/1a and 53/2 of the UK Sector of the Southern North Sea on the southern margin of the Sole Pit Trough. The Camelot North Field was discovered in 1967 and development commenced from the Camelot A platform in 1989 (wells Al to A5). The Camelot Northeast Field came on-stream from the B platform (53/2-7 well) in 1992. The Cador accumulation, in the north of Block 53/1a, was subsequently developed through the A6 horizontal well in 1993. The current estimate of gas initially in place (GIIP) for the field is 280 billion cubic feet. Ultimate recovery factors are expected to be as much as 90% and since more than 80% of the GIIP has already been recovered, the Camelot Fields have proven to be prolific producers.
This paper focuses on field history after 1988 and, in particular, on the recent exploratory drilling on the southern field margin beneath the South Leman Graben. In this area depth conversion is a major challenge with large velocity contrasts, low relief structures and thin hydrocarbon columns. Recent well results, following mapping of the new 3D seismic data set, indicate that fault reactivation occurred in late Cretaceous to early Tertiary times. Fault movements associated with this event resulted in trap readjustments and/or gas leakage and have exerted an important additional control on hydrocarbon spill points.
The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea
Authors: Sarginson M. J. 
Published: April 2008

Abstract
The 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 Gawain Field, Blocks 49/24, 49/29a, UK North Sea
Authors: Osbon R. A. , Werngren O. C. , Kyei A. , Manley D. , Six J. 
Published: April 2008

Abstract
The 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 Hewett Fields: Blocks 48/28a, 48/29, 48/30, 52/4a, 52/5a, UK North Sea: Hewett, Deborah, Big Dotty, Little Dotty, Della, Dawn and Delilah Fields
Authors: Cooke-Yarborough P. , Smith E. 
Published: April 2008

abstract
The Hewett Fields complex, discovered in 1966, is located in the southwestern part of the Southern North Sea Basin. Gas is currently being produced from four horizons: Upper and Lower Bunter sandstones in the Triassic, Rotliegendes sandstones, and Zechstein dolomites in the Permian. Seven fields, containing a total of ten reservoirs, lie within the Hewett Unit and all have a NW-SE orientation. Gas flows, via two 30-inch (0.76 m) pipelines, to the ConocoPhillips-operated Bacton terminal, where onshore compression facilities are located. There are also compressors located on two platforms. Over 4 TCF (113 billion cubic metres) of gas has so far been produced in over 30 years of production.
The Indefatigable Field, Blocks 49/18, 49/19, 49/23, 49/24, UK North Sea
Authors: McCrone C. W. , Gainski M. , Lumsden P. J. 
Published: April 2008

abstract
Indefatigable is a mature dry gas field on the northeastern margin of the UK Southern North Sea Rotliegend Play fairway. The field was discovered, 49/18-1, by the Amoco operated group in 1966 and subsequent appraisal drilling established that the field extended over four blocks (i.e. 49/18, 49/19, 49/23 & 49/24). There have been several phases of development, initial production concentrated on the main horst block with first gas in 1971, followed by the west flank area in 1977/78. Then in 1987/88 the SW and SE Indefatigable satellite accumulations were brought on-stream.
The Rotliegend Leman Sandstone Formation reservoir primarily consists of stacked aeolian dune sandstones (150-400 ft) of good reservoir quality (porosity 15%, permeability 100-1000 mD). However, the integration of the 1992/93 3D seismic survey, well data, reservoir pressure and production data has lead to a much more complex view of the field with 11 gas-water contacts and 15 reservoir compartments.
This has resulted in an upward revision of the gas initially-in-place from 5.2 to 5.6 TCF and recoverable reserves from 4.4 to 4.7 TCF. Current work is focused on maximizing recovery from the various reservoir compartments and accessing this additional potential.
The Pickerill Field, Blocks 48/11a, 48/11b, 48/12c, 48/17b, UK North Sea
Authors: Werngren O. C. , Manley D. , Heward A. P. 
Published: April 2008

Abstract
The Pickerill Field is a dry gas accumulation straddling four separate licences in the UK Southern North Sea. Discovered in 1984, 12 appraisal wells were drilled to define the field before Annex B approval in 1989. Subsequently, Pickerill has been developed using 15 high angle wells, a large number of which have been sidetracked reflecting the geological complexity of the accumulation. Pickerill has been in production since August 1992, and has an estimated initial reserves in excess of 500 BCF.
The Trent Gas Field, Block 43/24a, UK North Sea
Authors: O'Mara Peter T. , Merryweather Marilyn , Stockwell Mark , Bowler Mike M. 
Published: April 2008

Abstract

The Trent gas field lies within the UKCS Southern Gas Basin (Block 43/24a) located 120 km off the Yorkshire coast in average water depths of 160 ft. The accumulation is contained within a NW-SE trending Base Permian closure, which straddles blocks 43/24, 43/23 and 43/25. The Carboniferous subcrop beneath the Base Permian unconformity varies in age from Westphalian A in the east to Namurian in the west. Although the Base Permian closure covers an area of 75 km
2
the producible reserves are only located in the central core area of 43/24a. The main reservoir horizon is the Trent Sandstone of Marsdenian age, equivalent to the Chatsworth Grit Sandstone, UK onshore. Additional reservoir zones are within the lowermost Westphalian A. The field has been developed through the application of fracture stimulation of deviated wells.
The Tyne Gas Fields, Block 44/18a, UK North Sea
Authors: O'Mara P. T. , Merryweather M. , Cooper D. S. 
Published: April 2008

abstract
The Tyne Fields, operated by ARCO British Limited, are located within UKCS Block 44/18a, situated 180km off the Yorkshire coast in a water depth of 65 ft. The fields comprise three separate accumulations, each with a different gas-water contact and varying gas compositions, which are known as Tyne North, Tyne South and Tyne West. The three accumulations are combined structural and stratigraphical traps. The reservoir sandstones are of the Lower Ketch member of the Schooner Formation and are Carboniferous Westphalian C/D in age. The fields have been developed through long reach development wells.
The Windermere Gas Field, Blocks 49/9b, 49/4a, UK Southern North Sea
Authors: Bailey R. J. , Clever J. E. 
Published: April 2008

Abstract

The Windermere Field, in the central area of the Southern North Sea gas province, exploits a variant of the Rotliegend-Leman Sandstone gas play. A thin, basal aeolian sandstone is top-sealed by lacustrine Silverpit Formation, clay stones and sourced by the underlying Westphalian Coal Measures. Since the reservoir unit has no mappable seismic expression, trap definition depends on depth mapping the Base Zechstein and adding the appropriate Silverpit Formation isochore. The trap is a simple, uncompartmentalized, anticlinal feature, lying largely within Block 49/9b. The 49/9b-2 discovery well (1989) penetrated the crest of the feature and the 49/9b-4 appraisal well (1994-1995) was drilled down-plunge to the SE. Both encountered some 20 m of predominantly aeolian-dune sandstone overlying the Base Permian Unconformity. This reservoir flowed dry gas at rates of 0.8-1.0 MMm
3
/d. The GWC was not penetrated; however RFT pressure projections suggest that it lies at around 3528 m. Stochastic estimates suggested Leman Sandstone GIIP of 2.8 bcm (104 BCF). The field's two-well development is tied back to a minimum facilities platform with export to Den Helder, via the Markham ST-1 platform. On commissioning, in August 1997, the two-wells flowed at 1.8 MMm
3
/day. By January 1999, 0.682 bcm of the originally-estimated 2.3 bcm gas reserve had been produced.
The Hatfield Moors and Hatfield West Gas (Storage) Fields, South Yorkshire
Authors: Ward J. , Chan A. , Ramsay B. 
Published: April 2008

abstract
Hatfield Moors and Hatfield West are two small gas fields with GIIP of 6.1 BCF and 2.4 BCF, respectively on adjacent licences PL161-3 and PL 162-2, east of Doncaster in South Yorkshire, England, operated and wholly owned by Edinburgh Oil & Gas pic.
This paper describes the accidental discovery of the Hatfield Moors Gas Field and its subsequent development and eventual utilization for gas storage, the first such project onshore UK. The nearby Hatfield West Field is also described. The two fields are located on adjacent faulted anticlinal structures in the NW part of the Gainsborough half-graben. The reservoir for both fields is the Westphalian B Oaks Rock sandstone. Reservoir quality is excellent.
A gas storage project was agreed with Scottish Power in 1998. Two horizontal wells, Hatfield Moors-5 (1998) and Hatfield Moors-5z (1999) have been drilled for the project by Edinburgh Oil & Gas pic using innovative drilling techniques. Since 1999 gas has been imported from the Transco network and exported from the reservoir according to market demands under the terms of the gas storage contract.
The Saltfleetby Field, Block L 47/16, Licence PEDL 005, Onshore UK
Authors: Hodge T. 
Published: April 2008

Abstract
The Saltfleetby Gas Field is located onshore in East Lincolnshire at the western extent of the Humber Basin, midway between the Southern North Sea gas fields and the established Onshore Oilfields of Welton and Scampton North. Commercial discovery was in 1996, following the re-entry of a 1986 exploration well, confirming the pre-drill belief that the earlier drilling had been mis-appraised. Basic assumptions at the time of drilling the re-entry well suggested a possible 40 BCF gas-in-place in Early Westphalian sandstones. This assessment was based on only a single 2D seismic line, an association with gravity form, and the mud logging information from the earlier exploration well.
Full delineation of the field extent following 3D seismic mapping and development drilling has indicated a gas-in-place of 114 BCF. Field development consent was granted in March 1999 and production commenced in December 1999. Initial field production exceeded 50 MMSCFD from four wells and to date (end July 2001) 24 BCF of gas has been produced. Ultimate gas recovery is expected to be 73 BCF proven plus probable reserves. A fifth horizontal well has been drilled in a deeper, Namurian, zone and a sixth well confirmed hydrocarbons in a southern promontory to complete the field development. An 8 km mixed phase export pipeline of 10" diameter exists to the Theddlethorpe processing plant, where gas and condensate is separated. Sharing of Pickerill compression facilities, located at Theddlethorpe were commissioned late in 2001.
The Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey and Sussex, UK Onshore
Authors: Trueman S. 
Published: April 2008

Abstract

The Weald Basin of SE England is a lozenge shaped accumulation of sediments occuring from Southampton and Winchester in the west to Maidstone and Hastings in the east. It is approximately 150 km long by 60 km wide, covering an area of some 9000 km
2
(Fig. 1). Several commercial oil and gas discoveries have been made, mostly on the flanks of the basin. These fields have been in continous production since the early 1980s. Field size in terms of recoverable hydrocarbons is small, 0.5 to 6 MMBBL of oil is typical. Hydrocarbons are produced primarily from the Middle Jurassic Bathonian Great Oolite at Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth and Horndean fields but also from the Late Oxfordian-Early Kimmeridgian Corallian Sandstone at Palmers Wood; Portland Sandstone at Brockham and Godley Bridge; Corallian Limestone at Bletchingley; Purbeck Sandstones in Albury and Late Triassic Rhaetic calcarenites in Humbly Grove. Cumulative oil production from the basin as a whole is currently 19.1 MMSTB
The Flora Field, Blocks 31/26a, 31/26c, UK North Sea
Authors: Hayward R. D. , Martin C. A. L. , Harrison D. , Van Dort G. , Guthrie S. , Padget N. 
Published: April 2008

Abstract
The Flora Field straddles Blocks 31/26a and 31/26c of the UK sector of the North Sea on the southern margin of the Central Graben. The field is located on the Grensen Nose, a long-lived structural high, and was discovered by the Amerada Hess operated well 31/26a-12 in mid-1997.
The Flora Field accumulation is reservoired within the Flora Sandstone, an Upper Carboniferous fluvial deposit, and a thin Upper Jurassic veneer, trapped within a tilted fault block. Oil is sourced principally from the Kimmeridge Clay Formation of the Central Graben and is sealed by overlying Lower Cretaceous marls and Upper Cretaceous Chalk Group.
Reservoir quality is generally good with average net/gross of 85% and porosity of 21%, although permeability (Kh) exhibits a great deal of heterogeneity with a range of 0.1 to <10000mD (average 300 mD). The reservoir suffers both sub-horizontal (floodplain shales) and vertical (faults) compartmentalization, as well as fracturing and a tar mat at the oil-water contact modifying flow and sweep of the reservoir. Expected recoverable reserves currently stand at 13 MMBBL