bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Eider Field, Block 211/16a and 211/21a, UK North Sea
Authors: Wensrich M. D. , Eastwood K. M. , Van Panhuys C. D. , Smart J. M. 
Published: April 2008

Abstract
The Eider Oilfield is located some 160 knortheast of the Shetland Islands mainly in Block 211/16a, part of Production Licence P296, with the southern tip extending into Block 211/2la. The discovery well was drilled in 1976 in a water depth of about 530 ft. Hydrocarbons are trapped at a depth of 8750 ft TVSS in an easterly dipping fault block that is part of the Tern-Eider horst in the East Shetlands Basin. The reservoir is the Middle Jurassic Brent Group, deposited in a wave-dominated delta system. It has an average gross thickness of 259 ft and an average net thickness of 210 ft. Porosities average 23% and permeabilities 375 md. The expected STOIIP and Ultimate Recovery are estimated at 204 MMBBL and 85 MMBBL respectively, representing a recovery factor of 42%.
The field is planned to be developed by five producers drilled along the crest of the structure. Pressure maintenance and sweep (secondary recovery) will be provided by four down-flank water injectors. The Eider production facility is a satellite platform of the neighbouring North Cormorant and Tern platforms and is designed for future unmanned operation. Production started in November 1988 and averaged some 54 000 BOPD. Water injection began in June 1989, using water, piped at injection pressure, from the Tern platform. First stage processing of the crude oil is carried out on the Eider platforms and then it is piped to the North Cormorant platform for further processing. From there it is evacuated via the Cormorant Alpha platform into the Brent System pipeline for export to the Sullom Voe terminal.
The Emerald Field, Blocks 2/10a, 2/15a, 3/11b, UK North Sea
Authors: Stewart D. M. , Faulkner A. J. G. 
Published: April 2008

Abstract
The Emerald Oil Field lies in Blocks 2/10a, 2/15a and 3/1 lb in the UK sector of the northern North Sea. The field is located on the 'Transitional Shelf, an area on the western flank of the Viking Graben, downfaulted from the East Shetland Platform. The first well was drilled on the structure in 1978. Subsequently, a further seven wells have been drilled to delineate the field.
The Emerald Field is an elongate dip and fault closed structure subparallel to the local NW-SE regional structural trend. the 'Emerald Sandstone' forms the main reservoir of the field and comprises a homogeneous transgressive unit of Callovian to Bathonian age, undelain by tilted Precambrian and Devonian Basement Horst blocks. Sealing is provided by siltstones and shales of the overlying Healther and Kimmeridge Clay Formations. The reservoir lies at depths between 5150-5600 ft, and wells drilled to date have encountered pay thicknesses of 42-74 ft. Where the sandstone is hydrocarbon bearing, it has a 100% net/ gross ratio. Porosities average 28% and permeabilities lie in the range 0-1 to 1.3 darcies. Wireline and test data indicate that the field contains a continouous oil column of 200 ft. Three distinct structural culminations exist on and adjacent to the field, which give rise to three separate gas caps, centred around wells 2/10a-4, 2/10a-7 and 2/10a-6 The maximum flow rate achieved from the reservoir to date is 6822 BOPD of 24° API oil with a GOR of 300 SCF/STBBL. In-place hydrocarbons are estimated to be 216 MMBBL of oil and 61 BCF of gas, with an estimated 43 MMBBL of oil recoverable by the initial development plan. initial development drilling began in Spring 1989 and the development scheme will use a floating production system. Production to the facility, via flexible risers, is from seven pre-drilled deviated wells with gas lift. An additional four pre-drilled water injection wells will provide reservoir pressure support.
The Heather Field, Block 2/5, UK North Sea
Authors: Penny Brian 
Published: April 2008

Abstract
The Heather Oil Field is located at the western margin of the East Shetland Basin, in the northern North Sea, and is operated by Unocal UK Ltd. Oil is trapped in Middle Jurassic Brent Group sandstones below 9500 ft TVSS in a highly-faulted reservoir that has undergone considerable diagenetic modification. The field was declared commerical in 1974, began producing in 1978 from a single platform and has recovered 84 MMBBL of oil to date through primary and secondary recovery methods. Ultimate reserves are estimated to be 100 MMBBL of oil.
The Magnus Field, Block 211/7a, 12a, UK North Sea
Authors: Shepherd M. 
Published: April 2008

abstract
Magnus is the most northerly producing field in the UK sector of the North Sea. The oil accumulation occurs within sandstones of an Upper Jurassic submarine fan sequence. The combination trap style consists of reservoir truncation by unconformity at the crest of the easterly dipping fault block structure and a stratigraphic pinchout element at the northern and southern limits of the sand rich fan. The reservoir is enveloped by the likely hydrocarbon source rock, the organic rich mudstones of the Kimmeridge Clay Formation.
The Miller Field, Blocks 16/7B, 16/8B, UK North Sea
Authors: Rooksby S. K. 
Published: April 2008

Abstract
The Miller Oil Field is located on the western margin of the South Viking Graben in UKCS Blocks 16/7b and 16/8b. The oil is trapped in Upper Jurassic turbidite sands shed from the Fladen Ground Spur via the Brae complex submarine fan systems. The reservoir sands are of good quality with an average porosity of 16% and permeabilities occasionally in excess of 1 Darcy. The trap is formed within a subtle structural-stratigraphic combination. Overlying slow velocity Lower Cretaceous sediments produce a time flat which, after depth conversion, produces a 3-way dip closed feature. The trap is completed by stratigraphic pinchout of the reservoir sands to the northwest. The most recent (1985) seismic data allow the top reservoir reflector to be picked directly, which was not the case during the exploration and appraisal phase, when only the Top Kimmeridge Clay seismic pick could be made. The estimate of recoverable hydrocarbons is currently 300 MMBBL of oil and 570 BCF of gas. Development drilling commenced early in 1989. No results are yet available.
The Ninian Field, Blocks 3/3 & 3/8, UK North Sea
Authors: Van Vessem E. J. , Gan T. L. 
Published: April 2008

Abstract
The Ninian Field, located in the northern North Sea, lies in the East Shetland Basin on the west side of the Viking Graben. The field straddles Blocks 3/3 and 3/8 and is developed under a unitization agreement with Chevron UK Limited as operator. The structure is a westward tilted fault block. The estimated original oil-in-place contained in the marine-deltaic sandstones of the Middle Jurassic Brent Group, is 2920 MMBBL, of which an estimated 35 to 40% is recoverable. The oil is a paraffinic-naphthenic type with an API gravity of 36°. The field development consists of three fixed platforms with a total of 109 drilling slots. The natural drive in the field is negligible so that water flooding is required. The production of the Ninian Field started in December 1978 and reached a peak of 315 000 BOPD in the summer of 1982. At the end of 1988 over 811 MMBBL had been produced.
The Thistle Field, Blocks 211/18a and 211/19, UK North Sea
Authors: Williams R. R. , Milne A. D. 
Published: April 2008

Abstract
The Thistle Oilfield is located on the western margin of the North Viking Graben in UK Blocks 21l/18a and 211/19. The field was discovered in 1973 by the Halibut Group, operated by the Signal Oil Company. The discovery well was drilled in 1973 and the field was declared commerical before completion of the first two appraisal wells. The extension of the field into Block 211/19 was confirmed by well 211/19-1 drilled in 1974 and the field was subsequently unitized.
The Middle Jurassic Brent Group forms the oil-bearing reservoir sequence. The structure is an easterly dipping, rotated fault block divided into five main compartments by N-S normal faults and E-W cross faults. A 60 slot drilling and production platform was installed in 1976 and production began in February 1978. It is now connected by pipeline to Sullom Voe and production through this link commenced in late 1978. Due to only limited aquifer support, injection wells have been drilled on the east flank of the field, in order to maintain reservoir pressure. In addition, several wells in partly isolated fault blocks are produced by gas lift completions. The current STOIIP is estimated at 794 MMBBL of which 396 MMBBL will ultimately be recovered. Cumulative production to the end of 1988 was 334 MMBBL from 34 production wells, with support from 13 injection wells.
The Balmoral Field, Block 16/21, UK North Sea
Authors: Tonkin P. C. , Fraser A. R. 
Published: April 2008

Abstract
The Balmoral oilfield operated by Sun Oil Britain Ltd, lies within UK blocks 16/21 b and 16/21c, 140 miles off the northeast coast of Scotland. The field was discovered by the drilling of well 16/21-1 in 1975. Andrew Formation sandstones of Late Palaeocene age form the reservoir, which is sealed by Lista Formation claystones. The sandstones are of submarine fan origin sourced from the north and west of the area. The trap is structural, formed by the differential compaction of Tertiary sediments over a Palaeozoic structural high.
The upper section of the reservoir consists of two units of consolidated sandstone (units U and M) of channel-fill origin separated by a channel abandonment claystone (unit SI). Porosities for these sandstone units range from 17-28% and permeabilities are up to 3300 md. The lower section of the reservoir consists of friable sandstones (Unit F), characterized by grain-coating clays which have prevented consolidation. This unit is mainly of submarine fan lobe origin. Porosities range from 20-28% and permeabilities are up to 700 md.
Balmoral came on stream in November 1986. Recoverable reserves are estimated to be 68 MMBBL of undersaturated 39.9° API oil, and annual production remains at the 35 000 BOPD plateau rate.
The oil is produced from 12 wells with reservoir pressure maintained by the injection of water through a further six wells. These are all tied into a floating production vessel (FPV), the first such purpose-built production facility to be used in the North Sea. Production in Balmoral is expected to continue until the year 2001.
The Beatrice Field, Block 11/30a, UK North Sea
Authors: Stevens V. 
Published: April 2008

Abstract

The Beatrice Field was discovered in 1976 in Block 1l/30a within the Inner Moray Firth Basin. The reservoir consists of multilayered Lower and Middle Jurassic sediments containing a STOIIP of 480 MMBBL of high wax crude oil. The reservoir sequence comprises 1100 ft of Hettangian (Lower Jurassic) to Callovian (Middle Jurassic) sandstones, siltstones and claystones. The Beatrice Field is co-sourced by a combination of Devonian and Jurassic rocks. The hydrocarbon trap comprises a tilted faultblock, the top of which is truncated by the main field boundary fault. The field has low energy, and the
P
i
of 2897 psi at 6500 ft TVSS, GOR 126 SCF/STBBL and
P
h
of 635 psi, together with the poor aquifer influx, necessitated the development of water injection from the start of production and use of electrical submersible pumps in all wells. Ultimate oil recovery is expected to be 146 MMBBL. The field has been developed with four platforms at three sites in 133 ft waterdepth. The crude is transported 42 miles by peline to the dedicated oil terminal at Nigg on the Cromarty Firth.
The Crawford Field, Block 9/28a, UK North Sea
Authors: YALIZ A. 
Published: April 2008

Abstract
The Crawford Field was discovered in 1975 in UK Block 9/28 and the first oil was produced in April 1989. The field has a complex structural history. The reservoir is located on a down-faulted, westward tilting faultblock along the western margin of the Viking Graben. The eastern margin of the faultblock is severely truncated at Base Cretaceous level. The main producing zones comprise Middle Jurassic (Brent Group equivalent) and Triassic (Skagerrak Formation) sandstones. The seal is formed by Cretaceous marls and limestones. Reservoir quality and thickness are extremely variable, and drainage areas are limited. The reservoir fluid is a medium gravity oil having a thin gas cap. Oil in-place is in the order of 130 MMBBL but recovery factors are expected to be low.
The Fulmar Field, Blocks 30/16 & 30/llb, UK North Sea
Authors: Stockbridge C. P. , Gray D. I. 
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 field is a partially eroded anticline with steeply dipping flanks formed by the withdrawal of deeper Zechstein salt. The reservoir consists of thick Upper Jurassic, shallow marine, very bioturbated sandstones of the Fulmar Formation and deep marine turbidites interbedded within the Kimmeridge Clay Formation. Seal to the reservoir is provided by the Kimmeridgian shales in the west and Upper Cretaceous chalks which unconformably overlie the Fulmar Formation in the east.
The reservoir section has been subdivided into seven members and 14 reservoir units. Reservoir quality is generally excellent, although there are lower-energy sandstone facies found in the eastern part of the field. The Fulmar oil is highly undersaturated and a secondary gas cap has been created by gas injection.
Two exploration wells were drilled before the field was declared commercial. Development is from a 36 slot steel platform and a six slot template. Oil evacuation is by a floating storage unit and gas evacuation is via the Fulmar gas pipeline. Total STOIIP is 815 MMBBL and ultimate recovery is 462 MMBBL oil and 264 BCF gas. Production started in 1982 and 319 MMBBL oil and 121 BCF gas have been produced by year-end 1988. A total of 80 BCF gas has been re-injected for conservation purposes.
The Kittiwake Field, Block 21/18, UK North Sea
Authors: Glennie K. W. , Armstrong L. A. 
Published: April 2008

Abstract

Kittiwake was discovered by well 21/18-2 within a 7th Round block, part of Production Licence P351. Highly undersaturated oil is present in the Fulmar Formation and Skagerrak Formation reservoir sequences; 70
MMBBL
of reserves is in Fulmar sandstones whereas oil in the Skagerrak is mostly immovable. The field will be developed from a single 16-slot platform with initially 5 producing and 5 water-injection wells. Solution gas is removed via the Fulmar Field pipeline to St Fergus and, as from September 1990, the oil is loaded onto tankers from a single-buoy mooring.
The Maureen Field, Block 16/29a, UK North Sea
Authors: Cutts P. L. 
Published: April 2008

Abstract
The Maureen Oilfield is located on a fault-bounded terrace in Block 16/29a of the UK Sector of the North Sea, at the intersection of the South Viking Graben and the eastern Witch Ground Graben. The field was discovered in late 1972 by the 16/29-1 well, and was confirmed by three further appraisal wells. The reservoir consists of submarine fan sandstones of the Palaeocene Maureen Formation, deposited by sediment gravity flows sourced from the East Shetland Platform. The Palaeocene sandstones, ranging from 140 to 400 ft in thickness, have good reservoir properties, with porosities ranging from 18-25% and permeabilities ranging from 30-3000 md. Hydrocarbons are trapped in a simple domal anticline, elongated NW-SE, which was formed at the Palaeocene level by Eocene/Oligocene-aged movement of underlying Permian salt. The reservoir sequence is sealed by Lista Formation claystones. Geochemical analysis suggests Upper Jurassic Kimmeridge Clay shales have been the source of Maureen hydrocarbons. Estimated recoverable reserves are 210 MMBBL. Twelve production wells have been drilled on the Maureen Field. A further seven water injection wells have been drilled to maintain reservoir pressure.
The Tartan Field, Block 15/16, UK North Sea
Authors: Coward R. N. , Clark N. M. , Pinnock S. J. 
Published: April 2008

Abstract
Tartan Field lies 118 miles northeast of Aberdeen in UK Block 15/16 on the southern flank of the Witch Ground Graben. The Field consists of two major southerly-dipping rotated fault blocks, the 'Upthrown Block' to the south and the 'Downthrown Block' to the north. The primary reservoir comprises Oxfordian-Kimmeridgian shallow marine sandstone of the Piper Formation deposited during a regional marine transgression. The secondary reservoir consists of Volgian turbidites (the 'Hot Lenses') within the Kimmeridge Clay Formation. The accumulations have been sourced from maturation of the Kimmeridge Clay Formation below approximately 10000 ft in adjacent basins. The Piper Formation exhibits markedly different petrophysical properties within each block. A relatively homogeneous intergranular porosity system is present throughout the oil zone of the 'Upthrown Block'. Porosities are lower and more variable in the 'Downthrown Block' as a result of cementation and the presence of an intense compaction fabric. The trapping mechanism is a combination of structural and stratigraphic elements. The Field was discovered in December 1974 by the 15/16-1 well which penetrated 263 ft of Piper Formation sandstone full to base with oil. A further ten straight holes and three sidetracked holes delineated the structure. Tartan Field came onstream in January 1981 and is currently producing 30000 BOPD through eight platform producers, assisted by six subsea water injection wells. Ultimate recoverable reserves are currently estimated at 116 MMBBL of crude oil.
The Camelot Fields, Blocks 53/1a, 53/2, UK North Sea
Authors: Holmes A. J. 
Published: April 2008

Abstract
The Camelot Gas Fields (Camelot North, Northeast and Central-South) lie in Blocks 53/la and 53/2 in the Southern North Sea, some 30 miles (48 km) east of Great Yarmouth. Initial sub commercial discovery wells were drilled in 1967, 1969 and 1972. Further exploration and appraisal drilling was carried out in 1987 and 1988. This paper covers the Field history up to the 53/la-10 appraisal well in June 1988. The Lower Permian, Leman Sandstone Formation is the reservoir, with the gas accumulations trapped in tilted fault terraces. The Leman Sandstone Fm. in the Camelot area is 800 ft thick with a gas column up to 200 ft. Development of the fields will be in two phases. Phase I will consist of 5 wells deviated from the Camelot 'CA' platform to produce reserves from the Camelot North and Central-South Fields. Production commenced in October 1989. Phase II scheduled for 1991/92 will tie-in the Camelot Northeast Field. Gas is exported from the unmanned 'CA' gathering platform via pipeline to Amoco's Leman 'A' complex, from where the gas is transported to shore via the existing Amoco pipeline from Leman to Bacton. Total recoverable reserves for the Camelot Fields are estimated at 215 BCF.
The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea
Authors: Farmer R. T. , Hillier A. P. 
Published: April 2008

Abstract
The Clipper Gas Field is a moderate-sized faulted anticlinal trap located in Blocks 48/19a and 48/19c 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 Fm. is on average about 715 ft thick, laterally heterogeneous and zoned vertically with the best reservoir properties about the middle of the formation. Porosity is fair with a field average of 11.1%. Matrix permeability, however, is less than 1 millidarcy on average and is so low that some intervals in the field will not flow gas unless stimulated. Steep dipping zones of natural fractures occur in certain areas of the field; these commonly allow high flow rates to be achieved from large blocks of low-permeability matrix. Expected recoverable reserves from the most favourable part of the field are 558 BCF and Clipper Field is now being developed in conjunction with part of the adjacent Barque Gas Field. Later development of the remainder of Clipper Field will depend upon reservoir performance in the initial development area.
The Indefatigable Field, Blocks 49/18, 49/19, 49/23, 49/24, UK North Sea
Authors: Pearson J. F. S. , Youngs R. A. , Smith A. 
Published: April 2008

Abstract
The Indefatigable Field was discovered in June 1966 by the Amoco Operated Group well 49/18-1. The field is located 55 miles northeast of Great Yarmouth in the central part of the Southern North Sea Basin in water depths of 100 ft. The field lies in Blocks 49/18, 19 and 49/23 and 24. The reservoir section is Lower Permian Rotliegendes sandstones comprising a mixed sequence of aeolian and fluvial sediments at an average depth of 8500 ft subsea. Maximum reservoir thickness is in excess of 420 ft; however, the average pay thickness is of the order of 150 ft. The main reservoir trap is a complexly faulted NW-SE-trending anticlinal horst with a maximum vertical closure of 1300 ft. The field is approximately 17 miles long and 6 miles wide and has an areal extent of some 60 square miles. Recoverable reserves in the Field are estimated to be 4418 BCF of gas. The field is not unitized and is jointly operated by Amoco and Shell.
The Rough Gas Storage Field, Blocks 47/3d, 47/8b, UK North Sea
Authors: Stuart I. A. 
Published: April 2008

Abstract
The Rough Gas Field is operated by British Gas as the world's first offshore gas storage reservoir. This relatively small field (original reserves 366 BCF) is located on the western margin of the Southern North Sea Basin. The reservoir, the Rotliegendes Gp (Leman Sandstone Fm.) average thickness 95 ft, is developed in a basin-margin facies association in which aeolian and wadi-related fluvial processes have interacted. Small-scale dune and interdune sandstones, with generally excellent permeability, alternate with wadi facies sandstones with variable but mainly poorer permeability. The vertical distribution of these facies permits a three-fold zonation of the reservoir. Flow profiles obtained from Production Logging Tools show a very strong correspondence between sedimentary facies and productivity/injectivity. The Carboniferous subcrop includes several very low-permeability sandstone intervals which contact the Rotliegendes at the angular Base Rotliegendes unconformity. A small amount of gas from these sandstones seeps across the unconformity surface into the Rotliegendes. The Rough Field was discovered by Gulf in 1968, and was operated by Amoco on a conventional depletion basis with 6 development wells from 1975 until the early 1980s. In 1980 British Gas secured 100% ownership of the Field and its facilities, and converted it to storage mode. Excess summer supplies are injected into the reservoir, to be produced during the winter to meet the peak demand. Conversion to storage mode has necessitated the installation of substantial new facilities, and the drilling of 23 further wells. First injection of gas was achieved in 1985.