bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fossil contourites: type example from an Oligocene palaeoslope system, Cyprus
Authors: Stow Dorrik A. V. , Kahler Gisela , Reeder Mike 
Published: April 2008

Abstract
As part of a wider programme on the recognition and decoding of contourite sediments, we propose the adoption of part of the Lefkara Formation on Cyprus as the first in a series of type examples of fossil contourites in ancient series exposed on land. A clear case can be made for interpreting these mainly Oligocene age sediments as carbonate-rich contourites. They combine faint structures due to current action with pervasive bioturbation, typically show cyclic grain size alternation, and have compositional differences from the more easily identifiable calciturbidites. One particularly diagnostic contourite facies is a lenticular, thin-bedded calcarenite-cacisiltite from which the finer bioclastic material and terrigenous clays have been winnowed away. This facies is a well developed condensed unit, which occurs at the same stratigraphic interval throughout Cyprus. Variations in thickness and rates of sedimentation of the contourite units, as well as the presence of widespread hiatuses and alongslope palaeocurrent trends are consistent with drift development on a lower slope apron in the closing Tethys ocean.
Lessons from oil and gas exploration in and around Britain
Authors: Hardman R. F. P. 
Published: April 2008

Abstract
After 35 years, exploration in and around Britain has reached a mature stage. Pure oil and gas exploration has with certain exceptions given way to the search for small fields close to infrastructure and maximizing recovery from existing fields. To examine the lessons of 35 years of exploration before many of the major players leave the stage is opportune. Lessons learned can be applied elsewhere.
An examination of the history suggests that lessons can be grouped under four headings: organization, technical skills, personal qualities and tactics. Successful companies optimize all of these. Unsuccessful companies, on the other hand, often fail because of a particular flaw in one of them.
It is concluded that successful exploration companies would field a team captained by a technically competent open-minded manager closely linked to skilled geoscientists, all of whom would have a deep understanding (through relatively long service) of the area being explored. Both managers and geoscientists would be able to take sensible risks and would not confuse the primary concern of the technical merits of a prospect with the secondary concern of the economics of success. Finally, luck appears to play an important part but there is no doubt that successful companies work hard for their luck.
Other lessons centre on the quirkiness of individual behaviour. This is something that no amount of study can eliminate.
The Douglas Oil Fields, Block 110/13b, East Irish Sea
Authors: Yaliz A. , McKim N. 
Published: April 2008

Abstract
The Douglas Field, on stream in February 1996, is the first oil field to be developed in the East Irish Sea Basin, with an estimated STOIIP of 202 MMBBL. The field structure consists of three tilted fault blocks formed during extensional faulting in Triassic-early Jurassic times, and later readjusted by contractional movements during Tertiary inversion. The oil is trapped in the Triassic Ormskirk Sandstone Formation, which comprises moderate to high porosity aeolian and fluvial sandstones. The reservoir depth is shallow (2140 ft) with a maximum oil column of 375 ft. The reservoir can be divided into several laterally extensive units based on vertical facies variations. The reservoir quality is principally controlled by primary depositional processes, and authigenic clay minerals are not important. However, bitumen is formed extensively in specific areas of the field causing significant permeability reduction. The hydrocarbon filling history of the field was complex, with the occurrence of at least two phases of oil generation and migration. The field contains a relatively 'dead' oil with a low GOR (170scf/bbl). Pressure maintenance is achieved through sea water injection, and to date ten production and six injection wells have been drilled. The crude is light (44° API) and contains high levels of H2S (0.5mol%) and mercaptans, which are removed during processing offshore.
The Hamilton and Hamilton North Gas Fields, Block 110/13a, East Irish Sea
Authors: Yaliz A. , Taylor P. 
Published: April 2008

Abstract

The Hamilton and Hamilton North Fields are located in Block 110/13a in the East Irish Sea, and contain 627 BCF and 230 BCF GIIP, respectively. First gas was produced from the Hamilton North Field in December 1995. The fields are being developed with four producers in the Hamilton Field and three in the Hamilton North Field. The Hamilton Field structure consists of a N-S trending horst block with dip closure to the north and south, while the Hamilton North structure is defined by major faults to the north and west with dip closure to the east and south. The gas is trapped in the highly productive Triassic Ormskirk Sandstone Formation. The reservoir comprises high porosity aeolian and fluvial sandstones. Depth to reservoir is shallow (2300-2600 ft) with the gas-water contact being at 2910 ft in the Hamilton Field and 3166 ft in the Hamilton North Field. Reservoir quality is principally controlled by primary depositional processes and no significant diagenetic effects are observed. The hydrocarbon filling history was complex, with at least two phases of hydrocarbon generation. Hamilton North gas is sweet whereas the Hamilton gas contains up to 11OOppm H
2
S, which is removed during processing at the Douglas complex and at the Point of Ayr gas terminal. Cumulative gas production to May 1999 was 180 BCF and no water-cut has been observed to date.
The Lennox Oil and Gas Field, Block 110/15, East Irish Sea
Authors: Yaliz A. , Chapman T. 
Published: April 2008

Abstract

The Lennox Field, located in blocks 110/15 and 110/14, was the second oil field to be developed in the East Irish Sea Basin. It contains 184 MMBBL of oil in-place within a 143 ft thick oil rim overlain by a large gas cap up to 750 ft thick. The GIIP is estimated to be 497 BCF. The field came on stream in February 1996, and it is now being developed with seven horizontal oil producers, including two multi-lateral wells and two crestal gas injectors. Production from the field can be divided into two distinct phases; the oil rim development phase, and the gas cap blow-down phase. The latter phase is currently anticipated to commence in 2004. The field structure consists of a roll-over anticline formed in the hanging wall of the Formby Point Fault during extensional faulting in Triassic-early Jurassic times, and later readjusted by contractional movements during Tertiary inversion. The oil and gas are trapped in the highly productive Triassic Ormskirk Sandstone Formation. The reservoir comprise high porosity aeolian and fluvial sandstones occurring at a shallow depth (
c.
2500 ft) with a maximum gas column of 750 ft above an oil rim of 143 ft. The reservoir quality is principally controlled by primary depositional processes as no significant adverse diagenetic effects are observed. The hydrocarbon filling history was complex, with at least three phases of oil and gas generation. The field contains a light, saturated oil (45° API) with a GOR of 650 SCF/BBL. The crude contains high levels of H
2
S (0.1 mol%) and mercaptans (450 ppm), which are removed during processing at the Douglas complex. Water cut from the field is currently around 2-5%, and no free gas production has been observed to date. Gas production from Lennox is anticipated to start in 2004.
The Armada development, UK Central North Sea: The Fleming, Drake and Hawkins Gas-Condensate Fields
Authors: Stuart I. A. 
Published: April 2008

abstract
In 1994 the Armada partnership sanctioned the simultaneous development of the Fleming, Drake and Hawkins Gas-condensate Fields by means of shared facilities; the overall project was called the Armada Development. The operator is BG International (formerly British Gas). The development was interesting because the component fields are not only separate accumulations, but are of completely different geological type.
The Fleming Field is a Palaeocene, Maureen Formation high-density turbidite reservoir, sourced from the north but pinching out eastwards against the N S Utsira/Jaeren High and Hawking-Varg Ridge, and therefore forming a 20 km long, continuous, but very narrow reservoir. The drake Field is an Upper Jurassic. Fulmar Formation, shallow marine, shore-face reservoir, with excellent reservoir quality in a compact fault block. The Hawkins Field reservoir is poorer quality Fulmar Formation, typical of a more distal setting; the trap is formed by closure over a salt dome, and the structure is consequently quite heavily faulted.
The challenge was to develop these disparate reservoirs from a single surface site. to capture the askward shape of Fleming and the distance between Drake and Hawkins. This was achieved by means of extended each drilling; although the high cost of such wells meant that every one had to be designed for maximum yield. Overall eifht wells were drilled, five to Fleming, two to Drake and one to Kawkins (these numbers being approximately proportional to gas-in-place). These wells are capable of delivering the project design peak rate of 450 mmscfd off-platform (equivalent to about 480 mmscfd reservoir gas), and up to 24000 BOPD condensate. Armada began production on schedule in October 1997.
The Birch Field, Block 16/12a, UK North Sea
Authors: Hook J. , Abhvani A. , Gluyas J. G. , Lawlor M. 
Published: April 2008

Abstract

The Birch Field is an oil field located in Block 16/12a on the UK Continental Shelf (UKCS) and is part of the well-established 'Brae Trend'. Birch produces an undersaturated volatile oil from the Brae Conglomerate, a locally thick conglomeratic unit within the Late Jurassic Brae Formation. The reservoir was deposited as a small submarine fan in the hanging wall of the main fault bounding the western side of the South Viking Graben. The current estimate for oil in place is about 70MMSTB with expected ultimate oil reserves of 30MMSTB. The field was brought on stream in September 1995 as a phased waterflood subsea development, tied back to Marathon's Brae 'A' platform in neighbouring Block 16/7a. During Phase I the discovery and both appraisal wells were re-completed as two oil producers and one water injection well. Phase II comprised a third oil production well and a second water injection well drilled and completed in 1996-1997. Oil production peaked at
c.
28 000 BOPD in the second half of 1996. The field is currently in decline and production in June 1999 was
c.
7000 BOPD with a water-cut of
c.
40%. Cumulative oil production to end June 1999 was 21 MM STB and remaining oil reserves are estimated as 9MMSTB.
The Central Brae Field, Blocks 16/07a, 16/07b, UK North Sea
Authors: Fletcher Keith J. 
Published: April 2008

abstract
The Central Brae Oilfield is the smallest of three Upper Jurassic fields being developed in UK, Block 16/07a. The field was discovered in 1976 and commended production in September 1989 through a sub-sea template tied back to the Brae 'A' platform in the South Brae Oilfield. The field Stooip is 244 MMBBLs, and by May 1999 cumulative exports of oil and NGL reached 44 MMBBLs.
The Central Brae reservoir is a proximal submarine fan sequence, comprising dominantly sand-matrix conglomerate and sanstone with a minor mudstone units. The sediments were shed eastwards off the Fladen Ground Spur and were deposited as a relatively small and steep fan at the margin of the South Viking Graben. Mudstone facies border the submarine fan deposits to the north and south, forming stratigraphic seals. The structure is a faulted anticline developed during the latest Jurassic and early Cretaceous, initially formed as a hangingwall anticline during extension but subsequently tightened during compressional phases. The western boundary of the field is formed by a sealing fault, whilst to the east, there is an oil-water contact at 13426 ft TVDss. The overlying seal is the Kimmeridge Clay Formation, which also interdigitates with the coarser facies basinwards and provides the source of the hydrocarbons.
The South Brae Field, Blocks 16/07a, 16/07b, UK North Sea
Authors: Fletcher Keith J. 
Published: April 2008

Abstract
The South Brae Oilfield lies at the western margin of the South Viking Graben, 161 miles NE of Aberdeen. Oil production began in July 1983 from a single platform located in 368 ft of water. The field STOOIP is 795 MMBBLs, and in May 1999, cumulative exports of oil and NGL reached 265 MMBBLs. The reservoir lies at depths in excess of 11 800 ft TVDss, has a maximum gross hydrocarbon column of 1670 ft, and covers an area of approximately 6000 acres.
The reservoir consists of Upper Jurassic Brae Formation sandstones and conglomerates deposited as submarine fan complexes that are downfaulted against tight sealing rocks of probable Devonian age at the western margin of the field. The other field margins are constrained by a combination of structural dip and stratigraphic pinchout.
The Brent Field, Block 211/29, UK North Sea
Authors: Taylor S. R. , Almond J. , Arnott S. , Kemshell D. , Taylor D. 
Published: April 2008

Abstract
The Brent Field was the first discovery in the northern part of the North Sea, and is one of the largest hydrocarbon accumulations in the United Kingdom licence area. There are two separate major accumulations: one in the Middle Jurassic (Brent Group reservoir) and one in the Lower Jurassic/Triassic (Statfjord Formation reservoir). The Brent Field lies entirely within UK licence Block 211/29 at latitude 61°N and longitude 2°E; the adjacent Brent South accumulation extends into Block 3/4A. The water depth is 460 ft. The Brent Field discovery well was drilled in 1971, and was followed by six further exploration and appraisal wells. Seismic data over the Brent Field has been acquired in four separate vintages. The latest acquisition in 1995 allowed detailed mapping of the complex eastern margin of the field for the first time
The Brent Field is developed from four fixed platforms (Alpha, Bravo, Charlie, Delta) installed between 1975 and 1978. Production commenced in 1976 and, for the first 22 years of field life, the platforms provided production, water injection and gas injection facilities for both the Brent and Statfjord Formation reservoirs. The Brent South accumulation is produced via the Brent Alpha platform, through sub-sea tie-backs and extended reach wells. In 1992, the decision was taken to depressurize the Brent Field to recover an additional 1.5 TSCF of gas and 34 MMSTB of oil, extending the field's life by 5-10 years. In January 1998, water injection into the main field was stopped and depressurization of the field initiated. As of January 2000, a total of 220 platform wells and three sub-sea wells (173 producers, 50 water injectors) have been drilled in the Brent Field.
The original oil/condensate-in-place is currently estimated at 3.8 MMMSTB, and the estimated original wet gas-in-place is 7.5 TSCF. Total ultimate recovery for all reservoirs is expected to be 1988 MMSTB oil and condensate and 6000 BSCF gas. Cumulative oil and net gas production, as of 1st January 2000, was 1875 MMSTB oil and 4196 BSCF gas
This paper summarizes the current understanding of the field based on acquisition of new 3D seismic data, 130 new wells, detailed structural and sedimentological modelling, development of the complex crestal part of the field and finally, the initiation of an extensive brown field re-development project to depressurize the reservoir
The Deveron Field, Block 211/18a, UK North Sea
Authors: Brown A. M. , Milne A. D. 
Published: April 2008

Abstract
Cumulative oil production at the end of 2000 was 15.4 MMBO, which for a STOIIP of 61.3 MMBO, represents a recovery to date of 25%. Deveron shares facilities on the Thistle Alpha platform and has been on production since 1984, from two (originally three) deviated platform wells. The performance of these wells has been steady, subject to well and plant uptimes. Field management activity continues to focus on monitoring and maintaining the two production wells, and denning field and production enhancement opportunities.
The Dunbar, Ellon and Grant Fields (Alwyn South Area), Blocks 3/8a, 3/9b, 3/13a, 3/14, 3/15, UK North Sea
Authors: Ritchie J. S. 
Published: April 2008

Abstract
The Dunbar, Ellon and Grant oil and gas fields (also known as the Alwyn South area) are located in the southeastern part of the East Shetland Basin, approximately 140 km E of the Shetland Islands. Most of the accumulations lie in Blocks 3/9, 3/14 and 3/15, which are parts of Licence P090 operated by Total Oil Marine pic (33.33%) with Elf Exploration UK PLC as sole partner (66.67%). Ellon was discovered in 1972, Dunbar in 1973 and Grant in 1977. Dunbar consists of a number of generally N-S trending, westerly dipping Mesozoic fault blocks with variable amounts of crestal erosion. Reservoir is provided by fluvial, deltaic and shallow marine sandstones of the Middle Jurassic Brent Group, Lower Jurassic Statfjord Formation and Upper Triassic Upper Lunde Formation. The Brent oil composition of Dunbar varies with depth and evolves from volatile oil at the base of the column to gas condensate at the top without a discontinuity of composition. In addition there is a small gas accumulation within a Paleocene submarine fan reservoir in a compactional structure.
Ellon consists of two westerly dipping fault blocks with gas condensate contained within the Brent Group. Grant is one westerly dipping fault block with gas condensate in the Brent Group. In both the Ellon panels and also in Grant, thin waxy oil 'rims' are found below the gas. The depth of the shallowest structural crest within the Alwyn South complex is 3100 m TVDSS, with the deepest proven hydrocarbon at around 3800 m TVDSS. Sealing for the Alwyn South accumulations is provided by various combinations of Cretaceous, Upper Jurassic (Heather and Kimmeridge Clay Formations) and Lower Jurassic (Dunlin Group) mudstones. The source rock for the hydrocarbons is the Upper Jurassic Kimmeridge Clay Formation, which is mature and adjacent to the fields.
These accumulations are being developed from a tender-assisted minimally manned fixed platform with a total of 28 well slots located over the Dunbar Field, in a water depth of 145 m. The Ellon and Grant Fields are produced as sub-sea satellites to Dunbar from a well-head cluster located between Ellon and Grant, in a water depth of 135 m. First oil and gas production from Dunbar and Ellon was in December 1994 and gas production commenced from Grant in July 1998. The time lag between discovery and development reflects the complex geology (structure, compartmentalization, reservoir thickness variations, dia-genesis and differing hydrocarbon compositions) with a total of 28 exploration and appraisal wells being drilled in the Alwyn South area between 1971 and 1998. Total oil and gas initially in place is in the order of 850 MMBBL and 2.62 TCF respectively, with the current estimate for ultimate recoverable reserves being 200 MMBBL liquids and 1.28 TCF gas.
The Kingfisher Field, Block 16/8a, UK North Sea
Authors: Spence Samantha , Kreutz Helge 
Published: April 2008

Abstract

The Kingfisher Field is located in the South Viking Graben, Block 16/8a, with a minor extension into Block 16/8c. Block 16/8 was initially awarded in June 1970 to Shell and Esso, with the Kingfisher discovery well 16/8-1 spudded in 1972. The well tested high H
2
S oil at marginal rates from Upper Jurassic Brae Formation sandstones. Subsequent appraisal well 16/8a-4 (1984) tested gas/condensate from better quality Brae Formation sandstone reservoirs. This well also discovered the deeper Middle Jurassic Heather Formation sandstone gas/condensate accumulation at near-HPHT conditions. The Brae and Heather Formation sandstones contain stacked hydrocarbon accumulations in separate combinations of stratigraphic and structural traps. Production by natural aquifer drive commenced from a sub-sea satellite to Marathon's Brae B platform in 1997, initially from the Brae reservoirs. To date, three production wells have been completed and a fourth well is planned to be on stream in 2000. The Brae Formation sandstones at Kingfisher are interpreted as distal deposits of the Brae/Miller fan-apron system and range in quality from excellent to very poor across the field. The Heather Formation reservoir consists of medium quality sands deposited within a submarine incised valley. The most recent volumetric estimate (1998) for the total field predicts an ultimate recovery of 41.2 MMBBL of pipeline liquids and 280 BCF of dry export gas. Regional reservoir architecture and connectivity as well as hydrocarbon composition are key to understanding the production performance of the critical gas/condensate below dewpoint. Advances in sub-sea and horizontal drilling technology have enabled field development.
The Balmoral, Glamis and Stirling Fields, Block 16/21, UK Central North Sea
Authors: Gambaro M. , Currie M. 
Published: April 2008

Abstract
The Balmoral Oilfield is a mature asset in its final phase of production. Associated with the Balmoral development have been the less significant Glamis and Stirling Fields. Each field is different from the perspective of geology and many other issues. Balmoral is a typical Paleocene oilfield with good water drive from a large regional aquifer. Interestingly this was not recognized at the start of the development when water injection facilities were commissioned. Glamis is a smaller field of Late Jurassic age containing somewhat lighter oil than Balmoral. Water injection has been necessary to maximize recovery in this field. Stirling is one of the few fields in the North Sea to produce commercially from the naturally fractured Devonian Sandstone. This field is developed by a single horizontal well.
Balmoral oil recovery has significantly exceeded original expectations, whilst Glamis and Stirling have produced as much as expected.
The Britannia Field, Blocks 15/29a, 15/30, 16/26, 16/27a, 16/27b, UK North Sea
Authors: Hill P. J. , Palfrey A. J. 
Published: April 2008

abstract
The Britannia Field is located 140 miles NE of Aberdeen at the southeast end of the Witch Ground Graben, on the southern flank of the Fladen Ground Spur. Gas and condensate are trapped in Lower Cretaceous (Aptian) deepwater, marine sandstones in a combined stratigraphic/structural trap that straddles four UKCS blocks. Reservoir quality varies from west to cast across the field. The principal reservoirs in the west (Blocks 15/29a, 15/30) arc in clean, blocky, high-density turbidite sands. The principal reservoirs in the east (Blocks 16/26, 16/27a, 16/27b) are in fine-grained sandstones and unusual shurried facies that have a high mud content and show gravity-driven structuring. The bulk of the field's reserves lies in the east and is produced via a 36-slot platform. A 14-slot sub-sea template tied back to the platform via a nine-mile flowline bundle produces the western area. Reserves are being developed by pressure depletion and are estimated at 3 TCF gas together with 131 MMBOE condensate and natural gas liquids. Britannia came on-stream in August 1998 and is expected to haave a field life in the order of 30 years.