bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Brent Field, Block 211/29, UK North Sea
Authors: Struijk A. P. , Green R. T. 
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 field lies entirely within UK licence Block 211/29 at latitude 61°N and longitude 2°E. The water depth is 460 ft. The discovery well was drilled in 1971, and six further exploration and appraisal wells were drilled. Seismic data over the Brent Field has been acquired in three separate vintages. The latest acquisition is a 3-D grid recorded in 1986. Reprocessing of the entire 1986 3-D seismic data set was initiated in 1989.
The original oil/condensate-in-place, estimated on 1/1/89, is 3500 MMBBL, and the estimated original wet gas-in-place is 6700 TCF. Oil production is now in the decline phase. Average production in 1988 was 334,000 BOPD, with gas sales remaining at the plateau rate of 500 MMSCFD.
The field is being developed from four fixed platforms, each providing production, water injection and gas injection facilities for both Brent and Statfjord Formation reservoirs. Gas injection is distributed to achieve an intermediate oil rim development in some reservoir units. The platforms were installed between 1975 and 1978. Production commenced in 1976. The slump faulted crestal areas of both reservoirs have yet to be developed.
These crestal areas contain about 5% of the recoverable reserves. Appraisal drilling was carried out in the crest during 1988 and 1989.
The Brent Field is located approximately 100 miles north-east of the Shetland Islands and 300 miles NNE of Aberdeen (Fig. 1). The discovery well location is at latitude 61°05'53.87" North longitude 1°41'30.H" East. The water depth is 460 ft
The field comprises two distinct reservoirs, the Brent Group and the Statfjord Formation, which are of Middle Jurassic and Lower Jurassic/Triassic age respectively. The reservoirs occur in a westerly dipping tilted fault block in a fault controlled unconformity trap (Fig. 2).
The size of the hydrocarbon bearing area is approximately 10 miles from north to south and 3 miles from east to west (Fig. 3).
The reservoirs are in turn divided into seven separate reservoir units; four cycles in the Brent Group reservoir and three units in the Statfjord Formation reservoir. Laterally two major east-west orientated faults divide the field into three separate production areas. A fourth area is the north-south orientated crestal part of both reservoirs, which is faulted and has a series of down faulted slump blocks overlain by 'Reworked Sediment'. This area still has to be developed.
The Shell/Esso joint venture North Sea oilfields are named after water and waterside birds. The Brent Field is named after the Brent goose.
The Hutton Field, Blocks 211/28, 211/27, UK North Sea
Authors: Haig D. Brian 
Published: April 2008

Abstract
The Hutton oil field is situated in the East Shetlands Basin in the UK North Sea on the western side of the Viking Graben. It straddles UK Blocks 211/27 and 211/28. The field was discovered in July 1973 by the Conoco well 211/28-la and is operated by Conoco (UK) Limited. The structure comprises a series of southwesterly dipping tilted fault blocks. The reservoir sandstones are Middle Jurassic in age and were deposited as a result of deltaic progradation across the Hutton area. The oil bearing Brent Group sandstones vary in thickness from 150 ft to 380 ft with average porosities of 22% and permeabilities of 500-2000 md in the producing zones. Original recoverable reserves have been estimated at 190 MMBBL, of which the field has produced 107 MMBBL to date. The field is developed via a tension-leg platform, the first of its kind in the world.
The Osprey Field, Blocks 211/18a & 211/23a, UK North Sea*
Authors: Erickson John W. , Van Panhuys C. D. 
Published: April 2008

Abstract

The Osprey Oilfield is located 180 km northeast of the Shetland Islands in Blocks 211/23a and 211/18a in the UK sector of the northern North Sea. The discovery well 211/23-3 was drilled in January 1974 in a water depth of 530 ft. The trap is defined at around 8500 ft TVSS by two dip and fault closed structures, the main 'Horst Block' and the satellite 'Western Pool'. The hydrocarbons are contained in reservoir sandstones belonging to the Middle Jurassic Brent Group which was deposited by a wave-dominated delta system in the East Shetlands Basin. The expected
STOIIP
and ultimate recovery are estimated at 158
MMBBL
and 60
MMBBL
of oil respectively, which represents a recovery factor of 38%. The 'Horst Block' contains 85% of the reserves with an
OOWC
about 150 ft shallower than in the 'Western Pool'. Reservoir quality is excellent, with average porosities varying from 23-26% and average permeabilities varying from 35-5300 md. The development plan envisages eleven satellite wells, six producers and five water injectors, closely clustered around two subsea manifolds. First production is expected in late 1990/early 1991. The wet crude oil will be piped to the Dunlin 'A' platform for processing and from there to the Cormorant Alpha platform into the Brent System pipeline for export to the Sullom Voe terminal.
The Claymore Field, Block 14/19, UK North Sea
Authors: Harker S. D. , Green S. C. H. , Romani R. S. 
Published: April 2008

Abstract
The Claymore Field is located in UK North Sea Block 14/19 on the southwest margin of the Witch Ground Graben. The principal structure is a southerly tilted and truncated fault block. The field is divided into three producing areas. Major production is from Upper Jurassic paralic sandstones of the Sgiath Formation and turbidite sandstones of the Claymore Sandstone Member of the Kimmeridge Clay Formation in the downflank Main Area. Minor production is from Permian carbonates of the Halibut Bank Formation and Carboniferous sandstones of the Forth Formation in the crestal Central Area. The Northern Area is a northerly plunging nose, extending graben wards from the Claymore tilt block. Production in the Northern Area is from Lower Cretaceous turbidite sandstones of the Valhall Formation.
A small amount of oil was recovered on a wireline test in 1972 from Permian carbonates in the crestally located 14/19-1 well, in what is now termed the Central Area. In 1974 the Main Area was discovered by the southerly downdip well 14/19-2, and the Northern Area was discovered by the northerly downdip well 14/19-6A. Initial oil in place was 1452.9 MMBBL with currently estimated ultimate proved recovery of 511.0 MMBBL of oil. A 36-slot steel platform was installed in 1977. Two subsea water-injection templates were added in 1981 and 1985. Cumulative production to 6 July 1988 was 322.9 MMBBL of oil and daily production was 75 000 BOPD of oil from 28 producers, supported by 16 injectors.
The Clyde Field, Block 30/17b, UK North Sea
Authors: Stevens D. A. , Wallis R. J. 
Published: April 2008

Abstract
The Clyde Field, which was discovered in 1978, is located on the SW edge of the North Sea Central Graben. The reservoir is developed with Late Jurassic shallow marine sands of the Fulmar Sand Formation. An estimated 408 MMBBL of oil is present (Annex B), of which 154 MMBBL is considered recoverable.
The structure of the Clyde Field takes the form of a rotated Jurassic fault block, truncated at its crest by a major unconformity. Oil is retained within a combination trap, sourced from Late Jurassic Kimmeridge Clay thermally matured in the highly productive basinal lows, adjacent to the field.
Reservoir sand quality is highly variable, ranging from excellent with permeabilities in excess of Id, to poor with permeabilities of less than 1 md. The principal control on reservoir quality appears to be original depositional texture, although strong diagenetic effects are also present.
Production is from a single, centrally located, platform provided with thirty slots. Aquifer support is insufficient to maintain reservoir pressure at the current plateau production rate of 50 000 BOPD and so a programme of water injection has been implemented.
The Forties Field, Block 21/10, 22/6a, UK North Sea
Authors: Wills J. M. 
Published: April 2008

Abstract
The Forties Field is located 180 km (112 miles) ENE of Aberdeen, predominantly in UK Licence Block 21/10. It was discovered in 1970, when an exploration well encountered hydrocarbons in Palaeocene sandstone within an anticlinal structure. Four appraisal wells confirmed the existence of a major oilfield, with an area of approximately 90 sq km (35 sq miles) at a depth of approximately 2000 m (6500 ft). The reservoir occurs in thick Late Palaeocene sandstones deposited in two major sand-rich submarine fan sequences.
The field has been producing oil since September 1975. Stock Tank Oil Initially in Place (STOIIP) has been calculated as 4343 MMBBL, and original reserves estimated as 2470 MMBBL, representing an overall recovery of 57%. The field came off plateau production of 500 000 BOPD in 1981, and by mid-1989 production had declined to about 250 000 BOPD. After fourteen years production, the field has produced more than 2 billion STB. Remaining reserves are about 500 MMBBL which includes recovery via artificial lift. Field life has been projected to extend beyond the year 2000.
Water injection into the aquifer commenced in 1976, and continues at the present day at an average rate of 390 000 BWPD. There is also a significant contribution to pressure support from the underlying aquifer.
At present there are 103 available wells in the field, 81 producers and 22 injectors.
The Scapa Field, Block 14/19, UK North Sea
Authors: McGann G. J. , Green S. C. H. , Harker S. D. , Romani R. S. 
Published: April 2008

Abstract
The Scapa Field is located in UK North Sea Block 14/19 in the Witch Ground Graben, 112 miles northeast of Aberdeen. The field was discovered in 1975 by the 14/19–9 well which tested 32° API crude from the Scapa Sandstone Member of the Early Cretaceous Valhall Formation. The field is a combination structural/stratigraphic trap situated in a NW–SE trending syncline. Updip limit to the NE is by onlap termination of the reservoir sands onto the Claymore tilt block, and to the southwest by fault closure and/or sand pinch-out into tight conglomerates associated with the Halibut Shelf boundary fault. Two thinly bedded, fine- to medium-grained turbidite sand units, in partial pressure communication, form the oil–bearing zone within the Scapa Sandstone Member.
Original oil in place was 206 MMBBL. In 1984, prior to development, a long-term production test was conducted via a deviated well drilled from the Claymore platform. Subsequent wells were thus drilled in a dynamic reservoir-pressure environment. Field development utilizes an integrated production/injection subsea template system tied back to the Claymore platform. Template production commenced in 1986 from currently estimated proved ultimate recoverable reserves of 63 MMBBL and averaged 28 000 BOPD in June 1988 from four production wells supported by four injection wells.
The Leman Field, Blocks 49/26, 49/27, 49/28, 53/1, 53/2, UK North Sea
Authors: Hillier A. P. , Williams B. P. J. 
Published: April 2008

Abstract
Discovered in 1966 and starting production in 1968, Leman was the second gas field to come into production in the UK sector of the North Sea. It is classified as a giant field with an estimated ultimate recovery of 11 500 BCF of gas in the aeolian dune sands of the Rotliegend Group. The field extends over five blocks and is being developed by two groups with Shell and Amoco being the operators. Despite being such an old field development drilling is still ongoing in the field with the less permeable northwest area currently being developed.
Granite magmatism
Authors: Atherton Michael P. 
Published: April 2008

AbstractRead’s two presidential addresses to the Geological Society (1948, 1949) heralded the end of the coherent rearguard action by the ‘granitizers’ against the ‘magmatists’. They were the distillation of his thoughts on the genesis of granite and culminated in his concept of the ‘Granite Series’. In this, he identified a continuity from metamorphic through migmatitic rocks to granite. Although he was wrong on granitization, the general idea remains intact and granites are produced by high-temperature metamorphism leading to partial melting. However the role of migmatites is still contentious. Not all granites belong to the granite series as he presented it; this particularly applies to Cordilleran (Andean) type granites. The genesis of this type will be discussed in the context of the earlier, classic work of Nockolds (1940) on the Garabal Hill complex where he demonstrated fractional crystallization was a major process in producing the diversity present and was similar to that seen in volcanic rocks, which had clearly been liquids. He also proposed that the source was basaltic with the implication, strongly supported by modern isotopic studies, that granites of this type are essentially mantle derived. Nockolds contribution was a geochemical confirmation of Bowen’s belief in the importance of closed-system fractional crystallization in the differentiation of plutonic rocks. Most authorities today would accept this but would not necessarily follow Bowen in the belief that major granitic batholiths formed by differentiation of basalt or that the system was closed. Recent models of the generation of the two main types of granite are presented, incorporating many of the ideas of Nockolds and Read. The discussion focuses on high-level differentiation, partial melting and intrusion in an extensional regime, high-T/low-P metamorphism associated with the magmatism, and the relation of granite to the plate tectonic setting.
Wave-form sheeted contourite drift on the Barra Fan, NW UK continental margin
Authors: Knutz Paul C. , Jones E John W. , Howe John E. , Van Weering Tjeerd J. C. , Stow Dorrik A. V. 
Published: April 2008

AbstractThe lithology of a 30 m long piston core (MD95-2006) and high-resolution, seismic profiles from the lower Barra Fan, Rockall Trough, reveal a sheeted drift form with internal sediment waves deposited over the last glacial-interglacial cycle. Deposition of these mainly fine-grained deposits was controlled by a combination of downslope and alongslope transport mechanisms that interacted with the positive topography created by debrite lobes on the lower fan. The core penetrates a small field of sediment waves (wavelength approx. 1 km, height 3-6 m), which onlap a debrite lobe dated to the last glacial maximum. The sedimentary sequence shows: (1) silty-muddy contourites deposited during the mid-Devensian (Marine Isotope Stage 3), (2) glacimarine hemipelagites and sandy turbidites deposited between 26 and 18 C14 ka BP, followed by a short phase of erosion and redeposition by bottom currents, and (3) glacimarine hemipelagites and silty-muddy contourites representing the glacial to Holocene transition. On the distal fan edge, a drift sequence with upslope-migrating sediment waves (wavelengths approx. 3 km, height 15-30 m) onlaps the tongue of a previous slide event (pre-Devensian?). These bedforms were probably generated by decelerating, low-density glacigenic turbidity currents, but pirated by contour-following bottom currents on the distal part of the drift.
Eastern New Zealand Drifts, Miocene-Recent
Authors: Carter Lionel , McCave I. Nicholas 
Published: April 2008

AbstractSediment from New Zealand passes into the north-flowing SW Pacific deep western boundary current (DWBC) to form widespread drifts. South of 49¼S, where the DWBC is reinforced by the Antarctic Circumpolar Current, drifts are small and, in the case of Campbell 'skin' Drift, reduced to a veneer over oceanic sediments. North of 49¼S deposition prevails with (1) Chatham Terrace Drifts - 350 km long and 320 m thick deposits around eastern Chatham Rise at 3000 m depth, (2) Chatham Deep Drift - 400 m thick, 300 km long ridge around the 4500-5000 m deep rise base, (3) Louisville Moat Drift -400 m of sediment within an isostatic depression along Louisville Seamount Chain and (4) Rekohu Drift - a 250 km long, 480 m thick ridge of Oligocene to Recent sediment. These drifts are sparsely surveyed, but two others have sufficient detail to be case studies. North Chatham Drift plasters northern Chatham Rise at 2000-4500 m depth. Drilling recovered 587 m of nannofossil ooze/chalk with cyclical amounts of terrigenous detritus and reworked subantarctic microfossils. Deposition has been almost continuous since the early Miocene. Hikurangi Fan-drift is a 300 km-long lobe, developed down-current of Hikurangi Channel/Fan through redirection of turbidity current plumes by the DWBC at 4850->5500 m depth. Seismically, the drift core comprises 200-360 m of probable Miocene palaeo-drift formed prior to the Pleistocene inception of Hikurangi Channel when 400 m of fan-drift accumulated.
The Foinaven Field, Blocks 204/19 and 204/24a, UK North Sea
Authors: Carruth A. G. 
Published: April 2008

Abstract
The Foinaven Field was discovered in 1992 and is estimated to hold up to one billion barrels of oil, with the current development expecting to recover 250 million barrels. BP Amoco is the operator of the field, holding a 72% interest with Shell UK as partner. The Foinaven structure is a faulted anticline and the trapping mechanism has elements of stratigraphic pinch-out, fault and dip closure. The field is divided into five fault/stratigraphical segments with varying oil-water and gas-oil contacts. The reservoir is Paleocene in age and comprises channelized, silici-clastic turbidites, with three main oil-containing sandstone intervals. Reservoir rock varies in character from thinly interbedded sandstones to massive channel sandstone. The reservoir is good quality, fine to medium grained, with 20-30% porosity, and permeability of 500-2000 mD. The hydrocarbons are from a mixed source of Middle and Upper Jurassic mudstones. Reservoir oil is sweet with an API gravity of 26 degrees, with some wax content and relatively low viscosity. Field development was sanctioned in October 1994. Development drilling began a month later with the first oil being produced in November 1997 through the Petrojarl Foinaven floating production installation (FPSO), which is leased from and operated by Golar-Nor Offshore. Current daily production averages 80 MBOPD and cumulative oil production to end October 1999 is 50MMBBL.
The East Brae Field, Blocks 16/03a, 16/03b, UK North Sea
Authors: Branter Stephen R. F. 
Published: April 2008

Abstract
The East Brae gas condensate field is the most northern of the four Upper Jurassic fields operated by Marathon Oil UK Limited in the UK North Sea. The field lies at the western margin of the South Viking Graben in UK Blocks 16/03a and 16/03b. The field was discovered in 1980 and commenced production in December 1993 from the East Brae platform. Recoverable reserves are estimated as 242 MMBBL of condensate and 1530 BSCF of sales gas.
The Ivanhoe, Rob Roy and Hamish Fields, Block 15/21, UK North Sea
Authors: Harvey M. A. , Currie S. 
Published: April 2008

Abstract
The Ivanhoe, Rob Roy and Hamish Fields lie in the Moray Firth of the UKCS in Block 15/21 and contain undersaturated oil trapped in the prolific Upper Jurassic Piper reservoir in tilted fault block traps. The fields were brought on stream in 1989 and since then the reservoir model has undergone several revisions with changes to the calculated oil in place volumes. The two main areas of uncertainty in the geological model are the position of the faults and the distribution of permeability. Improvements in the quality of the seismic data and the well ties brought about greater confidence in the seismic pick at top reservoir and the placement of the major bounding faults to the fields. The reservoir is generally sand-prone with a high net to gross ratio, porosity and permeability, which suggest that the reservoir would behave in a fairly homogeneous manner to fluid flow. Detailed reservoir description shows that this is not always the case. Improvements to the geological model permit a better understanding of the connection between the injector and producer wells and the degrees of influence from faults and heterogeneities in the reservoir to the fluid flow. Based on the current model the present recoverable reserves are estimated to be 187 MMBBL.
The Pierce Field, Blocks 23/22a, 23/27, UK North Sea
Authors: Birch Philip , Haynes Jamie 
Published: April 2008

Abstract
The Pierce Field contains oil and gas in Palaeocene Forties Sand and fractured Chalk, draped around the flanks of a pair of Central Graben salt diapirs. Whilst the two diapirs constitute a single field containing over 387 MMSTB AND 125 BCF, it took almost 25 years, and several advances in seismic, drilling and production technology, for the field to be brought into production. Many appraisal wells were drilled on the field. Data from these wells were interpreted to suggest the field was highly segmented both in terms of petroleum distribution and pressure variance. On the basis of this interpretation an economic development required a floating production system with long reach horizontal wells to penetrate the many reservoir segments. The results of development drilling have indicated that few pressure seals exist within the field, with concentric faults being more likely to seal than radial faults. The various reservoir pressures and oil-water contacts have been re-interpreted as a single, highly tilted oil-water contact, facilitated by the location of the field in the low permeability toe of the Forties submarine fan, a major conduit for the transport of basinal fluids away from the deep Central Graben
Palaeocene reservoir depositional patterns closely resemble those predicted by analogue models. The greatest reservoir thickness and net/gross are located in areas of flow velocity reduction (depletive flow), on the 'lee' side of the diapirs, but porosity and permeability are optimized in areas of increased flow velocity (accumulative flow), towards the crests of the diapirs
Strontium residual salt analysis has been used to study the charge history of the field. Interpretation suggests that South Pierce was filled before North Pierce, from a local Upper Jurassic source kitchen. Oil and gas subsequently spilled into North Pierce to form a composite trap with a single, tilted oil-water contact. The South Pierce gas cap has since been breached, and the escape of gas is currently leading to the retreat of the tilted water contact, once again isolating the two diapir structures