bluuebunny/crossref_metadata_2025 huggingface dataset:
The Kingfisher Field, Block 16/8a, UK North Sea
Authors: Spence Samantha , Kreutz Helge
Published: April 2008

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

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

The Scott Field straddles Blocks 15/21 and 15/22 on the southern flanks of the Witch Ground Graben in the Outer Moray Firth Basin, UKCS. The oil field is developed in the highly productive Upper Jurassic Humber Group sandstones of Oxfordian to Kimmeridgian age. The field was discovered in 1983, sanctioned in 1990, and produced first oil in 1993.

The field structure, effectively a large southwards tilted fault block, is compartmentalized into a series of four main pressure isolated fault blocks by mid to late Jurassic faulting. The Kimmeridge Clay Formation provides both the top seal and the source of the trapped hydrocarbons. Fluid contact, overpressure and compositional trends suggest that the trap was filled primarily from the north. Some trap-defining faults were already active during the deposition of the reservoir intervals. Well data indicate that the development of accommodation space was technically controlled during this period, with subsidence occurring more rapidly in the western areas of the field.

The Scott Field reservoir consists of two major sand packages, the Scott Sandstone Member and the Piper Sandstone Member, bounded above and below by marine flooding surfaces. The late Oxfordian Scott Sandstone Member consists of a westwards prograding marine shoreface sandstone overlain by aggradational and retrogradational back-barrier deposits. Above this, the Mid Shale is a regionally extensive flooding event separating the Scott Sandstone Member from the overlying Piper Sandstone Member. The early Kimmeridgian Piper Sandstone Member consists of stacked mass flow sandstones, overlain by a shoreface/back-barrier system. Lateral facies changes and thickness variations significantly affect reservoir distribution in both Scott and Piper intervals.

The best reservoir quality occurs within the coarsest grained, highest energy facies, particularly the shoreface and proximal washover deposits. At the crest of the field, 10400 ft TVDss, multi-Darcy permeabilities and porosities of 20% are common. However, reservoir quality declines progressively downflank due to increased quartz cementation and compaction.

The Scott Field currently produces from 23 wells supported by 20 water injectors. Current modelling is aimed at targeting bypassed oil to increase ultimate recovery. The field has presently produced 300 MMSTB of oil from forecast reserves of 440 MMSTB with an estimated ultimate recovery factor of c. 46%.
The Banff Field, Blocks 22/27a, 29/2a, UK North Sea
Authors: Evans N. , MacLeod J. A. , Macmillan N. , Rorison P. , Salvador P.
Published: April 2008

The Banff Field is an oil field with a small gas cap containing an estimated 300 MMB0 oil-in place. The structure straddles the boundary between blocks 22/27a and 29/2a in the West Central Graben area of UK Central North Sea. The field was discovered by well 29/2a-6 in 1991. Banff Field is a Steeply dipping raft of fractured Late Cretaceous and Danian Chalk on the flank of a salt diapir. Paleocene sands draped over the raft provide addtional reservoir potential. A vertical oil column of over 3000 ft is present within the reservoir sourced from the underlying upper jurassic Kimmeridge Formation shales. Hydrocarbon migration into the trap is believed to have started in the Eocene.

The highest reservoir productivity occurs in the Late Cretaceous Tor Formation, which is expected to yield most of the field's reserves. Chalk porosity ranges from 15% to 35% but matrix permeabilities are generally less than 5 mD. Drainage is achieved through extensive faulting and fracturing

Initial uncertainties over reservoir performance and connectivity led to a phased development. Phase i comprised a six month Early Production System (EPS), during which time 5 MMBo were produced and the viability of the field was confirmed. Phase 2 Production is by means of a Floating Production System and Offtake (FPSO) Vessel Named the Ramform Banff. First oil production was achieved on 30 January 1999 and ultimate reserves are expected to be in excess of 75 MMBO.
The Curlew Field, Block 29/7, UK North Sea
Authors: Eneyok G. , Bussink P. , Maan A.
Published: April 2008

abstract

In 1964, Block 29/7 was awarded as part of the first licencing round to Shell and Esso (UK). The Curlew area comprises a series of terraces that step down from the Western Platform into the West Central Graben. Exploration drilling started in 1977 but it wasn't until 1990 that well 29/7-4 successfully tested a 100 ft column of undersaturated volatile oil in the Upper Jurassic Fulmar Formation sandstones. Further exploration drillng, aided by 3D seismic data (acquired in 1991), yielded additional discoveries: Curlew C (1993, oil) and Curlew D (1994, condensate-rich gas). In Curlew D new technologies were succesfully applied to described and evaluate the isolated hanging wall compartment. Oil was discovered in what is now called Curlew D South in February 2000.

Hydrocarbon accumulations in the Curlew area occur in dip-closed faulted anticlinal structures. The producing Upper Jurassic Fulmar Formation is a heterogeneous mix of bioturbated shallow marine sandstones. barrier sandstones, and lagoonal/swamp deposits. The range in reservoir quality is reflected in the field porosity (5-27%) and permeability (0.001-800 mD). Reservoir compartments in the field (curlew B, D, and D South) are controlled by complex reservoir architecture, structure and fault geometry. Each reservoir compartment is characterized by a different fluid contact and a distinct fluid type. The reservoir heterogencity provieds potential for bypassed hydrocarbons in undrilled compartments, as was proven by the Curlew D South development.

Curlew B, D, and D South have since been developed. Evacuation of hydrocarbons from the Curlew area is via the Maersk Curlew FPSO, to which the producing wells have been tied back. Gas is fed nto the Fulmar Gas Line and oil is taken onshore by shuttle tankers. The initially-in-place volume in Curlew B at standard conditions is 24 MMSTB of oil and 25 BSCF of solution gas. Curlew B was developed via horizontal well 29/7-10y and came on stream in November 1997 at a rate of about 23 000 STB/D. The initially-in-place volume in Curlew D is 340 BSCF of gas and 100 MMSTB of condensate. Curlew D was developed via two vertical wells, 29/7-8z and 29/7-9, and started production in February 1998 with production rates up to 115 MMSCF/D of gas and 34 000 STB/D. Gas production from the field is constrained. however, by the facilities. Curlew D South is developed by the vertical well 29/7-11 which came on stream in March 2000 after a North Sea record-time tie back of the original appraisal well.
The Erskine Field, Block 23/26, UK North Sea
Authors: Coward R. N.
Published: April 2008

The Erskine Field is a high temperature, high pressure (HTHP), gas condensate accumulation located on the western margin of the East Central Graben. The field was discovered in 1981 by the 23/26a-3RE well and subsequently delineated by six appraisal wells. Development approval was granted in 1995 and to date five development wells have been drilled. In December 1997, Erskine Field became the first HTHP field in the UKCS to achieve production. Hydrocarbons are produced from three separate Jurassic reservoirs. In order of decreasing importance, these are: the Late Oxfordian Erskine Sandstone (Puffin Formation), the Middle Jurassic Pentland Reservoir, and the Late Oxfordian Heather Turbidite Reservoir.

The Erskine Sandstone is very fine to fine-grained highly bioturbated, shaley sandstone. The sandstones represent shallow marine progradational sequences, deposited predominantly in the offshore transition zone. Within the majority of the Erskine Sandstone, porosity is high (20-25%) but with relatively poor associated permeability (0.1-10mD). However, the tops of the coarsening upward sequences (E30 and E70 zones) have appreciably better permeability and are thought to be the major conduits for fluid flow. The E30 and E70 zones would not have been identified, had it not been for the extensive coring programme undertaken in the development wells.

The Pentland Reservoir is a regionally extensive sequence of interbedded sandstone, shales, coals and siltstones, deposited in a fluvial-lacustrine environment in a delta plain setting. Permeability in the Pentland reservoir (0.1 mD-1 D) is in general far superior to the values observed in the Erskine Sandstone. The main control on the observed variability in porosity and permeability characteristics is grain size, that in turn is controlled by facies.

The Heather Turbidite Reservoir occurs within two thin predominantly fine-grained turbidite sandstone beds in the Heather Shale Formation. This reservoir is restricted to the Alpha Terrace region in the SW of the field, and is drained by a single development well.

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

The Fife Field and its smaller satellite the Fergus Field are the southernmost of the cluster of oil fields within the UK Central North Sea. The Fife Field lies at the intersection of four blocks, 31/26a, 31/27a, 39/la and 39/2a. It is a small to moderate size offshore field with reserves of 48.3 MMSTB and is produced by five sub-sea wells through a Floating, Production, Storage, Offloading (FPSO) vessel. The field was discovered in 1991 and the first oil was produced in 1995. The Fergus Field, located in Block 39/2a, is a satellite located 5 km SE of the Fife Field. It is produced by a single well tied-back by a sub-sea flowline to the Fife Field infrastructure. The Fergus Field was discovered in 1994 and first oil was produced in 1996. Reserves are estimated as 11.3 MMSTB

The main reservoir interval in both fields comprises fine-grained, heavily bioturbated, shallow marine shelf sandstones of Upper Jurassic age. Significant volumes of chert and carbonate cements, both banded and nodular, occlude porosity and impart reservoir layering within an otherwise thick sandy, mud deficient reservoir interval. Sandstone porosity is in the range 19-31%. Permeabilities are low in the Fife Field reservoir sandstones, typically less than lOOmD. By contrast, better permeabilities (average 500 mD) are seen in the Fergus Field, where a more proximal shelf sandstone facies is present within the oil leg. Two thin intervals of pebbly, very coarse-grained sandstone are intercalated with the shelf sandstones in the crest of the Fife Field. These may represent submarine toes of fan deltas sourced from an active fault system located to the north of the field. The pebbly sandstones show permeabilities in excess of a Darcy and have caused early water breakthrough problems in production wells

A subsidiary reservoir is present within the Tor Formation of the Chalk Group in the Fife Field, but is not oil bearing within the Fergus Field. This comprises white to grey, intensely bioturbated, stylolitized chalk with an average porosity of 24.5% and an average air permeability of slightly less than a millidarcy. Both the Fife and Fergus Fields are defined by simple four-way dip closure at top Jurassic. An episode of structural inversion at the end of the Jurassic created both structures. The overlying Chalk oil pool in the Fife Field has a trap defined by dip closure on three sides and a probable diagenetic trapping element to the south
The Forties and Brimmond Fields, Blocks 21/10, 22/6a, UK North Sea
Authors: Carter A. , Heale J.
Published: April 2008

This paper updates the earlier account of the Forties Field detailed in Geological Society Memoir 14 (Wills 1991), and gives a brief description of the Brimmond Field, a small Eocene accumulation overlying Forties (Fig. 1).

The Forties Field is located 180 km ENE of Aberdeen. It was discovered in 1970 by well 21/10-1 which encountered 119 m of oil bearing Paleocene sands at a depth of 2131 m sub-sea. A five well appraisal programme confirmed the presence of a major discovery including an extension into Block 22/6 to the southeast. Oil-in-place was estimated to be 4600 MMSTB with recoverable reserves of 1800 MM STB. The field was brought onto production in September 1975. Plateau production of 500 MBOD was reached in 1978, declining from 1981 to 77 MBOD in 1999.

In September 1992 a programme of infill drilling commenced, which continues today. The earlier infill targets were identified using 3D seismic acquired in 1988. Acquisition of a further 3D survey in 1996 has allowed the infill drilling programme to continue with new seismic imaging of lithology, fluids and saturation changes. The performance of the 1997 drilling showed that high step-out and new technology wells, including multi-lateral and horizontal wells, did not deliver significantly better targets than drilling in previous years.

In line with smaller targets, and in the current oil price environment, low cost technology is being developed through the 1999 drilling programme. Through Tubing Rotary Drilling (TTRD) is currently seen as the most promising way of achieving a step
The Fulmar Field, Blocks 30/16, 30/11b, UK North Sea
Authors: Kuhn O. , Smith S. W. , Van Noort K. , Loiseau B.
Published: April 2008

The Fulmar Field is located on the southwestern margin of the Central Graben in Blocks 30/16 and 30/11b of the UK sector of the North Sea. The Fulmar Field was discovered 1975 and began producing in 1982. Currently (2000) the field produces at a rate of 8000 BOPD at a watercut above 90% mainly through the process of rinsing of residual oil. Total STOIIP is 822 MMBBL and ultimate recovery is 567 MMBBL of oil and 342 BSCF of wet gas. As of the end of 1999, 547 MMSTB of oil and 325 BSCF of wet gas had been produced. The high recovery factor (69%) of the field is thought to be linked to the combination of well density, large length of reservoir perforated, excellent reservoir quality, sweep by water injection, good pressure support and oil stripping from a secondary gas cap formed early in field life.

The Fulmar Field is a small triangular, partly eroded domal anticline with steeply dipping flanks, located on a fault terrace within the western margin of the South West Central Graben at a depth between 9900 and 11 500 ft TVDss. The field has been shaped by three major tectonic processes: (1) halokinesis, (2) syndepositional reactivation of Caledonian basement faults; and (3) syndepositional through post-depositional displacements along the nearby Auk Horst Boundary Fault. The reservoir consists of thick Upper Jurassic, shallow marine, very bioturbated sandstones of the Fulmar Formation overlain by the deeper marine Ribble Sands interbedded within the Kimmeridge Clay Formation. Reservoir seal is provided by the Kimmeridge Clay in the west and Upper Cretaceous chalks which unconformably overlie the Fulmar Formation in the east. The reservoir section has been lithostratigraphically subdivided into six reservoir units and 24 sub-units. Integration of bio- and lithostratigraphic data has led to a sequence stratigraphic model of the Jurassic succession in the Fulmar Field. In total four depositional sequences are identified, which progressively onlap Triassic basement towards the southwest. The older Jurassic sequences are characterized by rapid progradation of shoreface sands, whereas aggradation of thick sediment packages is typical of the younger intervals. This change of depositional architecture is linked to syndepositional reactivation of basement faults. Major transgressive intervals form intra-reservoir barriers or baffles to flow. Facies changes (Mersey-Clyde Sands) from proximal to distal facies are abrupt and are also linked to basement faults.
The Maureen Field, Block 16/29a, UK Central North Sea
Authors: Chandler Peter M. , Dickinson Barbara
Published: April 2008

abstract

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

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

The Barque Field is associated with some of the earliest gas discoveries in the southern North Sea. In the Sole Pit area the reservoir, the Rotliegend Group Leman Sandstone Formation of Lower Permian age, occurs between Carboniferous Coal Measures, which source the gas, and Zechstein evaporites which form an excellent seal. Primarily aeolian, the sandstone has generally very low permeability resulting from deep burial of the Sole Pit Trough. The deepest burial and hence the maximum diagenetic damage to the reservoir was achieved in the early Late Cretaceous prior to two phases of inversion in Late Cretaceous and Mid-Tertiary.

Compaction and diagenesis reduced reservoir permeability to such an extent that parts of the field would be non-productive were it not for the presence of effective natural fracture zones and well stimulation by hydraulic fracturing techniques. Though appraisal and evaluation have been relatively extensive, remaining uncertainties dictated a conservative development in conjunction with the adjacent Clipper Field. A selected initial area was developed for first gas in October 1990. Good reservoir performance from horizontal wells led to later development of the whole field.
The Corvette Field, Block 49/24, UK Southern North Sea
Authors: Hillier A. P.
Published: April 2008

abstract

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

The Guinevere Gas Field was discovered in January 1988 by the Mobil-operated well 48/17b-5. The field lies in the UK Sector of the Southern North Sea and occupies Block 48/17b. The field is located within the footwall of the Dowsing Fault Zone on the western flank of the Sole Pit Basin. Guinevere is a compressional northwesterly-trending fault block that comprises Early Permian Leman Sandstone Formation (Rotliegend Group) reservoir, sourced from the Carboniferous below and sealed by Later Permian Zechstein evaporates above.

The Guinevere Gas Field is estimated to contain 90 BCF of recoverable gas reserves and was brought on-stream in June 1993 using a single not-normally-manned minimum facilities platform. Field life is predicted to be 13 years. Gas and condensate are evacuated though the Lancelot Area Production System (LAPS) to the onshore Bacton gas terminal in East Anglia.
The Johnston Gas Field, Blocks 43/26a, 43/27a, UK Southern North Sea
Authors: Lawton David E. , Roberson Paul P.
Published: April 2008

abstract

The Johnston Field is a dry gas accumulation located within blocks 43/26a and 43/27a of the UK Southern North Sea. The discovery well was drilled in 1990 and after the drilling of one appraisal well in 1991, a development plan was submitted and approved in 1993. Initially two development wells were drilled from a four slot sub-sea template, with commercial production commencing in October 1994. A further horizontal development well was added to the field in 1997.

The field has a structural trap, fault bounded to the SW and dip-closed to the north, east and south. This field geometry has been established using high quality 3D seismic data, enhanced by seismic attribute analysis. The sandstone reservoir interval consists of the Early Permian, Lower Leman Sandstone Formation of the Upper Rotliegend Group. This reservoir consists of a series of interbedded aeolian dune, fluvial, and clastic sabkha lithofacies. The quality of the reservoir is variable and is principally controlled by the distribution of the various lithofacies. The top seal and fault bounding side seal are provided by the overlying clay stone of the Silverpit Shale Formation and the evaporite dominated Zechstein Supergroup.

The field has been developed using a phased development plan, with the acquisition of a 3D seismic survey allowing for the optimized drilling of a high deliverability horizontal well.

Current mapped gas initially-in-place estimates for the field are between 360 and 403 BCF, with an estimated recovery factor of between 60 and 75%.
The Murdoch Gas Field, Block 44/22a, UK Southern North Sea
Authors: Conway A. M. , Valvatne C.
Published: April 2008

The Murdoch Field was discovered in 1984 when gas was tested from the Murdoch Sandstone of the Westphalian B, Carboniferous in well 44/22-1. The field lies along an elongate NW-SE trending faulted ridge, clearly evident at Top Base Permian structural level. Six exploration and appraisal wells were drilled on the structure prior to commencing a joint development in 1992 with the adjacent Caister Field. The reservoir unit, the Murdoch Sandstone, is interpreted as a low sinuosity fluvial complex of lower Westphalian B age. It is around 120' thick and was deposited by a large NE-SW flowing braided river system in which channels stacked and amalgamated to form the sand package. Production commenced at the beginning of October 1993 making it the first Carboniferous development in the UK North Sea. The maximum deliverabihty of the field is currently about 180MMSCFD from six of the eight producers. Developed with a not-normally-manned platform facility, the gas is delivered to the Theddlethorpe Gas Terminal. Heterogeneity in reservoir quality combined with complex structural compartmentalization are the key control mechanisms on gas production in the Murdoch Field.
The Schooner Field, Blocks 44/26a, 43/30a, UK North Sea
Authors: Moscariello A.
Published: April 2008

The Schooner Field is Shell U.K.'s first Carboniferous gas development in the North Sea. The field was discovered in 1987 by well 44/26-2 and gas production began in October 1996 from four wells. In contrast to the majority of the fields in the Southern North Sea producing from the aeolian Leman Sandstones Formation (Rotliegend), Schooner targets the low net-to-gross, fluvial Upper Carboniferous Barren Red Measures and Coal Measures formations. The reservoir consists of discrete, low sinuosity fluvio-deltaic channels draining a swampy coastal floodplain evolving upwards into a highly aggrading, low gradient, distal fluvial fan, dominated by braided and anastomosing channels. In Schooner, like other Carboniferous fields, reservoir connectivity is one of the key subsurface uncertainties due both to channel lateral discontinuity and fault compartmentalization. Production data and reservoir properties distribution, together with a new stratigraphical subdivision driven mostly by chemostratigraphic techniques, have been used to reassess the volume of gas-in-place which currently is estimated at 29.98 Gm
3
(1059 BCF)
The West Firsby Oilfield, Development Licence 003, Lincolnshire
Authors: Bailey R. J.
Published: April 2008

The West Firsby Oilfield exemplifies the classic east Midlands oil play, sourced by early Namurian pro-deltaic shales. Stacked fluvio-deltaic sandstone reservoirs of latest Namurian to early Westphalian 'A' age are structured into a Variscan inversion anticline in the hanging wall of the northeastern boundary fault of the Dinantian-Namurian Gainsborough Trough. The Enterprise West Firsby-1 discovery well, drilled on a 'Top Westphalian 'A'' seismic depth closure, encountered oil-bearing sandstones at three levels. These are thought to represent the earliest Westphalian 'A' Sub-Alton/Crawshaw distributary channel and mouthbar sandstones (Reservoir Zone [RZ] 1), the stacked fluvial channel sands of the Namurian Rough Rock (RZ2) and an underlying high quality mouth-bar sandstone (RZ3). In the hanging wall setting, these units can be correlated over an area far larger than the West Firsby Field.

On acquiring operatorship of the Development Licence (DL 003) in 1991, Tullow Exploration put the WF-1 well into production from RZ2 and 3 disposing of produced water in the earlier-drilled and unsuccessful WF-2 step-out. Between 1992 and 1996, three new production wells (WF-4, -5 and -6) were drilled from the same surface site. The wells principally produce from RZ2 and involve high-angle/horizontal sections in these sandstones, approaching 170 m in length in WF-6. Strong aquifer support, coupled with the injection of produced water into RZ2 of WF-2, promotes early natural flow from such wells at rates up to 800BOPD, and when this declines jet-pumping can maintain production at rates of several hundred BOPD/well. As of 1st January 1999, the West Firsby Oilfield had produced 0.97 MMBBL of an estimated 13 MMBBL OIIP, maintaining an average annual rate during 1998 of 345 BOPD from four wells. Remaining recoverable reserves are estimated at around 1.03 MMBBL.
The Malory Field, Block 48/12d, UK North Sea
Authors: O'Brien R. E. , Lappin M. , Komlosi F. , Loftus A.
Published: April 2008

The Malory Field straddles blocks 48/12d and 48/12c of the UK Sector of the Southern North Sea on the western margin of the Sole Pit Trough. The field is located within an upthrown part of the Dowsing Fault Zone and was discovered by the Mobil operated well 48/12d-9 in early 1997.

The Malory Field is a small fault-bounded horst structure with expected recoverable reserves of 75 BSCF. The reservoir consists of a 249 ft-section of Lower Permian, Rotliegendes Leman Sandstone Formation sandstones, is sourced from the Carboniferous Westphalian Coal Measures below, and is sealed by overlying Upper Permian Zechstein evaporites.

Reservoir quality is generally good with an average porosity of 14.7% and core permeabilities (Kh) between 0.2 and 1651 mD. This preservation of reservoir quality is attributed to a combination of the structure being located on a broad palaeostructural high, with a lower maximum burial depth than adjacent structures and associated lower compactional porosity loss, the presence of an early hydrocarbon charge and the preferential precipitation of chlorite over illite cements.
The Viking Field, Blocks 49/12a, 49/16, 49/17, UK North Sea
Authors: Riches Hugh
Published: April 2008

First production from the Viking Fields began in 1972 and at its peak a total of 13 platforms produced at rates up to 950 MMSCF/D from 20 wells. This supplied around 10% of the United Kingdom's natural gas requirements, 27 years on, that rate had declined to approximately 40 MMSCF/D. However following an extremely successful infield drilling programme in the mid 1990s, significant volumes of new gas have been discovered and new technology has facilitated the development of accumulations previously considered non-commercial. This has led to three new developments within the Viking area: the Vampire Field on the eastern margin; Kx to the south of the Philips' Alison Field; and four previously non-producing fields, captured within the Phoenix Development.

The major change since Morgan (1991) has primarily been the re-negotiation of the gas sales contract and the removal of the Gas Levy in 1992. This provided favourable marketing conditions for the development of additional Viking gas production and initiated an appraisal programme for remaining reserves. This programme, which will be the focus of this paper, began with the acquisition of a 3D seismic survey in 1993 and has concluded in the development of the Viking Extensions in 1998, now known as the Phoenix Development.

The Leman Sandstone Formation forms the reservoir and consists of aeolian and fluvial sandstones, which are interbedded in the north of the area with silty shales deposited within a sabkha environment. Hydrocarbons were sourced from the underlying Carboniferous Westphahan coals and carbonaceous shales, and migration into the Rotliegendes Group probably occurred during the Late Cretaceous to Early Tertiary.

The average daily production from the original Viking A and B fields and associated satellites had declined to 196 MMSCF/D by March 1989, peaking to over 300 MMSCF/D with seasonal demand. By October 1999, this had further reduced to around 40 MMSCF/D. Production from the Phoenix wells is currently at around 290 MMSCF/D, with further development wells planned. Cumulative production to date is approximately 2880 BCF.
The Kimmeridge Bay Oilfield, Dorset, UK Onshore
Authors: Gluyas J. G. , Evans I. J. , Richards D.
Published: April 2008

The Kimmeridge Oilfield is the oldest commercial discovery of petroleum in the Wessex Basin. The field was discovered in 1959. The discovery well was completed for production and that same well continues to produce today, more than forty years after discovery.

More than three million barrels of oil have been produced. Oil is trapped in fractured, Middle Jurassic, Cornbrash limestones in an anticline. The anticline is a product of Alpine inversion tectonics. Moreover, the Kimmeridge accumulation is unusual insofar as it is the only inversion structure to contain a commercial quantity of petroleum and the only producing field in the hanging wall of the Purbeck Disturbance.
3D Seismic Technology: Are We Realising Its Full Potential?
Authors: Davies Richard J. , Stewart Simon A. , Cartwright Joseph A. , Lappin Mark , Johnston Rodney , Fraser Scot I. , Brown Alistair R.
Published: April 2008

Three-dimensional (3D) seismic data have had a substantial impact on the successful exploration and production of hydrocarbons. Although most commonly acquired by the oil and gas exploration industry, these data are starting to be used as a research tool in other Earth sciences disciplines. However despite some innovative new directions of academic investigation, most of the examples of how 3D seismic data have increased our understanding of the structure and stratigraphy of sedimentary basins come from the industry that acquired these data. The 3D seismic tool is also making significant inroads into other areas of Earth sciences, such as igneous and structural geology. However, there are pitfalls that parallel these advances: geoscientists need to be multidisciplined and true integrators, and at the same time have an ever-increasing knowledge of geophysical acquisition and processing. Notably the utility of the 3D seismic tool seems to have been overlooked by most of the academic community, and we would submit that academia has yet to take full advantage of this technology as a research tool. We propose that the remaining scientific potential far exceeds the advances made thus far and major opportunities, as well as challenges, lie ahead.
Seismic Geomorphology: Imaging Elements of Depositional Systems from Shelf to Deep Basin Using 3D Seismic Data: Implications for Exploration and Development
Authors: Posamentier Henry W.
Published: April 2008

3D seismic data can play a vital role in hydrocarbon exploration and development especially with regard to mitigating risk associated with presence of reservoir, source, and seal facies. Such data can afford direct imaging of depositional elements, which can then be analyzed using seismic stratigraphy and seismic geomorphology to yield predictions of lithologic distribution, insights to compartmentalization. and identification of stratigraphic trapping possibilities. Benefits can be direct, whereby depositional elements at exploration depths can be identified and interpreted, or they can be indirect, whereby shallow-buried depositional systems can be clearly imaged and provide analogues to deeper exploration or development targets. Examples of imaged depositional elements from both shallow and deep sections are presented.
Initial Deformation in a Subduction Thrust System: Polygonal Normal Faulting in the Incoming Sedimentary Sequence of the Nankai Subduction Zone, Southwestern Japan
Authors: Heffernan A. S. , Moore J. C. , Bangs N. L. , Moore G. F. , Shipley T. H.
Published: April 2008

3D seismic data from the Nankai margin provide detailed imagery documenting the onset of deformation at an active sediment-dominated accretionary prism, including a previously unmapped network of normal faults. The Nankai margin off southwest Japan is characterized by active subduction, seismogenesis, and a large accretionary prism with fold-and-thrust belt structure. Imbricate thrusting is the dominant structural style of the outer 20 km of the prism. This structural domain develops at the prism toe, where an incipient imbricate thrust displays significant along-strike variability in dip, offset, and development of hangingwall anticlines.

Compressional deformation is preceded by normal faulting that initiates seaward of the trench axis. Seismic data in this area reveal a complex, intersecting pattern of normal faults within the incoming hemipelagic sediments. Underlying the faulted section is a high-amplitude reflector interpreted as representing oceanic basement. This reflector contains elongate horsts and grabens oriented perpendicular to the margin interpreted as relict spreading centre fabric.

Analysis of the orientation of normal faults within the Shikoku basin sequence shows a correlation between fault geometry and basement structure. This faulting is notably similar to layer-bound compaction faults, documented in the North Sea and elsewhere, attributed to both hydrofracturing and volumetric contraction of fine-grained sediments. Mapped normal faults may thus be the result of a combination of differential compaction of sediments above irregular, dipping oceanic basement and compactional dewatering seaward of the toe of the accretionary prism.
Tertiary Inversion in the Faroe-Shetland Channel and the Development of Major Erosional Scarps
Authors: Smallwood John R.
Published: April 2008

At the shallowest point of the Faroe-Shetland Channel, between the Faroe Islands and the Shetland Isles, the sea bed is deformed into a series of major scarps and hollows. The cuspate scarps, or 'Judd Falls', are up to 15 km in length and are over 200 m high. Interpretation of 3D seismic data and high resolution 2D seismic data shows that the scarps are part of a larger series of structures that are partly buried. A second series of buried asymmetric hollows has been mapped 50 km to the northwest. Both sets of hollows are interpreted to have a deep-water erosional origin, postulated to be associated with the initiation of the high-energy bottom currents of the south-flowing Northern Component Water from the Norwegian-Greenland Sea into the North Atlantic. Present-day measurements presented here show that deep-water current velocity can peak at over 0.8ms
-1
. Both erosional complexes are positioned directly above Tertiary inversion structures, and this study has identified two periods of compressional deformation, latest Ypresian and late Lutetian, in addition to previously documented phases. Compression in the area has been linked to changes in the interaction between the Mid-Atlantic Ridge and the Iceland mantle plume. Enhanced plume activity also concentrated deep-water flow in the Faroe-Shetland Channel by physically impeding deep-water currents elsewhere. Where enhanced deep-water flow encountered the partial barriers of the inversion structures, accelerated turbulent erosional currents carved the scarps into the sea bed.
3D Seismic Analysis of the Geometry of Igneous Sills and Sill Junction Relationships
Authors: Hansen Dothe MØller , Cartwright Joseph A. , Thomas David
Published: April 2008

We use 3D seismic data in a novel way to describe the three-dimensional geometry of a number of igneous bodies intruded into the upper crust as well as to define and classify sill junction relationships. Igneous intrusions were emplaced into Upper Cretaceous and Palaeocene sediments of the Faroe-Shetland Basin during the Early Palaeogene and in many cases they adopt remarkable saucer- or trough-shaped geometries that are 2-8 km in diameter and have a vertical relief of several hundred metres. Individual intrusions are interlinked and form highly interconnected sill complexes. Three geometrically distinctive classes of sill junctions are defined and illustrated with examples from seismic data. Each class implies a specific evolutionary sequence of events and these are discussed for each of the classes of junction. The class of junction often changes along the line of junction with one class evolving in space to another. This has significant implications for spatial reconstruction of sill complexes based on two-dimensional outcrop and this is illustrated with reference to an example from a 3D seismic dataset.
Seismic Characteristics of Large-Scale Sandstone Intrusions in the Paleogene of the South Viking Graben, UK and Norwegian North Sea
Authors: Huuse Mads , Duranti Davide , Steinsland Noralf , Guargena Claudia G. , Prat Philippe , Holm Kristine , Cartwright Joseph A. , Hurst Andrew
Published: April 2008

Post-depositional remobilization and injection of sand can significantly change the geometry of deepwater clastic reservoirs. Features associated with these processes are particularly well developed in the lower Paleogene of the South Viking Graben of the UK and Norwegian North Sea. Seismic scale sandstone intrusions can be grouped in two classes. Class 1 comprises low-angle (20-40 degrees) tabular sandstone intrusions emanating from steep-sided
in situ
sand bodies within the Balder Formation. The intrusions may be 5-30+m thick and crosscut 120-250+m of compacted stratigraphic section. They terminate at an unconformity at the top of the Frigg interval where they may have extruded onto the palaeo-seafloor. Class 2 comprises conical sandstone intrusions that emanate some 50-300+m upward from distinct apexes located 400-700+m above the nearest depositional sand body. The conical intrusions may have been sourced from underlying sand bodies by clastic blow out pipes. Both types of intrusions seem to adopt their particular geometry independently of (but occasionally exploiting) polygonal faults within the encasing mudstones. Sandstone intrusions may be highly porous and permeable and are thus important both as reservoirs and as plumbing within thick mudstone sequences.
4D Seismic Imaging of an Injected C02 Plume at the Sleipner Field, Central North Sea
Authors: Chadwick R.A. , Arts R. , Eiken O. , Kirby G.A. , Lindeberg E. , Zweigel P.
Published: April 2008

C0
2
produced at the Sleipner field is being injected into the Utsira Sand, a major saline aquifer. Time-lapse seismic data acquired in 1999, with 2.35 million tonnes of C0
2
in the reservoir, image the C0
2,
plume as a number of bright sub-horizontal reflections. These are interpreted as tuned responses from thin (< 8 m thick) layers of C02 trapped beneath intra-reservoir shales. A prominent vertical 'chimney' of C0
2
appears to be the principal feeder of these layers in the upper part of the reservoir. Amplitude-thickness scaling for each layer, followed by a layer summation, indicates that roughly 80% of the total injected C0
2
is concentrated in the layers. The remainder is interpreted to occupy the feeder 'chimneys' and dispersed clouds between the layers. A prominent velocity pushdown is evident beneath the C0
2
accumulations. Velocity estimation using the Gassmann relationships suggests that the observed pushdown cannot readily be explained by C0
2
present only at high saturations in the thin layers; a minor proportion of low saturation C0
2
is also required. This is consistent with the layer volume summation, but significant uncertainty remains.
Towards an Automated Strategy for Modelling Extensional Basins and Margins in Four Dimensions
Authors: White Nicky , Haines John , Jones Stephen , Hanne Detlef
Published: April 2008

There is a need for quantitative models which predict the structural and thermal evolution of sedimentary basins and margins in three dimensions. Although many different, two-dimensional algorithms exist, most of them are forward models which assume that rifting is instantaneous. We outline a three-dimensional optimization strategy which calculates spatial and temporal variations in strain rate. This approach is a generalization of an existing two-dimensional inversion algorithm which already tackles three issues of interest to the hydrocarbon industry. First, the residual misfit between observed and predicted basin geometries allows competing structural and stratigraphic interpretations to be objectively tested. Secondly, the animated evolution of basin and margins can be produced using the strain rate tensor. Thirdly, spatial and temporal variations of strain rate control basal heatflow, which in turn constrains the temperature and maturation histories of the sedimentary pile. Here, we present a small selection of two-dimensional results and show how our three-dimensional formulation is a logical extension of earlier work. A three-dimensional algorithm is under development.