bluuebunny/crossref_metadata_2025 huggingface dataset:
The Captain Field, Block 13/22a, UK North Sea
Authors: Pinnock S. J. , Clitheroe A. R. J. , Rose P. T. S.
Published: April 2008

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

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

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

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

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

The Boulton Field was discovered in 1984 when gas was tested from the Lower Ketch Unit, Carboniferous Westphalian C/D, in well 44/21-2. Following appraisal drilling in 1990, the Boulton 'B' structure was delineated and a trap confirmed by a combination of up-dip seal against basal Permian shales, and salts and lateral seal against sealing faults and impermeable Westphalian C sediments. A second structure was drilled in the same year, Boulton 'F', with gas discovered in the deeper Murdoch Sand Interval of the Westphalian C/D. The two separate structures collectively form the Boulton Field.

Current deliverability from the 'B' structure, Lower Ketch Sands is approximately 100 MMSCFD from a single producer. Developed with a minimal platform facility, the gas is delivered to Theddlethorpe Gas Terminal via offshore compression at the nearby Murdoch Field. The reservoir in Boulton 'B' comprises a series of channel sands deposited in a braided stream complex flowing predominantly from north to south across an Upper Carboniferous alluvial plain. Sandbody connectivity within the complex fluvial architecture of the Westphalian C is a key control on gas production.
The Camelot Fields, Blocks 53/1a, 53/2, UK North Sea
Authors: Karasek R. M. , Hunt J. R.
Published: April 2008

The group of gas accumulations known as the Camelot Fields straddle Blocks 53/1a and 53/2 of the UK Sector of the Southern North Sea on the southern margin of the Sole Pit Trough. The Camelot North Field was discovered in 1967 and development commenced from the Camelot A platform in 1989 (wells Al to A5). The Camelot Northeast Field came on-stream from the B platform (53/2-7 well) in 1992. The Cador accumulation, in the north of Block 53/1a, was subsequently developed through the A6 horizontal well in 1993. The current estimate of gas initially in place (GIIP) for the field is 280 billion cubic feet. Ultimate recovery factors are expected to be as much as 90% and since more than 80% of the GIIP has already been recovered, the Camelot Fields have proven to be prolific producers.

This paper focuses on field history after 1988 and, in particular, on the recent exploratory drilling on the southern field margin beneath the South Leman Graben. In this area depth conversion is a major challenge with large velocity contrasts, low relief structures and thin hydrocarbon columns. Recent well results, following mapping of the new 3D seismic data set, indicate that fault reactivation occurred in late Cretaceous to early Tertiary times. Fault movements associated with this event resulted in trap readjustments and/or gas leakage and have exerted an important additional control on hydrocarbon spill points.
The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea
Authors: Sarginson M. J.
Published: April 2008

The Clipper Gas Field is a moderate-sized faulted anticlinal trap located in Blocks 48/19a, 48/19c and 48/20a within the Sole Pit area of the southern North Sea Gas Basin. The reservoir is formed by the Lower Permian Leman Sandstone Formation, lying between truncated Westphalian Coal Measures and the Upper Permian evaporitic Zechstein Group which form source and seal respectively. Reservoir permeability is very low, mainly as a result of compaction and diagenesis which accompanied deep burial of the Sole Pit Trough, a sub basin within the main gas basin. The Leman Sandstone Formation is on average about 715 ft thick, laterally heterogeneous and zoned vertically with the best reservoir properties located in the middle of the formation. Porosity is fair with a field average of 11.1%. Matrix permeability, however, is less than one millidarcy on average. Well productivity depends on intersecting open natural fractures or permeable streaks within aeolian dune slipface sandstones. Field development started in 1988. 24 development wells have been drilled to date. Expected recoverable reserves are 753 BCF.
The Gawain Field, Blocks 49/24, 49/29a, UK North Sea
Authors: Osbon R. A. , Werngren O. C. , Kyei A. , Manley D. , Six J.
Published: April 2008

The Gawain Field is located on the Inde shelf in the Southern North Sea, 85 km NE of the Norfolk coast. Gawain was discovered in 1970 by well 49/29-1 and a total of nine wells have been drilled on the structure. Gas is produced from the Leman Sandstone Formation of Early Permian age. The reservoir section is comprised predominantly of stacked aeolian dune sands possessing excellent poroperm characteristics. The structure is a complex NW-SE trending horst block with a common gas-water contact at 8904 ft TVDss. Low structural relief has presented a major challenge to field development, which has utilized extended reach wells to maximize drainage potential. Initial gas-in-place is estimated at 289 BCF with recoverable reserves in the order of 196 BCF. The field came on production in September 1995 via a sub-sea tie back to the Thames infrastructure and has an expected field life of 10 years
The Hewett Fields: Blocks 48/28a, 48/29, 48/30, 52/4a, 52/5a, UK North Sea: Hewett, Deborah, Big Dotty, Little Dotty, Della, Dawn and Delilah Fields
Authors: Cooke-Yarborough P. , Smith E.
Published: April 2008

abstract

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

abstract

Indefatigable is a mature dry gas field on the northeastern margin of the UK Southern North Sea Rotliegend Play fairway. The field was discovered, 49/18-1, by the Amoco operated group in 1966 and subsequent appraisal drilling established that the field extended over four blocks (i.e. 49/18, 49/19, 49/23 & 49/24). There have been several phases of development, initial production concentrated on the main horst block with first gas in 1971, followed by the west flank area in 1977/78. Then in 1987/88 the SW and SE Indefatigable satellite accumulations were brought on-stream.

The Rotliegend Leman Sandstone Formation reservoir primarily consists of stacked aeolian dune sandstones (150-400 ft) of good reservoir quality (porosity 15%, permeability 100-1000 mD). However, the integration of the 1992/93 3D seismic survey, well data, reservoir pressure and production data has lead to a much more complex view of the field with 11 gas-water contacts and 15 reservoir compartments.

This has resulted in an upward revision of the gas initially-in-place from 5.2 to 5.6 TCF and recoverable reserves from 4.4 to 4.7 TCF. Current work is focused on maximizing recovery from the various reservoir compartments and accessing this additional potential.
The Pickerill Field, Blocks 48/11a, 48/11b, 48/12c, 48/17b, UK North Sea
Authors: Werngren O. C. , Manley D. , Heward A. P.
Published: April 2008

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

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

abstract

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

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

abstract

Hatfield Moors and Hatfield West are two small gas fields with GIIP of 6.1 BCF and 2.4 BCF, respectively on adjacent licences PL161-3 and PL 162-2, east of Doncaster in South Yorkshire, England, operated and wholly owned by Edinburgh Oil & Gas pic.

This paper describes the accidental discovery of the Hatfield Moors Gas Field and its subsequent development and eventual utilization for gas storage, the first such project onshore UK. The nearby Hatfield West Field is also described. The two fields are located on adjacent faulted anticlinal structures in the NW part of the Gainsborough half-graben. The reservoir for both fields is the Westphalian B Oaks Rock sandstone. Reservoir quality is excellent.

A gas storage project was agreed with Scottish Power in 1998. Two horizontal wells, Hatfield Moors-5 (1998) and Hatfield Moors-5z (1999) have been drilled for the project by Edinburgh Oil & Gas pic using innovative drilling techniques. Since 1999 gas has been imported from the Transco network and exported from the reservoir according to market demands under the terms of the gas storage contract.
The Saltfleetby Field, Block L 47/16, Licence PEDL 005, Onshore UK
Authors: Hodge T.
Published: April 2008

The Saltfleetby Gas Field is located onshore in East Lincolnshire at the western extent of the Humber Basin, midway between the Southern North Sea gas fields and the established Onshore Oilfields of Welton and Scampton North. Commercial discovery was in 1996, following the re-entry of a 1986 exploration well, confirming the pre-drill belief that the earlier drilling had been mis-appraised. Basic assumptions at the time of drilling the re-entry well suggested a possible 40 BCF gas-in-place in Early Westphalian sandstones. This assessment was based on only a single 2D seismic line, an association with gravity form, and the mud logging information from the earlier exploration well.

Full delineation of the field extent following 3D seismic mapping and development drilling has indicated a gas-in-place of 114 BCF. Field development consent was granted in March 1999 and production commenced in December 1999. Initial field production exceeded 50 MMSCFD from four wells and to date (end July 2001) 24 BCF of gas has been produced. Ultimate gas recovery is expected to be 73 BCF proven plus probable reserves. A fifth horizontal well has been drilled in a deeper, Namurian, zone and a sixth well confirmed hydrocarbons in a southern promontory to complete the field development. An 8 km mixed phase export pipeline of 10" diameter exists to the Theddlethorpe processing plant, where gas and condensate is separated. Sharing of Pickerill compression facilities, located at Theddlethorpe were commissioned late in 2001.
The Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey and Sussex, UK Onshore
Authors: Trueman S.
Published: April 2008

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

The Flora Field straddles Blocks 31/26a and 31/26c of the UK sector of the North Sea on the southern margin of the Central Graben. The field is located on the Grensen Nose, a long-lived structural high, and was discovered by the Amerada Hess operated well 31/26a-12 in mid-1997.

The Flora Field accumulation is reservoired within the Flora Sandstone, an Upper Carboniferous fluvial deposit, and a thin Upper Jurassic veneer, trapped within a tilted fault block. Oil is sourced principally from the Kimmeridge Clay Formation of the Central Graben and is sealed by overlying Lower Cretaceous marls and Upper Cretaceous Chalk Group.

Reservoir quality is generally good with average net/gross of 85% and porosity of 21%, although permeability (Kh) exhibits a great deal of heterogeneity with a range of 0.1 to <10000mD (average 300 mD). The reservoir suffers both sub-horizontal (floodplain shales) and vertical (faults) compartmentalization, as well as fracturing and a tar mat at the oil-water contact modifying flow and sweep of the reservoir. Expected recoverable reserves currently stand at 13 MMBBL
The Use of Near-Seafloor 3D Seismic Data in Deepwater Exploration and Production
Authors: Steffens G.S. , Shipp R.C. , Prather B.E. , Nott J.A. , Gibson J.L. , Winker C.D.
Published: April 2008

The analysis of 3D seismic data in the near-seafloor interval is a useful speciality in deepwater exploration and production. In addition to the well-established benefits of 3D seismic data, the higher frequency content of near-seafloor data has a variety of applications throughout the life cycle of deepwater plays. These benefits include: (1) depositional process modelling, (2) stratal architectural information for building reservoir models, and (3) drilling hazard assessment.

Detailed mapping of well-imaged 3D seismic intervals in the near-seafloor interval is providing new insights to deepwater depositional processes and architectures. Depositional patterns are more confidently identified in near-seafloor settings, enabling the investigation of testable relationships between stratal stacking patterns, gradient changes and accommodation. These relationships as well as spatial and geometric information from these data are useful for building and constraining reservoir models, linking key observations from subsurface data at prospective levels with fine-scale outcrop analogue data. In particular, near-seafloor 3D data can image surfaces related to episodes of aggradation, starvation, bypass, and/or erosion that are typically hard to recognize or map at exploration depths, but are critical in controlling reservoir bed-length and connectivity in three dimensions. Near-seafloor 3D seismic data can supplement or even replace traditional 2D-based site surveys for assessing potential drilling hazards. Although usually lower in vertical resolution than 2D site survey data, 3D data have the distinct advantage of better imaging of 3D geometric bodies, providing insight into complex stratal stacking patterns, and allowing data volume manipulation and perspective.
Structural Controls on the Positioning of Submarine Channels on the Lower Slopes of the Niger Delta
Authors: Morgan Richard
Published: April 2008

Recently acquired 2D seismic data shot over the western Niger Delta have enabled a pre-delta rift framework to be delineated inshore of a transform fault dominated continental margin which lies beneath the later, delta sediment apron. The delta apron has been deformed by toe-of-slope thrusting where faults have climbed from a detachment surface at or near the top of the over-pressured Akata Formation mudstones. The overlying mixed clastic succession of the Agbada Formation has been faulted by a broadly oceanward stepping series of NW-SE trending thrusts climbing from this detachment level. The principal thrusts have been offset by NE-SW trending transfer zones, the positions of which have been inherited from trends within a pre-delta rift framework that underlies part of the western delta slope.

3D seismic data partly covering the 2D grid show turbidite channel complexes at numerous stratigraphic levels within the Agbada Formation and clustered in particular areas of the slope. Commonly, submarine channels can be seen to have cut through the relief caused by folding at the positions of intersection with transfer fault zones. These data show the relationship between structure and channel formation and highlight the importance of transfer fault zones in localizing channel systems on the lower slope. Nevertheless, the 2D seismic data has provided an explanation for the location of the transfer zones within the toe-thrust belt in the form of an underlying structural framework, and both data types have contributed to the understanding of controls on reservoir distribution in an area where the principal sand delivery systems are perpendicular to the main structural trend.
3D Anatomy of Late Neogene Contourite Drifts and Associated Mass Flows in the Faroe-Shetland Basin
Authors: Knutz Paul C. , Cartwright Joseph A.
Published: April 2008

We have combined 3D mapping of key reflectors with seismic profiles to describe the geometry and anatomy of contourite drifts formed by deep waters passing through the oceanic gateway of the Faroe-Shetland Channel. The West Shetland Drift complex is characterized by sheeted-mounded drift units, and upslope migrating sediment waves accreting over an early Pliocene unconformity. The basin section is constructed by a series of asymmetric depositional units of early Pliocene-Pleistocene age, interlayered by three mega-debrite sequences that extend into the basin. The Pliocene drift surface display an enhanced topography of bifurcating moat-channels that tend to branch out in a southwest direction. Along the lower slope a succession of upslope migrating sediment waves has accumulated from the Pliocene drift topography. These features extend to the present sea bed at water depths of 700-1000 m where they appear as a series of linear, bifurcating ridges. The high accumulation rates of the West Shetland Drift since the early Pliocene transition and the formation of upslope migrating sediment waves is related to a sustained flow of Norwegian Sea deep waters and cross-slope transport of fine-grained sediments from the NW European shelf.
Interactions between Topography and Channel Development from 3D Seismic Analysis: an Example from the Tertiary of the Flett Ridge, Faroe-Shetland Basin, UK
Authors: Robinson Andrew M. , Cartwright Joseph A. , Burgess Peter M. , Davies Richard J.
Published: April 2008

Interpretation of 3D and 2D seismic data in the Faroe-Shetland Basin (FSB) has revealed the important role that structurally controlled bathymetry had in controlling sedimentary dispersal during Early Cenozoic thermal subsidence. The Flett Ridge was a major NE-SW structural high during some of the Palaeogene, actively growing and influencing adjacent sedimentary systems. During the Palaeogene this area of the FSB was a key entry point for siliciclastic sediment with a major deltaic system prograding towards the NW during the Middle Eocene. Prior to delta development, the Flett Ridge was onlapped during the Late Palaeocene and subsequently blanketed and drowned in Early Eocene times. Major periods of fluvial incision cutting up to 100 m into the Middle Eocene strata are identified and a variety of channel networks with differing trends documented. Broad channels or valleys of earliest Middle Eocene age inherited the palaeotopography created by the Flett Ridge, whereas subsequent later Middle Eocene meandering channels trend perpendicular to the shelf edge and traverse the Flett Ridge structure. Seismic amplitude maps suggest that a complex and variable channelized drainage system developed across the coastal plain and delta top in the Middle Eocene. These channels influenced sediment supply creating an area of bypass to the more distal fan systems preserved at the base of slope. Later faulting on the ridge crest may also have affected the channel network pattern.
The Evolution and Growth of Central Graben Salt Structures, Salt Dome Province, Danish North Sea
Authors: Rank-Friend Malene , Elders Christopher F.
Published: April 2008

The remarkable spatial resolution of 3D seismic data is particularly important in the study of salt structures, where changes in the distribution of accommodation space resulting from salt withdrawal can be mapped and related to the evolution of the individual salt structures. The Salt Dome Province of the Danish Central Graben provides an interesting example of this approach. Three adjacent salt structures (Skjold, Dan and Kraka) exhibit very different geometries, and their evolution has been the subject of some debate. The present study suggests that the Dan structure is composed almost entirely of Zechstein salt, which, facilitated by de-coupled extension during the Mid-Late Jurassic, has been intruded into and along weak planes of Triassic salt, resulting in an overall domal, circular outline. Skjold is located to the NW of Dan. It consists of Zechstein salt and forms a mature salt stock, which terminates within Upper Cretaceous strata. Skjold evolved from a linear NW-SE trending salt wall and became a point source structure during the Early Cretaceous, in common with the many other Central Graben diapers and coincident with the commencement of thermal subsidence. By contrast, Kraka, a NW-SE trending pillow structure located to the south of the Dan-Skjold alignment never became diapiric. Gravitational downbuilding of the mature Skjold diapir during rapid Cenozoic deposition was punctuated by rejuvenated (active) growth induced by regional compression, most significantly during the Mid-Miocene. This event affected also the Dan and Kraka structures, which otherwise experienced very limited growth during the Cenozoic.
Integrating 3D Seismic Data with Structural Restorations to Elucidate the Evolution of a Stepped Counter-Regional Salt System, Eastern Louisiana Shelf, Northern Gulf of Mexico
Authors: Trudgill Bruce D. , Rowan Mark G.
Published: April 2008

By integrating 3D and 2D seismic interpretation with structural restorations we have reconstructed the evolution of a complex, composite stepped counter-regional salt system in the West Delta/South Pass (WDSP) area of the northern Gulf of Mexico. Biostratigraphically calibrated well data allow the last 10 Ma of the evolution of the salt system to be divided into six stages: (1) sea-floor extrusion of isolated salt tongues fed from the Jurassic Louann salt through northward dipping feeders prior to 7.5 Ma; (2) amalgamation of the salt tongues to form a salt-tongue canopy between 7.5 and 6.4 Ma; (3) counter-regional evacuation of the salt-tongue canopy as a result of enhanced sediment loading due to progradation of the shelf margin between 6.4 and 5.0Ma; (4) evacuation of salt into a series of salt walls linking salt domes between 5.00 and 2.55 Ma; (5) evacuation of the salt walls to form counter-regional fault welds between 1.95 and 0.5 Ma; and (6) final evacuation of most of the salt from deeper levels leaving a series of isolated salt domes connected by counter-regional fault welds. The counter-regional evacuation of the WDSP salt systems illustrates the value and limitations of published 2D models for allochthonous salt, and the reconstructed evolution yields insights into the complex interactions between salt deformation and sedimentation. The results also suggest that the WDSP salt systems significantly affected sediment transport pathways, trap geometries and possibly late stage petroleum migration across evacuating salt welds.

Supplementary material:
Three movies depicting the 2D and 3D restorations and models are available at
https://doi.org/10.6084/m9.figshare.c.4784595
Exploration 3D Seismic over the Gjallar Ridge, Mid-Norway: Visualization of Structures on the Norwegian Volcanic Margin from Moho to Seafloor
Authors: Corfield S. M. , Wheeler W. , Karpuz R. , Wilson M. , Helland R.
Published: April 2008

We present an analysis of a unique 3D survey that allows us to relate the deep structure of the crystalline crust to the shallow structure of the overlying, potentially hydrocarbon-rich sedimentary basins. The survey is located over the Gjallar Ridge, Mid-Norway, and extends from a Moho-level reflector at around 15 km depth to polygonal faulting and diapiric structures at or near the seabed. 3D visualization techniques using seismic workstations and the Cave immersive environment have been used to illustrate the geometries of these features. The deep reflector is correlated with the top of a deep, high-density, high-velocity body that is interpreted to indicate the presence of magmatic underplating and is intimately related to localized uplift of the Gjallar Ridge. Abundant high-amplitude reflectors in the deep Cretaceous sections of the survey are interpreted as sills emplaced during the Palaeocene magmatic event and are therefore interpreted to be coeval with the magmatic underplate. In contrast, the shallow parts of the survey have numerous gas-charged mud diapirs and an extensive network of polygonal faults extending to the seabed. Study of such very deep or very shallow features is not standard industry practice. However, the intention here is to demonstrate that, by utilizing the full volume of 3D seismic data, it is not only of scientific interest but also results in a greater understanding of the tectonic history of a hydrocarbon prospect.
Visualization and Interpretation of 3D Seismic in the Carboniferous of the UK Southern North Sea
Authors: Lynch Jeremy J.
Published: April 2008

Examples from the Carboniferous of the UK Southern North Sea are used to illustrate the application of visualization tools to increase the effectiveness of 3D seismic interpretation. Maintaining the seismic data to the fore throughout the interpretation workflow and decision-making process is vital for well planning in field development and trap validation in prospect evaluation. Scaling of the seismic into the 'true-depth' domain and the automatic generation and visualization of layers using isochores derived from well data are the key elements in this interpretation workflow. Together these allow full integration of the seismic with various well data and interpreted elements. The main example is from Murdoch K, one of ConocoPhillips's most recent UK discoveries, part of a pre-Permian extensional graben inverted during the Early Tertiary tectonic phase. Other examples from the McAdam Field and an exploration prospect are used to highlight additional aspects of the method.
Direct Visualization and Extraction of Stratigraphic Targets in Complex Structural Settings
Authors: James Huw , Bond Rob , Eastwood Lucy
Published: April 2008

Advances in 3D visualization and volume detection have greatly improved our ability to find stratigraphic targets in areas of complex structure. In this paper we apply volume sculpting, seismic facies analysis and prediction of rock properties from seismic data to resolve a potential reservoir channel from a highly faulted setting in offshore Indonesia. These techniques use computational power to search for patterns in the data. These patterns may be presented to the interpreter or may be used to transform seismic and well data into estimates of rock properties. Such techniques should improve development efficiency in areas where complex structure has previously precluded the use of these techniques.
4D/Time-Lapse Seismic: Examples from the Foinaven, Schiehallion and Loyal Fields, UKCS, West of Shetland
Authors: Bagley G. , Saxby I. , McGarrity J. , Pearse C. , Slater C.
Published: April 2008

4D or time-lapse seismic data has become a business of usual tool for reservoir management in high-cost environments for oil production such as the West of Shetlands. 4D seismic can be used to visualize fluid movement in a qualitative/semi-quantitative sense to visualize field behaviour, predict well performance and predict reservoir pressure. Whilst the data may be easily visualized using 3D visualization technology the challenges for the future include the need to obtain quantitative predictions through better quality seismic data.

Supplementary material:
Ten movies showing 3D and 4D seismic data are available at
https://doi.org/10.6084/m9.figshare.c.4784616
Modelling Fault Geometry and Displacement for very Large Networks
Authors: Lister Dustin L.
Published: April 2008

Traditional methods for building fault models are time-consuming when applied to a complex fault network or where many faults exist since the workflows typically rely on manual intervention at several stages. Structural detail is often simplified to reduce cycle times and consequently, the workflow favours large-scale and simplistic fault systems. There is generally no integrated assessment of kinematic information that would be useful in guiding fault interpretation. A new methodology for constructing a complex fault network with small offset is presented. The method recognizes that interpretation of large numbers of interconnected low displacement faults, is most efficiently done using map based interpretations. A novel semi-automated skeletonization algorithm is used to extract fault traces from horizon maps providing a polyline data set for subsequent use in 3D surface creation. Displacement information is derived automatically during or after the skeletonization providing kinematic information for guiding further interpretation. The new method is validated against manual interpretations of fault geometry and displacement before application to a region of the Central North Sea exposing polygonal faults. The new technique allows for the first time, a rapid and accurate appraisal of complex near-seismic scale fault geometry and displacement from interpretations of 3D seismic data across a large survey area.
Neoproterozoic, passive-margin, sedimentary systems of the Kanin Peninsula, and northern and central Timan, NW Russia
Authors: Roberts David , Siedlecka A. , Olovyanishnikov V. G.
Published: April 2008

Neoproterozoic, slope-to-basin, lithostratigraphic successions are discontinuously exposed within the Timan Range, in NW Russia, NE of a faulted basinal margin that marks the outer edge of a former, fluvial to shallow-marine, pericratonic domain. The Mid to Late Riphean, deep-water depositional systems of the Kanin Peninsula, and northern and central Timan attain considerable thicknesses, up to 10 000 m in the case of Kanin Peninsula. Basements to these successions are nowhere exposed. Although the successions accumulated along a comparatively stable, passive margin of Baltica, there are notable differences in sedimentary facies from area to area. Whereas the successions in northern and central Timan preserve a record of relative stability, with sedimentation keeping pace with subsidence, the nearby Kanin succession shows evidence of repeated faulting. This may reflect a non-contemporaneity of the diverse successions or a segmentation of the basin margin. Comparisons are also made with deep-water, turbidite-fan systems in northwestern parts of the Timan-Varanger Belt, on the Rybachi and Varanger Peninsulas. The lateral differences in sedimentary facies in these areas, seen in relation to the situation in Timan and Kanin, do, in fact, suggest that the 1800 km long Timanian Basin margin may have been segmented, and possibly into sub-basinal domains.
Late Neoproterozoic sedimentation in the Timan foreland
Authors: Grazhdankin D.
Published: April 2008

The late Neoproterozoic Vendian succession fills a peri- to epicratonic Mezen Basin in front of the Timan Orogen, and is exposed along the northwestern flank of the basin. In the SE White Sea area, the siliciclastic succession demonstrates a wide range of lithofacies that define a transition from a low-energy shallow-marine muddy shelf to a braid-delta plain. Significantly, the prodelta, distributary-mouth bar, and delta plain lithofacies all demonstrate a remarkably tight clustering of palaeocurrent trends suggesting that the sediment was sourced from the NE. This pattern is interpreted as representing deposition in a distal setting in the Timan foreland basin. U-Pb zircon dates of 558 ± 1 Ma and 555.3 ± 0.3 Ma for volcanic tuffs in the Vendian succession provide lower age constraints for the emergence of the Timanian hinterland.
The Vendian alkaline igneous suite of northern Timan: ion microprobe U-Pb zircon ages of gabbros and syenite
Authors: Larionov Alexander N. , Andreichev V. A. , Gee D. G.
Published: April 2008

Near the Barents Sea coast in northern Timan, turbidites of probable Neoproterozoic age are intruded by pre-tectonic dolerites and a major suite of gabbros, granites and syenites (some nepheline bearing). Zircon ion microprobe dating of three plutons has yielded well-defined ages of 613–617 Ma. This alkaline igneous activity apparently represents a final phase of Vendian extensional magmatism prior to Timanian Orogeny. Previous work on late to post-orogenic calc-alkaline granites in the basement beneath the Pechora Basin, three hundred kilometres towards the SE, has yielded
c.
550–560 Ma single zircon Pb-evaporation ages. These compositionally different intrusive suites are inferred to constrain the main phase of Timanian Orogeny to
c.
610–560 Ma.
Timanian blueschist-facies metamorphism in the Kvarkush metamorphic basement, Northern Urals, Russia
Authors: Beckholmen Monica , Glodny Johannes
Published: April 2008

The core of the Kvarkush Anticline, on the western side of the Northern Urals, contains pre-Ordovician metasediments and minor metabasites that have undergone multistage deformation and transitional greenschist- to blueschist-facies metamorphism. Metamorphic conditions for the blueschist-facies assemblages are estimated at 350–400 °C and 7–8 kbar. The metamorphic rocks are cut by mafic dykes, one of which yields a Sm-Nd mineral age of 398 ± 37 Ma (2σ). The age of the high-pressure/low-temperature (
HP/LT
) metamorphism has been controversial. New Rb-Sr mineral data yield ages for the waning of blueschist-facies metamorphism at
c.
536 Ma (535 ± 6 Ma, 535.8 ± 6.5 Ma, 536 ± 19 Ma, all 2σ), demonstrating that the specific conditions required for blueschist-facies metamorphism were attained in latest Neoproterozoic to earliest Cambrian times. The new data are the first well-constrained documentation of
HP/LT
metamorphism within the Timanian Orogen. We suggest that easterly-directed subduction of the East European continental margin (present-day coordinates) during the Timanian Orogeny, involving compressional thickening of the margin sediments, is the most likely scenario for the formation of the Kvarkush blueschists. The Kvarkush
HP/LT
metasediments, together with lower greenschist-facies and subgreenschist-facies metasediments further west, form parts of a Timanian orogenic wedge on an east-dipping thrust ramp. Reworking during the Uralian orogenesis was of minor importance.
Evolution of the ocean crust: results from recent seismic experiments
Authors: Orcutt J. A. , Burnett M. , McClain J. S.
Published: April 2008

We present results from recent analyses of seismic refraction and sea-floor microseismicity studies in the Pacific and Atlantic oceans which lend support to the hypothesis that processes responsible for the construction of ophiolite suites are similar to phenomena extant at mid-ocean ridges. Seismicity at fast-spreading ridges is characterized by very low magnitude (0–1) and shallow (<2–3 km) microearthquakes and long-term oscillations or harmonic tremor. A detailed seismic-refraction experiment on a fast-spreading portion of the East Pacific Rise supports the hypothesis of the existence of a crustal magma chamber. Analyses of these data indicate that the chamber is largely unperturbed by the presence of conjugate spreading centres and the inverted delta-shaped zone of partial melt is characterized by a half width in excess of 6 km. Finally, a new approach for obtaining upper-crustal velocities when applied to data characterized by the presence of shear waves provides several counter-examples to the hypothesis that the shallow crust evolves with time.
Parent magmas of the Semail ophiolite, Oman
Authors: Pallister J. S.
Published: April 2008

The plutonic rocks of the Semail ophiolite in the southeastern Oman Mountains formed in a spreading-ridge magma chamber that was repeatedly replenished by primitive magma. An average composition of the parent magma is calculated by mass balance of the igneous stratigraphy. The average parent magma was in equilibrium with most early-formed cumulus minerals from the ophiolite and is very similar to primitive mid-ocean-ridge basalt (MORB). Comparison with experimentally determined liquidus relations for primitive MORB also suggests that most of the cumulus minerals could have been produced by fractionation of the average parent magma. The magma is basaltic—in contrast to the picritic melts proposed as parents for some ophiolites. Although the
average
parent magma composition is basaltic, individual batches of magma that fed the magma chamber varied in composition because of mantle processes. The primary mantle melts were probably picritic, but due to reaction during ascent through the upper mantle and mixing or density entrapment within the crustal-level magma chamber, these picritic melts were probably not erupted on the sea floor. A model with primary mantle melting at 40–60 km depth followed by reaction during ascent and possibly second-stage melting at ≤25 km depth is favoured for the ophiolite.
Occurrence and significance of gneissic amphibolites in the Vema fracture zone, equatorial Mid-Atlantic Ridge
Authors: Honnorez J. , Mevel C. , Montigny R.
Published: April 2008

Numerous gneissic amphibolites were recovered together with variably deformed and metamorphosed gabbros and serpentinites in the Vema fracture zone during two separate cruises. Petrological studies and K/Ar dating show that these rocks result from recrystallization of gabbros under stress, at temperatures consistent with amphibolite facies, probably in the vicinity of the ridge axis. We suggest that gneissic amphibolites were formed in a large subvertical shear zone related to transform fault movement which favoured penetration of seawater in oceanic layer 3. Less deformed metagabbros recrystallized away from the fault zone under static conditions from interaction with evolved seawater-derived fluids.