Four-way Dip Closure Research Articles

Identification of hydrocarbons in chalk reservoirs from surface seismic data: South Arne field, North Sea

Seismic data are mainly used to map out structures in the subsurface, but are also increasingly used to detect differences in porosity and in the fluids that occupy the pore space in sedimentary rocks. Hydrocarbons are generally lighter than brine, and the bulk density and sonic velocity (speed of pressure waves or P-wave velocity) of hydrocarbon-bearing sedimentary rocks are therefore reduced compared to non-reservoir rocks. However, sound is transmitted in different wave forms through the rock, and the shear velocity (speed of shear waves or S-wave velocity) is hardly affected by the density of the pore fluid. In order to detect the presence of hydrocarbons from seismic data, it is thus necessary to investigate how porosity and pore fluids affect the acoustic properties of a sedimentary rock. Much previous research has focused on describing such effects in sandstone (see Mavko et al. 1998), and only in recent years have corresponding studies on the rock physics of chalk appeared (e.g. Walls et al. 1998; Røgen 2002; Fabricius 2003; Gommesen 2003; Japsen et al. 2004). In the North Sea, chalk of the Danian Ekofisk Formation and the Maastrichtian Tor Formation are important reservoir rocks. More information could no doubt be extracted from seismic data if the fundamental physical properties of chalk were better understood. The presence of gas in chalk is known to cause a phase reversal in the seismic signal (Megson 1992), but the presence of oil in chalk has only recently been demonstrated to have an effect on surface seismic data (Japsen et al. 2004). The need for a better link between chalk reservoir parameters and geophysical observations has, however, strongly increased since the discovery of the Halfdan field proved major reserves outside four-way dip closures (Jacobsen et al. 1999; Vejbæk & Kristensen 2000).

The discovery of Goldeneye: Kopervik prospect and play mapping in the South Halibut Basin of the Moray Firth

Exploration within the Kopervik play is impeded by difficulty in imaging the Kopervik Sandstone on seismic data due to the lack of acoustic impedance contrast between the sandstones and overlying shales. The exploration method employed in the mapping of the Kopervik play fairway of the South Halibut Basin on poorquality 3D seismic data, leading to the Goldeneye Field discovery, is described. In the early 1990s, Shell/Esso acquired acreage in the South Halibut Basin based on the identification on 2D seismic data of a number of potential stratigraphic traps in the Kopervik play. The first well targeted an Apto-Albian isochron thick, just south of the proven Kopervik fairway, but encountered no reservoir. Subsequent mapping better delineated the fairway as being restricted to the southern fringe of the South Halibut Shelf. The basal sequence boundary was mapped locally on 3D seismic data and amplitude extractions were interpreted as showing erosion at the base of the Kopervik channel complex. At the northern edge of this fairway, a small four-way dip closure identified above Goldeneye on a regionally mappable seismic reflector did not conform to deeper structure, suggesting the presence of a thick section of mounded Kopervik Sandstone. The presence of gas/condensate in thin Jurassic sandstones in a well immediately north of this closure, far removed from the Jurassic gas kitchen, suggested that long-distance migration had occurred along the Kopervik fairway and hence that gas might be trapped at Goldeneye. The Goldeneye discovery well, drilled in 1996, encountered a 305 ft column of gas/condensate above a thin oil rim within the thickest section of Lower Cretaceous Kopervik Sandstone so far encountered in the Outer Moray Firth. Subsequently, two further prospects were drilled with mixed results. The Goldeneye structure is now considered unique within the Ettrick sub-basin of the South Halibut Basin.

Late Cenozoic depositional history of the Danish North Sea Basin: implications for the petroleum systems in the Kraka, Halfdan, Siri and Nini fields

The Central Graben area was filled with a thick pile of sediments during the Middle Miocene – Quaternary, corresponding to a period of 15Ma. As hydrocarbon expulsion from the most prolific source rock, the Upper Jurassic Bo Member, was initiated only 20 Ma BP and still occurs today, the Middle Miocene – Quaternary evolution is important. In the Middle Miocene, the Central Graben area was covered by a sea with water depth of 500–700 m. During the Late Miocene (Tortonian), the basin was successively filled by prograding slope and deltaic sediments from the northeast. The progradational infill resulted in local tilting of the substratum due to the loading effect of the deposits. In the latest Late Miocene (Messinian), the main input of sediments occurred from the south, as illustrated by a thick onlapping succession of upper Messinian sediments. Pliocene sedimentation was characterized by regular infill from the east within a shelf to shallow marine depositional environment. Following the Miocene and Pliocene, the North Sea Basin tilted due to strong uplift of the Fennoscandian shield and increased subsidence and sedimentation rates within the Central Graben area. This further complicated the maturation of the source rock, migration pathways and accumulation of hydrocarbons. The consequence of this complex burial history is exemplified by the Kraka and Halfdan fields. The Kraka Field has a large down-flank oil accumulation, which is the result of a porosity anomaly resulting from an early invasion of oil in this position before the late tilting of the North Sea Basin. The history of the non-structural accumulation of the Halfdan Field can be readily modelled; it constituted a simple four-way dip closure during the Late Miocene when peak oil migration occurred. The Quaternary tilting of the North Sea Basin due to uplift of the Fennoscandian Shield and strong subsidence of the Central Graben area resulted in a distinct gradient favouring long-distance migration of hydrocarbons. The occurrence of viable migration routes, especially within Paleocene sand layers, has resulted in long-distance migration of oil into the Siri submarine valley system. The most northern indication of hydrocarbons has been recognized as far as 75km from the source area. Long-distance migration of hydrocarbons is also indicated by direct hydrocarbon indications (DHIs) throughout the Cenozoic succession in the Danish North Sea. DHIs are particularly prominent above known hydrocarbon accumulations in the Central Graben. This indicates pronounced vertical migration, for instance along active faults, above these structures.

Improving recovery from mature oil fields producing from carbonate reservoirs: Upper Jurassic Smackover Formation, Womack Hill field (eastern Gulf Coast, U.S.A.)

Reservoir characterization, modeling, and simulation were undertaken to improve production from Womack Hill field (eastern Gulf Coast, United States). This field produces oil from Upper Jurassic Smackover carbonate shoal reservoirs. These reservoirs occur in vertically stacked, heterogeneous depositional and porosity cycles. The cycles consist of lime mudstone and wackestone at the base and ooid grainstone at the top. Porosity has been enhanced through dissolution and dolomitization. Porosity is chiefly interparticle, solution-enlarged interparticle, grain moldic, intercrystalline dolomite, and vuggy pores. Dolostone pore systems and flow units have the highest reservoir potential. Petroleum-trapping mechanisms include a fault trap (footwall uplift with closure to the south against a major west-southeast–trending normal fault) in the western area, a footwall uplift trap associated with a possible southwest-northeast–trending normal fault in the south-central area, and a salt-cored anticline with four-way dip closure in the eastern area. Potential barriers to flow are present as a result of petrophysical differences among and within the cycles, as well as the presence of normal faulting. Reservoir performance analysis and simulation indicate that the unitized western area has less than 1 MMSTB of oil remaining to be recovered, and that the eastern area has 2–3 MMSTB of oil to be recovered. A field-scale reservoir management strategy that includes the drilling of infill wells in the eastern area of the field and perforating existing wells in stratigraphically higher porosity zones in the unitized western area is recommended for sustaining production from the Womack Hill field.

Real-time data transfer to 3D model—maximizing wellbore value

Editor's note: Most of the material in this article was presented at the 10th Abu Dhabi International Petroleum Exhibition and Conference in 2002 and originally published as SPE paper 78526. It is under copyright by SPE and is reprinted here with permission. Ula, a mature water-flooded oil field in block 7/12 of the Norwegian sector of the North Sea (Figure 1), is operated by BP Norge AS on behalf of partners DONG Norge AS and Svenska Petroleum AS. The oil accumulation is moderately deep (3350–3800 m TVDSS) and hot (150° C). The reservoir consists of upper Jurassic shallow marine sediments in a four-way dip closure above a salt structure (Figure 2). The field was discovered in 1976, and first oil was produced in 1986. Plateau oil production of 100–150 mbd was maintained until late 1993. Subsequent production has been about 25 mbd, sustained by infill drilling in the upper unit 1A reservoir and by injecting water and gas. A water-alternating gas (WAG) scheme has recently commenced. Figure 1. Location of Ula Field in the Norwegian sector of the North Sea. Figure 2. Cross-section through Ula Field. Vertical exaggeration approximately two-fold. Main reservoir (units 2,3) shaded in gray. Unit 1 reservoir is below the dashed line and above the gray shaded area. This paper describes recent experience on the last two unit 1A infill wells, which were geosteered, near-horizontal wells on the crest of the field structure. During the drilling of these wells, a real-time data link connected the Ula platform with BP's offices in Stavanger. This link enabled data from a directional drilling/LWD vendor and a mudlogging company to be loaded directly into BP's corporate subsurface database on a regular and automatic basis. The drilling and LWD data were also available to the entire drilling and completions team through a Web-based browser. The real-time …

The MacCulloch Field, Block 15/24b, UK North Sea

Abstract The MacCulloch Field lies within Block 15/24b in the UK Central North Sea and is located on the northern flank of the Witch Ground Graben. It was discovered by Conoco well 15/24b-3 in 1990. MacCulloch Field is a four-way dip closure at Top Paleocene over a deeper Mesozoic structure. The reservoir consists of Upper Balmoral Sandstones containing 32-37° API oils derived from Kimmeridge Clay Formation shales and sealed by shales belonging to the Sele Formation. The field contains recoverable reserves of 60-90 MMBOE. Reservoir quality is generally very good, with an average porosity of 28% and core permeabilities (Kh) between 200 mD and 2D. AVO anomalies and a seismic flat spot are associated with oil filled reservoir and the oil-water contact in certain areas of the field.

The Moira Field, Block 16/29a, UK Central North Sea

Abstract 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 Maureen Field, Block 16/29a, UK Central North Sea

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 Fife and Fergus Fields, Block 31/26a, UK North Sea

Abstract 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

4-D time lapse reservoir monitoring of Nelson Field, Central North Sea: Successful use of an integrated rock physics model to predict and track reservoir production

Nelson Field, in the U.K. sector of the Central North Sea approximately 180 km east of Aberdeen in 280 ft of water, is on the Forties-Montrose ridge and forms a broad, low relief anticline with four-way dip closure (Figure 1). Figure 1. Nelson Field in relation to Forties-Montrose trend and established infrastructure. 4-D seismic data, acquired using conventional towed streamers, have been successfully applied to the Paleocene reservoirs of the North Sea. Importantly, AVO applications enhance the 4-D difference signal in this reservoir. We tested a new multivariate solution to predict shear-wave slowness against field data, and used this to establish an integrated rock physics model of the Forties Sandstone. This formed the basis for full elastic inversion of the AVO data sets. Full elastic inversion results demonstrate that quantifiable seismic differences can be detected and that they are of similar magnitude to those estimated independently from core and log data. Our study found that the predicted, simulated, drainage pattern and the actual time-lapse seismic difference signal are in good agreement. The 4-D is detecting OWC movements as small as 15–20 ft within the main sand channel fairways. 4-D seismic may provide a valuable tool to monitor reservoir drainage patterns for areas characterized by low net-to-gross sand ratios, but the method clearly works best within main sand fairways to target potential upside areas. The field was discovered in 1988. An extensive appraisal campaign by Enterprise and Shell/Esso followed. By 1990 13 appraisal wells had been drilled. The field began producing in February 1994 from eight wells. To date, 27 development wells have been drilled from a single central platform: 23 oil producers and 4 water injectors. In addition, four subsea producers exploit the southern satellite area. Plateau production was maintained during 1994–1996 at 150 000 b/d. Top Reservoir is relatively shallow at …

3D Seismic Recognition of the Jurassic Smackover Reservoir of Grayson Field Using Leading Edge Reservoir Characterization Seismic Processing

ABSTRACT The discovery well at Grayson Field was drilled on a four-way dip closure defined by only three 2D seismic lines. Investors were hoping to find a maximum of 30-40 feet of pay. After the discovery of 140 feet of gross pay in the Jurassic Smackover limestone in February 1993, the participants decided that a 3D seismic program was needed. The objective of the 3D seismic program was to define the structural and stratigraphic limits of the new field. This paper compares the results of different processing techniques on the Grayson 3D seismic volume. Specific processing and interpretive tools available to the explorationist will be covered, illustrated with many different seismic displays. Evidence will be presented that 1) relative amplitude of the Smackover reflector does not define the reservoir's stratigraphic parameters, 2) attributes of the acoustic impedance data (velocity) show good statistical correlation to key reservoir parameters, 3) A.V.O. analysis shows a hydrocarbon indicator over the reservoir, and 4) reservoir characterization (petrophysical) data generated with the 3D seismic data delineates the production. Through the use of this fully integrated sub-surface well information and 3D seismic data set, the thinner upper pay interval can be discerned from the thicker main pay. The reprocessed seismic data defines a new pay interval in the field. Results of recent drilling prove that the 3D seismic data expense was well worth the money.

CORNEA CASE STUDY: LESSONS FORTHE FUTURE

The Cornea Field was discovered in January 1997. The Cornea structure represents a relatively simple trap configuration comprising a large, elongated, four-way dip closure, formed by the drape of Albian age sediments over a northeast to southwest trending positive basement feature. It is located on an active hydrocarbon migration fairway with proven charge and is capped by a regionally extensive Albian seal. An associated Direct Hydrocarbon Indicator extends over an area of 50 km2 and this feature coincides with gas-fluid contacts throughout the field.Subsequent to the initial Cornea discovery wells in permit WA–241-P, further exploration drilling took place within WA–241-P, and also within two, newly-acquired, adjacent permits, WA–265-P and WA–266-P, during 1998 and 1999. Detailed field assessment during and subsequent to these wells, involving geological, geophysical and reservoir engineering disciplines, indicated that the field consisted of an extensive gas cap over a thin, laterally discontinuous oil rim. The poor quality of the Lower Cretaceous marine reservoir succession and the extremely low expected oil recovery indicated that recoverable volumes would be low.This paper contains a review of the data and studies that led to a full understanding of the field. Key learning points from the case study are introduced here and may help future exploration campaigns in other areas.

Detachment faulting and petroleum prospectivity in the Rio Muni Basin, Equatorial Guinea, West Africa

Abstract The change from rifting to drifting is generally signified by a characteristic end-rift, or break-up, unconformity. In the Rio Muni Basin, two such unconformities bound an Aptian-Cenomanian transitional sequence of allochthonous carbonates and clastics considered unique among the South Atlantic passive margins. The transitional sequence comprises allochthonous thin-skin ‘rafts’, up to 2500 m thick, of shallow water carbonate and clastic sediment emplaced in a relatively deepwater setting along shallow detachments. A new model for the rift to drift development of the Rio Muni Basin interprets the raft tectonics as a response to a combination of end-rift-early post-rift uplift of the basin margins and deep off-shore bathymetry c. 1800 m. Seismic interpretations reveal spectacular hanging wall geometry in the rafts as a consequence of their movement across a geometrically complex, ramp-flat basal detachment. In places, the hanging walls of the rafts display an ‘eggbox’ topography of closely spaced anticlines, often with four-way dip closure. Information from wells and analogy with adjacent basins indicates potential source rocks in the Aptian and Turonian. Several migration paths are identified, including the juxtaposition of hanging wall reservoirs with the source-bearing stratigraphy across transverse fault zones. Raft tectonics has considerable isostatic and thermal consequences, with attendant implications for predicting the timing of potential source rock maturity. Modelling maturity at variously located wells and pseudowells indicates the principal effect of the raft tectonics to have been a very rapid episode of burial in the basin centre and isostatic rebound of the unloaded margins.

THE USE OF OIL FINGERPRINTING TO ENHANCE FIELD PRODUCTION ON BARROW ISLAND

Oil production from well B28 completed in the Windalia Sand Reservoir of the Barrow Island Field was anomalously high in comparison to surrounding wells. Reservoir properties evaluated from the well could not account for the high production rates. Oil fingerprinting, which is a reservoir-geochemistry technique based on the gas chromatographic character of oil, was applied to identify the reservoir affiliation of the additional oil. The oil fingerprinting indicated that the oil from the B28 well is geochemically similar to oil from the deeper Flacourt Formation Reservoir.The results of the oil fingerprinting prompted a re-evaluation of the existing geological model in the area of well B28. The well intersects the Barrow Fault within a downthrown sliver of Windalia Sand. A large volume fracture stimulation over this interval may have opened the Barrow Fault to the underlying upper Flacourt Formation Reservoir. However, the structure outlined by the oil-water contact in the upper Flacourt Formation Reservoir had been mapped as a four-way dip closure 500 m north east of the B28 well. A review of the local stratigraphy identified a thin sand (the B28 sand), at the top of the Lowendal member of the IYluderong Shale, which could form a conduit from the Barrow Fault to the nearby upper Flacourt Formation Reservoir. The interpretation of the B28 sand conduit also increased the mapped extent of the upper Flacourt accumulation. In December 1997, 41 years after development began on Barrow Island, the B28 sand was successfully targeted by infill well CUM and subsequently developed as an extension to the Flacourt accumulation. Well CUM has the second highest initial production rate (1,360 BOPD) in the history of the field. The application of oil fingerprinting has enhanced the stratigraphic and structural model of an area with limited well control and sparse, poor quality seismic.

Play concepts-northwest Palawan, Philippines

The offshore area of northwest Palawan, Philippines, contains a number of provenexploration plays. These include u • pinnacle reefs developed on Nido carbonate platforms (e.g. Nido, Matinloc, Cadlao); • a seaward horst block reef fairway with large pinnacle reefs (e.g. Malampaya—Camago trend); • early Miocene Galoc Clastic Unit turbidites (e.g. Octon, Galoc); and • four-way dip closures (e.g. West Linapacan, Octon). The recent discovery by Fletcher Challenge Petroleum at Calauit Field has shown a potentialexploration play in deep-water Nido Limestone turbidites. The traditional and, to date, only economically productive play in northwest Palawan has been the Nido Limestone reefs. This paper presents a review of the old play types and presents new untested play types. These new play types include u • pre-Nido syn-rift plays; • pre-Nido marine turbidite play: and • mid-Miocene reefs. It also presents new insights into factors controlling reef development on the carbonate platforms where four reef types are now recognized. The Galoc Clastic Unit turbidite play is discussed and new play fairways presented.

Play concepts-northwest Palawan, Philippines

The offshore area of northwest Palawan, Philippines, contains a number of provenexploration plays. These include u • pinnacle reefs developed on Nido carbonate platforms (e.g. Nido, Matinloc, Cadlao); • a seaward horst block reef fairway with large pinnacle reefs (e.g. Malampaya—Camago trend); • early Miocene Galoc Clastic Unit turbidites (e.g. Octon, Galoc); and • four-way dip closures (e.g. West Linapacan, Octon). The recent discovery by Fletcher Challenge Petroleum at Calauit Field has shown a potentialexploration play in deep-water Nido Limestone turbidites. The traditional and, to date, only economically productive play in northwest Palawan has been the Nido Limestone reefs. This paper presents a review of the old play types and presents new untested play types. These new play types include u • pre-Nido syn-rift plays; • pre-Nido marine turbidite play: and • mid-Miocene reefs. It also presents new insights into factors controlling reef development on the carbonate platforms where four reef types are now recognized. The Galoc Clastic Unit turbidite play is discussed and new play fairways presented.

The petroleum potential of deep-water northwestPalawan Block GSEC 66

This paper presents the results of the evaluation of the petroleum, potential of thedeep-water acreage of Philodrill, GSEC 66, or what the authors call the “Northwest Malampaya Block”. All the elements necessary for a major hydrocarbon accumulation are believed to be present in the block. Probable source rocks are the deep-water Nido Limestone, the pre-Nido Early Tertiary syn-rift section, and pre-Tertiary sediments. Potential reservoirs include the Nido reefal buildups, Nido and pre-Nido detrital and/or fractured carbonates, Early Miocene Galoc elastic equivalent turbidites and pre-Nido sediments. The principal play-types recognized in the area are the Late Oligocene to Early Miocene reefs and the erosional/karsted carbonate highs. After evaluation of available pre-1982 seismic data, an acquisition program of 1625 km was undertaken. Eleven leads/prospects were delineated in the area after the interpretation of this new seismic data. Two prospects were upgraded to drillable status (the Santa Monica Prospect and the Ipil Prospect). The Santa Monica Prospect is a well-defined four-way dip closure on the Nido Limestone with a vertical closure of over 1500 feet and an areal closure of over 20,500 acres. The Ipil Prospect is a gently closed feature developed at the Nido Limestone platform level with an areal closure of over 11,600 acres and a vertical relief of 400 feet. The technical merits of the delineated huge prospects, combined with the very favorable deep-water exploration terms of the Philippines and their proximity to the soon-to-be-developed Malampaya-Camago Field, make this block a very promising area for further exploration work.

Cenozoic compressional structures on the NE Atlantic margin; nature, origin and potential significance for hydrocarbon exploration

Compressional structures of Cenozoic age are ubiquitous features of the NE Atlantic margin between the western Barents Sea and offshore western Ireland. The structural suite includes simple domes or anticlines, reverse faults and broad-scale inversions. Our analysis focuses on a recently delineated group of structures in the Norwegian Sea, although these are placed in the context of similar features on the Barents margin, West of Shetlands, on the Faroes and their surrounding shelf, and in the Rockall Trough. Some (although not all) of the compressional anticlines were formed at the sites of pre-existing Cretaceous-Palaeocene depocentres. They show a multi-phase growth history. In the Norwegian Sea, particularly important phases occurred in the middle Eocene to early Oligocene and in the Miocene. We interpret the formation of these structures as a natural outcome of the transition to sea-floor spreading that occurred in the early Eocene. From this time, extremely thick sedimentary successions that had accumulated during some 300 million years of extensional tectonics were subjected to mild compression. The overall compressive stress field can be explained in terms of spreading in the adjacent ocean (ridge push) and by the distant effects of Alpine tectonics. In a plate-wide sense these effects can be regarded as two sides of the same coin. The origin of the Norwegian Sea structures is most easily visualized in terms of ridge push. NW-SE transfer zones, characteristic of the entire margin, are strongly implicated in these tectonics. A kinematic model is described that links significant structuring with a change in the spreading direction of Oligocene-Miocene age (35-20 Ma, A13-6). The compressional structures are mainly observed by their effect on sediments and volcanics of Cretaceous and Cenozoic age. They are frequently expressed in the present-day sea-floor relief, and in the case of the Faroe islands are probably responsible for present subaerial exposure. From the point of view of hydrocarbon exploration, the Cenozoic compressive anticlines have obvious potential as fourway dip closures or as components of structural-stratigraphic traps. The NW-SE fractures, orientated parallel or sub-parallel to the maximum horizontal stress direction, were probably periodically open for fluid flow from the time of NE Atlantic opening and onwards. They may therefore have facilitated migration from deeper source rocks or remigration from pre-existing hydrocarbon accumulations.

The Fife Field, UK central North Sea

The Fife Field is located in the far southeastern part of the Central North Sea Basin close to the UK, Norwegian, Danish median line. The field is a shallow relief four-way dip closure formed by inversion during Late Cretaceous/ early Tertiary times. The reservoir consists of thick Upper Jurassic, heavily bioturbated sandstones which are considered to have been deposited in a similar setting to the Fulmar Formation. The depth to the top of the Upper Jurassic at the crest of the field is 8250 ft sub-sea with the oil-water contact at 8512 ft sub-sea. The seal to reservoir is provided by Volgian-Ryazanian shales of the Kimmeridge Clay Formation and Upper Cretaceous Chalk. Although Jurassic sandstones form the primary reservoir, additional hydrocarbons have been encountered in the Tor Formation of the Chalk Group which is fractured over the crest of the field. The Fife Field was discovered in 1991 and is currently under development. Production started in August 1995 via the 'Uisge Gorm' Floating Production Storage and Offloading facility (FPSO). STOIIP is estimated at 132 x 106BBL and ultimate recovery is predicted to be 34 x 106 BBL oil. The low mobility of the oil and the low vertical permeability of the reservoir contribute to the predicted low (26%) recovery efficiencies.

Monobore Completions and Novel Wireline Perforating of High-Angle Wells in the Nelson Field

The Nelson field gas-lift completions were designed to optimize production, enhance safety and reliability, and minimize well-maintenance costs. The completions are of a near-monobore design and include an annular safety system, which is regarded as a major safety benefit during gas lift. The single-trip completions were batch installed in eight high-angle (up to 70{degree}) predrilled wells. This paper presents details of the completion design and the approach taken to planning and installing the completions. The paper also describes the use of a novel technique for perforating the platform wells with wireline guns.