ABSTRACT Upper Jurassic proximal submarine fan deposits form the reservoirs of three large oil and gas condensate fields in Block 16/7a at the western margin of the U.K. South Viking Graben. High-relief (up to 1670 ft [~510 m]) hydrocarbon columns are trapped by a combination of abutment against the graben margin fault system to the west, basinward slope away from the graben margin to the east, and lateral stratigraphic trapping against interfan fine-grained sediments. Gravel and sand were supplied to the fans by noncohesive debris flows and high-density turbidity currents down an eroded fault scarp from the platform area of the Fladen Ground Spur to the west. The South Brae and North Brae fields have pronounced conglomeratic channel systems in the upper part of the Brae Formation, which pass downdip into thick, laterally extensive (up to 25 km [16 mi]) basin-floor sandstone fans that host three other large fields, Miller, Kingfisher, and East Brae. The Central Brae field is contained within a more cone-shaped fan, with thick conglomeratic deposits in the most proximal area that grade downdip into a thick sandstone package of relatively limited basinward extent (approximately 7 km [4 mi] downslope). The fan systems of the Brae Formation are contained within the Kimmeridge Clay Formation, which is a world-class source rock and also provides the top seal for the fields. Numerous exploration, appraisal, and development wells, supported by seismic imaging and reservoir pressure and production data, allow the architecture of the proximal fan systems to be established. The best developed channel systems at South Brae, which occur in the upper part of the reservoir, are approximately 1 km (0.6 mi) wide and are separated by thick units of interchannel mudstones and thin sandstones. These channels widen and become unconfined downdip where they merge into the basin-floor fan systems. Channel-fill sequences, which can total around 300 ft (91 m) in thickness, typically comprise a unit of very thick-bedded conglomerates with minor interbedded sandstones, which is overlain by a unit of thick-bedded sandstones up to 100 ft (30 m) thick. In individual South Brae reservoir layers, several channels that radiate from a single sediment source area can be found. In contrast, a single prominent channel system exists at the North Brae field, where the channel facies are similar to those at South Brae, but the total channel thickness reaches 800 ft (244 m). On the southern flank of the North Brae field, thick sandstone lobes occur that are connected to the central channel, and on the north side of the field, separate channel systems exist, which contain hydrocarbons that are not connected to the main field area. At Central Brae, laterally extensive, poorly confined channel systems were probably the depositional avenues in the upper part of the reservoir, but the bulk of the reservoir comprises a stacked sequence of downdip elongated tongues of conglomerates and thinner sandstones, which pass downslope into thick-bedded sandstones. Fan systems, which evolved through time, began to develop in the Brae area in the mid to late Oxfordian (from around 160 Ma), during the initial phase of intense rifting, but the increased organization in sediment dispersal patterns and the extension of the fans into the basin center occurred from the late Kimmeridgian (about 152 Ma) as rift extension ceased. Coarse clastic deposition during the later phases of the fans was periodically interrupted by deposition of mudstones, probably as a result of episodes of high relative sea level temporarily flooding the source areas. Central Brae was the first fan to be abandoned, followed by the South Brae system, and finally the North Brae system in the earliest late Volgian (around 144 Ma), when the Fladen Ground Spur was finally transgressed. Fan abandonment appears to have been relatively rapid as good quality turbidite sandstones occur very close to the top of the final depositional systems in both the basin-floor and proximal locations.

ABSTRACT The structural evolution of the T-Block (U.K. 16/17) Brae Formation fields in the southern part of the South Viking Graben reflects a history of Late Jurassic rifting and Early Cretaceous inversion. Triassic rifting follows an inherited Caledonian trend, with Permian and Triassic depocenters to the northwest and southeast of a ridge trending north–northeast through the South Viking Graben from the area of the Thelma field. In the northern part of the area, in Trees Block (U.K. 16/12), halokinesis has created accommodation space for Middle Jurassic deposition. Further south, in T-Block, Middle Jurassic deposition does not appear to have been influenced by Caledonide structures. Rifting commenced in Trees Block in the early part of the Late Jurassic, with development of a north–south striking northern fault segment. The faulting propagated southward from the northern segment and northward from a segment to the south of T-Block, to create a relay zone opposite Thelma and Toni. At the segment centers, the fault throws are large, and the Middle Jurassic sequence dips to the west, toward the footwall. In comparison, at the Thelma relay zone, the fault displacements are much smaller, and the Middle Jurassic dips to the east. Flexural uplift and back-tilting have affected the footwall sediments and normal faults. The fault segment evolution is likely to have been a significant control on Brae sedimentation, the back-tilting of the footwalls at the segment centers funneling sediment supply into the Thelma relay zone, and footwall uplift providing emergent source areas adjacent to the developing graben. The basin morphology has been modified by postrifting thermal subsidence, increasing the eastward dip of the fault terraces. Inversion in the Early Cretaceous caused uplift of the hanging wall, creating a bulge over Thelma and Toni, and uplift on the fault adjacent to Trees Block. This inversion event is likely to be the result of oblique northwesterly compression, causing shortening and left-lateral strike-slip on the marginal faults. This event can be related to an unconformity between the Valhall and the Carrack formations, which constrains timing to the late Barremian–Aptian.

ABSTRACT Anticlines along the western margin of the South Viking Graben in the Brae area of the U.K. North Sea form the structural components of large structural and stratigraphic traps within Upper Jurassic Brae Formation submarine fan deposits. Various interpretations of the origin of these anticlines and their attendant inboard synclines at the graben boundary have been previously published, with both gravity-driven processes and inversion being invoked. Based on regional interpretation of 3-D seismic data sets and analysis of thickness variations in uppermost Jurassic and Cretaceous sequences in numerous wells, it is concluded that gravity-driven processes were more important than inversion. Differential compaction of mudstone-rich slope deposits laterally adjacent to coarse clastic submarine fan reservoirs has resulted in the field reservoirs now being at slightly higher elevations than the finer grained deposits along the length of the anticlines. Compaction of the very thick sandstone- and mudstone-dominated successions in the basin center has also been greater than that of the more conglomeratic successions adjacent to the basin margin, where sequences are underpinned by the slope of the footwall, resulting in over-steepened slopes toward the basin on the outboard side of the anticlines. Movement of Permian salt that underlies the Jurassic (and Triassic) in the basin has also had significant broad effects on the Upper Jurassic structures, creating depressions and underpinning some anticlines. Continued slow subsidence of the basin-fill down the main graben boundary fault system in the under-filled rift during the latest Jurassic and Early Cretaceous, above changes in footwall slope (from eroded slope to graben-boundary fault, or, in the case of East Brae, across a plunging basement nose) is considered to be the primary cause of the anticlines and their inboard synclines. Reversal of movement along the main boundary fault, causing inversion of the graben-margin sequences, is considered unlikely as the primary mechanism for anticline formation. Additional movement down the graben-boundary fault system in the early Maastrichtian may have slightly tightened the anticlines. Final minor fault movement along the graben margin occurred in the mid Eocene, but this is unlikely to have significantly affected the Brae structures. Some of the anticlines provide evidence of the presence of the underlying thick reservoir sequences (due to differential compaction over conglomeratic sections), but not all positive structural features contain coarse clastic sediments.

Abstract North Brae is located in Block 16/07a, and was discovered in 1975 by Pan Ocean Oil Company. The field was purchased by Marathon Oil Company in 1976 and was delineated in the early 1980s. Production by gas recycling was commenced in 1988. Liquid reserves are estimated at 207 MMBBLs with recoverable dry gas of 800 BCF. The North Brae Field is one of three gas/condensate fields in the Brae fields area of the South Viking Graben in the UK Sector of the North Sea. The reservoir is part of a large turbidite and debris flow, submarine fan system that also encompasses the East Brae and Kingfisher fields to the northeast of North Brae. North Brae is located at the proximal end of this fan system, and channelized massive conglomerates and sandstones characterize its reservoirs. The stratigraphy of the fan system was influenced by highly variable changes in relative sea level that controlled sediment input. Structural activity was also important, such as syn-sedimentary normal faulting related to the subsidence of the South Viking Graben, and structural inversion, in a series of regional compressive episodes commencing in the Late Jurassic and Early Cretaceous.

ABSTRACT Sixteen oil and gas fields have been discovered and developed along the western margin of the South Viking Graben in Quadrant 16 of the United Kingdom Continental Shelf. Late Jurassic extension created the graben, and submarine fan conglomerates and sandstones along its margin form most of the fields’ reservoirs. In the early 1970s, 2-D seismic was able to identify structures beneath the Base Cretaceous unconformity, which became the targets for initial drilling. The first well was Shell’s 16/8-1 in 1972, drilled toward the graben center. This well found hydrocarbons in interbedded sandstones and shales later developed as the Kingfisher field. Drilling in the more proximal Brae Formation conglomerates began in 1974 when 16/7-1 discovered the North Brae gas condensate field. However, an appraisal well to the south found an oil column, and this subsequently became Central Brae field. In 1976, drilling on another submarine fan two blocks to the south discovered the Thelma field. However, the key to developing the area was the discovery of the world-class South Brae oil field in 1978. This was rapidly appraised in the next two years and the Brae A platform was installed, with first oil produced in 1983. Meanwhile, the compulsorily relinquished portions of Blocks 16/7 and 16/8 were awarded to BP and Conoco, respectively, who discovered the Miller field extending across the block boundary in 1982. A further four platforms have been installed in the area: Brae B on North Brae, onstream in 1988; Miller in 1992; and East Brae and Tiffany in 1993. A further 12 fields have been developed by subsea tieback or by extended reach drilling. A billion barrels of oil and 7 tcf of gas have been produced from these fields.

Abstract The Marathon-operated West Brae Field straddles Blocks 16/06a and 16/07a in the UK Central North Sea approximately 140 miles (225 km) NE of Aberdeen. The field was discovered in 1975 with drilling of exploration well 16/07-2. The West Brae reservoirs consist of Eocene Balder Formation and Upper Sele Formation Sandstones that were deposited in NW-SE trending submarine channels across the area. Development of the field commenced in April 1997 with first oil being achieved in October the same year. The field has been developed using sub-sea tie-back to the Brae A platform, which lies 5.6 miles (9 km) SE of the sub-sea manifold. Recoverable reserves are estimated to be 60 MMBBLs, of which some 23 MMBBLs had been produced by 31 December 1999.

Abstract The Central Brae Oilfield is the smallest of three Upper Jurassic fields being developed in UK, Block 16/07a. The field was discovered in 1976 and commenced production in September 1989 through a sub-sea template tied back to the Brae ‘A’ platform in the South Brae Oilfield. The field STOOIP is 244 MMBBLs, and by May 1999 cumulative exports of oil and NGL reached 44 MMBBLs. The Central Brae reservoir is a proximal submarine fan sequence, comprising dominantly sand-matrix conglomerate and sandstone with minor mudstone units. The sediments were shed eastwards off the Fladen Ground Spur and were deposited as a relatively small and steep fan at the margin of the South Viking Graben. Mudstone facies border the submarine fan deposits to the north and south, forming stratigraphic seals. The structure is a faulted anticline developed during the latest Jurassic and early Cretaceous, initially formed as a hangingwall anticline during extension but subsequently tightened during compressional phases. The western boundary of the field is formed by a sealing fault, whilst to the east, there is an oil-water contact at 13 426 ft TVDss. The overlying seal is the Kimmeridge Clay Formation, which also interdigitates with the coarser facies basinwards and provides the source of the hydrocarbons.

Abstract The East Brae gas condensate field is the most northern of the four Upper Jurassic fields operated by Marathon Oil UK Limited in the UK North Sea. The field lies at the western margin of the South Viking Graben in UK Blocks 16/03a and 16/03b. The field was discovered in 1980 and commenced production in December 1993 from the East Brae platform. Recoverable reserves are estimated as 242 MMBBL of condensate and 1530 BSCF of sales gas. The reservoir is composed predominantly of medium grained sandstones which were deposited by turbidity currents. The East Brae reservoir sequence is currently interpreted to be the basin floor lateral equivalent of the North Brae feeder system to the southwest. The structure is a faulted anticline developed during the latest Jurassic and early Cretaceous in response to regional compression. The reservoir is enclosed by the Kimmeridge Clay Formation, which also interdigitates with the coarser facies basinwards, and provides the source of the hydrocarbons.

Abstract The South Brae Oilfield lies at the western margin of the South Viking Graben, 161 miles NE of Aberdeen. Oil production began in July 1983 from a single platform located in 368 ft of water. The field STOOIP is 795 MMBBLs, and in May 1999, cumulative exports of oil and NGL reached 265 MMBBLs. The reservoir lies at depths in excess of 11 800 ft TVDss, has a maximum gross hydrocarbon column of 1670 ft, and covers an area of approximately 6000 acres. The reservoir consists of Upper Jurassic Brae Formation sandstones and conglomerates deposited as submarine fan complexes that are downfaulted against tight sealing rocks of probable Devonian age at the western margin of the field. The other field margins are constrained by a combination of structural dip and stratigraphic pinchout. The reservoir is capped by, and interdigitates with, organic rich mudstones of the Kimmeridge Clay and Brae Formations. This intimate association of source rock and reservoir facies allows for short migration routes into the reservoir.

ABSTRACT Heterogeneity in hydrocarbon reservoirs has significant impact on fluid flow during production and may lead to oil being trapped in low-permeability reservoir compartments. This is particularly true for producing turbidite fields with significant thin-bedded turbidite (TBT; 3–10 cm [1.2–3.9 in.] sand and silt unit) and very thin-bedded turbidite (VTBT; 1–3 cm [0.4–1.2 in.] sand and silt unit) successions. The principal geological attributes used to characterize TBT–VTBT include facies and facies associations, sandstone/mudstone ratio, bed geometry, sand connectivity, sediment texture, sedimentary structures, and vertical sequences of bed thickness. Their combination enables definition of four fundamental attribute indices that reflect the reservoir quality of TBT–VTBT successions. The attribute indices are sand connectivity index, sediment textural index, facies ratio index, and facies net-to-gross index. Twenty TBT and VTBT facies are recognized in cores from North Brae field wells. The combination of results from the application of the attribute indices approach to core data from the field reveals six facies associations (FA), which may also be applicable elsewhere, each characterized by different attribute indices. FA1 has high-to-very-high sand connectivity and textural indices (mature, fine-medium-grained, well-sorted sand). Its core-based porosities and horizontal and vertical permeabilities indicate that it possesses the most favorable reservoir properties. For FA2, a lower sand connectivity index because of extensive mudstone lamination signals poorer quality reservoir features. FA3 and FA4 show moderate attribute indices and mixed reservoir quality facies, whereas more studies are needed to determine the suitability of FA5 and FA6 for potential shale gas exploitation in other areas.

Abstract The Brae fields, operated by Marathon Oil (UK) Limited, are situated in Block 16/7 in the UK, North Sea. The first of the Brae fields was discovered in 1975 with the testing of a rich gas condensate accumulation, later named North Brae. Further drilling led to the discovery of three oilfields, West, Central and South Brae, and appraisal drilling concentrated on South Brae. After four wells had been drilled to appraise South Brae a fan delta sedimentary model was developed to explain the geology. The South Brae plan of development was based on this model. Early development drilling in 1983/4 came up with major surprises and indicated that the reservoir system was more complex than originally assumed. As the planned production profile appeared difficult to achieve a combined study involving geophysical, geological and reservoir engineering was instigated to understand the geological model and achieve optimal well locations. The available 2D seismic, although lacking in quality and resolution, was an essential part of this study. After a new geological model had been developed further development wells were more successful. This enabled the field to achieve predicted production rates and enabled an effective water-flood to be put in place to improve recovery. By 1982 North Brae had been appraised and the development plan for this reservoir was assessed using a compositional reservoir stimulator. Gas cycling with partial pressure maintenance was selected as the best development option. Prior to the platform being installed in 1987 a 3D seismic programme was completed. With experience gained from South Brae and integrating geological and geophysical interpretations a refined geological model was rapidly and efficiently developed. Subsequent development drilling was highly successful and the field produced at plateau rates earlier than expected. Reservoir simulation incorporating the complex geology confirmed that gas cycling was indeed the best option and that excellent recoveries could be expected. The multi-disciplinary study on South Brae successfully achieved its objectives and using the experience gained from this study enabled the development of North Brae to be rapidly optimised with excellent results.

Abstract The Braefields,operated by Marathon Oil (UK) Limited, are situated in Block 16/7 in the UK, NorthSea. The first of the Brae fields was discovered in 1975 with the testing of a rich gas condensate accumulation, later named North Brae. Further drilling led to the discovery of three oil fields, West, Central and South Brae, and appraisal drilling concentrated on South Brae. After four wells had been drilled to appraise South Brae a fan delta sedimentary model was developed to explain the geology. The South Brae plan of development was based on this model. Early development drilling in 1983/4 came up with major surprises and indicated that the reservoir system was more complex than originally assumed . As the planned production profile appeared difficult to achieve a combined study involving geophysical, geological and reservoir engineering was instigated to understand the geological model and achieve optimal well locations. The available 2D seismic although lacking in quality and resolution was an essential part of this study. After a new geological model had been developed further development wells were more successful. This enabled the field to achieve predicted production rates and enabled an effective waterflood to be put in place to improve recovery. By 1982 North Brae had been appraised and the development plan for this reservoir was assessed using a compositional reservoir simulator. Gas cycling with partial pressure maintenance was selected as the best development option. Prior to the platform being installed in 1987 a 3D seismic programme was completed. With experience gained from South Brae and integrating geological and geophysical interpretations a refined geological model was rapidly and efficiently developed. Subsequent development drilling was highly successful and the field produced at plateau rates earlier than expected. Reservoir simulation incorporating the complex geology confirmed that gas cycling was indeed the best option and that excellent recoveries could be expected. The multi-disciplinary study on South Brae successfully achieved its objectives and using the experience gained from this study enabled the development of North Brae to be rapidly optimised with excellent results .

Abstract The understanding of the reservoir in the West Brae field in the North Sea has improved because of the incorporation of reprocessed seismic data into reservoir characterization and modeling. The field was discovered in 1975 with initial production in 1997 from two early Eocene turbidite sands in the Balder and Sele formations (Flugga sand member). Both turbidite sands are of good quality, with an average porosity of 30%, an average net-to-gross ratio of 85%, and permeability up to 7500 md. The field produces mainly black oil (22° API) with a dry gas cap and has two distinct oil-water contacts. A high-quality four-dimensional seismic data set was acquired in 2007, which was parallel processed with the 1993 baseline seismic data. These new data prompted a rebuild of the reservoir model to assess the potential for bypassed hydrocarbons. The West Brae model is the result of a multidisciplinary reservoir characterization study that has incorporated attributes from the 1993 reprocessed seismic survey into the static geologic model. The key to incorporating the three-dimensional seismic data into the reservoir model was an elastic simultaneous inversion attribute that clearly identified the good-quality reservoir sands. The integration of the new seismic data into the West Brae reservoir model has improved reservoir understanding by (1) providing a stratigraphic framework for the geomodel, (2) refining the depositional model, and (3) creating more consistency in the geostatistical distribution of reservoir properties in the model. Colocated cokriging of the well data and a “soft” seismic attribute volume (Poisson impedance) has helped reduce the uncertainty of sand distribution and the prediction of flow potential in the West Brae field. This case study has shown that using a multidisciplinary team (geophysics, geology, petrophysics, and reservoir engineering) and an integrated data set significantly reduces the uncertainty for a reservoir characterization study.

ABSTRACT Synrift to early postrift Upper Jurassic submarine fan sequences form the reservoirs of numerous large oil and gas condensate fields in the South Viking Graben. The largest of these fields are in the Brae area, on the western side of the graben. Here, proximal conglomerate and sandstone facies of the Brae Formation host the South Brae, Central Brae, and North Brae fields, each within its own discrete submarine fan unit. More distal, basin-floor sandstone facies derived from the later episodes of South Brae and North Brae fan activity host the Miller, Kingfisher, and East Brae fields. Interfan areas comprise thick sequences of fine-grained sediments, which provide very significant lateral stratigraphic trapping elements for all the fields. An extensive well and seismic data set now allows a more detailed tectonostratigraphic evaluation of the Jurassic reservoir sequences in the context of the development of the graben and footwall than was previously possible. The submarine fans resulted from the uplift of the Fladen Ground Spur footwall to the west, with the consequent erosion and redeposition into the graben of very large volumes of gravel, sand, and mud. A prerift sequence of the Bathonian alluvial to paralic Sleipner Formation, which culminated with deposition of an extensive coal unit, extends across the graben and was probably also deposited on the footwall. Late Jurassic rifting began in the early Callovian, with deposition of the Hugin Formation in a shallow marine setting, with sand and mud supplied from the low-relief platform area to the west. Episodes of abrupt but slight deepening of the basin, caused by initial fault movements at the graben boundary, are suggested by numerous sharp-based coarsening-upward sequences within this formation. Following a period of apparent quiescence, when the Fladen Ground Spur may have been flooded, the main rift phase began in the late Oxfordian when subsidence of the graben margin and uplift of the footwall resulted in a deep marine trough and subaerial relief on the footwall probably totaling several thousand feet (hundreds of meters). Early submarine fan systems are likely to have been relatively unorganized cones of conglomerate and sandstone deposited from noncohesive debris flows and high-density turbidity currents. Fan systems became more organized upward as accommodation space close to the graben margin was filled following the climax of rifting in the late Kimmeridgian, and two large proximal to basin-floor fan systems developed at South Brae and North Brae, with conglomeratic channels in the proximal areas and sheetlike sandstone units on the basin floor. In the later stages of Brae Formation deposition, the top of the footwall is likely to have been close to sea level, which allowed periodic flooding of the source area and deposition of regionally extensive, relatively thin mudstone units across the fans, which act as internal reservoir baffles within fields. At the peak of fan deposition, during the early Volgian, the three main fan systems in the area (the South, Central, and North Brae fans) plus several smaller fans were all active. However, fans became inactive sequentially, with deposition first on the Central Brae, then on the South Brae, and finally on the North Brae fans ceasing relatively abruptly as the Fladen Ground Spur was progressively transgressed. Deposition of mudstones of the Kimmeridge Clay Formation, which are the hydrocarbon source rocks and the top seals for the fields and with which the Brae Formation interdigitates, continued after fan deposition ceased, into the earliest Cretaceous. The current sub-Upper Jurassic basement rock types of the footwall in the immediate area of the Brae fields comprise well-lithified Devonian sandstones and a significant but minor area of Silurian granite. However, the origin of the coarse clastic detritus, particularly the sands, within the Upper Jurassic fan systems was not simply a result of erosion of these rock types. Regional mapping and provenance studies suggest that a considerable thickness of Middle Jurassic, Triassic, and Permian sedimentary rocks previously overlay the present-day basement rocks of the footwall. These strata were probably almost completely eroded from the area immediately west of the fields where footwall uplift is likely to have been the greatest and redeposited into the graben during the Late Jurassic.

ABSTRACT Facies models for deep-water resedimented conglomerates have not changed a great deal since the 1970s and 1980s, but modern reservoir modeling for hydrocarbon fields requires a modified approach to facies classification. The Brae trend of the South Viking Graben, North Sea, comprises a whole suite of turbidite architectural styles, built from a wide range of bed types, which are interpreted to extend over the entire range of deep-water sedimentary process and product. Many questions can be answered about facies and facies models using what we know about the Brae fields, outcrop analogs, and modern sea-floor studies. What types of bodies are constructed on the slope, intraslope, and basin floor, where conglomeratic lithofacies are common? What are the basic rock fabrics and how should these be interpreted and upscaled into meaningful reservoir flow units? What can be correlated and at what scale? Are there basin margin-wide events that mark phases of particular sedimentary events, and what roles do sea-level change and tectonics have on these pulses of sedimentation? This chapter has one central aim, to propose a comprehensive, practical rock fabric (here called “lithofabric”) model for the entire range of deep-water clastic rock fabrics. This work draws on several kilometers (several thousand feet) of detailed core descriptions from Thelma and Tiffany (CNR International operated fields), and the Inverewe prospect in the North Sea, in conjunction with outcrop and sea-floor examples from Turkey, California, Wales, and circum-Mediterranean Sea areas. Particular focus is given to conglomerates and pebbly sandstones, to capture lithofabric variations. The scheme focuses on fabric instead of on the interpretation of every event that led to every bed or bedset. This approach is particularly critical in amalgamated bedsets where the interpretation of bed boundaries is often subjective. The approach allows workers to focus on and capture vertical changes in rock fabric in core or in the field, without the need to define every bed boundary or distinguish bed boundaries from “intraevent” fabric changes. The aim is to move away from the “event bed” approach to describing deep-water facies, which involves interpretation during the description stage, particularly for coarser lithologies and structureless sandstones. This chapter starts with a review of current facies models and process-interpretation schemes for rock fabric, outlining their strengths and weaknesses. The new approach for describing lithofabric is then presented. Models are offered for the variety of lithofabrics produced by higher energy, coarser grained turbidity currents and debris flows. The various parent flows that can produce structureless sandstones are shown diagrammatically, to illustrate how similar fabrics can be produced by different processes. A series of models are shown, comparing existing proximal to distal facies-distribution models with the new scheme, highlighting differences and consolidating commonalities.

Abstract In the dynamic process of finding and producing oil and gas today, the utilization of computer enhance team technology is becoming increasingly important. During an era of eroded product prices, the need for low cost reserve replacement and optimized exploitation of producing fields is critical to the attainment of competitive rates of return on invested capital. The ramifications of the business environment on exploration and production organization, staffing, location and focus have been numerous and significant. The traditional organization of oil and gas companies was along discipline lines with little effort to integrate the professional skills of geology, geophysics, engineering and land management. In the last five years, there has been a meaningful restructuring of many exploration and production organizations. New multi-discipline teams encourage the technical interaction of geologist, geophysicist, engineer and land manager. Utilization of integrated data base systems and networked interactive workstations provide efficient access to the information needed to problem solve, interpret, and evaluate multidisciplinary projects. The effective blend of hardware and software, skilled professionals, team dynamics and a focused work plan is proving to be a competitive advantage. The results of such groups are being documented by many exploration, development and reservoir management successes. Publication of successful multidisciplinary team results is being seen more frequently in the industry's technical literature. Documented examples at Bay Marchand, Cognac, Eugene Island 360/361 and the Brae fields provide evidence of the improved understanding produced when geophysical, geological, petrophysical and production data are effectively integrated. Reserves added in these cases are