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Otter is the most north-westerly of the Brent Province fields of the Northern North Sea, located in UK blocks 210/15a and 210/20d, 530 km north of Aberdeen, operated by TOTAL with partners Shell U.K. Exploration and Production, ExxonMobil and Dana. The field was discovered by the Phillips 210/15-2 well in 1977 (then called Wendy) and appraised by Fina well 210/15a- 5 in 1997, following 3D seismic acquisition in 1994. Decision to proceed with development was confirmed after the success of appraisal well 210/15a-6 drilled by TotalFina in 2000. The Otter structure is an easterly dipping tilted panel that is divided into four major blocks and several minor blocks by a network of subsidiary faults. The reservoir is the Middle Jurassic Brent Group, with the uppermost Tarbert Formation shallow marine sandstones comprising the main producing target. The oil source rock is the Late Jurassic Kimmeridge Clay, present in the offstructure areas, though locally absent over the Otter field area, top seal being provided by the Mid to Late Jurassic Heather shales. The Otter oil is a medium gravity crude (36.5° API) with a GOR of 79m3/m3 (443 scf/bbl), in a normally pressured reservoir at a crestal depth of 1970m subsea. The core displays from the 210/15a-5 and 210/15-2 wells, illustrate the major reservoir target of the Tarbert, the upper contact with the Heather Formation caprock and the facies variations in the underlying channelised Ness formation. The 2002 to 2003 Otter field development drilling campaign utilised a combination of detailed trajectory planning and integrated geosteering techniques, including real time transmission of borehole image data and wellsite chemostratigraphy. The objective of this work was to maximise oil recovery, with a minimum number of wells, from the complexly faulted Otter structure. To achieve this, sub-horizontal production wells were planned to track near top reservoir, through the structural culminations, to connect adjacent fault blocks. Illustrations of this work are presented in the accompanying poster displays.

The 2002 to 2003 Otter Field development drilling campaign utilized a combination of detailed trajectory planning and integrated geosteering techniques. The objective of this work was to maximize oil recovery, with a minimal number of wells, from the complexly faulted Otter structure. To achieve this, subhorizontal production wells were planned to track near top reservoir, through the structural culminations, to connect adjacent fault blocks. Otter is the most northwesterly of the Brent Province fields of the Northern North Sea, located in UK blocks 210/15a and 210/20d, 530 km north of Aberdeen, operated by TOTAL with partners Shell U.K. Exploration and Production, ExxonMobil and Dana. The field was discovered by the Phillips 210/15-2 well in 1977 (then called Wendy) and appraised by Fina well 210/15a-5 in 1997, following 3D seismic acquisition in 1994. The decision to proceed with development was confirmed after the success of appraisal well 210/15a-6 drilled by TotalFina in 2000. The Otter structure is an easterly dipping tilted panel that is divided into four major blocks and several minor blocks by a network of subsidiary faults. The reservoir is the Middle Jurassic Brent Group, with the uppermost Tarbert Formation shallow marine sandstones comprising the main producing target. The oil source rock is the Late Jurassic Kimmeridge Clay, present in the off-structure areas, though locally absent over the Otter Field area. Top seal is provided by the Mid- to Late Jurassic Heather Shales. The Otter oil is a medium gravity crude (36.5° API) with a GOR of 79m 3 /m 3 (443 scf/bbl), in a normally pressured reservoir at a crestal depth of 1970m subsea. Otter well planning was conducted using a 3D geocellular model based on interpretation of both conventional and acoustic impedance inversion seismic datasets. Apilot study, prior to development drilling, included geochemical and petrophysical reservoir unit definition and the forward modelling of LWD log response in sub-horizontal wells. The results of these studies were used to aid geosteering, incorporating real time chemostratigraphy and LWD data at the wellsite. In addition, borehole resistivity images while drilling were used to assist in structural interpretation in real time and thus to guide the well trajectory to maximize the pay section. A key component in using these new technologies was the office-based integration of all the data via web-based monitoring of the operations. Three production wells target the culminations at the extremities of the Otter Field, supported by a downdip water injector, all drilled from a centrally located subsea template. Following the successful drilling of the first production well, 210/215a-T1, production start-up was in October 2002, via subsea tieback to the Eider facility.

Piper was discovered in 1972 by the 15/17-1A well, located on a 4-way dip closed structure on the northern flank of the Witch Ground Graben. Appraisal drilling through 1973 showed the field to comprise four gently folded, tilted fault blocks with productive reservoirs in Late Jurassic paralic to shallow marine sandstones (Sgiath and Piper formations). Production commenced in 1976 and until the Piper Alpha disaster of 1988, the field had produced 834#106 bbl oil out of the then estimated recoverable reserves of 952#106 bbl. Redevelopment started by pre-drilling 1 injection and 7 production wells based on 1990 reprocessed 3D seismic, prior to the installation of the Piper Bravo platform in 1993. A study of permeability repartition and sweep efficiency, combining existing and new well data from cores, logs, pressures and fluid distribution, aided the optimization of well locations. In addition, a new 3D seismic survey was acquired in 1992–3. Advantageous fluid redistribution and natural aquifer repressurization of the reservoirs occurred during the 4Y years of production shutdown. By mid-1996, 12 production and 4 injection wells were in operation. Piper Bravo wells redeveloped three of the four fault panels, using half of the number of wells in operation at the time of the Piper Alpha disaster. The production rate has been significantly increased over the projected 1988 decline and a much lower water cut achieved. The ultimate recovery for the Piper field is now estimated at 1014#106 bbl oil (73.4%), an increase of 62#106 bbl over the pre-redevelopment figure.

Multiple episodes of extensional tectonism dominated the formation of Mesozoic fault-bounded basins on the Grand Banks of Newfoundland, the Irish Continental Shelf and the central North Sea. A range of structural and stratigraphic responses in the Jeanne d'Arc, Porcupine and Moray Firth basins support widespread synchronous tectonic controls on sedimentation during one of these episodes, the Late Cimmerian. Rifting was preceded by a phase of related tectonism during which subsidence rates began to vary across broad areas but without significant fault block rotation. This Late Cimmerian ‘onset warp’ pattern of subsidence is considered to have been essential in the establishment of restricted anoxic basins from latest Oxfordian through Kimmeridgian (sensu gallico) time and the development of one prolific layer of organic-rich source rocks. The most prominent and widely recognized structural/lithostratigraphic response to Late Cimmerian rifting was the deposition of sediment wedges. Tithonian to early Valanginian strata generally thicken- into northerly trending faults in the Jeanne d'Arc and Porcupine basins, indicating that extensional stress was orientated WNW-ESE across a very broad area. The misalignment of this regional Late Cimmerian extensional stress with local inherited structural fabric may be responsible for transpressional uplift of individual fault blocks in the Outer Moray Firth basin. Sedimentological responses to Late Cimmerian rifting were varied, though a common lithofacies stacking pattern is recognized. Variably thick conglomerates and/or sandstones were widely deposited at the start of rift deformation, while palaeoenvironments ranged from alluvial and braid plain to submarine fan even within individual basins. The relatively coarse basal sediments fine upwards into a second layer of commonly organic-rich shales and mark The widest variations in palaeoenvironments and sediment thicknesses occurred during the last phase of Late Cimmerian rift tectonism, though all three basins show evidence of decreasing water depths, increasing oxygen levels and increasing grain size. This lithofacies stacking pattern of relatively coarse to fine to coarse (reservoir/source/reservoir) and the development of bounding unconformities are largely attributable to progressive changes in rift-controlled subsidence. Rift basin subsidence rates are interpreted to increase from a low at initiation of faulting to a mid-rift peak, followed by slowing subsidence to the end of extension. A number of counteracting crustal mechanisms that may account for progressive variations in rift-induced subsidence are considered.

Three discrete turbidite sandstone bodies form the Scapa Sandstone Member reservoir units within the limestone, marl and conglomerate sequence of the Early Cretaceous Valhall Formation in the Scapa field (UK North Sea Block 14/19). Eighteen palynological zones have been established for the Valhall Formation, designated as VA in the early Aptian through VR in the latest Ryazanian. Scapa reservoir sandstones are restricted to the late Hauterivian VF to early Valanginian VQ zones. Black, anoxic mudstones of the Fischschiefer Member form a widespread intra- early Aptian correlation marker at the base of zone VA in the upper Valhall Formation.

The paper adresses the stratigraphic and structural evoulution of offshore SW Oman. The Cirle Oil operated Block 52 comprises 91,000 sq km of the region ranging in water depth from the shoreline to greater than 3000m. Aspects of the petroleum system and petroleum prospectivity are presented.

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

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

C039 Applied Seismic Stratigraphy in the Prinos Basin Offshore NE Greece S.D. Harker (PGS Reservoir) & A.J. Burrows* (PGS Resrvoir) SUMMARY The application of seismic stratigraphic and structural analysis has led to an understanding of the Late Tertiary sedimentary succession and evolution of the Prinos Basin. A total of five Miocene sequences and one Pliocene-Recent sequence have been recognised using the seismic signatures from 2D and 3D surveys that have been tied to the available wells. The basin contains the eponymous Prinos oil field one of the few producing hydrocarbon resources in Greece. It is located offshore in the Northern

Oil-bearing Upper Jurassic Oxfordian-Kimmeridgian sandstones of the Sgiath and Piper formations are of major economic importance in the Witch Ground Graben, United Kingdom North Sea. They form the reservoirs in 14 fields that originally contained 2 billion bbl of oil reserves, including Scott field, which in 1993 will be the largest producing United Kingdom North Sea oil field to come on stream in more than a decade. The Sgiath and Piper formations represent Late Jurassic transgressive and regressive phases that began with paralic deposition and culminated in a wave-dominated delta system. These phases preceded the major graben rifting episode (late Kimmeridgian to early Ryazanian) and deposition of the Kimmeridge Clay Formation, the principal source rock of the Witch Ground Graben oil fields. A threefold subdivision of the middle to upper Oxfordian Sgiath Formation is formally proposed, with Scott field well 15/21a-15 as the designated reference well. The basal Skene Member consists of thinly interbedded paralic carbonaceous shales, coals, and sandstones. This is overlain by transgressive marine shales of the Saltire Member. The uppermost Oxfordian Scott Member consists of shallow marine sandstones that prograded to the southwest (a precursor of the Kimmeridgian wave-dominated delta sequence of the Piper Formation, which prograded to the south and to the west). The contact of the Sgiath and Piper formations is a basinwide transgressive marine shale (I shale), which can act as an effective barrier to fluid communication between the Sgiath and Piper reservoir sandstones. The recognition of transgressive marine shales, or maximum flooding surfaces, is of great use in understanding regional geological history and in solving exploration and development problems.

Extensional tectonism is clearly a major factor in the formation of sedimentary basins. Tectonism influences many of the factors which control sediment deposition and preservation including: rates and styles of basin subsidence, accommodation space, drainage area size and topography, and rates of sediment input. These tectonically-influenced factors are interrelated and their local interplay determines, to a great extent, the formation, composition and structural style of sedimentary sequences.