Abstract The Howe and Bardolino fields lie in UK Blocks 22/12a and 22/13a, respectively, on the eastern flank of the Forties–Montrose High. The Howe Field was discovered in 1987 by well 22/12a-1, and Bardolino in 1988 with well 22/13a-1ST. Both share common Jurassic reservoirs, have Upper Jurassic Kimmeridge Clay Formation top seals, require some form of lateral seal and have similar fluids. Howe has been producing relatively dry oil throughout its production life, indicating relatively good connectivity across the field area. In contrast, the Bardolino accumulation is proven to be compartmentalized. Bardolino is likely to be segmented through some fault-related mechanism. In place volumes at the Howe Field are 46.8 MMbbl, with 17 MMbbl produced thus far through a combination of natural aquifer and solution gas cap drive by subsea development well 22/12a-9Z. In place volumes at the Bardolino Field are 11.2 MMbbl, with 1.1 MMbbl produced to date through depletion drive by a subsea development well 22/13a-8. This represents recovery rates of 35% for Howe and 10% for Bardolino to date. In place volumes for the undeveloped Pentland Formation at Howe are 5 MMbbl. In place estimates for the undeveloped Kimmeridge Clay Formation sandstones at Bardolino are 8 MMbbl.

Abstract The Golden Eagle Field is located 18 km north of the Buzzard Field in the Moray Firth, and consists of oil accumulations in the Lower Cretaceous Punt and Upper Jurassic Burns Sandstone members. The development area comprises three fields, Golden Eagle, Peregrine and Solitaire, but up to 90% of the oil-in-place and ultimate recovery are in Golden Eagle. The two satellite fields are primarily structural closures, while the Golden Eagle Field reservoirs have a major element of stratigraphic pinchout. Production commenced in October 2014 and approximately 140 MMbbl of recoverable oil is anticipated over its field life from the 19 development wells (14 producers and 5 injectors) that form the initial development phase. Production performance to date has exceeded expectations, aided through the use of completions that provide zonal control of the reservoir units which has successfully supported reservoir management and improved sweep efficiency. A number of significant lessons have been learned during the early stages of the field life from the integration of dynamic data (real-time downhole fibre-optic reservoir monitoring instruments, inter- and intra-well tracers, and well interference tests) and seismic data improvements (post-start-up acquisition of high-density ocean-bottom node seismic and depth-conversion improvements).

Abstract The Perth Field was discovered in 1983 and appraised from 1992 to 1997, but has remained undeveloped due to the lack of a suitable export solution for the sour fluids. The field is a combined structural–stratigraphic trap on the southern edge of the Tartan Ridge in the Outer Moray Firth. An oil column of >1000 ft is developed in the turbiditic Upper Jurassic Claymore Sandstone Member which is mostly 500–800 ft thick in the proven appraised Core Perth area. Reference case oil in place within Core Perth is estimated at 197 MMbbl. An undrilled northern terrace may contain a similar amount of oil, with an additional 40 MMbbl estimated to be in place in a separate, proven northeastern fault panel. Potential development by subsea tieback to the Scott platform became an option in 2017. P50 reserves for 15 years’ production from Core Perth (five producers and two water injectors) are estimated at 47.3 MMbbl (24% recovery factor). The preferred concept is for oil and gas to be processed on a new self-contained sour module located on a standalone structure at Scott with oil exported in the Forties Pipeline System. Sour gas would be incinerated in a dedicated flare with recovered hydrocarbon gas exported to Scott.

Abstract Hutton (discovered in 1973) and NW Hutton (discovered in 1975), together with Q-West (discovered in 1994) and Darwin (discovered in 1983, undeveloped), are part of a single petroleum system. The main fields were defined as two separate legal entities. Although Q–West covered multiple blocks, it was wholly developed via the Hutton platform. Together, Hutton and NW Hutton produced 328 MMbbl of oil and a small quantity of associated gas from Middle Jurassic Brent Group sandstones. The trap is a complex series of tilted fault blocks sealed by Mid–Upper Jurassic Heather and Kimmeridge Clay Formation mudstones. Oil was sourced from the Kimmeridge Clay Formation, which is mature for oil generation in the hanging walls to the field-bounding faults and deep on the footwall flanks. NW Hutton underperformed relative to Hutton. In part this was due to the poorer reservoir quality encountered at depth compared with the shallower Hutton Field but a significant component of the underperformance was due to the way in which the field was developed and then operated. Both fields contain areas of unproduced and unswept oil, with the NW Hutton portion having the largest remaining oil in place.

Abstract The Maria oilfield is located on a fault-bounded terrace in Block 16/29a of the UK sector of the North Sea, at the intersection of the South Viking Graben and the eastern Witch Ground Graben. The field was discovered in December 1993 by the 16/29a-11Y well and was confirmed by two further appraisal wells. The reservoir consists of shoreface sandstones of the Jurassic Fulmar Formation. The Jurassic sandstones, ranging from 100 to 180 ft in thickness, have variable reservoir properties, with porosities ranging from 10 to 18% and permeabilities from 1 to 300 mD. Hydrocarbons are trapped in a truncated rotated fault block, striking NW–SE. The reservoir sequence is sealed by Kimmeridge Clay Formation and Heather Formation claystones. Geochemical analysis suggests that Middle Jurassic Pentland Formation and Upper Jurassic Kimmeridge Clay Formation mudstones have been the source of the Maria hydrocarbons. Estimated recoverable reserves are 10.6 MMbbl and 67 bcf (21.8 MMboe). Two further production wells were drilled in 2018 to access unexploited areas.

Abstract The Pelican Field lies in the East Shetland Basin, in Block 211/26, roughly 150 km NE of the Shetland Islands. It was discovered in 1975 by exploration well 211/26-4. Development was delayed until 1995 when economic development became feasible as a subsea tie back to the Cormorant Alpha Platform. The reservoir is the Middle Jurassic Brent Group, comprising sands deposited in a fluvio-deltaic, shallow-marine, wave-dominated system. The reservoir interval has an average thickness of around 300 ft, ranging from 220 ft on the crest to 400 ft in down-flank areas. The crest of the field lies at around 10 500 ft true vertical depth subsea. Current estimate of oil in place for the field is c. 500 MMbbl. The Pelican Field suffers from significant deterioration of reservoir properties with depth, leading to low recovery factors of 15–20%. To date, 21 production and injection wells have been drilled recovering a total of 76 MMbbl. Oil production started in 1996 and peak oil production was achieved at 50 000 bopd in the same year. Rates declined due to water-cut development in most of the wells and current production rates are around 2000 bopd.

Abstract The Penguins Cluster of fields are owned jointly (50:50) by Shell UK Ltd (Shell) and Esso Exploration and Production UK Ltd (Esso), with Shell as the operator. The cluster was discovered in 1974 and is composed of a combination of oil and gas condensate accumulations located 50–65 km north of the Brent Field, at the northern end of the North Viking Graben. Two main producing reservoirs are present: the Penguins West Field (Penguin A) consists of an Upper Jurassic Magnus Sandstone Member reservoir, while the Penguins East Field (Penguin C, D and E) consists of a Middle Jurassic Brent Group reservoir, underlain by currently undeveloped Statfjord and Triassic (Cormorant) reservoirs. The Magnus reservoir is composed of turbidite sands with an average porosity of 15% and permeabilities of 0.10–300 mD. The Brent reservoirs are composed of deltaic shoreface deposits with an average porosity of 14% and permeabilities of 0.01–1000 mD. The fields were brought on stream in 2003 as a subsea development via what at the time was the world's longest comingled tieback to the Brent Charlie facility. A total of nine producing wells have been drilled from four subsea manifolds, producing c. 78 MMboe to date through depletion drive.

Abstract The Clair Field is a giant oilfield containing in the region of 6–7 Bbbl of stock tank oil initially in place, located approximately 75 km west of the Shetland Islands. As such, it represents the single biggest hydrocarbon accumulation on the UK Continental Shelf. Clair was discovered in 1977, but first production did not occur from Phase 1 until 2005, after a lengthy appraisal period. The major appraisal milestone occurred in 1991 after well 206/8-8 proved up fractured clastic red beds of the Devonian Lower Clair Group. This was followed up with an extended well test on 206/8-10Z, which demonstrated the longer-term performance of the reservoir. Further appraisal on Clair Ridge led to the sanction of the Clair Ridge, which came on stream in November 2018. Following the Greater Clair appraisal programme in 2013–15, development options are currently being worked for Clair South, which will develop the Lower Clair Group reservoirs together with overlying shallow-marine reservoirs of the Cretaceous and Jurassic.

Abstract The Solan Field is a Jurassic reservoired oil accumulation located in Block 205/26a in the East Solan Basin, West of Shetland. The field was discovered in 1991 by the 205/26a-4 well which encountered oil in the Kimmeridgian to Early Volgian age Solan Sandstone and appraised between 1992 and 2009 by four wells and four sidetracks. Premier Oil farmed into Licence P.164 in 2011 and became operator. The reservoir, which is up to 100 ft thick, is a basin-floor turbidite sequence and is informally subdivided into a thick and good quality Upper Solan sandstone unit and a thinner, poorer quality, Lower Solan sandstone unit, separated by the laterally extensive Middle Solan unit. Whilst the reservoir sandstones are relatively clean (texturally and compositionally mature) and laterally extensive, sub-seismic structural and stratigraphic complexity resulted in a challenging field development. The field development to date comprises four subsea wells (two oil producers and two water injectors) tied back to a small jacket and topsides with an innovative subsea oil storage tank. Oil export is via shuttle tanker. First oil was achieved in April 2016. The field oil in place volume is in the range of 55–85 MMbbl.

Abstract The application of production geochemistry techniques has been shown to provide abundant and often low-cost high-value fluid information that helps to maximize and safeguard production. Critical aspects to providing successful data relate to the appropriate sampling strategy and sampling selection which are generally project-aim-specific. In addition, the continuous direct integration of the production geochemistry data with subsurface and surface understanding is pivotal. Examples from two specific areas have been presented including: (a) the effective use of IsoTubes in the production realm; and (b) the application of geochemical fingerprinting primarily based on multidimensional gas chromatography. Mud gas stable carbon isotopes from low-cost IsoTubes have been shown to be very effective in recognizing within-well fluid compartments, as well as recognizing specific hydrocarbon seals in overburden section, including the selective partial seal for only C 2+ gas species. With respect to geochemical fingerprinting, examples have been presented related to reservoir surveillance including compartmentalization, lateral and vertical connectivity, as well as fluid movements and fault/baffle breakthrough. The production-related examples focus on fluid allocation within a single well, as well as on its application for pipeline residence times, fluid identification and well testing.

Abstract The Elgin–Franklin complex contains gas condensates in Upper Jurassic reservoirs in the North Sea Central Graben. Upper parts of the reservoirs contain bitumens, which previous studies have suggested were formed by the thermal cracking of oil as the reservoirs experienced temperatures of >150°C during rapid Plio-Pleistocene subsidence. Bitumen-stained cores contaminated by oil-based drilling muds have been analysed by hydropyrolysis. Asphaltene-bound aliphatic hydrocarbon fractions were dominated by n -hexadecane and n -octadecane originating from fatty acid additives in the muds. Uncontaminated asphaltene-bound aromatic hydrocarbon fractions, however, contained a PAH distribution very similar to normal North Sea oils, suggesting that the bitumens may not have been derived from oil cracking. 1D basin models of well 29/5b-6 and a pseudo-well east of the Elgin–Franklin complex utilize a thermal history derived from the basin's rifting and subsidence histories, combined with the conservation of energy currently not contained in the thermal histories. Vitrinite reflectance values predicted by the conventional kinetic models do not match the measured data. Using the pressure-dependent PresRo ® model, however, a good match was achieved between observed and measured data. The predicted petroleum generation is combined with published diagenetic cement data from the Elgin and Franklin fields to produce a composite model for petroleum generation, diagenetic cement and bitumen formation.

ABSTRACT The South Viking Graben (SVG) hosts many large oil and gas condensate reservoirs, some within Middle Jurassic and Cenozoic rocks, but most within thick submarine fan sandstone and conglomerate sequences of the Upper Jurassic Brae Formation and their correlative equivalents, collectively termed here the Brae Play. Regional studies carried out over the last few years (based on the extensive well database and a variety of 3-D seismic data) and the recent acquisition of extensive, high-quality, broadband 3-D seismic data across the SVG have led to better definition of the half-graben geometry and the extents of the Upper Jurassic submarine fans that host these hydrocarbon accumulations. A summary structure map, seismic sections that extend across the graben, and a 3-D image of the “Base Cretaceous” are used to illustrate the main structural features. On its western side, the top of an eroded scarp, which grades downdip into the major fault plane, can be used as the lateral limit of the postrift graben fill. The uppermost Kimmeridge Clay Formation (KCF; termed Draupne Formation in Norway), which is the top seal and dominant source rock for Brae Play fields, onlaps this eroded slope and limits the western extent of the synrift section. At depth, the top of the prerift Bathonian Sleipner Formation can be mapped along this fault margin abutting the uneroded footwall fault; this boundary defines the edge of the thickest Upper Jurassic synrift section within the graben. The top of the prerift section becomes progressively shallower to the east, where an approximate minimum limit of the graben can be defined along much of its length by the eastern limit of seismically mappable KCF (Draupne) Formation. Thick sequences of Upper Jurassic conglomerates and sandstones within the KCF (i.e., the Brae Formation) were deposited as submarine fans within the graben. Most sediment was derived from the west (i.e., the Fladen Ground Spur), but some important fan systems were fed from the east (i.e., the Utsira High). The maximum limits of these fan systems are delineated, aided by the use of lithofacies correlation, reservoir pressure, and biostratigraphic data; changes in fan distributions through the Late Jurassic are also shown. An updated palynological zonation scheme that has been widely used throughout the area is also presented. Although the area is in a mature stage of exploitation, further mapping using the most recent high-quality 3-D seismic, available extensive well datasets, and the mapped extents of the fan systems might lead to additional hydrocarbon accumulations being identified.

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 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 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 The Thelma field is the most southerly of three fields located in Block 16/17 of the U. K. sector of the South Viking Graben and is operated by CNR International (U.K.) Ltd. The Thelma field comprises two submarine fans, the northern Thelma fan and the southern Southeast Thelma (SET) fan, revealed by subsurface mapping. The two fans consist of both Upper Jurassic Brae (upper Oxfordian–lower Volgian) and sand-shale (middle Volgian) members of the Kimmeridge Clay Formation. The two fan depocenters are separated by a low net-to-gross central region high, which was overtopped or diverted around by turbidity currents that formed the younger sand-shale member. The Brae member contains conglomerates, pebbly sandstones, sandstones, and thin-bedded turbidites (TBTs) of deep-water association. Seismic data are generally poor in this area, and conceptual and reservoir geological models are primarily based on oil field core, wireline logs, and dynamic reservoir data. Three conceptual models were created to propose geological scenarios for field development: Concept A has the SET fan fed independently from the southwest, Concept B has the SET fan fed as an extension of the Thelma fan from the north, and Concept C has an SET fan fed by bypass across the central region high. Each concept has different implications for fan connectivity. Using detailed core descriptions from the Thelma field, state-of-the-art deep-water facies analysis, a new facies scheme, and known deep-water facies associations on the modern seafloor and outcrop analogs, we test the conceptual models to validate the geology. The large-scale organization of the architectural elements of the Brae and sand-shale members is not well understood. By reviewing coarse-grained deep-water processes and the rock fabrics that they produce as a framework for rock property distribution in coarse-grained deep-water systems, we aim to investigate their architectural style. We recognize a series of facies associations from detailed facies descriptions of the cored intervals and, by distilling these sedimentological trends, ascribe the associations to uncored intervals and use these as a basis for correlation and reservoir modeling in the Thelma–SET area. The model is built from cored sedimentary facies, and facies associations recognizable on core-calibrated well logs, and then matched with dynamic well data, to test conceptual models. By combining the conceptual geological models with dynamic well testing of reservoir behavior, we have a more robust understanding of the two fields. Thelma is a higher energy system, with strong aquifer support facilitated by channelized reservoir architecture and poor lateral shale continuity, whereas SET is a lower energy system with poor aquifer support because of persistent lateral continuity of shale caps on sandstone lobes, and with no deep channeling recognized.