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.

ABSTRACT This chapter dissects the petroleum systems of the South Viking Graben, and, in as far as data allow, starts with a discussion of the oils and gas-condensates in terms of their expulsion maturity spectra based on bulk, molecular, and isotopic properties of four molecular weight fractions (gas, gasoline, mid, and heavy) of the major accumulations. The Upper Jurassic source rocks are characterized in terms of the amount (total organic carbon), kerogen type (kinetics), and yield properties, the latter in units of million barrels of oil per square kilometers of mature source rock. Depth trends for temperature and maturity parameters are used, together with 1-D modeling, to derive an asymmetric basin-wide geothermal model based on variation of heat flow. This is generalized using 3-D modeling of seismic surfaces to define the source rock kitchens, the expelled volumes, the migration paths, and the hydrocarbon charges to major groups of traps. Charge volumes predicted by modeling are compared with reported in-place petroleum. The Brae member fan sands of the U.K. margin are the “closed” (close-coupled) end-member example of the generally “open” petroleum systems of the North Sea. While the Upper Jurassic Kimmeridge Clay–Draupne Formation source rocks explain the observed volumes and properties of oils, uncertainty remains on the properties and origin(s) of gas(es) required to explain the observed gas/oil ratios, gas compositions, and isotope profiles.

Abstract Coastal exposures of Mesozoic sediments in the Wessex basin and Channel subbasin (southern UK), and the Lusitanian basin (Portugal) provide keys to the petroleum systems being exploited for oil and gas offshore Atlantic Canada. These coastal areas have striking similarities to the Canadian offshore region and provide insight to controls and characteristics of the reservoirs. Outcrops demonstrate a range of depositional environments from terrigenous and non-marine, shallow siliciclastic and carbonate sediments, through to deep marine sediments, and clarify key stratigraphic surfaces representing conformable and non-conformable surfaces. Validation of these analog sections and surfaces can help predict downdip, updip, and lateral potential of the petroleum systems, especially source rock and reservoir.