Abstract Core-based studies have had material impacts on the understanding of a number of late-life, mature North Sea Brent Group hydrocarbon reservoirs. These studies have included sedimentological, diagenetic and reservoir quality focused evaluations of core. The primary objective of the studies has been to improve conceptual and qualitative models that can be utilized in reservoir modelling and also for infill drilling and well workover evaluations. Most of these studies have been undertaken on old core samples collected in the 1980s and 1990s. Two case studies are described here that provide examples of the utility of core in mature fields. (1) Heather Field calcite: to quantitatively assess the distribution of calcite cements and their impact on hydrocarbon volumes and reservoir quality distribution in Brent reservoirs. (2) Thistle Field Etive Formation barriers and baffles: to characterize and describe the origin and distribution of low-permeability intervals within the Etive Formation reservoir. These two studies used a wide variety of core-based techniques including core logging and description, optical microscopy and petrographical studies, isotope analyses, X-ray diffraction (XRD) and scanning electron microscopy-energy dispersive X-ray spectroscopy (SEM-EDS) (FEI Company analysis tool and software, QEMSCAN)-based mineralogy, portable-X-ray fluorescence (XRF), NDTr and Thermo Scientific Inc. NITON TM operational software (NDT) geochemical analysis, as well as image analysis of grain size and texture. These data were then integrated with other subsurface datasets, such as well log, seismic data and well performance data, in order to address the specific reservoir challenge. These new and focused reappraisals of core demonstrate the dual value of core-based studies, which can: improve the understanding of producing hydrocarbon reservoirs, leading to improved productivity and recovery. Core is a full asset life-cycle resource and provides critical insight at all stages of field maturity as production behaviour changes and alternative development strategies are considered; further our general knowledge and understanding of clastic sedimentology and diagenesis using rich and diverse core-based datasets backed up by substantial well log and seismic datasets.

Abstract This chapter describes Middle Jurassic second-order sequences J20 and J30, and their component third-order sequences, J22–J26 and J32–J36. The J22 sequence contains the major Intra-Aalenian Unconformity (‘Mid-Cimmerian’) across a wide area of the North Sea Basin and an equivalent event onshore UK. The base J24 (Lower Bajocian) is marked by the Rannoch Shale (Brent Group) and by the flooding of the Ollach Sandstone, Hebrides Basin. The base J26 (Upper Bajocian) ties to the Mid Ness Shale (Brent Group) and the base of the Upper Trigonia Grit Member, central England. The base J32 (Upper Bajocian) ties to the base of the Tarbert Formation, the base of the Great Oolite Group in central England and the base of the Great Estuarine Group, Hebrides Basin. The base J33 (Middle Bathonian) falls within the Tarbert Formation and the base of the Taynton Limestone, central England. The base J34 (uppermost Middle Bathonian) commonly falls at the top of the Brent Group. The base J36 (uppermost Bathonian) represents a major increase in marine influence, at the base of the Beatrice Formation, in the Inner Moray Firth and at the base of the Staffin Bay Formation, Hebrides Basin.

Abstract The most important North Sea Jurassic–lowermost Cretaceous lithostratigraphic units, as developed in the UK, Norway and Danish sectors, are summarized in this chapter (55 units from the UK, 25 from Norway and 10 from Denmark). Some significant issues remain with the use and application of lithostratigraphic terminology in the Jurassic of the North Sea Basin. In particular, there are inconsistencies in unit definition and nomenclature changes across country sector boundaries that obscure the recognition of regional stratigraphic patterns that exist across the region. To aid clarity and to overcome some issues of definition, some revisions are made to the existing lithostratigraphic schemes. Several informal lithostratigraphic units are described, a number of unit definitions are revised and various formerly informal units are formalized (Buzzard Sandstone Member, Ettrick Sandstone Member and Galley Sandstone Member). It is recommended that use of the Heno Formation in offshore Denmark is discontinued. In addition, four new lithostratigraphic member terms are introduced (Home Sandstone Member, North Ettrick Sandstone Member, Gyda Sandstone Member and Tambar Sandstone Member). All described units are placed into a sequence stratigraphic context. All significant lithostratigraphic boundaries conform with key sequence stratigraphic surfaces.

Abstract The most recent advance in infrared spectroscopy is in the use of real-time imaging reflectance spectrometers to study cores and cuttings. These are non-contact and non-destructive, and acquire continuous mineral and hydrocarbon data in a detailed sub-millimetre pixel image format. The main strength of this approach is the unique ability to accurately discriminate and quantify the clays, carbonates and sulfates, along with hydrocarbon information. Three hyperspectral core-scanning projects from the UK and Norwegian Continental Shelf highlight how these detailed, continuous mineral and hydrocarbon data can be used in geological and petrophysical evaluations. In the Dunbar Field of the Northern North Sea, UK, the spectral recognition of illite and kaolinite polytypes associated with faulted sandstone units contributed to a successful revision of lithostratigraphic correlation between wells with core material and those with only cuttings. These had been hitherto problematical. In Norway, hyperspectral mineral data from mixed carbonate–siliciclastic sequences across the Permo-Triassic boundary in the Alta Field, Barents Sea, helped in the delineation of a karstified dolomitic reservoir. A kaolinite cyclicity associated with an Upper Triassic stacked alluvial fan sequence was also identified in the Lorry Prospect, Norwegian Sea. Finally, it is demonstrated how hyperspectral data can be applied quantitatively to help to calibrate downhole petrophysical data, improve gamma log scaling for shale volume calculations and link mineralogy to permeability.

Abstract Located 160 km NE of the Shetland Islands in the East Shetland Basin, the Dunlin Cluster comprises four produced fields, Dunlin, Dunlin SW, Osprey and Merlin, in addition to some near-field satellite discoveries, Skye and Block 6. Dunlin was discovered in July 1973 and production began in August 1978. The field was developed using a concrete gravity-base platform, Dunlin Alpha, which also served as the production facility for the rest of the Dunlin Cluster. Osprey was discovered in 1974 but not tied-in until January 1991. Dunlin SW was discovered in 1973 but not brought onto production until 1996. Merlin was discovered in February 1997 and tied-in later that same year. Fairfield Energy acquired the Dunlin Cluster in 2008, and a programme of investment and facilities improvements, primarily in fuel gas infrastructure and power generation, sought to boost water-injection rates and bolster production, thereby extending the life of the asset. Ultimately, the Dunlin Cluster ceased production on 15 June 2015 after having maximized economic hydrocarbon recovery. The total Dunlin Cluster production exceeded 500 MMbbl of oil (Dunlin and Dunlin SW, 395 MMbbl oil; Osprey, 92 MMbbl oil; and Merlin, 27 MMbbl oil).

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 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 Wireline and seismic acoustic impedance imaging show that the marine part of the clastic Brent Group reservoir in the Heather Field, northern North Sea, contains much calcite cement in the flank parts of the structure. The non-marine Ness Formation and crest parts of the structure contain negligible calcite cement. This localized calcite cement has led to relatively poor reservoir performance since first oil in 1978, although a new suite of wells has boosted production with plans to keep the field active until 2030. Understanding the origin and distribution of calcite cement would help the development of more realistic reservoir models and boost production rates through optimum well location. We have thus used a suite of techniques, including standard point counting, SEM-EDS mineralogy, BSE microscopy, fluid inclusion thermometry and stable isotope analysis, to develop new and improved models of calcite distribution. Calcite seems to have attributes of both early and late diagenetic cement. A 30–40% intergranular volume in calcite cemented beds seems to support pre-compactional growth but high-temperature fluid inclusions and the presence of primary oil inclusions suggest late growth. Much calcite may have developed early but it seems to have recrystallized, and possibly undergone redistribution, at close to maximum burial or had a late growth event. Calcite cement probably originated as marine-derived micrite, bioclasts or early marine cement but adopted the isotopic characteristics of high-temperature growth as it recrystallized. Quartz grains have corroded outlines in calcite-cemented areas with one sample, with 79% calcite cement, displaying signs of nearly total replacement of quartz grains by calcite. The flank localization of calcite cement remains to be explained, although it could be due to primary depositional factors, early diagenetic loss of calcite from crestal regions or late diagenetic loss of calcite from crestal regions. Controversially, the growth of calcite seems to be associated with quartz dissolution, although the geochemical and petrophysical cause of this remains obscure. Diagenetic loss of quartz from sandstones cannot easily be explained by conventional modelling approaches and yet seems to be an important phenomenon in Heather sandstones.

Abstract The Knarr Field is located in the northern Norwegian North Sea, beyond the Brent Group delta fairway. Knarr was discovered in 2008 with the Jordbær well, additional resources were added to the field in 2011 with the successful Jordbær Vest well. The field extends over an area of approximately 20 km 2 . The original oil in place is estimated to be 26 MSm 3 (163 MBBL). The reservoir is the Late Pliensbachian Cook Formation and its current burial depth is approximately −3700 m true vertical depth subsea (TVDSS). In Knarr, the Cook Formation is split into five sandstones that are separated by four shale intervals which can be correlated across the field. The three lower sands (Lower Cook) are interpreted to have been deposited in a tidally-dominated environment, while the upper two sandstones (Upper Cook) were deposited in a wave-dominated shallow-marine setting. The reservoir properties of the Cook Formation in the Knarr area are remarkably good for a reservoir at this depth, with porosities up to 28% and permeabilities in excess of 1 D. The good reservoir properties are the result of grain-coating chlorite, which has inhibited diagenetic quartz development. The field is developed with three oil producers and three water injectors produced via a floating production storage and offloading vessel (FPSO). First oil was achieved in March 2015.

Abstract A classical Upper Jurassic fault block in the North Sea, the Fulla Structure, has Brent Group sandstones with good reservoir quality and apparently insignificant fault-related reservoir damage. Core data show high-porous sandstones that extend close to the main faults and there is no evidence of catalase, only of soft-sedimentary deformation. Shear bands are relatively thin with high offsets, and have a texture comparable to the wall rock. To investigate the deformation mechanism and products synthetic Brent Group sands are deformed in a triaxial plane strain box with pre-defined effective consolidation in the range of 100–8000 kPa, simulating a burial depth in the range of 10–800 m. This range covers the burial depth at the time of active faulting for most Jurassic traps in the North Sea, including the Fulla Structure. The experiments demonstrate that grain rolling and grain-boundary sliding are the dominant deformation mechanisms at all the simulated burial depths, and this deformation has no impact on the reservoir quality. The experiments concur with observations from the investigated wells and strengthen an interpretation of limited reservoir damage associated with the Late Jurassic fault activity.