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 Lower Jurassic second-order sequences J00 and J10, and their component third-order sequences J1–J6 and J12–J18. Two sequences (J1 and J3) are new, four sequences (J2, J4, J12 and J16) are amended and one sequence (J17) is renamed. A significant unconformity at the base of the J12 sequence (Upper Sinemurian) is present near the base of the Dunlin Group in the North Viking Graben–East Shetland Platform and in the Danish Central Graben, and correlates with an equivalent unconformity around the margins of the London Platform, onshore UK. A marked unconformity at the base of the J16 sequence is recognized in the North Viking Graben and onshore UK, where it is related to structural movements on the Market Weighton High, eastern England. Several levels of carbon enrichment (carbon isotope excursions (CIEs)) and associated geochemical changes tie to J sequences defining maximum flooding surfaces: the Upper Sinemurian CIE equates to the base J6 maximum flooding surface (MFS), the basal Pliensbachian CIE ties to the base J13 MFS, the basal Toarcian CIE relates to the base J17 MFS and the Toarcian Ocean Anoxic Event corresponds with the base J18 MFS.

Abstract This chapter describes uppermost Middle Jurassic–lowermost Cretaceous second-order stratigraphic sequences J40, J50, J60 and J70, and their component third-order sequences J42–J46, J52–J56, J62–J66 and J71–J76. The latest Callovian–Berriasian was an interval of significant tectonism that led to the development of complex stratigraphy and highly variable successions, the elucidation of which is aided by the recognition of the correlation of the J sequences. Marine sedimentation dominated the Callovian–Berriasian interval, with the development of multiple sandstone members comprising reservoir units in many hydrocarbon fields, charged by marine source rocks (e.g. the Kimmeridge Clay Formation). Each of these units is subdivided and correlated by a succession of J sequences. Several sequences are renumbered (e.g. J54, J55, J65 and J66), some sequence definitions are amended or their basal boundaries recalibrated chronostratigraphically (J52, J54, J72, J73, J74 and J76) and new sequence subdivisions are recognized (J64a, J64b, J72a–J72c, J73a and J73b). Significant unconformities are recognized at the bases of the J54, J55, J62, J63, J64, J71 and J73 sequences. The top of J70 (J76) equates to the major ‘Base Cretaceous Unconformity’ seismic sequence boundary.

Abstract The application of sequence stratigraphic concepts and methods augments the efficient development of North Sea hydrocarbon fields with Jurassic reservoirs. In particular, the approach provides enhancements to the development of robust reservoir zonations, more accurate assessments of the extent and continuity of reservoir zones and flow units, clearer identification and prediction of the most productive reservoir intervals, improved understanding of field-wide pressure barriers or baffles to fluid flow, and enhanced reservoir models. In addition, carbon capture and storage (CCS) projects in Jurassic rocks will benefit from the adoption of a sequence stratigraphic approach by enhancing the understanding of storage unit architecture, connectivity and top seals. In this chapter, these applications are discussed with reference to around 20 case studies from the North Sea Basin.

Abstract The application of sequence stratigraphic concepts and methods significantly enhances the evaluation of stratigraphic traps. In this chapter, five examples of, as yet undrilled, potential UK North Sea Jurassic combination stratigraphic traps, from the East Shetland Platform, South Viking Graben, Inner Moray Firth and Central Graben, are discussed and the potential application of sequence stratigraphic methods in their evaluation considered.

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.