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 The Lochranza Field was developed using seismic amplitude analysis, evolving conceptual geological models and the implementation of horizontal well technology, built on the knowledge gained from the adjacent Donan Field redevelopment. Subtle depositional and structural complexities were, however, encountered in the Lochranza development wells. These had the potential to impact on the successful targeting of reservoir sands. Thinning sands and erratic lateral sand pinch-outs at the margins of the deep-water Balmoral Fan complex, small-scale sand injection and subtle structural complexity across the Lochranza Field were identified in the first phase of development. These introduced greater interpretation uncertainty and made further development challenging. This highlighted the importance of considering alternative geological scenarios, whilst these insights aided the identification of infill well opportunities. These uncertainties were partially mitigated by the planned development well trajectory, the data acquisition programme and the ability to geosteer based upon the geology encountered. It proved important to be mindful of different geological scenarios whilst geosteering, guided by the real-time dataset, keeping the 3D geological model peripheral to decision-making to limit the impact of anchoring bias. Identification of infill targets used a pragmatic approach based upon empirical data that showed that well recovery efficiency could be characterized by net pay length, stand-off from the oil–water contact (OWC) and connected hydrocarbon volume. Infill opportunities were defined probabilistically and subsequently supported by 3D reservoir simulation. This assessment was helped significantly by additional appraisal being undertaken as part of development well drilling.

Abstract As giant oil fields mature, the flow of results from development drilling and production history, as well as interpretations of new seismic data, provide an evolving view of in-place volumes, reservoir architecture and fluid movement through the reservoir. Often, such changes can trigger modifications to asset development plans and, together with economic conditions, revisions to estimates of ultimate recovery. The development of the Alba Field – a relatively heavy oil (19° API) accumulation lying in an Eocene deep-water channel complex in Block 16/26 of the UK's Central North Sea – has followed a similar pattern. With an estimated 900 mmbbl of oil in place, the reservoir is characterized by thick, high net-to-gross (NTG) sands with extremely favourable reservoir properties. Because of the less favourable mobility ratio, Alba has been developed exclusively by horizontal production wells, with pressure support provided by a series of seawater injectors. By mid-2012, after 18 years of production, more than 390 mmbbl of oil had been recovered. During production, several key seismic and drilling technologies were applied to address reservoir complexities and reservoir management concerns that emerged as field development progressed. The most significant of these include the following: a dramatic uplift in imaging the depositional architecture was provided by converted shear wave seismic data (1998), revealing an extremely irregular top reservoir and hinting at greater internal complexity than initially modelled; advances in extended reach drilling technology enabled a greater number of infill targets to be accessed, while geosteering techniques allowed better well placement, and horizontal completions using gravel packs improved well reliability; spectacular images of production cones beneath horizontal production wells extracted from a dedicated 4D monitor survey (2008) addressed the field's key dynamic uncertainty – where is the remaining oil? A challenge for Alba has been to fully understand a 4D seismic signal that originates from long horizontal producers where vertical rather than lateral sweep dominates. Ultimately, reliable reservoir models that capture these valuable dynamic insights, based on geologically reasonable interpretations, will be the key tool that enables bypassed oil to be targeted and recovered, as fields such as Alba advance towards their development vision.