Abstract The Shearwater Field, located in Block 22/30b in the UK Central Graben, remains one of the best-known fields in the UK Continental Shelf (UKCS). At the time of the initial development, Shearwater represented one of the most complex and technically challenging high-pressure and high-temperature (HPHT) developments of its kind in the North Sea. During the early life of the field, pressure depletion resulted in compaction of the Fulmar reservoir, leading to mechanical failure of the development wells. The compaction also resulted in weakening of the overburden due to an effect known as stress arching. Over time, this resulted in in situ stress changes in the overburden which have been observed from 4D seismic datasets and are in line with geomechanical modelling. This is particularly true for the Hod Formation in the Chalk Group, and resulted in the need to make changes to infill well design, including the use of new drilling technologies, to ensure safe and effective well delivery. The insights presented here, which relate to the understanding of pore pressure and fluid fill in the overburden, and how the overburden has responded to stress changes over time, are of relevance to current and future HPHT field developments in both the UK North Sea and elsewhere.

Abstract This paper is reformatted and slightly modified from the original publication in The Leading Edge, 2011, 30, no. 9, 1008–1018.

Abstract Development of the Shearwater Field, a deep gas-condensate accumulation in the HPHT region of the UKCS’ began in 1997 with the initiation of development drilling and construction of topside facilities. It formed part of the major development of the Central North Sea HPHT gas play throughout the late 1990s, together with other gas developments across Elgin/Franklin and Erskine. As such, Shearwater should be viewed, together with these other structures, as part of an expansion of the gas sector in the North Sea in an area of challenging subsurface conditions and limited development experience to constrain production uncertainty. Field sanction was based on the understanding and modelling of key subsurface uncertainties. Development experience since then has tested that initial subsurface view and lessons learnt will provide a key analogue to help constrain the development of any future HPHT gas accumulations. This paper describes the subsurface model for the Shearwater structure and how recent development experience and production performance has constrained the reservoir characterization uncertainty of the Fulmar Formation.

Abstract The Merganser Field is located in the East Central Graben of the UK Central North Sea, and consists of a gas/condensate column trapped in a structural attic on the flanks of a fully penetrating salt diapir. A large salt overhang obscures the field and structural definition is challenging owing to poor seismic imaging. Exploration drilling established a column of 1327 ft in Paleocene-aged deep-marine deposits of the Forties, Andrew and Maureen Sandstone members, and revealed significant geological complexity. Depositional styles record the relationship between salt tectonics and sedimentation, with variable reservoir distribution influenced by halo-kinetically induced palaeorelief and accommodation space. Re-mobilization of sediments is observed at multiple scales, and includes centimetre-scale de-watering structures, decimetre-scale sand injectites and kilometre-scale olistoliths. Whilst the hydrocarbon properties are consistent, contact depths are variable. Pressure data indicate compartmentalization across the field, which is likely to be caused by either radial faulting or hydrodynamic effects. Owing to the magnitude of subsurface uncertainty, the Merganser discovery could not sustain the investment required for standalone facilities. The development of the neighbouring Scoter Field provided the requisite local infrastructure to progress Merganser into production. The Field Development Plan (FDP) estimated recovery of 100 bscf gas and 3 mmstb condensate, and focused on delivering a low-cost development solution consisting of two horizontal wells and a subsea tie-back that would be robust against the downside, yet maintain flexibility to optimize in an upside outcome. Pilot holes were drilled to establish top reservoir with the subsequent horizontal well trajectories being re-designed to reflect structural geometry. The reservoir sections would maximize connectivity between fault compartments and stratigraphic units, and positioning was optimized with well-site biostratigraphy. Each reservoir section exceeds 4000 ft and maintains at least 1000 ft vertical stand-off from the gas/water contact. The facilities include a 5 km subsea tie back to the Scoter production manifold, with metering at the Merganser manifold for allocation purposes. Gas and condensate are commingled with Scoter, and transported 11 km to Shearwater for processing. The gas is transported onshore through the Shearwater Elgin Area Line and condensate through the Forties Pipeline System to Kinneil. Field performance to date has exceeded the FDP P50 both in terms of daily rate and cumulative production. Early production rates peaked at 100 mmscf/day of gas and 6000 stb/day of condensate and, to end-2014, Merganser has produced 161 bcf of gas and 10 mmstb condensate. This performance is due to a combination of better than expected connectivity, high reservoir k h , lower draw-down afforded by long horizontal wells and compression at the Shearwater platform. Subsurface uncertainties prior to development were considerable and the ‘appraisal through development’ strategy has demonstrated that success is achievable through meticulous planning and scenario analysis.

Abstract Seismic mapping of the salt-influenced Late Jurassic Shearwater fault system (central North Sea) has revealed that salt mobility has had fundamental control on the development of supra-salt faulting in the area. The Shearwater fault system consists of four distinct fault segments each of which increase in displacement towards a salt diapir developed in a central area where the segments intersect. The evolution of the fault system is recorded by sediment geometries in Late Jurassic syn-rift sequences, which reveal that the salt diapir and fault system evolved simultaneously with a fundamental inter-relationship between salt mobility and the evolution of the fault system. Comparisons of faulting in the Shearwater area with faults developed in the salt-free northern North Sea show that significant differences exist in the nature of fault geometries, footwall dips and fault related hanging wall depocenters. All of these variations can be attributed directly to the influence of salt mobility. Consequently, caution should be used when applying conventional models of fault development derived from salt-free settings to evaporite basins.

Abstract The integration of detailed seismic mapping, overpressure studies, basin modelling and new drilling has provided new insights into the ‘plumbing’ system of the deep, High-temperature, high-pressure (HPHT) play in the Central Graben. Although overpressure distribution in the pre-Cretaceous section is broadly related to depth, large-scale compartmentalization of the main Jurassic/Triassic reservoirs has resulted in the generation of a number of distinct pressure cells. These pressure cells are bounded by major structural faults (e.g. Forties/Montrose High) or by ‘interpod’ settings where the Jurassic/Triassic reservoir sequence thins over salt ridges. Evidence is presented that shows overpressure is a key control on hydrocarbon retention in this area, with several structures known to have blown top seals or to be leaky (i.e. underfilled) at present. The commercial Shearwater structure is shown to be an example of the latter, having evidence for a palaeo-oil column before the seal presumably breached and the trap recharged with a later gas-condensate fill. The length of hydrocarbon column in the structure at present day is controlled by the aquifer pressure and, in turn, by the shallowest point in the Shearwater pressure cell. The overpressure and trap filling history has had important implications for hydrocarbon migration, retention and the resultant composition of hydrocarbon accumulations in this part of the HPHT area. A conceptual model is presented here.

Abstract The 40-year history of the pre-Cretaceous high-pressure — high-temperature (HPHT) plays of the UK CNS is described. The exploration and exploitation of this basin has been achieved by remarkable developments in seismic, drilling and development technologies. These advances have provided predictive geological models to address significant multiple risk elements, and the ability to drill and develop reservoirs safely in HPHT conditions with temperatures in excess of 300° F, reservoir pressures exceeding 10 000 psi and surface to reservoir pressure gradients in excess of 0.8 psi/ft. UK Continental Shelf exploration acreage was first awarded in 1964 in the First Licence Round. At this time seismic data did not image the Base Cretaceous surface and early drilling activity focused on the Tertiary and on obvious salt supported anticlines or major basement ridges. The subsequent period from 1968–1972 saw the discovery of the first hydrocarbons in the pre-Cretaceous in graben margin structures or on mid-graben highs, but the deeper HPHT realm remained untested. In the 1970s the discovery of the Auk, Argyll and Fulmar Fields established potentially significant plays around the fringes of the basin. However, exploration for pre-Cretaceous reservoirs in the deeper parts of the basin where HPHT conditions occurred faced significant operational obstacles. As these were overcome the 1980s saw the extension of pre-Cretaceous plays into the HPHT realm, with deep, high-quality reservoirs occurring at depths in excess of 15 000 feet. This exploration phase resulted in the discovery of significant reserves at the Elgin, Franklin, Shearwater, Jade and ETAP fields. Throughout the exploration history of the CNS, the accurate prediction of deep reservoir distribution and quality and top seal integrity have been crucial to success. Innovative seismic technologies will play a key part in reducing the remaining uncertainties in these play elements.

Abstract The Erskine Field is a high temperature, high pressure (HTHP), gas condensate accumulation located on the western margin of the East Central Graben. The field was discovered in 1981 by the 23/26a-3RE well and subsequently delineated by six appraisal wells. Development approval was granted in 1995 and to date five development wells have been drilled. In December 1997, Erskine Field became the first HTHP field in the UKCS to achieve production. Hydrocarbons are produced from three separate Jurassic reservoirs. In order of decreasing importance, these are: the Late Oxfordian Erskine Sandstone (Puffin Formation), the Middle Jurassic Pentland Reservoir, and the Late Oxfordian Heather Turbidite Reservoir. The Erskine Sandstone is very fine to fine-grained highly bioturbated, shaley sandstone. The sandstones represent shallow marine progradational sequences, deposited predominantly in the offshore transition zone. Within the majority of the Erskine Sandstone, porosity is high (20-25%) but with relatively poor associated permeability (0.1-10 mD). However, the tops of the coarsening upward sequences (E30 and E70 zones) have appreciably better permeability and are thought to be the major conduits for fluid flow. The E30 and E70 zones would not have been identified, had it not been for the extensive coring programme undertaken in the development wells. The Pentland Reservoir is a regionally extensive sequence of interbedded sandstone, shales, coals and siltstones, deposited in a fluvial-lacustrine environment in a delta plain setting. Permeability in the Pentland reservoir (0.1 mD-1 D) is in general far superior to the values observed in the Erskine Sandstone. The main control on the observed variability in porosity and permeability characteristics is grain size, that in turn is controlled by facies. The Heather Turbidite Reservoir occurs within two thin predominantly fine-grained turbidite sandstone beds in the Heather Shale Formation. This reservoir is restricted to the Alpha Terrace region in the SW of the field, and is drained by a single development well. Total Erskine Field reserves are estimated at approx 400 BCF of gas and 66 MMBBL of condensate.

Abstract: The application of geomechanics to oil and gas field development leads to significant improvements in the economic performance of the asset. The geomechanical issues that affect field development start at the exploration stage and continue to affect appraisal and development decisions all the way through to field abandonment. Field developments now use improved static reservoir characterization, which includes both the mechanical properties of the field and the initial stress distribution over the field, along with numerical reservoir modelling to assess the dynamic stress evolution that accompanies oil and gas production, or fluid injection, into the reservoirs. Characterizing large volumes of rock in the subsurface for geomechanical analysis is accompanied by uncertainty resulting from the low core sampling rates of around 1 part per trillion (ppt) for geomechanical properties and due to the remote geophysical and petrophysical techniques used to construct field models. However, some uncertainties also result from theoretical simplifications used to describe the geomechanical behaviour of the geology. This paper provides a brief overview of geomechanical engineering applied to petroleum field developments. Select case studies are used to highlight how detailed geological knowledge improves the geomechanical characterization and analysis of field developments. The first case study investigates the stress regimes present in active fault systems and re-evaluates the industry’s interpretation of Andersonian stress states of faulting. The second case study discusses how the stress magnitudes and, potentially, stress regimes can change as a result of production and pore pressure depletion in an oil or gas field. The last case study addresses the geomechanical characterization of reservoirs, showing how subtle changes in geological processes are manifested in significant variations in strength. The studies presented here illustrate how the timely application of petroleum geomechanical engineering can significantly enhance field development, including drilling performance, infill drilling, completion design, production and recovery.

Abstract The Maureen Field comprises the Maureen, Mary and Morag accumulations, the reservoirs being Palaeocene sandstones, Upper Jurassic sandstones and Permian dolomites respectively. The field lies about 10 km NNE of the Moira Palaeocene field. Maureen was discovered in 1973, came on-stream in 1983 and produced 217.4 MMBBL (from an estimated STOIIP of 397 MMBBL). The field ceased production in October 1999. It is trapped in a four-way dip closure over a salt dome and sealed by the overlying Lista Formation mudstones. The reservoir is up to 450 ft gross thickness, with core porosity from 18-28% and good sand connectivity. Morag was discovered in 1979, came on-stream in 1991 and produced 2.6 MMBBL before being shut-in in 1994. It produced from clean fractured dolomites in a stratigraphic trap. Mary was discovered and came on-stream in 1991. The intial well died after 1 year. A later well was put on-stream in 1997. Mary produced 2.83 MMBBL before final shut-in in June 1999. Reservoir quality is reasonable, but sand distribution is problematic. All the oils are sourced from the Kimmeridge Clay Formation on the adjacent Maureen Shelf area.

Abstract This paper highlights how a global approach to quantifying structural uncertainties has ultimately reduced overall structural uncertainty through improved seismic imaging, notably anisotropic pre-stack depth migration, in a structurally complex area. The Elgin/Franklin high pressure/high temperature (HP/HT) fields lie in the Central Graben area of the North Sea UK sector, c. 240 km east of Aberdeen. The fields are the deepest production in the North Sea and represent the largest gas condensate development in the world, with recoverable reserves estimated at over 700 × 10 6 BBL equivalent. The reservoirs produce from the Jurassic Fulmar shallow-marine and Pentland fluvial reservoirs at depths of 5100–5600 m subsea. Production from these HP/HT reservoirs (1100 bar/200°C) started in March 2001 and flows over 200 000 BOE per day from 12 wells. For this type of producing environment, the stakes are high for understanding uncertainties related to imaging. Improved fault imaging translates not only to reduced uncertainties in bulk rock volumes, and ultimately in-place hydrocarbon volumes but also to an increased understanding of the static/dynamic behaviour of the fields through better imaging of internal faulting. The application of various proprietary and contractor-based seismic depth processing since 1997 has allowed for a better understanding of structural configuration of the deep reservoirs. This rich processing history has provided the interpretation team with various processing volumes (isotropic Post-SDM, anisotropic Post-SDM and, most recently, anisotropic Pre-SDM) to allow a more complete understanding of the uncertainties related to different imaging approaches. Historically, the effects of anisotropy on vertical and lateral positioning were realized and a number of internal proprietary software tools were developed to quality control depth imaging processing. The 1998 Glenelg discovery southwest of Elgin Field was the focus for the initial anisotropic Pre-SDM study, which was later expanded to include the Elgin/Franklin fields area. This processing benefited from Total’s internal QC tools and a combination of additional data (e.g. walk-away VSP profiles with different orientations, long-offset 2D seismic data) which provided an optimum mix to derive and verify the anisotropic parameters for the velocity model. Overall, the new seismic data shown significant improvement over the previous time- and depth-migrated datasets, reduced uncertainty on internal and bounding-fault positions and allowed the observation of the vertical and spatial uncertainties attached to different migration approaches. This understanding of the variability in seismic imaging and its effects on the reservoir parameters and structural configurations in depth is used as an input to understand ranges of in-place hydrocarbon volumes, the potential of near-field exploration and future infill-drilling strategies.