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 The Shearwater Field is a high-pressure–high-temperature (HPHT) gas condensate field located 180 km east of Aberdeen in UKCS Blocks 22/30b and 22/30e within the East Central Graben. Shell UK Limited operates the field on behalf of co-venturers Esso Exploration and Production UK Limited and Arco British Limited, via a fixed steel jacket production platform and bridge-linked wellhead jacket in a water depth of 295 ft. Sandstones of the Upper Jurassic Fulmar Formation constitute the primary reservoir upon which the initial field development was sanctioned; however, additional production has been achieved from intra-Heather Formation sandstones, as well as from the Middle Jurassic Pentland Formation. Following first gas in 2000, a series of well failures occurred such that by 2008 production from the main field Fulmar reservoir had ceased. This resulted in a shut-in period for the main field from 2010 before a platform well slot recovery and redevelopment drilling campaign reinstated production from the Fulmar reservoir in 2015. In addition to replacement wells, the redevelopment drilling also included the design and execution of additional wells targeting undeveloped reservoirs and near-field exploration targets, based on the lessons learned during the initial development campaign, resulting in concurrent production from all discovered reservoirs via six active production wells by 2018.

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 Shearwater Field is located 242 km east of Aberdeen in the Central North Sea (CNS) and has three satellite fields, Starling, Scoter and Merganser. Acting as the hub for the gas-condensate-producing normal-pressure–normal-temperature (NPNT) satellites, Shearwater, which produces high-pressure–high-temperature (HPHT) Jurassic reservoirs, comprises a bridge-linked wellhead jacket to a production platform. The satellites, developed as subsea tiebacks, target Paleocene turbidite reservoirs, with the Starling Field most distant at 33 km from the host while Merganser is tied in via Scoter through a 15 km pipeline. Each satellite consists of a subsea manifold connected to two production wells at Merganser, and three production wells each at Scoter and Starling. All reservoir traps at the satellites are due to Permian-age Zechstein salt diapirs. Starling and Scoter produce Forties Sandstone Member reservoirs via three deviated wells targeting anticline structures. At Merganser, two long horizontal production wells cross over 4000 ft of faulted Paleocene reservoir intervals to produce under salt diapir overhangs. The satellites have been instrumental in maintaining the Shearwater facilities given early main field well failures, whilst recent challenges have developed as the satellites mature, requiring infill wells and well interventions to maximize economic recovery.

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.