Abstract The Babbage gas field was discovered in 1988 by exploration well 48/2-2 which drilled into the Permian-age lower Leman Sandstone Formation below a salt wall. Seismic imaging is compromised by the presence of this salt wall, which runs east–west across the southern part of the structure, creating uncertainties in depth conversion and in the in-place volumes. Pre-stack depth migration with beam and reverse time migrations appropriate for the complex salt geometry provided an uplift in subsalt seismic imaging, enabling the development of the field, which is located at the northern edge of the main reservoir fairway in a mixed aeolian–fluvial setting. Advances in artificial fracturing technology were also critical to the development: in this area, deep burial is associated with the presence of pore-occluding clays, which reduce the reservoir permeability to sub-millidarcy levels. The Babbage Field was sanctioned in 2008, based on an in-place volume range of 248–582 bcf; first production was in 2010. It produces from five horizontal development wells that were artificially fracced to improve deliverability of gas from the tight matrix. None of the wells has drilled the gas–water contact, which remains a key uncertainty to the in-place volumes, along with depth-conversion uncertainty below the salt wall.

Abstract The Breagh Field is in UK Blocks 42/12a, 42/13a and 42/8a. It is a gas field with multiple reservoir intervals within sandstones of the Early Carboniferous Yoredale Formation (equivalent to the Middle Limestone Formation within the Yoredale Group onshore). It was the first and is presently the only field developed within these sandstones, offshore UK. Breagh was discovered in 1997 by well 42/13-2 and proved by development well 42/13a-A1. Its crest is at 7110 ft TVDSS (true vertical depth subsea), marked by the unconformity between the base Zechstein and the subcropping Yoredale Formation. It has a free water level at 7690 ft TVDSS, a maximum column height of 510 ft and a field extent of 94 km 2 . Breagh was developed using ten wells from a 12 slot normally unattended platform; five of the wells have been stimulated by hydraulic fractures with proppant injection. The unprocessed gas flows through a 110 km 20-inch diameter pipeline to the Teesside Gas Processing Plant. Production started in 2013, reached a peak rate of 150 MMscfgd in 2014 and, by the end of 2018, had produced 140 bcf. The field is operated by INEOS Oil and Gas UK Ltd (70%) with partner ONE-Dyas B.V. (30%).

Abstract The Carrack Field, located in the Southern North Sea Blocks 49/14b and 49/15a, has of the order or 15 bcm (530 bcf) gas initially in place and is operated by Shell UK Ltd. The field consists of a pop-up structure in the south of the field and extends to the north with a gently-dipping monoclinal structure. The reservoir comprises sandstones of the Permian Silverpit and Leman Sandstone formations, which contain c. 85% of the in-place resources. The quality of the reservoir decreases rapidly to the north. Gas is also produced from Carboniferous sandstones of late Duckmantian (Westphalian B)–Bolsovian (Westphalian C) age. Initially, the field was in pressure communication both laterally and vertically with a single gas–water contact. During production time, however, the three main fault blocks behaved independently, and decimetre-thick shale intervals acted as vertical baffles between the sandstone units. The Carrack Field has been in production since 2003 and is developed by a single platform with seven mainly deviated wells. The current production rate is c. 0.7 MMm 3 /day (25 MMscfgd). Until the end of field life in the 2030s, the field is expected to produce gas of the order of a few bcm. The main remaining opportunity is the undeveloped Carrack West compartment.

Abstract The Endurance, four-way, dip-closed structure in UK Blocks 42/25 and 43/21 occurs over a salt swell diapir and within Triassic and younger strata. The Lower Triassic Bunter Sandstone Formation reservoir within the structure was tested twice for natural gas (in 1970 and 1990) but both wells were dry. The reservoir is both thick and high quality and, as such, an excellent candidate site for subsurface CO 2 storage. In 2013 a consortium led by National Grid Carbon drilled an appraisal well on the structure and undertook an injection test ahead of a planned development of Endurance as the first bespoke storage site on the UK Continental Shelf with an expected injection rate of 2.68 × 10 6 t of dense phase CO 2 each year for 20 years. The site was not developed following the UK Government's removal of financial support for carbon capture and storage (CCS) demonstration projects, but it is hoped with the recent March 2020 Budget that government support for CCS may now be back on track.

Abstract The Ensign Field is located in UK offshore licence Blocks 48/14a, 48/15a and 48/15b. The field is located 100 km east of the Humberside coast within the Sole Pit area of the Southern North Sea. The reservoir consists of sandstones of the Permian Rotliegend Group (Leman Sandstone Formation). Reservoir quality has been impacted by diagenesis during deep burial, whereby illitization has reduced permeability to sub-millidarcy scale. The field has been developed with two horizontal production wells, both completed with five hydraulic fracture stages. First gas from the field was achieved in 2012 via the Ensign normally unmanned installation and exported through the Lincolnshire Offshore Gas Gathering System. The field is compartmentalized by multiple regional-scale De Keyser fault zones. A heterogeneous natural fracture network exists with only a limited contribution to flow. Well performance and ultimate gas recovery have been lower than originally anticipated due to sub-optimal completions and a higher degree of compartmentalization than originally expected. The volume of gas that is connected to the wells is limited by low-offset faults, which have been identified by integrating long-term production data, and core, log and reprocessed seismic data. Production ceased in 2018 when the original export route was decommissioned.

Abstract The Grove gas field is located in the Southern North Sea, within the UK offshore licence Blocks 49/10a, 49/9c and 49/10c. The field lies 180 km east of the Humberside coast and 4 km from the UK–Netherlands median line on the western margin of the Cleaver Bank High. The reservoir consists of late Westphalian C fluvial red beds interbedded with mud-prone floodplain deposits. Grove was put on production in 2007 through a single normally unmanned platform which is connected to the Markham J6A facilities by means of a 13.4 km 10-inch pipeline and subsequently exported to Den Helder in the Netherlands. The field has been developed by means of six production wells, targeting a variety of fault blocks and sandstone units. Reservoir complexity due to differential erosion, heterogeneity and faulting has presented development challenges and productivity per well is highly variable. Additionally, the evaporites within the overlying Zechstein Group present drilling and well integrity issues.

Abstract The Hewett Field has been in production for some 50 years. Unusually for a Southern North Sea field in the UK Sector, there has been production from several different reservoirs and almost entirely from intervals younger than the principal Leman Sandstone Formation (LSF) reservoir in the basin. Some of these reservoirs are particular to the Hewett area. This reflects the location of the field at the basin margin bound by the Dowsing Fault Zone, which has influenced structural evolution, deposition and the migration of hydrocarbons. The principal reservoirs are the Permo-Triassic Hewett Sandstone (Lower Bunter), Triassic Bunter Sandstone Formation (BSF) (Upper Bunter) and Permian Zechsteinkalk Formation. There has also been minor production from the Permian Plattendolomit Formation and the LSF. Sour gas is present in the BSF only. Several phases of field development are recognized, ultimately comprising three wellhead platforms with production from 35 wells. Gas is exported onshore to Bacton, where the sour gas was also processed. Peak production was in 1976 and c. 3.5 tcf of gas has been recovered. Hewett has also provided the hub for six satellite fields which have produced a further 0.9 tcf of gas. It is expected that the asset will cease production in 2020.

Abstract Six satellite fields have been developed through the Hewett Field facilities: Big Dotty, Little Dotty, Deborah, Della, Dawn and Delilah. Little Dotty has produced from both the Leman Sandstone Formation (LSF) and Bunter Sandstone Formation (BSF) whilst the other satellites are exclusively LSF developments. The LSF reservoir quality exhibits a marked contrast across the Dowsing Fault Zone, which separates the inboard satellites to the SW from the outboard satellites to the NE. The inboard satellites, Big Dotty, Little Dotty and Dawn, display the best reservoir quality, reflecting their lesser depth of maximum burial. These fields share a strong aquifer, exhibited a rapid water-cut development and are now shut-in. The greater depth of maximum burial experienced by the outboard satellites, Deborah, Della and Delilah, is reflected in poorer reservoir quality along with weaker aquifers that are also more compartmentalized. These remain in production and will achieve higher recovery factors. Big Dotty was developed from a wellhead platform whereas the other fields were developed as subsea tie-backs. Collectively, these satellite fields have produced some 0.9 tcf of gas, playing an important strategic role in offsetting the production decline in the Hewett Field and extending the life of the asset.

Abstract The Viking Fields were a gas development in the UK Southern North Sea, c. 130 km east of the Lincolnshire coast in 30 m water depth and covering Blocks 49/11d, 49/12a, 49/16a, 49/16c, 49/17a. The area comprised the Viking A, B, C, D and E Fields. The Viking Fields were discovered in 1965 and started producing in 1972. The development was in two phases from 1971 to 1994 and from 1995 to 2000; the latter phase included the ‘Phoenix development’. The fields continued to produce until September 2015. Plugging and abandonment of the Viking Field wells was complete in 2017, with final decommissioning planned for 2021. The Viking Fields have produced 3.3 tcf of gas from the Rotliegend Group, Leman Sandstone Formation, aeolian-dominated reservoir rocks with a porosity range of 7–25% and average permeability of >100 mD. The Viking reservoirs are impacted by NE--SW De Keyser faults which often delineate and compartmentalize the reservoirs. The final recovery factor for the Viking Fields was 90%. This paper summarizes the geology, development history and performance of these legacy assets.

Abstract Remaining resources in mature basins, such as the southern North Sea (SNS), are often associated with complex or unconventional reservoirs. Unlocking the value of these resources requires non-conventional approaches to the description and the development of the reservoir. Originally developed as a conventional reservoir, the Hoton field in the SNS delivers economic rates from a tight and fractured Lower Leman Sandstone. The northern part of the field is developed via a trilateral producer, but the field’s southern half, which appraisal drilling showed to consist of poor-quality rock, was deemed too tight for development. Roughly 40% of the field’s resource of dry gas lies within the southern part of the field with no plans to develop it. A reassessment of the southern area’s potential using geomechanical tools suggests that it also could deliver commercial well rates, similar to those experienced in the northern area of the field. A combination of structural restorations using Dynel2D and forward deformation modelling using Poly3D produces palaeostress predictions, which are used to constrain a discrete fracture network model. From these, well profiles are generated that suggest that a development well into the southern part of the field can recover about half of the currently stranded resource.

Abstract Twenty-three years after BP discovered the Chiswick Field in 1984, first gas production was achieved by Venture Production. During its long period of appraisal and development, this asset has passed between five different operators and a large number of co-venturers. Prior to development, the field represented one of the largest undeveloped gas volumes present in the UK Southern North Sea. Key uncertainties include reservoir compartmentalization, low net/gross ratios and poor reservoir permeability, uncertainties in structural mapping and gas–water contact depths, as well as a widely varying Carboniferous subcrop and significant lateral changes in fluviatile sandstone architecture. Drilling and completion during the first phase of development were a significant challenge, with ambitious long and deep fracture-stimulated horizontal wells. The installation comprised a five-slot minimum facilities well-head platform with production tied back via the Venture-operated Markham J6A Platform with gas landed in Den Helder, Holland. As part of Phase II development a further three wells are being planned to accelerate recovery and access the remaining undeveloped reserves in both the primary Carboniferous and secondary Rotliegend reservoirs in the Chiswick Field.