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 Chiswick Field is a Carboniferous gas field located in UK Blocks 49/4a and 49/4b in the Southern North Sea, approximately 18 km NW of the Markham Field, close to the UK–Netherlands median line. The Kew Field is situated approximately 3 km NE of the Chiswick Field. The Kew structure is a NW–SE-trending horst separated from the Chiswick Field, a large anticlinal domal structure, by a major NW–SE fault and a structural low. The productive reservoir units are Carboniferous (Westphalian A and B) fluvial sandstones. Both fields are situated on the eastern edge of the Silverpit Basin (part of the Southern Permian Basin). The initial exploration drilling had Leman Sandstone Formation as the primary objective, but the first wells encountered a tight Permian reservoir with gas-bearing Carboniferous reservoirs, subsequently appraised and developed. The current estimate for the gas initially in place of Chiswick and Kew is respectively 687 bcf and 85 bcf in the Carboniferous reservoir. The fields to date (Q4 2018) have produced respectively 220 bcf and 33 bcf sales gas. Gas recovery is through natural depletion from hydraulically fractured, horizontal development wells.

Abstract The Cygnus Field is located in Blocks 44/11a and 44/12a of the UK Southern North Sea. The field was first discovered in 1988 as a tight lower Leman Sandstone Formation gas discovery by well 44/12- 1. After the licences had sat idle for several years, GDF Britain (now Neptune E&P UK Ltd) appraised the field from 2006 to 2010. During the appraisal phase, the lower Leman Sandstone was found to be of better quality than first discovered and the gas-bearing lower Ketch Member reservoir was also encountered. The field development was sanctioned in 2012. The field has been developed from two wellhead platforms targeting Leman Sandstone and Ketch Member reservoirs. Five main fault blocks have been developed, with two wells in each fault block planned in the field development plan. The wells are long horizontal wells completed with stand-alone sand screens. At the time of writing, the production plateau is 320 MMscfgd (266 MMscfgd when third-party constraints apply), producing from nine wells with the final production well to be drilled.

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 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 abandoned Juliet gas field is a small, highly compartmentalized, accumulation situated south and east of the Amethyst Gas Field. It was discovered in 2008 by well 47/14b-10 and flowed first gas on 5 January 2014. The field consists of at least two culminations within a very low-relief east–west-orientated fault-bounded anticline. The reservoir comprises aeolian sandstones of the Permian, Rotliegend Group, Leman Sandstone Formation. Reservoir quality varies from good to moderate, with a high production rate achieved from horizontal wells. Seismic time-to-depth conversion is affected by Quaternary seabed channels, chalk burial history and a rapid thickening in the Basalanhydrit Formation located over the east of the field, associated with the edge of the Zechstein Basin. Gas-in-place at pre-development was expected to be 105 bcf, with reserves of 67 bcf. The field was developed using two horizontal wells and a subsea tie-back to the Pickerill Field, 22 km to the east. Since development, the field appears to be more compartmentalized than initially expected.

Abstract Block 49/25a contains the Sean gas fields, Sean North, Sean South and Sean East – collectively known as the Greater Sean area and discovered in 1969. The fields are located in the Southern Gas Basin, about 15 km SE of the Indefatigable gas field. Approximately 1.1 tcf of gas is trapped in a series of fault-bounded dip closures consisting of Permian sandstones belonging to the Leman Sandstone Formation (Rotliegend Group). The reservoir is overlain by evaporites of the Late Permian Zechstein Group. The fields are characterized by excellent Leman reservoir quality, and resources have increased significantly over the years. The reservoir largely behaves as a well-connected tank, which has resulted in high recovery factors (>90%). In 2015, Oranje-Nassau Energie UK Ltd (ONE) took over operatorship of the field through purchasing the rights of both Shell and Esso, giving ONE a 50% operated interest together with SSE E&P UK Ltd (SSE). In 2017, an infill well (SSPD05) was drilled by ONE to test a pop-up structure situated between Sean North and Sean South. The well found, as expected, partially depleted reservoir but has proven to accelerate production and add incremental reserves to the field.

Abstract The Tolmount Field is a lean gas condensate accumulation located in Block 42/28d of the UK Southern North Sea. The field was discovered in 2011 by well 42/28d-12, which encountered good-quality gas-bearing reservoir sandstones of the Permian Leman Sandstone Formation. The discovery was appraised in 2013 by wells 42/28d-13 and 42/28d-13Z, which logged the gas–water contact on the eastern flank of the field. The Tolmount structure is a four-way, dip-closed, faulted anticline, orientated NW to SE. The reservoir comprises mixed aeolian dune and fluvial sheetflood facies deposited within an arid continental basin. Dune sands display the best reservoir properties with porosities around 22% and permeabilities exceeding 100 mD. Only minor diagenetic alteration has occurred, primarily in the form of grain-coating illite. Superior reservoir quality is observed at Tolmount compared to adjacent areas, due to the preservation of dune facies, a hypothesized early gas emplacement and a relatively benign burial history. Current mapped gas initially-in-place estimates for the field are between 450 bcf and 800 bcf, with an estimated recovery factor between 70 and 90%. An initial four-well development is planned, with first gas expected in 2020.

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 The Cygnus Field, operated by ENGIE E&P UK Limited, is located in UK Southern North Sea blocks 44/11 and 44/12. The reservoir comprises sandstones of the Permian Leman Sandstone Formation and Carboniferous Ketch Formation. Cygnus was first drilled in 1988 by well 44/12-1, which encountered gas shows in sandstones in the Leman Sandstone Formation whilst targeting a Carboniferous objective. The initial evaluation indicated the presence of poor-quality reservoir with conventional log analysis indicating high water saturations. Further appraisal activity ceased until 2002 when a group led by ENGIE E&P UK Limited were awarded the licence in the 20th round having recognized the missed pay potential. Through appraisal drilling, a second reservoir (the Carboniferous Ketch Formation) was discovered and the Leman Sandstone Formation was proven to be capable of achieving stabilized flow rates greater than 30 MMscf/d. The Cygnus discovery now proves that a northern-sourced Leman Sandstone Formation play fairway exists, establishing an extension of the Rotliegend play to the northern feather edge of the Southern Permian Basin. The Cygnus Field's estimated ultimate recoverable volume is forecast to be 760 Bscf, making it the largest field discovered in the UK Southern North Sea in the last 30 years.

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 The Ensign Gas Field is located in the Sole Pit basin in the Southern North Sea. The reservoir is the Rotliegend Group Leman Sandstone Formation of Lower Permian age and comprises sediments deposited in an arid continental environment. The main gas-bearing interval in the field consists of sabkha, waterlain and minor aeolian sands, reflecting deposition in an erg margin/lake margin setting. The poor primary reservoir quality of these sands has been severely reduced by extensive illite cementation resulting in average air permeabilities of <1 mD. Attempts to develop the field economically utilizing fracture-stimulated vertical wells has met with mixed results, with flow rates of 14 MMscf per day and lower being measured during testing. The most recent appraisal well drilled on the field was a long horizontal well that was stimulated with five hydraulic fractures resulting in an economic flow rate of 44 MMscf per day. Analysis of the core and log data acquired during the appraisal of the field has shown that the reservoir contains a heterogeneous distribution of fractures, faults and micro-faults. The fracture population is dominated by conductive north–south striking fractures, with subordinate NNW–SSE resistive fractures and NE–SW mixed fractures that are arranged in clusters, with zones of high and low fracture density. Well results to date suggest that the NE–SW open and partially open fractures observed in core do not improve reservoir productivity, but those orientated north–south that are conductive appear to improve well deliverability.