Abstract Hydrocarbon reservoirs hosted in Permian strata were some of the first to have been discovered in Europe. With discoveries in the Zechstein carbonates of Norway in recent years, and with exploration of Zechstein prospects both onshore and offshore UK, as well as in Dutch, Danish and Norwegian offshore sectors, understanding the architecture of the Zechstein carbonates remains very relevant. Here we study outcrops of Roker Formation carbonates (Z2, Ca2) in NE England to better understand geological processes associated with deformation following evaporite dissolution, with implications for exploration and production. Collapse of Z2 Roker Formation strata in NE England, following the dissolution of c. 100 m or more of the Z1 Hartlepool Anhydrite, resulted in fundamental changes to the architecture of the succession. Complete dissolution of the anhydrite removed an effective regional seal and dramatically enhanced matrix and fracture permeability of the overlying Roker Formation. The collapsed Roker Formation can be vertically divided into three zones, based upon the degree of deformation. The lower zone and vertical collapse-breccia pipes that can extend across all zones have the highest permeabilities. The process of collapse was gradual, with local variations in the degree of brecciation. We derive a schematic sequence of collapse, recognizing the impact of mechanical barriers within the succession in retarding deformation up-section and it is this that ultimately leads to the vertical zonation. Timing of evaporite dissolution is poorly constrained: it could have occurred soon after deposition, at the end of the Permian or during Tertiary uplift. It is known that evaporite dissolution has occurred offshore, with the oil fields Auk and Argyll (UK Central North Sea) given as examples of dissolution collapse-brecciated reservoirs. Reservoir quality is typically improved, with both matrix and fracture porosity and permeability enhanced. Complete evaporite dissolution could in some cases lead to the potential breach of the seal.

Abstract With a history spanning over 50 years, the UK Continental Shelf (UKCS) is one of the most explored and mature basins in the world. Over 44 Bbbl of reserves have been recovered from over 450 fields across the UKCS, enabled by continuous improvement in seismic, drilling and development technologies. Starting in 1965 with BP's West Sole discovery in the Southern Gas Basin, every sector of the UKCS has since opened up. But it is not just the discoveries that have characterized this ultra-mature region. It has weathered a turbulent history of oil prices, fiscal changes, an ever-changing corporate environment and the industry's worst offshore disaster, which serves as a reminder of the uncompromising conditions of the North Sea. Production peaked at the turn of the millennium, and it is only since 2013 that there has been a partial reversal of the declining trend. With discoveries getting scarcer and smaller, maintaining the trend will not be easy, especially with the number of companies exiting the region for more prospective global opportunities on the rise. However, with an estimated 10–20 Bbbl yet to find in the basin, there is still a lot to play for in the coming years.

Abstract Exploration drilling activity, discovery history and creaming curves in the offshore UK are analysed for each UK Continental Shelf (UKCS) basin and each play in the North Sea from the earliest wells drilled in 1965 until the end of 2017. Around 52 Bboe of commercially recoverable oil and gas has been discovered, with around half of this volume found in the first 10 years of exploration. UKCS exploration plays are generally at a mature or super-mature stage and the exploration challenges reflect this. Although technical success rates have steadily increased since the 1990s, pool sizes are becoming smaller. In the last 10 years the average commercial discovery size has been 27 MMboe recoverable, and since 2010 only 10% of discoveries have been bigger than 43 MMboe recoverable. The UK Oil and Gas Authority's 6 Bboe mid-case yet-to-find estimate, as published in 2018, would take 40 years to unlock at the current rate of discovery. Future exploration in the mature UKCS is intertwined with prolonging the life of production infrastructure and is increasingly dependent on the development of new low-cost development concepts. Increased focus on the search for subtle traps, and more reliable pre-drill risk and volume estimation through improved benchmarking and calibration will be key to future exploration success.

Abstract This paper focuses on the southern part of the East Midlands oil province, in which most hydrocarbon reservoirs are in Carboniferous strata and are primarily oil producing. The oils are predominantly sourced from the Namurian interbedded shales in the Gainsborough Trough and are trapped within anticlinal structures. Oil and gas exploration and production in the UK was marked by the Hardstoft-1 discovery in 1919. Since this discovery, more than 33 fields have been discovered in the East Midlands oil province, including the fields studied in this paper: Egmanton (in 1955), Bothamsall and Corringham (in 1958), Gainsborough and Beckingham (in 1959), South Leverton (in 1960), Glentworth (in 1961), and, the UK's second largest onshore field, Welton (in 1981). All of these fields produce from a Carboniferous petroleum system, sourced from Pendleian-age shales, reservoired in Namurian- and Westphalian-age sands, and trapped predominantly via structural, anticlinal traps.

Abstract The Crosby Warren Field is located onshore the UK, south of the Humber Estuary. It was discovered by RTZ Oil & Gas with the CW-1 (L46/12-3) well in 1986. The oil reservoir is Carboniferous, Namurian, Beacon Hill Flags sandstone, with gas found in Namurian sandstones of the Rough Rock, and the discovery well originally flowed waxy 40° API oil at rates of 45 bopd, which increased to nearly 700 bopd following fracture stimulation. The Beacon Hill Flags are a 10 m-thick group of laminated sandstones within a substantial gross thickness of sandstones, silts, muds and occasional thin claystones. The expected ultimate recovery for the field will be about 0.9 MMbbl of oil and 0.7 bcf of gas. Almost all of the oil and gas have already been recovered, and end of life for the field is expected to be in 2022.

Abstract The Elswick Field is located within Exploration Licence EXL 269a (Cuadrilla Resources Ltd is the operator) on the Fylde peninsula, West Lancashire, UK. It is the first producing onshore gas field to be developed by hydraulic fracture stimulation in the region. Production from the single well field started in 1996 and has produced over 0.5 bcf for onsite electricity generation. Geologically, the field lies within a Tertiary domal structure within the Elswick Graben, Bowland Basin. The reservoir is the Permian Collyhurst Sandstone Formation: tight, low-porosity fluvial desert sandstones, alluvial fan conglomerates and argillaceous sandstones. The reservoir quality is primarily controlled by depositional processes further reduced by diagenesis. Depth to the reservoir is 3331 ft TVDSS with the gas–water contact at 3400 ft TVDSS and with a net pay thickness of 38 ft.

Abstract The Humbly Grove Field has, for the UK, a unique development history. It was discovered as an oilfield in May 1980 and produced as an oilfield until 2000 along with small satellite fields Herriard (developed) and Hester's Copse (not developed). Peak production of 2219 bopd was achieved during July 1986 but, by October 1988, the rate had fallen to around 1000 bopd, a rate that was more or less maintained until October 1995 after which the production fell rapidly. At this point the decision was taken to reconfigure the field as a gas storage facility. Significant renewed pressure depletion occurred between 2000 and 2005, following which first cushion and then storage gas was injected into two reservoirs: the Middle Jurassic, Great Oolite Group and the uppermost Triassic, Rhaetian Westbury Formation. Gas storage operations commenced in 2005 and the reservoirs have undergone cyclical gas injection and gas withdrawal since that date. The cyclical injection of gas and re-pressuring of the Great Oolite reservoir causes mobile oil to be swept towards dedicated oil production wells. This operates effectively as an enhanced oil recovery scheme. The co-produced liquid hydrocarbons provide a valuable secondary income stream for the field.

Abstract The Vale of Pickering gas fields were discovered over a 20-year period. The development scheme was aimed to deliver 9.3 MMscfd gas to the Knapton Power Station nearby. Cumulative production is 30.3 bcf from an estimated 172 bcf gas initially in place. The gas fields comprise a series of low relief structures at depths around 5000 ft true depth subsea. The primary reservoir is Zechstein Group dolomitized and fractured carbonates of the Permian Kirkham Abbey Formation with average reservoir quality ranges of 12–13% porosity and 0.5–1.5 mD permeability. Secondary reservoirs exist in Carboniferous sandstones directly below the Base Permian Unconformity. The gas is sourced from Lower Carboniferous shales. The fields were discovered using 2D seismic data and subsequent 3D seismic data have been merged to form a 260 km 2 dataset. Zechstein production has been limited by early water breakthrough. Artificial lift is planned to enhance the gas flow rate on the Pickering Field and anticipated water influx will be re-injected. If this enhanced gas recovery scheme is successful it can be applied to the other fields. Plans to hydraulically fracture a number of zones in the Carboniferous Lower Bowland Section are in progress.

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 Cavendish Field is located in UK Continental Shelf Block 43/19a on the northern margin of the Outer Silverpit Basin of the Southern North Sea, 87 miles (140 km) NE of the Lincolnshire coast in a water depth of 62 ft (18.9 m). The Cavendish Field is a gas field in the upper Carboniferous Namurian C (Millstone Grit Formation) and Westphalian A (Caister Coal Formation) strata. It was discovered in 1989 by Britoil-operated well 43/19-1. Production started in 2007 and ceased in 2018. Gas initially in place was 184 bcf and at end of field life 98 bcf had been produced. The field was developed by three wells drilled through the normally unmanned platform into fluvio-deltaic sandstone intervals that had sufficiently good reservoir quality to be effective reservoirs. The majority of the formation within closure comprises mudstones, siltstones and low permeability, non-reservoir-quality feldspathic sandstones. The quality of the reservoir is variable and is controlled by grain size, feldspar content and diagenesis. The field is a structural trap, sealed by a combination of intra-Carboniferous mudstones and a thick sequence of Permian mudstones and evaporites.

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.