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Human emissions of greenhouse gases have caused a predictable rise of 1.2 °C in global temperatures. Over the last 70 years, the rise has occurred at a geologically unprecedented speed and scale. To avoid a worsening situation, most developed nations are turning to renewable sources of power to meet their climate commitments, including the UK, Norway, Denmark and The Netherlands. The North Sea basin offers many advantages in the transition from fossil fuels by virtue of its natural resources, physical setting, offshore infrastructure and skilled workforce. Nonetheless, the magnitude of the up-front costs and the scale required to achieve net zero emissions are rarely acknowledged. In addition, some of the technologies being planned are commercially immature. In particular, the current cost of the capture, transport and disposal of carbon dioxide is problematic as a large-scale solution to industrial emissions. Repurposing the North Sea to meet a low-carbon future will require substantial collaboration between governments and industrial sectors. There are nonetheless significant opportunities for companies prepared to switch from the traditional oil and gas business to renewable energy production and other sustainable activities.

Clay-coated grains play an important role in preserving reservoir quality in high-pressure, high-temperature (HPHT) sandstone reservoirs. Previous studies have shown that the completeness of coverage of clay coats effectively inhibits quartz cementation. However, the main factors controlling the extent of coverage remain controversial. This research sheds light on the influence of different depositional processes and hydrodynamics on clay-coat coverage and reservoir quality evolution. Detailed petrographic analysis of core samples from the Triassic fluvial Skagerrak Formation, Central North Sea, identified that channel facies offer the best reservoir quality; however, this varies as a function of depositional energy, grain size and clay content. Due to their coarser grain size and lower clay content, high-energy channel sandstones have higher permeabilities (100–1150 mD) than low-energy channel sandstones ( Supplementary material: of data and technique used in this study are available at https://doi.org/10.6084/m9.figshare.c.6438450

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.

The Alma Field (formerly Argyll and then Ardmore) is located within Blocks 30/24 and 30/25 on the western margin of the Central Graben. Hamilton drilled the first discovery well 30/24-1 in 1969 and the field, named ‘Argyll’, became the first UK offshore oilfield when production commenced in 1975. Oil was produced from the Devonian Buchan Formation, Permian Rotliegend and Zechstein groups, and Jurassic Fulmar Formation from 1976 until 1992, when the field was abandoned for economic reasons. In 2002, Tuscan Energy and Acorn Oil & Gas redeveloped the field and renamed it as ‘Ardmore’. A further 5 MMbbl were produced until 2005, when the field was again abandoned due to commercial considerations. In 2011, EnQuest was awarded the licence to redevelop the field and renamed it as ‘Alma’. The field came on stream in October 2015 and has produced oil at an average c. 6000 bopd since start-up. Total ultimate recovery was expected to be about 100 MMbbl. As of end 2005, the field had produced 72.6 MMbbl as Argyll and 5 MMbbl as Ardmore. A further 4.3 MMbbl has been produced from the Alma Field to September 2017 (which includes about 0.5 MMbbl from a long-reach well drilled into the Duncan/Galia Field immediately west of Alma). In January 2020 EnQuest announced that the Alma Field would cease production early. The total production from the three phases of field development will be about 85 MMbbl of oil.

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 km2. 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%).

The Morag Field is a small oilfield underlying the Maureen Field in UK Block 16/29a. Black oil is trapped within Upper Permian, Morag Member, vuggy and fractured dolomite rafts between 9300 and 10 600 ft true vertical depth subsea. The dolomite reservoir occurs at the top of a Zechstein salt dome. Morag was discovered in 1979 by well 16/29a-A1, the first platform well drilled for the overlying Maureen Field with its Paleocene sandstone reservoir. Morag was produced via a single well (16/29a-A1) between 1991 and 1994. Three more platform wells were drilled into the Permian interval prior to Maureen Field start up but only one penetrated oil-bearing dolomite (16/29a-A2). An additional well (16/29a–A23Z) was drilled into the Morag Field in 1993. The well encountered Morag Member at virgin pressure and tested oil at high flow rate but then the well failed due to mechanical problems. Oil in place was calculated to be about 24 MMbbl in four independent fault blocks. Ultimately 16/29a-A1 delivered 2.6 MMbbl from a fault block calculated to have held 6.7 MMbbl stock tank oil initially in place.

Located 160 km NE of the Shetland Islands in the East Shetland Basin, the Dunlin Cluster comprises four produced fields, Dunlin, Dunlin SW, Osprey and Merlin, in addition to some near-field satellite discoveries, Skye and Block 6. Dunlin was discovered in July 1973 and production began in August 1978. The field was developed using a concrete gravity-base platform, Dunlin Alpha, which also served as the production facility for the rest of the Dunlin Cluster. Osprey was discovered in 1974 but not tied-in until January 1991. Dunlin SW was discovered in 1973 but not brought onto production until 1996. Merlin was discovered in February 1997 and tied-in later that same year. Fairfield Energy acquired the Dunlin Cluster in 2008, and a programme of investment and facilities improvements, primarily in fuel gas infrastructure and power generation, sought to boost water-injection rates and bolster production, thereby extending the life of the asset. Ultimately, the Dunlin Cluster ceased production on 15 June 2015 after having maximized economic hydrocarbon recovery. The total Dunlin Cluster production exceeded 500 MMbbl of oil (Dunlin and Dunlin SW, 395 MMbbl oil; Osprey, 92 MMbbl oil; and Merlin, 27 MMbbl oil).

The, as yet undeveloped, heavy-oil fields of the Western Platform contain about 500 MMbbl of oil in place. The fields are reservoired in highly porous and permeable, Middle Eocene, deep-water sandstones of the Tay Sandstone Member, deposited as turbidite flows from a shelf immediately to the west. Oil gravity varies from 19° API in the Harbour Field to 12° API in the northern end of the Pilot Field. The reservoirs are shallow: Pilot and Harbour are at about 2700 ft TVDSS, with the Narwhal, Elke, Blakeney and Feugh discoveries being deeper at about 3300 ft TVDSS. Overall, oil viscosity decreases and API oil gravity increases with depth. To date, the high oil viscosity has precluded development of these discoveries, and many previous operators have considered various development schemes, all based on water flood. The development of the Pilot Field is being planned using either a hot-water-flood, steam-flood or polymer-flood approach, which all have the potential of achieving a very high recovery factor of 35–55%. Steam has been evaluated in most detail and about 240 MMbbl could be recovered should all of these discoveries be steam flooded.

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.

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 Hester9s 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.

This volume was conceived when one of us (JG) returned to the UK in mid-1996. Having not worked the UK offshore since the late 1980s it was clear that there had been many changes, not least in the number of fields on production. During that first year back in the UK, JG9s copy of Abbots (1991) UK Oil and Gas Fields, 25 Years Commemorative Volume became exceedingly well used. A casual comment to Wendy Cawthorne of the Geological Society library to this effect solicited the response that JG was not alone in finding Abbots (1991) useful. Memoir 14 was the Geological Society9s 9best seller9. However, although Abbots (1991) continues to sell well, it was by 1996 out of date insofar as it contains papers describing only about half of the fields then on production. A combination of egotistical zeal, wishing for a bestseller and altruism towards the UK industry led us to make an offer to the Geological Society to revise Memoir 14. The offer was accepted and by April 1998, editors had been appointed and letters of invitation to contribute to the memoir were sent to exploration managers in all the UK operating companies. The responses to those letters were for the most part positive. A request was made to authors for manuscripts to be sent to the editors by June 1999. The first to arrive was six months ahead of schedule (thanks A. Yaliz & N. McKim for their paper on the Douglas Field). However, neither the editors

Hutton (discovered in 1973) and NW Hutton (discovered in 1975), together with Q-West (discovered in 1994) and Darwin (discovered in 1983, undeveloped), are part of a single petroleum system. The main fields were defined as two separate legal entities. Although Q–West covered multiple blocks, it was wholly developed via the Hutton platform. Together, Hutton and NW Hutton produced 328 MMbbl of oil and a small quantity of associated gas from Middle Jurassic Brent Group sandstones. The trap is a complex series of tilted fault blocks sealed by Mid–Upper Jurassic Heather and Kimmeridge Clay Formation mudstones. Oil was sourced from the Kimmeridge Clay Formation, which is mature for oil generation in the hanging walls to the field-bounding faults and deep on the footwall flanks. NW Hutton underperformed relative to Hutton. In part this was due to the poorer reservoir quality encountered at depth compared with the shallower Hutton Field but a significant component of the underperformance was due to the way in which the field was developed and then operated. Both fields contain areas of unproduced and unswept oil, with the NW Hutton portion having the largest remaining oil in place.

The abandoned Innes Field was within Block 30/24 on the western margin of the Central Trough in the UK sector of the North Sea. Hamilton Brothers Oil Company operated the licence, and Innes was the third commercially viable oil discovery in the block after Argyll and Duncan. It was discovered in 1983 with well 30/24-24. Three appraisal wells were drilled, one of which was successful. Oil occurs in the Early Permian Rotliegend Group sandstones sealed by Zechstein Group dolomites and Upper Jurassic shale. The discovery well and successful appraisal well were used for production. Export of light, gas-rich crude was via a 15 km pipeline to Argyll. Innes was produced using pressure decline. It was abandoned in 1992 having produced 5.8 MMbbl of oil and possibly 9.8 bcf of gas. Water cut was a few percent. Innes was re-examined between 2001 and 2003 by the Tuscan Energy/Acorn Oil and Gas partnership with a view to tying the field back to the newly redeveloped Argyll (Ardmore) Field but marginal economics and financial constraints for the two start-up companies prevented any further activity. Enquest currently owns the licence and the company has redeveloped Argyll/Ardmore, as Alma. There are no plans to redevelop Innes.

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 CO2 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 × 106 t of dense phase CO2 each year for 20 years. The site was not developed following the UK Government9s 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.

Unocal discovered the Acorn South Field with wells 29/8b-2 and 29/8b-2s in 1983. The well and its side-track found a small accumulation of oil in Upper Jurassic, Fulmar Formation sandstones in an inter-pod setting. Well 29/8b-3 drilled two years later on what was thought to be the same structure found Acorn North, a larger accumulation of oil in a Triassic Skagerrak Formation reservoir on the crest of a Triassic pod. Premier discovered the Beechnut Field two years later, well 29/9b-2 finding oil in the Fulmar and Skagerrak formations in a faulted, inter-pod setting. Both Acorn and Beechnut are deep, high-pressure and high-temperature fields with complex reservoir stratigraphy due to halokinesis during sedimentation and post-depositional structuration. The Skagerrak Formation reservoir in Acorn North is appreciably poorer than similar-age reservoirs further north whilst the Fulmar Formation in Beechnut is relatively poorly developed. Acorn9s mid-case oil in place is 90 MMbbl in the Skagerrak Formation and 13 MMbbl in the Fulmar Formation and, for Beechnut, is 15 MMbbl in the Fulmar Formation. Neither field has been developed. Limiting factors include the resource size, variable reservoir development (Beechnut), modest reservoir quality (Acorn North), compartmentalization concerns and development costs.

In June 1975, oil from the Argyll Field became the first to be produced from the UK North Sea. Seventeen years later, the Argyll Field was abandoned with all production facilities removed. In 2001, two new companies, Acorn Oil & Gas and Tuscan Energy, had identified Argyll as a potential field redevelopment. The UK's Department of Industry was approached with a request to relicense the Argyll Field out of round in order to redevelop the field. No company previously had sought to obtain a licence for production rather than exploration. In September 2003, a well was drilled on the renamed Ardmore Field. It flowed at 20 000 barrels of oil per day. However, after 2 months of sustained high rate, the well cut water. With a second well on stream, production peaked at 28 000 barrels of oil for 1 day before the facilities, designed for 50 000 barrels of fluid per day, tripped-out. All was not well; facilities and well issues limited production. In mid-2005, the field was abandoned again: 5 MMbbl (million barrels) from an expected 25 MMbbl was produced. However, the story was not yet finished. By 2013 EnQuest had acquired the licence and drilled six wells. Production restart began in late 2015.

In 2015, the North Sea petroleum province was 50 years old. The celebrations were short lived because oil prices and gas prices were in free fall. The demand from the UK market had outstripped demand back in 2005 and, 10 years on, falling production and increasing operating expenditure, when coupled with falling prices, had brought the North Sea to crisis point. Many fields became unprofitable and companies began to close down. In an effort to avert the developing crisis, this work examines what options exist for better utilizing the North Sea industry, be that monetizing co-produced fluids or using the pore space once occupied by petroleum for waste products such as carbon dioxide. We briefly examine: the possibility of utilizing heat from the co-produced fluids for power generation; extracting gases and ores from co-produced fluids; and evaluation of the role that carbon dioxide could play in enhanced oil and gas recovery, as well as its ultimate long-term storage in geological deep storage.

Modification of existing oilfield infrastructure could deliver a cost-effective way to extend the economic life of depleted onshore oilfields. Naturally warm connate and injection water contained within these fields could be initially co-produced with remaining oil reserves and used to deliver clean, cheap, non-intermittent heating. The East Midlands Petroleum Province contains over 30 fields with a production history spanning 95 years, and we have chosen to examine the Welton field in detail. Well data for the Welton field have been analysed to ascertain extractable heat within both oil- and non-oil-bearing (water-bearing) strata within the field. Production rates were calculated to be 728 m3 d−1 oil and 854 m3 d−1 water. These values also include productivity of intervening largely water-bearing intervals. Target formation temperature at 1500 m was determined to be 52.5°C, allowing an extractable heat energy calculation to be undertaken for a range of temperature differentials. For a 30°C depletion in temperature, 1.6 MWt extractable heat is available within the Welton field alone. This equates to 14040 MWh of heat energy available for consumption by the domestic market or within commercial greenhouses.

The Staffa Field occurs at the crest of an intermediate tilted fault block that is located between the Ninian and Alwyn fields in the northern North Sea. The partnership BP, Lasmo and Ranger discovered the field with well 3/8b-10 in 1985. By 1990, BP had left the partnership while Lasmo and Ranger had received Annex B approval for development. First production from this small field reservoired in sandstones belonging to the Middle Jurassic, Brent Group was obtained in 1992. At sanction, reserves were estimated to be about 5.5 MMBBL together with 26.8 BCF corresponding to a recovery factor of 18%. Field life was expected to be about 7.5 years (to 2000) and the plateau length six months. Although initial production exceeded the planned plateau rate of 8000 BOPD, production ceased in June 1993 when the pipeline to Ninian became blocked with wax or wax hydrates. Remedial solvent treatment failed to remove the blockage and replacement of the blocked section was undertaken. This too became blocked soon after resumption of production and the field was shut-in in November 1994. It was then abandoned, since further replacement of the line was not justified economically. At abandonment the field had produced 3.9 MMBBL of oil, 0.296 MMBBL of NGL and 6.457 BCF of gas Gust 13% of its original STOIIP).

When a reservoir fills with petroleum, the process commonly takes about 10 Ma. Cementation of a sandstone reservoir can occur in a similarly short time. There is much direct evidence that these two processes can occur at about the same time. In petroleum-bearing sandstone reservoirs it is common to find inclusions of petroleum trapped in diagenetic minerals. The effect on reservoir porosity and permeability caused by the interaction of these two processes is dramatic. Fields with a relatively early petroleum charge, earlier that is than cementation, can be saved from the ravages of reservoir quality destruction. Fields in which the two processes were acting at the same time commonly display porosity-depth gradients which are twice the regional average. If cementation beats petroleum in this ‘race for space’ there may be no field to produce, as the petroleum may not be recoverable from the low quality reservoir. We believe that the processes of petroleum generation/migration and cementation may share a common cause. Both processes are commonly associated with major changes within a basin: rapid burial/heating of the sediment pile and/or major faulting which changes the basin ‘plumbing’.