Abstract 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.

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 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.

Abstract 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.

Abstract Sandstones that share common detrital mineralogies, depositional environments, and burial histories also share common diagenetic histories. A survey of the diagenetic history of 100 sandstones from around the world has recognized five common, repetitive, and predictable styles of diagenesis in which similar diagenetic mineral assemblages have been observed. The five diagenetic styles are: (1) quartz, commonly with lesser quantities of neoformed clays (e.g., kaolinite and/or illite) and late-diagenetic, ferroan carbonate; (2) day minerals (illite or kaolinite) with lesser quantities of quartz or zeolite and late-diagenetic carbonate; (3) early diagenetic (low-temperature) grain-coating clay mineral cements such as chlorite, which may inhibit quartz cementation during later burial; (4) early diagenetic carbonate or evaporite cement, often localized, which severely reduces porosity and net pay at very shallow burial depths; and (5) zeolites, which occur over a wide range in burial temperature, often in association with abundant clay (usually smectite or chlorite) and late-diagenetic, nonferroan carbonates. The quartz diagenetic style is the most common and accounts for 40% of the sample set. It is also most likely to occur in mineralogically mature sand-stones, while early diagenetic carbonates and zeolites dominate in miner-alogically immature sandstones. Presence or absence of clay appears to be independent of both initial sand mineralogy and depositional environment. However, when clay is present, the type appears to vary as a function of ini-tial sand mineralogy and depositional environment. Large quantities of quartz are unusual cements in sequences that have never been hotter than ~75°C, while illite precipitation at temperatures below ~100°C is rare. Zeolite composition changes systematically from clinoptilolite at ~25°C to laumonite at temperatures >100°C. The repetitive nature and simplicity of these five styles can help predict modifications in reservoir quality due to burial. An accurate prediction of the reservoir quality in sandstones forms the basis of an accurate porosity and permeability prediction ahead of drilling wells in petroleum exploration, development, or production.

Abstract Prior to BP Exploration’s drilling the well Antufash-1 in the Yemeni waters of the Southern Red Sea, reservoir quality was estimated to be poor; it was dry, plugged, and abandoned. The Miocene sandstones encountered were tight, with a mean porosity of 4% in the cored section and a permeability of only 0.07 md. The prediction of low quality for the reservoir section of Antufash-1 was based on very few core analysis data. The diagenetic history of potential reservoir sands in the Antufash acreage was calculated from data on depth to prospect, burial and thermal history of the area, reservoir sand provenance, and depositional environment. An initial assessment, using limited local well data, led to the conclusion that only at depths <0.5 km was it reasonable to expect high reservoir quality (>100 md). However, at depths <1.5 km, permeability was likely to be as low as 10 md. Throughout this depth range, the chances of halite cementation were also reasoned to be high. The rapid deterioration of reservoir quality with depth was attributed to the instability of the original volcaniclastic detritus. Such detritus was predicted to have converted to a mixture of zeolites and smectitic clay soon after deposition. The reactivity of the assemblage was also predicted to have been exaggerated by the high thermal gradients in the area. The recommendation was to avoid large parts of the license area known to have received input of volcaniclastic sediment, and to develop prospects in the few areas thought to have had arkosic sand input. These sands, it was reasoned, would suffer less degradation of reservoir quality. The Antufash-1 well successfully proved the existence of such arkosic sands in the basin, and their diagenetic history was as predicted. Unfortunately, the sandstones were tight. Halite cement filled, as predicted, all remaining porosity.

Abstract Much of the remaining prospectivity in the Ula trend (Norwegian Central Graben) is deep (<3.5 km). A major risk to successful petroleum exploration in the trend is reservoir effectiveness. A few oil discoveries are not yet com-mercial because they occur in low-permeability sandstone. No simple porosity-depth relationship exists for the whole of the Ula trend. As such, mapping of economic basement is difficult. There are, however, simple porosity vs. depth relationships within the two main producing fields: Ula and Gyda. The porosity-depth relationships in the fields are due to downflank cementation by quartz. Quartz cementation was synchronous with oil emplacement, and evidence from petroleum-filled fluid inclusions has led to the conclusion that cementing fluids and petroleum competed in a “race for space.” The Ula trend displays evidence of all three outcomes of such a race: petroleum emplacement ahead of cementation, synchronous processes, and cementation ahead of petroleum emplacement. Porosity prediction for undrilled prospects and prospect segments was made by risking the three possible outcomes of such a race for space. The reservoir in prospect 7/12-JU4 was predicted to be oil bearing and have a mean porosity of about 16.4%: a function of synchronous petroleum emplacement and cementation. The well, however, was dry. It had a mean porosity of 14%; this compares well with the predicted porosity (13.9%) at the well location for a system in which cementation was completed before oil emplacement (equivalent to a porosity estimate for a dry hole).