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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.

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.

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.

Coal‐formed gas generated from the Permo‐Carboniferous coal measures has become one of the most important targets for deep hydrocarbon exploration in the Bohai Bay Basin, offshore eastern China. However, the proven gas reserves from this source rock are remain low to date, and the distribution characteristics and accumulation model for the coal‐formed gas are not clear. Here we review the coal‐formed gas deposits formed from the Permo‐Carboniferous coal measures in the Bohai Bay Basin. The accumulations are scattered, and dominated by middle‐small sized gas fields, of which the proven reserves ranging from 0.002 to 149.4×108m3 with an average of 44.30×108m3 and a mid‐point of 8.16×108m3. The commercially valuable gas fields are mainly found in the central and southern parts of the basin. Vertically, the coal‐formed gas is accumulated at multiple stratigraphic levels from Paleogene to Archaeozoic, among which the Paleogene and Permo‐Carboniferous are the main reservoir strata. According to the transporting pathway, filling mechanism and the relationship between source rocks and reservoir, the coal‐formed gas accumulation model can be defined into three types: “Upward migrated, fault transported gas” accumulation model, “Laterally migrated, sandbody transported gas” accumulation model, and “Downward migrated, sub‐source, fracture transported gas” accumulation model. Source rock distribution, thermal evolution and hydrocarbon generation capacity are the fundamental controlling factors for the macro distribution and enrichment of the coal‐formed gas. The fault activity and the configuration of fault and caprock control the vertical enrichment pattern.

SUMMARY Cosmic ray muons are highly penetrating, with some reaching several kilometres into solid rock. Consequently, muon detectors have been used to probe the interiors of large geological structures, by observing how the muon flux varies with direction of arrival. There is an increasing need to discriminate between materials differing only slightly in bulk density. A particularly demanding application is in monitoring underground reservoirs used for CO2 capture and storage, where bulk density changes of approximately 1 per cent are anticipated. Muon arrival is a random process, and it is the underlying expectation values, not the actual muon counts, which provide information on the physical parameters of the system. It is therefore necessary to distinguish between differences in muon counts due to real geological features, and those arising from random error. This is crucial in the low-contrast case, where the method can reach the information theoretic limit of what a data source can reveal, even in principle. To this end, methods to analyse information availability in low-contrast muon radiography have been developed, as have means to optimally interpret the available data, both for radiography and for tomography. This includes a method for calculating expectation values of muon flux for a given geological model directly, complementing existing Monte Carlo techniques. A case study, using a model of carbon capture is presented. It is shown that the new data analysis techniques have the potential to approximately double the effective sensitivity of the detectors.

The Permo-Carboniferous sandstones in the Gubei area, Bohai Bay Basin, are reservoirs for large accumulations of natural gas. The natural gas accumulations only occur in the sandstone beds thicker than 1.9 m. Moreover, the maximum porosity of every bed correlates positively with bed thickness up to 2.0 m and for thicker beds porosity is uniform. Porosity transitional zones developed at the top and bottom of each bed, with mean thicknesses of 1.25 m and 0.75 m, respectively. Porosity shows a positive correlation with the distance to the sandstone/mudstone contact in the zones. Interpretations based upon an extensive petrographic and geochemical database indicate that the sandstones experienced a mass fluid input from the adjacent mudstones during the early diagenesis. The infiltration resulted in extensive clay coats and pore-filling cements in sandstones, which were effective for inhibiting dissolution of grains during subsequent diagenesis process. The mass introduction only affected the marginal parts of the sandstones within 1.25 m of the top and 0.75 m of the bottom of every bed, causing thin sandstone beds with thickness of approximately 2 m to be tightly cemented totally. Thus the central parts of each (thicker) beds became preferential sites for the natural gas accumulation. The differential levels of cementation in thin and thick sandstone beds observed here has significant implications for exploration of similar interbedded sandstone and shale sequences elsewhere including shale gas targets.

The reservoir quality of tight sandstones is generally determined by the depositional environment, burial depth and diagenesis. However, the relationship between reservoir quality of tight sandstones and the controlling factors are very complicated. Deeply buried Middle-Upper Jurassic Shishugou Group sandstones are important tight oil sandstone reservoirs in the central Junggar Basin of NW china. The individual sandstones are thin (2–20 m, av.7.8 m), overlain by an unconformity and directly connected to the source rock by a well-developed fault system. The diagenetic system and reservoir quality of the Shishugou Group sandstones in the Central Junggar Basin was investigated using petrology, mineralogy, pore characteristics, sedimentary facies, burial and thermal history, knowledge of hydrocarbon charging, fault/fracture system, diagenetic reactions and sequence, controlling factors of reservoir quality, paleo-porosity reconstruction and formation mechanism of high-quality reservoir. The thin-section observation, scanning electron microscope (SEM and BSD), granularity analysis, Xray diffraction (XRD) and fluorescence microscope, 3D seismic and well logging analysis were used in this research. The top unconformity and faults system were the pathways for water and hydrocarbon migration. Organic acids and meteoric water with high concentrations of CO2 were the main fluids that caused dissolution of volcanic rock fragments, feldspar, analcime cement and early calcite cement. The paleo-porosity variation of Shishugou Group sandstones was analyzed quantitatively by the inversion and back stripping with the constrain of diagenetic evolution history and theoretical compaction models. The comprehensive researches including the origin of pore waters, origin of acidic fluids, fault/fracture system and hydrocarbon charging history, show that near-surface or meteoric diagenetic reactions of Shishugou Group sandstones closely beneath top unconformities were in open (geochemical) diagenetic systems, and that diagenetic (geochemical) systems were relatively open, especially in the faults-developed zone during burial process. The central sandstone body of the point bar, underwater distributary channel and distributary channel, which were cut through by the oil source fault, retained high-quality reservoir. The reservoir quality can be mostly predicted as a function of sedimentary environment (sedimentary facies and provenance), diagenetic reactions and burial history with the constrain of source rocks, diagenetic system and fault system.

Organic-inorganic interactions after oil charging are critical for determining the ongoing evolution of hydrocarbons and rock quality in water-wet siliciclastic reservoirs. It is the conceptual approach of this study to simulate and decipher these interactions by using quantitative analyses of the interrelated changes of minerals, water, hydrocarbons, gases, and organic acids in heated oil-water-rock systems. The experimental results show that organic-inorganic interactions occur between the organic oil and inorganic feldspar in the presence of water. Water promotes the oil degradation by an extra supply of H+ and OH- ions. In the oil-water-rock systems, mutual exchanges of H+ and OH- ions among minerals, water, and hydrocarbons probably result in the mutual interactions between oil degradation and mineral alteration, with water serving as a matrix for the ion exchange. In the oil-water-feldspar system, feldspar alteration does not cease in the oil zone in the presence of some water and, inversely, oil degradation can even accelerate the alterations of the aluminosilicate minerals. The mineral alterations from feldspar to boehmite, illite, and muscovite promote the oil degradation in the oil-deionized water-feldspar systems with the mutual ion exchange. Due to a possible competition between the Brønsted acid sites in the minerals and the halide anions or the direct replacement of K-feldspar by albite, the mineral alterations retard the oil degradation in the oil-NaCl water-feldspar systems. The experimental results also indicate that oil degradation via free radical cross-linking and free radical thermal cracking is extensive in anhydrous oil systems and may lead to blocking of pores and throats by the generated pyrobitumen in the oil zone of a reservoir. In contrast, in the oil-water transition zone of a reservoir, oil degradation via thermal cracking and oxidative decomposition may dominate the oil degradation and may lead to the generation of secondary pores with leaching of minerals by the generated CO2 and organic acids. This study clearly demonstrates that organic-inorganic interactions are very complex and proceed in diverse pathways in different hydrogeochemical systems. Thus, further quantitative investigations of the reaction pathways and reaction kinetics of coupled mineral alteration and oil degradation in oil-water-rock systems are merited. Meanwhile, the incorporation of such organic-inorganic reactions into geochemical models will improve the prediction of the evolution of organic and inorganic species in petroleum reservoirs.

Proximal to distal fan change in grain size, clay matrix content, and grain-coating clays have been identified as key contributing factors for eservoir quality evolution of submarine fan turbidite sandstones. This study evaluated the role played by grain-coating and pore-filling clays, depositional facies, and diagenesis in reservoir quality evolution of the Paleocene Forties submarine fan sandstones (Central North Sea) from proximal to distal fan settings. To help provide a comprehensive understanding of the role played by pore-filling and grain-coating clays in destroying and preserving reservoir quality, respectively, in turbidite sandstones, we have used a multi-disciplinary approach including petrography, burial history, scanning electron microscopy, and stable isotopes analysis. Results of the study showed that reservoir quality is influenced by both depositional facies and diagenesis. The proximal-fan, amalgamated sandstones facies have the best reservoir quality due to coarser grain size, lower pore-filling clays, and lower amount of ductile grains. In contrast, the distal-fan, mud-prone heterolithic facies have the poorest reservoir quality due to finer grain size, higher pore-filling clays, and higher amount of ductile grains. Pore-filling clays between 10 and 30% have a deleterious effect on reservoir quality, reducing porosities and permeabilities to generally

The Jurassic Shaximiao Formation on the eastern slope of western Sichuan depression in western Sichuan Basin of China develops a single or overlapping channel sandstones with strong internal heterogeneity. This study aims to reveal the origin of the differences of physical properties within the sandstone reservoirs under different assemblies of lithofacies. Based on analysis of sedimentary structure and grain size, the lithofacies are classified into nine types. Based on the classification of lithofacies formed under different energy of sedimentary environment and mechanical differentiation, the effect of early compaction on physical properties of sandstone reservoirs is confirmed. It is suggested that the physical properties of lithofacies can be influenced by differential diagenesis in different lithofacies assemblies. The rate of early compaction depends on the grain sorting and compositional maturity. The massive bedded lithofacies are prone to be of good grain sorting and high compositional maturity with relatively low compaction rate of 70.91%–72.75%. There are relatively high porosities and permeabilities of sandstones in the lithofacies assembly containing massive bedded lithofacies. Because of the export of diagenetic fluid along the bedding plane of parallel bedded sandstones, there would be relatively intensive dissolution of sandstones developed with parallel bedded lithofacies. Even if the development of parallel bedded sandstones could enhance the dissolution, yet they are subjected to relatively strong compaction, leading to the low proportion of intergranular pores. The permeability of sandstones within the lithofacies assembly containing parallel bedded lithofacies seems to be low. The porosity and permeability of sandstones within the lithofacies assembly containing horizontal bedded lithofacies are both poorer than other assemblies, caused by strong compaction, cementation and weak dissolution. The direction of bedding, argillaceous contents, and the capacity of resistance to compaction are the key factors controlling the physical property of high-quality sandstone reservoirs. The research conclusions can be used to interpret the genesis of different physical properties of sandstone reservoirs in other similar gas fields.

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.

The Ahdeb oil field is located in the Mesopotamian Basin of central Iraq within a northwest–southeast-trending anticline. Seven oil-bearing layers exist in the eastern area in the field, but there is only one oil-bearing layer in the western area. This study reveals that the reservoir filling process resulted from the difference in the elements in the petroleum system, the oil generation and migration process, and the formation of the structural trap. Most oils in the field, with pristane/phytane < 1 and a high relative abundance of hopanes exceeding C30, were generated from the Upper Jurassic–Lower Cretaceous Chia Gara Formation, whereas some oils were generated from the Lower Cretaceous Ratawi and Zubair Formations. The mid-Upper Cretaceous reservoirs in the field are composed of lime grainstones, packstones, and wackestones. The main oil accumulation occurred during the Maastrichtian, coinciding with peak oil generation from the Chia Gara Formation with a 50% transformation ratio from organic matter to oil. The reservoirs of the eastern structural trap in the field were filled with large amounts of medium to heavy oils. After the formation of two structural traps in the western area in the mid-Miocene, oils pre-existing in the second layer of the Khasib Formation in the east began migrating toward the structural traps in the west during the late Miocene, as verified by relatively higher 1-/4-methylcarbazole and 1,8-/2,7-dimethycarbazole ratios of oils in the west than that in the east and residual solid bitumen in the east. The strike-slip fault might also have restricted oil or gas migration during the Miocene, limiting oil accumulation in the west.

Feldspar dissolution, quartz cementation, and clay cementation are significant diagenetic processes in deep-water fan feldspar-rich sandstones in the Shengtuo area, Dongying sag (East China). The timing and origin of these water–rock interactions as well as the paleofluids in which relevant chemical reactions occurred were deduced using data from microscopy, fluid-inclusion microthermometry, oxygen-isotope microanalysis, and trace-element microanalysis. Three distinct, separate episodes of quartz overgrowths (referred to as Q1, Q2, and Q3) were distinguished by cathodoluminescence microscopy. The Q1 quartz, identified in all porous sandstones from 2500 to 3600 m (8200 to 11,800 ft), was formed at approximately 100°C–115°C (212°F–239°F) before oil filled the reservoirs. The Q2 quartz was mainly precipitated at 115°C–130°C (239°F–275°F), accompanying or slightly postdating the main phase of oil filling, and was identified in samples from 2800 to 3600 m (9200 to 11,800 ft). The Q3 quartz was only identified in sandstones buried deeper than 3500 m (11,400 ft) and was likely precipitated in the Quaternary when temperature exceeded 130°C–135°C (266°F–275°F). Secondary ion mass spectrometry oxygen-isotope microanalyses yielded δ18OVSMOW (Vienna standard mean ocean water) values ranging from 21.42‰ to 24.35‰ for Q1 quartz, from 22.03‰ to 24.99‰ for Q2 quartz, and from 21.72‰ to 22.91‰ for Q3 quartz. A mass-balance calculation and quantitative petrography data of the amount of leached feldspars and associated secondary minerals suggest that the internal feldspar dissolution is likely the primary source for the authigenic clays and quartz cements in these sandstones. Positive δ18O(water) values (+0.5‰ to +4.5‰ VSMOW) of quartz-forming waters indicate that quartz cementation and feldspar dissolution occurred in a geochemical system with a limited volume of diagenetically modified connate water. The variations of δ18O(cements) and trace-element compositions from Q1 quartz to Q2 quartz in individual overgrowth suggest that hydrocarbon filling changed the chemistry of the pore fluid significantly; further, δ18O(water) values of the pore water increased by approximately 2‰ VSMOW after oil filling. Meteoric freshwater did not contribute to quartz cementation and simultaneous feldspar dissolution. The detected CO2 and hydrocarbons in fluid inclusions in the quartz cements, the existence of CO2 in hydrocarbon-rich natural gas, and the pyrobitumen in the feldspar-hosted pores suggest that acids derived from organic matter (kerogen in source rocks and hydrocarbons in reservoirs) probably have promoted the extensive subsurface leaching reactions of feldspars in these sandstones. The ongoing development of Q2 and Q3 quartz suggests that quartz precipitation did not cease after oil filling. Further, diagenetic reactions likely have proceeded from water–rock interactions to hydrocarbon–water–rock interactions.

The Upper Devonian Buchan Formation reservoirs in the UK Central North Sea are litharenite/sublitharenite and were deposited in fluvial–aeolian settings. The grain-coating clays in the aeolian sandstones have effectively inhibited quartz overgrowth. Hence, the reduction of reservoir quality is mainly due to mechanical compaction and early dolomite precipitation in both fluvial and aeolian sandstones; quartz overgrowth and kaolinite illitization in fluvial sandstones; and limited smectite illitization in aeolian sandstones. The carbon/oxygen stable isotopes of dolomite cements suggest a predominantly marine carbon source and precipitation temperatures between 25 and 58 °C indicating a shallow burial depth during dolomite precipitation. The temperatures and the dolomite distribution indicate that the cements originated from the overlying Upper Permian Zechstein carbonates. Extensive quartz overgrowths formed at 80 and 120 °C in the late and deep diagenetic burial history. The most probable silica source was from feldspar kaolinitization and pressure dissolution of quartz grains. Through detailed petrography and geochemical analyses, the burial–paragenesis–thermal history of the Buchan Formation has been constructed. Similar diagenetic processes are likely to have occurred in the Buchan Formation in other parts of the Central and Northern North Sea. This study may allow new petroleum plays to be considered in areas previously thought to have poor hydrocarbon potential.

The Human-induced Earthquake Database, HiQuake, is a comprehensive record of earthquake sequences postulated to be induced by anthropogenic activity. It contains over 700 cases spanning the period 1868–2016. Activities that have been proposed to induce earthquakes include the impoundment of water reservoirs, erecting tall buildings, coastal engineering, quarrying, extraction of groundwater, coal, minerals, gas, oil and geothermal fluids, excavation of tunnels, and adding material to the subsurface by allowing abandoned mines to flood and injecting fluid for waste disposal, enhanced oil recovery, hydrofracturing, gas storage and carbon sequestration. Nuclear explosions induce earthquakes but evidence for chemical explosions doing so is weak. Because it is currently impossible to determine with 100% certainty which earthquakes are induced and which not, HiQuake includes all earthquake sequences proposed on scientific grounds to have been human-induced regardless of credibility. Challenges to constructing HiQuake include under-reporting which is ~ 30% of M ~ 4 events, ~ 60% of M ~ 3 events and ~ 90% of M ~ 2 events. The amount of stress released in an induced earthquake is not necessarily the same as the anthropogenic stress added because pre-existing tectonic stress may also be released. Thus earthquakes disproportionately large compared with the associated industrial activity may be induced. Knowledge of the magnitude of the largest earthquake that might be induced by a project, MMAX, is important for hazard reduction. Observed MMAX correlates positively with the scale of associated industrial projects, fluid injection pressure and rate, and the yield of nuclear devices. It correlates negatively with calculated inducing stress change, likely because the latter correlates inversely with project scale. The largest earthquake reported to date to be induced by fluid injection is the 2016 M 5.8 Pawnee, Oklahoma earthquake, by water-reservoir impoundment the 2008 M ~ 8 Wenchuan, People's Republic of China, earthquake, and by mass removal the 1976 M 7.3 Gazli, Uzbekistan earthquake. The minimum amount of anthropogenic stress needed to induce an earthquake is an unsound concept since earthquakes occur in the absence of industrial activity. The minimum amount of stress observed to modulate earthquake activity is a few hundredths of a megapascal and possibly as little as a few thousandths, equivalent to a few tens of centimeters of water-table depth. Faults near to failure are pervasive in the continental crust and induced earthquakes may thus occur essentially anywhere. In intraplate regions neither infrastructure nor populations may be prepared for earthquakes. Human-induced earthquakes that cause nuisance are rare, but in some cases may be a significant problem, e.g., in the hydrocarbon-producing areas of Oklahoma, USA. As the size of projects and density of populations increase, the potential nuisance of induced earthquakes is also increasing and effective management strategies are needed.

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.

The fluvial sandbodies from river channels with different patterns have remarkable heterogeneities. This study suggests that the pattern of river channel controls on the sandbody stacking pattern, resulting in the heterogeneities of physical properties of sandstone reservoirs. The study area is located in the Gaomiaozi and Zhongjiang areas of western Sichuan depression in China. Based on the observation of cores and interpretation of well logging data of sandstones, three types of lithofacies assemblies and three types of vertical facies stacking patterns are identified to determine the sandbody stacking patterns. The formation of sandbody stacking patterns and ratios of sand/mud were influenced by the sinuosity of river channels, as well as the hydrodynamic condition and the frequently migration of river channels. Three sandbody stacking patterns were identified as homogeneous type composed of massive sandstones with grain size changing vertically (HT), mixed type formed by massive sandstones alternating with thin-bedded mudstones (MT1), and mixed type formed by thin-bedded sandstones wrapped in thick-bedded mudstones (MT2). HT patterns occur in the relatively high-sinuosity river channels (sinuosity index of 1.15–1.25), with sand/mud ratios of 0.65–1.74. MT1 and MT2 patterns occur in the low-sinuosity river channels (sinuosity index of 1.00–1.04), with sand/mud ratios of 0.29–0.91. Because of the long transportation distance before deposition influenced by the loop current, the sands in the relatively high-sinuosity river channels are of good sorting of grain size, with the large grain size and the high compositional maturity. As a result, sandstones deposited in the high-sinuosity river channels have the homogeneous massive pattern and relatively high porosity and permeability. This study proposed that the pattern of river channel controls the quality of fluvial sandstone reservoirs, which can be used to explore the new gas field in the similar geological setting.

At the base of many flood basalt sequences and along volcanic rifted margins, volcanism can compete with the existing sedimentary environments, resulting in interbedded sequences of volcanic rocks and sediments. Here we report on sediment interlayers that are found in the lowermost volcanic units of the Etendeka flood basalts in NW Namibia (Twyfelfontein and Awahab formations), part of the much larger Paraná–Etendeka Igneous Province. The sandstone bodies, predominantly eolian dunes, are isolated in a sequence of Lower Cretaceous (∼ 134 Ma) lava flows. The uppermost part or where sediment deposition and lava emplacement is observed to interact is characterized by barchanoid dunes, which were actively migrating during the emplacement of the lava flows. The fossil (isolated by lava) barchan dunes studied in Dune Valley show three characteristically different diagenetic styles. In Dune Valley, each dune body is completely encapsulated by lava, with additional igneous intrusions cutting through some bodies. We recognize three distinct styles of diagenesis: Type 1: fossilised dunes that are red in color and lack major authigenic mineralization, with grain compaction and subsequent porosity loss being the dominant diagenetic process. Type 2: dunes that have been bleached white, which have undergone a more complex diagenetic pathway. Type 2 dunes have abundant calcite, kaolinite, and böhmite as authigenic phases and lack hematite grain coatings. Detrital plagioclase is absent in white dunes (XRD analysis), with pseudomorphs of kaolinite common. This diagenetic assemblage results in the white dunes having lower porosity and permeability compared to the red dunes. The observations are probably due to a flux of carbon dioxide (CO2), hydrogen sulfide (H2S) and/or hydrogen (H2)–rich hydrothermal groundwater derived from igneous intrusions below. Type 3: “hot contact” effects at lava-flow contacts, where the unconsolidated dunes were rapidly indurated during lava emplacement (volcano-eogenesis). Type 3 diagenesis is restricted to << 1 m depth below lava contacts and common in dunes displaying both Type 1 and Type 2 diagenesis. The distribution of diagenetic Types 1 and 2 is dune specific, and throughout Dune Valley approximately half of the dunes have been bleached (e.g., Type 2 diagenesis), whereas diagenetic Type 3 is a hot contact phenomenon and is therefore found along all basal lava and dike contacts. This work has relevance to understanding the development of sediment–lava systems, to hydrocarbon exploration and development in preserved sediment–lava sequences, and the hydrothermal process described provides an example of natural CO2 sequestration.

Dissolution of feldspars and precipitation of secondary minerals (kaolinite, illite and quartz) are significant diagenetic processes in arkosic sandstones. We examined moderately buried sandstones in the Eocene Shahejie Formation from two sags in the Bohai Bay Basin, East China. Three different types of mineral assemblages (MA) were identified: extensively leached feldspars with a large amount of authigenic kaolinite and quartz cement (MA-1), extensively leached feldspars with a large amount of authigenic kaolinite and minor quartz cement (MA-2), and extensively leached feldspars with a small amount of both authigenic kaolinite and quartz cement (MA-3). Numerical simulations at the continuum scale using Geochemist’s Workbench 9.0 were conducted to decipher the origin of the different mineral assemblages. The physicochemical reactions including feldspar dissolution, transport of Al3+ and SiO2(aq), and precipitation of kaolinite and quartz are coupled together in these simulations, with constraints of chemical reactions, kinetic law, dispersion, and advection. Modeling results suggest that a dissolution zone, a transitional zone, and a precipitation zone can be formed in a sandstone unit with suitable constraints of temperature, flow rate, fluid composition and mineral reaction rate. And MA-3, MA-2, and MA-1 assemblages develop in these three zones respectively. The higher SiO2(aq) concentration required for the saturation of quartz than for kaolinite and the low Al3+ concentration needed for the saturation of kaolinite lead to the precipitation of only kaolinite in the transitional zone in a geochemical system with feldspar dissolution serving as the dominant source of SiO2(aq) and Al3+. Comparisons between modeling results and observations of natural sandstone diagenesis suggest that an MA-1 assemblage is likely to occur in buried sandstones at high temperatures (>70–80 °C) and low flow rates. An MA-2 assemblage may occur in moderately buried sandstones at moderate temperatures (40–70 °C), in deeply buried sandstones with faults and fractures serving as conduits of meteoric freshwater, or in shallow sandstones where meteoric water is not abundant. An MA-3 assemblage tends to occur in shallow sandstones at low temperatures (

The Upper Devonian Buchan Formation in the Central North Sea is a typical terrestrial deposit and predominantly comprises fine to medium-grained sandstones with occasional conglomerates and mudstones. The Buchan Formation has been previously described as being made up mostly of braided fluvial sandstones; however, this study confirms the presence and significance of aeolian sandstones within this fluvial-dominated sequence. Facies architecture is investigated through analogue outcrop study, well log curves and numerical facies modelling, and the results show contrasting differences between fluvial and aeolian facies. The fluvial facies is composed of multiple superimposed and sand-dominated fining-upward cycles in the vertical direction, and laterally an individual cycle has a large width/thickness ratio but is smaller than the field scale. However, the high channel deposition proportion (CDP, average value = 72%) in fluvial-dominated intervals means that it is likely all the sand bodies are interconnected. Aeolian facies comprise superimposed dune and interdune depositions and can be laterally correlated over considerable distances (over 1 km). Although the aeolian sandstones are volumetrically minor (approx. 30%) within the whole Buchan Formation, they have very high porosity and permeability (14.1% - 28%, 27 - 5290 mD) and therefore are excellent potential reservoirs. The fluvial sandstones are significantly cemented by quartz overgrowth and dolomite and by comparison with the aeolian sandstones are poor reservoirs. Aeolian sandstones can be differentiated from fluvial sandstones using several features: pin-stripe lamentation, good sorting, high visible porosity, friable nature and lack of muddy or conglomeratic contents; these characteristics allow aeolian sandstones can be tentatively recognized by low gamma ray values, high sonic transit time and low density in uncored wells. The thin, laterally correlatable and permeable aeolian sandstones within the Buchan Formation are effective reservoirs and could form important exploration targets when the Devonian is targeted elsewhere in the North Sea.

Burial dissolution of feldspar and carbonate minerals has been proposed to generate large volumes of secondary pores in subsurface reservoirs. Secondary porosity due to feldspar dissolution is ubiquitous in buried sandstones; however, extensive burial dissolution of carbonate minerals in subsurface sandstones is still debatable. In this paper, we first present four types of typical selective dissolution assemblages of feldspars and carbonate minerals developed in different sandstones. Under the constraints of porosity data, water–rock experiments, geochemical calculations of aggressive fluids, diagenetic mass transfer, and a review of publications on mineral dissolution in sandstone reservoirs, we argue that the hypothesis for the creation of significant volumes of secondary porosity by mesodiagenetic carbonate dissolution in subsurface sandstones is in conflict with the limited volume of aggressive fluids in rocks. In addition, no transfer mechanism supports removal of the dissolution products due to the small water volume in the subsurface reservoirs and the low mass concentration gradients in the pore water. Convincing petrographic evidence supports the view that the extensive dissolution of carbonate cements in sandstone rocks is usually associated with a high flux of deep hot fluids provided via fault systems or with meteoric freshwater during the eodiagenesis and telodiagenesis stages. The presumption of extensive mesogenetic dissolution of carbonate cements producing a significant net increase in secondary porosity should be used with careful consideration of the geological background in prediction of sandstone quality.

The Middle–Upper Jurassic Shishugou Group in the central Junggar Basin was deposited in a lacustrine shallow-water delta-meandering river sedimentary system. The integrated petrological (thin-section, granularity and heavy minerals analysis), geochemical (trace elements and rare earth elements analysis) and geophysical analyses (well logging and 3D-seismic slice analysis) are used to determine redox conditions, paleoclimate, paleosalinity, provenance and sedimentary evolution extant during deposition of the Shishugou Group: (1) the redox condition changed from a weak anoxic/oxic condition to a strongly oxic condition; (2) the climate changed from humid to hot and arid in the Middle–Late Jurassic, which may have resulted in the lake water having slight–medium salinity; (3) the relatively distant northeastern provenance from the Kelameili Mountain is the most important sediment source; and (4) the south provenance from the Tianshan Mountains (Bogeda Shan) decreases with the development of the sag piedmont, which supplies sediments to the southeastern Fukang Sag. The sedimentary environment changed from a lacustrine shallow-water delta to a meandering river during the deposition of the Shishugou Group. The shallow-water meandering river delta was characterised by pervasive mudstones with oxide colours, thin single-layer sand bodies (1–15 m, mean 3 m), relatively low sand–strata ratios (0.2–0.5) and the absence of progradation, mouth bars and reverse rhythms. The gentle slope is the primary condition necessary for the formation of a shallow-water meandering river delta. Paleo-environment (climate change from warm-humid to hot-arid) and the stable and remote Kelameili Mountain provenance played critical roles in the development and evolution of lacustrine–delta-meandering river sedimentary systems.

Thin-bedded beach-bar sandstone reservoirs are common in the Eocene Shahejie Formation (Es4s) of Niuzhuang Sag, along the southern gentle slope of the Dongying Depression. Here we report on the link between sequence stratigraphy, sedimentary facies and diagenetic effects on reservoir quality. Seismic data, wireline logs, core observations and analyses are used to interpret depositional settings and sequence stratigraphic framework. Petrographic study based on microscopic observation of optical, cathodoluminescence (CL), confocal laser scanning (LSCM) and scanning electron microscope (SEM) and X-ray diffraction (XRD) analyses were used to describe the fabric, texture, allogenic and authigenic mineralogy of these highly heterogeneous sandstone reservoirs. The Es4s interval is interpreted as third-order sequence, composed of a lowstand systems tract (LST), a transgressive systems tract (TST) and a highstand systems tract (HST). On the fourth order, twenty-nine parasequences and seven parasequence sets have been identified. Sand bodies were deposited mainly in the shoreface shallow lake beach-bar (clastic beach-bar), semi-deep lake (carbonate beach-bar) and the fluvial channels. The depositional and diagenetic heterogeneities were mainly due to the following factors: (1) fine grain size, poor sorting, and continuous thin inter-bedded mud layers with siltstone/fine-sandstone having argillaceous layers in regular intervals, (2) immature sediment composition, and (3) even with the dissolution of grains and several fractures, destruction of porosity by cementation and compaction. Secondary pores from feldspar dissolution are better developed in sandstones with increased cementation. Grain coating smectite clays preserved the primary porosity at places while dominating pore filling authigenic illite and illite/smectite clays reduced permeability with little impact on porosity. Due to the high degree of heterogeneity in the Es4s beach-bar interval, it is recognized as middle to low permeable reservoir. The aforementioned study reflects significant insight into the understanding of the properties of the beach-bar sands and valuable for the comprehensive reservoir characterization and overall reservoir bed quality.

Turbidite deposits, overpressure, hydrothermal fluid activity, and CO 2 accumulations are the basic geologic characteristics of the Upper Miocene Huangliu Formation sandstone reservoir in the Dongfang gas field, Yinggehai Basin. This study aims to unravel the timing and origin of dissolution in sandstone and evaluate the effects of inorganic CO 2 accumulation on reservoir quality. A comparative study between area DFX-1 (CO 2 -rich) and area DFX-2 (CO 2 -poor) has illustrated the differences in diagenetic alteration and the effects of CO 2 accumulation on the sandstone reservoir. Diagenetic alteration of sandstones in area DFX-1 was characterised by intense dissolution and medium cementation. Dissolution of silicates following inorganic CO 2 charging in the DFX-1 area created a higher percentage of dissolution porosity (41.0%–53.9% of total visible porosity), compared with minor dissolution porosity in the DFX-2 area (16.7%–29.6% of total visible porosity). Small amounts of kaolinite, authigenic quartz, ankerite, and siderite were precipitated by CO 2 -water-rock reactions in area DFX-1; these minerals are almost absent in area DFX-2. The carbonate cement of the Huangliu Formation sandstone in area DFX-1 is characterised by light δ 13 C (−3.3‰ to −1.6‰, PDB), which is consistent with formation from inorganic carbon. The timing of dissolution by inorganic CO 2 is suggested to be at about 0.4 Ma based on the previous simulation experiments. In the two areas studied, overpressure was caused by pressure transmission along deep open faults and was not related to mudstone undercompaction. Overpressure did a little to contribute to porosity preservation. CO 2 accumulating at low partial pressures related to hydrothermal fluid flow cannot make a net increase in porosity in the Huangliu Formation sandstone of the Dongfang gas field.

We report on the discovery of oil from the Boulby Mine and its likely productive source rock from Yorkshire in NE England, located to the west (

We present quantitative petrographic data, high spatial resolution oxygen isotope analyses of quartz cement, basin modelling and a kinetic model for quartz precipitation for two Paleocene-Eocene Wilcox Group sandstones from Texas and two Jurassic Fulmar Formation sandstones from the Central North Sea. At each location, one sandstone has been buried to ca. 145 °C and one to ca. 185 °C. A key difference between the Wilcox and Fulmar burial histories is that the Wilcox sandstones are currently at higher vertical effective stresses and, from basin modelling studies, have been subjected to generally higher vertical effective stresses through their burial history. The amounts of quartz cement in the Wilcox sandstones are between 12 and 18%, and between 2 and 6% in the Fulmar sandstones. High-spatial-resolution oxygen isotope data obtained from the quartz cements suggest temperature ranges for quartz precipitation from 60 to 80 °C to values approaching maximum burial temperature. Factors such as grain coatings or the timing of petroleum emplacement cannot explain the differences in the amounts of quartz cement. Petrographic data show that most of the silica for quartz cement can be derived from intergranular pressure dissolution. Although the sample set is small, we interpret the results to suggest that the differences in quartz cementation in Fulmar and Wilcox sandstones can be explained better by differences in their vertical effective stress history than their temperature history; in this case, the supply of silica rather than the precipitation of quartz becomes an important control on the rate and extent of cementation.

Temperature-controlled precipitation kinetics has become the overwhelmingly dominant hypothesis for the control of quartz cementation in sandstones. Here, we integrate quantitative petrographic data, high spatial resolution oxygen isotope analyses of quartz cement, basin modelling and a kinetic model for quartz precipitation to suggest that the supply of silica from stress-sensitive intergranular pressure dissolution at grain contacts is in fact a key control on quartz cementation in sandstones. We present data from highly overpressured sandstones in which, despite the current burial temperature of 190 °C, quartz cement occurs in low amounts (4.6 ± 1.2% of bulk volume). In situ oxygen isotope data across quartz overgrowths suggest that cementation occurred over 100 Ma and a temperature range of 80–150 °C, during which time high fluid overpressures resulted in consistently low vertical effective stress. We argue that the very low amounts of quartz cement can only be explained by the low vertical effective stress which occurred throughout the burial history and which restricted silica supply as a result of a low rate of intergranular pressure dissolution at grain contacts.

An investigation of the Triassic Yanchang Formation, Ordos Basin, N. China, revealed that the diagenesis and quality of tight oil sandstone reservoirs (with an average porosity of 9.83% and an average permeability of 0.96 mD) were controlled by a closed diagenetic system. The carbonate cements observed in the sandstone were derived from decarboxylation of organic matter that occurred in the adjacent mudstones. These reactions supplied CO32−, which reacted with cations derived from grain dissolution in the sandstones. The average size of the diagenetic geochemical system with respect to carbonate cements was small (

Carbon capture and storage is a transition technology from a past and present fuelled by coal, oil and gas and a planned future dominated by renewable energy sources. The technology involves the capture of carbon dioxide emissions from fossil fuel power stations and other point sources, compression of the CO 2 into a fluid, transporting it and injecting it deep beneath the Earth's surface into depleted petroleum reservoirs and other porous formations. Once injected, the CO 2 must be monitored to ensure that it is emplaced and assimilated as planned and that none leaks back to surface. A variety of methods have been deployed to monitor the CO 2 storage site and many such methods have been adapted from oilfield practice. However, such methods are commonly indirect, episodic, require active signal generation and remain expensive throughout the monitoring period that may last for hundreds of years. A modelling framework was developed to concurrently simulate CO 2 geostorage conditions and background cosmic-ray muon tomography, in which the potential was assessed for using variations in muon attenuation, due to changes in CO 2 abundance, as a means of CO 2 detection. From this, we developed a passive, continuous monitoring method for CO 2 storage sites using muon tomography, the tools for which can be deployed during the active drilling phase (development) of the storage site. To do this, it was necessary to develop a muon detector that could be used in the hostile environment (saline, high temperature) of the well bore. A prototype detector has been built and tested at the 1.1 km deep Boulby potash mine on the northeast coast of England, supported by the existing STFC Boulby Underground Laboratory on the site. The detector is now ready to be commercialized. This article is part of the Theo Murphy meeting issue ‘Cosmic-ray muography’.

An example of diagenesis and reservoir quality of buried sandstones with ancient incursion of meteoric freshwater is presented in this study. The interpretation is based on information including porosity and permeability, petrography, stable isotopic composition of authigenic minerals, homogenization temperatures (Th) of aqueous fluid inclusions (AFIs), and pore water chemistry. These sandstones, closely beneath or far from the regional unconformity formed during the late Paleogene period, are located in the thick Shahejie Formation in the Gaoliu area of Nanpu Sag, Bohai Bay Basin, East China. Early-diagenetic calcite cements were leached to form intergranular secondary pores without precipitation of late-diagenetic calcite cements in most sandstones. Feldspars were leached to form abundant intragranular secondary pores, but with small amounts of concomitant secondary minerals including authigenic quartz and kaolinite. The mass imbalance between the amount of leached minerals and associated secondary minerals suggests that mineral leaching reactions occurred most likely in an open geochemical system, and diagenetic petrography textures suggest that advective flow dominated the transfer of solutes from leached feldspars and calcites. Low salinity and ion concentrations of present pore waters, and extensive water rock interactions suggest significant incursion of meteoric freshwater flux in the sandstones. Distances of the sandstones to the regional unconformity can reach up to 1800 m, while with significant uplift in the Gaoliu area, the burial depth of such sandstones (below sea level) can be less than 800–1000 m during the uplift and initial reburial stage. Significant uplift during the Oligocene period provided substantial hydraulic drive and widely developed faults served as favorable conduits for downward penetration of meteoric freshwater from the earth's surface (unconformity) to these sandstone beds. Extensive feldspar leaching has been occurring since the uplift period. Coupled high Th (95∼115 °C) of AFI and low δ 18 O(SMOW) values (+17∼+20‰) within the quartz overgrowths show that quartz cementation occurred in the presence of diagenetic modified meteoric freshwater with δ 18 O(SMOW) values of −7∼−2‰, indicating that authigenic quartz only have been formed during the late reburial stage when meteoric fresh water penetration slowed down. Secondary pores in thin sections and tested porosity suggest that meteoric freshwater leaching of feldspars and calcite minerals generated approximately 7–10% enhanced secondary porosity in these sandstones. Meteoric freshwater leaching reactions cannot be ignored in similar sandstones that located deep beneath the unconformity, with great uplift moving these sandstones above or close to sea level and with faults connecting the earth's surface with the sandstone beds.

Berea sandstone has been used by the petroleum industry as a representative model siliciclastic rock for a number of years. However, only incomplete data has been reported in the literature regarding its petrographic, geochemical, and petrophysical properties. In particular knowledge of the mineral distribution along the pore walls is particularly scarce, despite the fact that mineral exposed in the pore space will be crucial in determining the rock-fluid interactions that occur during core-flooding experiments. In this paper, four Berea sandstone samples (with 4 different permeability ranges from

The differential interferometric synthetic aperture radar (DInSAR) remote sensing technique has proven to be invaluable in the remote monitoring of earth surface movements associated with the extraction and geostorage (subsurface injection) of natural resources (water, oil, gas). However, a significant limitation of this technique is the low density and uneven coverage that may be achieved over vegetated rural environments. The Intermittent Small Baseline Subset (ISBAS) method, an amended version of the established SBAS algorithm, has been designed to improve coverage over rural, vegetated, land cover classes by allowing for the intermittent coherence that is predominant in such areas. In this paper we perform a validation of the ISBAS method over an area of gas production and geostorage in North Holland, the Netherlands. Forty-two ERS-2 (SAR) C-band images (1995–2000) and 63 ENVISAT (ASAR) C-band images (2003–2010) were processed using the ISBAS technique and the derived measurements enabled the identification of subsidence patterns in rural and urban areas alike. The dominant feature was an area of subsidence to the west of Alkmaar, attributed to natural gas production from the Bergermeer reservoir, where subsidence rates in the region of 3 mm/year were measured. Displacements derived using linear and non-linear surface deformation models were validated with respect to the first order system of levelling benchmarks which form the Amsterdam Ordnance Datum (NAP). It was established that ISBAS products were accurate to within 1.52 mm/year and 1.12 mm/year for the ERS and ENVISAT data sets respectively. Errors achieved were comparable to results using persistent scatterers interferometry (PSI) during a validation activity carried out in the European Space Agency Terrafirma project. These results confirm the capability of the ISBAS method to provide a more regular sampling of land motion measurements over gas fields that may be critically used in future to infer the properties of buried, fluid-filled, porous rock.

The Holywell Shale is part of the Carboniferous Bowland Shale Formation, identified as the main potential shale gas system in the UK. Here, we report geochemical and petrographic data from five outcrops of the Lower and Upper Holywell Shale across northeast Wales. At outcrop, the Holywell Shale is immature to early oil mature and has total organic carbon (TOC) values ranging between 0.1 and 10.3 wt %, with a mean of 1.9 wt %. Carbon isotope data clearly differentiate terrestrial and marine organic matter and show that both occur throughout the Holywell, with terrestrial sources (Type III/IV) dominating the Upper Holywell and marine sources dominating the Lower Holywell (Type II/III). Trace element data indicate that bottom waters were oxygenated, resulting in poorly preserved organic matter, supported by C/N and HI data. A range of silt- and clay-rich lithofacies occur, which show no relationship to either the amount or type of organic matter. We interpret the data in terms of a mixed supply of terrestrial and marine organic matter to marine depositional environments in which there was sufficient hydrodynamic energy to transport fine-grained sediment as bed load. The resulting mudstones exhibit a range of sedimentary textures with millimetre- to centimetre-scale silt–clay bed forms which show almost no relationship to organic matter type and amount. The small-scale variability and heterogeneity of both organofacies and lithofacies means that the reservoir quality of the Holywell Shale is inherently difficult to predict.