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Mudstones represent top-seals for many carbon capture sites as they tend to have the correct petrophysical properties, including suitable porosity and pore-size distribution. The pore network of mudstones is thus pivotal for many carbon capture and storage (CCS) projects. The key to understanding the effectiveness of top-seals is an appreciation of the controls on the pore network. For this reason, schemes to classify pore body size, pore type and pore throat size are presented. Pore types include primary and secondary interparticle and intraparticle pores and pores associated with organic matter and fractures. The most relevant mudstone pore body sizes for CCS top seals are likely to be between 0.625 µm). Petrophysical, geochemical, and geomechanical properties control porosity and the CO 2 sealing integrity of mudstones; these properties are, in turn, controlled by the rate and extent of compaction, mineral diagenesis and overpressure. The success of a CCS top-seal relies on pore throats in intact top-seal being sufficiently small, and fracture pressure (typically minimum horizontal stress, σ hmin ) not being exceeded by CO 2 pressure. CO 2 sorption, especially by smectite in top-seals, may improve the nanoscale sealing efficiency of clay minerals. The systematic workflow presented here will help facilitate the new drive to understand mudstone properties, as they are essential for establishing safe and durable CO 2 containment.

Incised valley fills are complex as they correspond to multiple sea-level cycles which makes interpretation and correlation of stratigraphic surfaces fraught with uncertainty. Despite numerous studies of the stratigraphy of incised valley fills, few have focused on extensive core coverage linked to high fidelity dating in a macro-tidal, tide-dominated settings. Here, we have drilled nineteen sediment cores through the Holocene succession of the macro-tidal Ravenglass Estuary in northwest England, UK. A facies and stratigraphic model of the Ravenglass incised valley complex was constructed, to understand the lateral and vertical stacking patterns relative to the sea-level changes. The Ravenglass Estuary formed in five main stages. First, incision by rivers (~11,500 to ~10,500 yrs BP) cutting through the shelf during lowstand, which was a period of fluvial dominance. Secondly, a rapid transgression and landward migration of the shoreline (10,500 to 6,000 yrs BP). Wave action was dominant, promoting spit formation. The third stage was a highstand at ~6,000 to ~5,000 yrs BP, creating maximum accommodation and the majority of backfilling. The spits narrowed the inlet and dampened wave action. The fourth stage was caused by a minor fall of sea-level (~5,000 to ~226 yrs BP), which forced the system to shift basinward. The fifth and final stage (226 yrs BP to present) involved the backfilling of the River Irt, southward migration of the northerly (Drigg) spit and merging of the River Irt with the Rivers Esk and Mite. The final stage was synchronous with the development of the central basin. As an analogue for ancient and deeply buried sandstones, most of the estuarine sedimentation occurred after transgression, of which the coarsest and cleanest sands are found in the tidal inlet, on the foreshore and within in-channel tidal bars. The best-connected (up to 1km) reservoir-equivalent sands belong to the more stable channels.

The origin and growth mechanisms of microcrystalline quartz cement in sandstones and its relationship to quartz overgrowths remain puzzling even though it has an important effect on rock properties in deeply buried sandstones; microcrystalline quartz cement inhibits the growth of quartz cement and so leaves sandstones with anomalously high porosity deep in sedimentary basins. Here we have examined the relationships between quartz cement, and duplicate layers of chalcedony/amorphous silica and microcrystalline quartz from outcrops of the Upper Cretaceous Heidelberg Formation, Germany. We have used an array of techniques including: NanoSIMS for spatially-resolved stable oxygen isotope analysis, and high-resolution chemical analysis of the silica cements using electron microprobe analysis, as well as crystallographic studies using TEM and EBSD. Based on burial history modeling and the low degree of compaction of the Heidelberg Formation sandstones, we conclude that maximum temperature due to conductive heating was about 42 °C; quartz overgrowths with δ18O of 18.8 ‰ developed from meteoric-derived formation water with δ18O of about −12 ‰ V-SMOW. Based on published precedents and an awareness that silica solubility decreases with decreasing temperature, we assume that chalcedony/amorphous silica and then microcrystalline quartz developed during cooling of flowing formation water. Chalcedony with δ18O of 27.4 ‰ developed from meteoric-derived formation water with δ18O of between −1 and −3 ‰ V-SMOW depending on whether the initial temperature of the cooling formation water was 45 or 55 °C. The interpreted higher δ18O of the warmer water responsible for chalcedony and microcrystalline quartz growth is typical of basin-center waters that have undergone considerable water–rock interaction. It is likely that the fluid movement was caused by thrust tectonics in the Coniacian to Campanian. The duplicate layers of chalcedony/amorphous silica and then microcrystalline quartz suggests that there were two thrust-induced fluid expulsion events.

Porosity and permeability define the reservoir quality of a sandstone. Porosity and permeability are controlled by primary sedimentary characteristics and subsequent diagenetic modification. Grain size, sorting, detrital mineralogy, and matrix content are defined at the point of deposition. Bioturbation, infiltration, continued alteration of reactive minerals and soft sediment deformation can occur soon after deposition and, together with the primary characteristics, these condition, or define, how a sediment will behave during subsequent burial. Diagenetic modifications include compaction, initially mechanical and then chemical, mineral growth and, in some cases, grain dissolution and development of secondary pores. Porosity and permeability typically decrease as diagenesis progresses. Scanning Electron Microscopy-Energy Dispersive Spectroscopy (SEM-EDS) approaches can be applied to study many aspects of sandstone diagenesis including detrital mineralogy, grain size, sorting, grain shape, grain angularity and matrix content. SEM-EDS is also useful for defining quantities and location in the pore network of cements that are mineralogically distinct from detrital grains (e.g., calcite, dolomite, siderite, or anhydrite). SEM-EDS can be useful for studying clay mineral cements, especially when they occur in patches bigger than 5–10 μm. In sandstones, SEM-EDS is not so useful when the cements are mineralogically identical to detrital grains (e.g., quartz cement in quartz sandstones) where additional signals such as cathodoluminescence (CL) may be required. Macro- and meso-pores can be quantified using SEM-EDS but, on its own, it cannot automatically measure micro-porosity as it is below the minimum 1 µm spatial resolution of the approach. Mechanical compaction, a key process that causes porosity-loss in sandstones, is not easily quantified using SEM-EDS. Nonetheless, together with additional routine techniques, SEM-EDS can be used to solve most problems associated with sandstone diagenesis and reservoir quality.

A study of the diagenetic evolution of the Late Jurassic sandstones of the shallow marine facies in the Tambar oil field, Norwegian North Sea was carried out to understand its controls on reservoir quality. Core samples and a set of wireline logs obtained from three wells were used to carry out petrographic studies including light optics and scanning electron microscopy, well log analysis, fluid inclusions, X-ray diffraction (XRD) for whole rock samples, clay mineral extracts and stable isotopes. The Tambar reservoir sandstones range mainly from siltstone to fine-grained sandstones, exclusively arkoses cemented mainly by microcrystalline quartz, euhedral quartz overgrowth, dolomite cement, illite and chlorite. Early diagenetic/eodigenetic minerals include pyrite, calcite, and microcrystalline quartz and late diagenetic/mesodiagenetic minerals include quartz overgrowth, dolomite, illite and chlorite. The δ18O values of dolomite cement in the Tambar sandstone reservoir range from −11.77‰ to −3.57‰ PDB, while the δ13C values of the dolomite cement are from −5.07‰ to −1.12‰ PDB. Homogenization temperature for fluid inclusions trapped in authigenic quartz fall between 130 °C and 169 °C. The reservoir quality is controlled mainly by early formed grain-coating microcrystalline quartz that precipitated from the dissolution of sponge spicules which significantly inhibits quartz overgrowth precipitation. Oil emplacement do not show significant control on reservoir quality because considerable quartz cementation has taken place before the onset of major oil charge. Only the coarse-grained sands show a correlation between quartz cement volume and water saturation. However, the interpreted temperature for dolomite cementation is significantly higher for water leg-suggested effect of oil emplacement on the late dolomite. Understanding these controls on the reservoir quality will enhance the exploration strategy for the Tambar oil field.

In the quest to use modern analogues to understand clay mineral distribution patterns to better predict clay mineral occurrence in ancient and deeply buried sandstones, it has been necessary to define palaeo sub-environments from cores through modern sediment successions. Holocene cores from Ravenglass in the NW of England, United Kingdom, contained metre-thick successions of massive sand that could not be unequivocally interpreted in terms of palaeo sub-environments using conventional descriptive logging facies analysis. We have therefore explored the use of geochemical data from portable X-ray fluorescence analyses, from whole-sediment samples, to develop a tool to uniquely define the palaeo sub-environment based on geochemical data. This work was carried out through mapping and defining sub-depositional environments in the Ravenglass Estuary and collecting 497 surface samples for analysis. Using R statistical software, we produced a classification tree based on surface geochemical data from Ravenglass that can take compositional data for any sediment sample from the core or the surface and define the sub-depositional environment. The classification tree allowed us to geochemically define ten out of eleven of the sub-depositional environments from the Ravenglass Estuary surface sediments. We applied the classification tree to a core drilled through the Holocene succession at Ravenglass, which allowed us to identify the dominant paleo sub-depositional environments. A texturally featureless (massive) metre-thick succession, that had defied interpretation based on core description, was successfully related to a palaeo sub-depositional environment using the geochemical classification approach. Calibrated geochemical classification models may prove to be widely applicable to the interpretation of sub-depositional environments from other marginal marine environments and even from ancient and deeply buried estuarine sandstones.

Particle size and morphology analysis is a problem common to a wide range of applications, including additive manufacturing, geological and agricultural materials’ characterisation, food manufacturing and pharmaceuticals. Here, we review the use of microfocus X-ray computed tomography (X-ray CT) for particle analysis. We give an overview of different sample preparation methods, image processing protocols, the morphology parameters that can be determined, and types of materials that are suitable for analysis of particle sizes using X-ray CT. The main conclusion is that size and shape parameters can be determined for particles larger than approximately 2 to 3 μm, given adequate resolution of the X-ray CT setup. Particles composed of high atomic number materials (Z > 40) require careful sample preparation to ensure X-ray transmission. Problems occur when particles with a broad range of sizes are closely packed together, or when particles are fused (sintered or cemented). The use of X-ray CT for particle size analysis promises to become increasingly widespread, offering measurements of size, shape, and porosity of large numbers of particles within one X-ray CT scan.

Grain-coating chlorite preserves porosity and permeability through the inhibition of quartz cement whereas pore-filling chlorite blocks pore-throats and diminishes reservoir quality. The aim of this study is to determine the origin and principal mechanisms which govern the distribution of grain-coating and pore-filling chlorite in Jurassic deltaic sandstones (Tilje Formation, Smorbukk field, Mid Norwegian Shelf). The study focussed on very high-density sampling for petrographic analysis, from three sections of sandstone core from the same well with contrasting reservoir quality, rather than the low-density sampling approach typically employed. The aim was to gain new understanding of specific controls on porosity and permeability based on core description, core analysis measurements and a suite of petrographic techniques. Results of this study show grain-coating chlorite originated from the thermally-driven recrystallisation of detrital clay coats and/or clay mineral precursors. Pore-filling chlorite has principally derived from the ductile deformation of chlorite-rich Fe-ooids, that were possibly reworked from a proximal evaporitic setting. The distribution of chlorite precursor material, detrital clay coats, and subsequently the distribution of grain-coating and pore-filling chlorite, were controlled by the relative dominance of tidal and fluvial processes active during sediment deposition. Optimum grain-coating chlorite is found in tidal-fluvial sandstones with moderate fluvial influence. Pore-filling chlorite is pervasive in tidal-fluvial channel sandstones deposited during periods of high fluvial discharge, or proximal to the central turbidity maximum zone; marked by an abundance of fluid mud. Tidal channel sandstones with no fluvial influence are pervasively quartz cemented due to an absence of grain-coating chlorite. Grain-coating chlorite and good reservoir quality occurs in heterolithic distributary mouth bar sandstones, however mixing of mud- and sand-prone facies due to intense bioturbation has reduced permeability. Results from this study can be used to predict reservoir quality in the Smorbukk field and in analogous shallow-marine sandstones worldwide.

The Upper Jurassic, shallow marine Corallian sandstones of the Weald Basin, UK, are significant onshore reservoirs due to their future potential for carbon capture and storage (CCS) and hydrogen storage. These reservoir rocks, buried to no deeper than 1700 m before uplift to 850 to 900 m at the present time, also provide an opportunity to study the pivotal role of shallow marine sandstone eodiagenesis. With little evidence of compaction, these rocks show low to moderate porosity for their relatively shallow burial depths. Their porosity ranges from 0.8 to 30% with an average of 12.6% and permeability range from 0.01 to 887 mD with an average of 31 mD. The Corallian sandstones of the Weald Basin are relatively poorly studied, consequently, there is a paucity of data on their reservoir quality which limits any ability to predict porosity and permeability away from wells. This study presents a potential first in the examination of diagenetic controls of reservoir quality of the Corallian sandstones, of the Weald Basin’s Palmers Wood and Bletchingley oil fields, using a combination of core analysis, sedimentary core logs, petrography, wireline analysis, SEM-EDS analysis and geochemical analysis to understand the extent of diagenetic evolution of the sandstones and its effects on reservoir quality. The analyses show a dominant quartz arenite lithology with minor feldspars, bioclasts, Fe-ooids and extra-basinal lithic grains. We conclude that little compactional porosity-loss occurred with cementation being the main process that caused porosity-loss. Early calcite cement, from neomorphism of contemporaneously deposited bioclasts, represents the majority of the early cement, which subsequently prevented mechanical compaction. Calcite cement is also interpreted to have formed during burial from decarboxylation-derived CO2 during source rock maturation. Other cements include the Fe-clay berthierine, apatite, pyrite, dolomite, siderite, quartz, illite and kaolinite. Reservoir quality in the Corallian sandstones show no significant depositional textural controls, it was reduced by dominant calcite cementation, locally preserved by berthierine grain coats that inhibited quartz cement and enhanced by detrital grain dissolution as well as cement dissolution. Reservoir quality in the Corallian sandstones can therefore be predicted by considering abundance of calcite cement from bioclasts, organically derived CO2 and Fe-clay coats.

Wireline and seismic acoustic impedance imaging show that the marine part of the clastic Brent Group reservoir in the Heather Field, Northern North Sea, contains much calcite cement in the flank parts of the structure. The non-marine Ness Formation and crest parts of the structure contain negligible calcite cement. This localised calcite cement has led to relatively poor reservoir performance since first oil in 1978 although a new suite of wells has boosted production with plans to keep the field active until 2030. Understanding the origin and distribution of calcite cement would help the development of more realistic reservoir models and boost production rates through optimum well location. We have thus used a suite of techniques, including standard point counting, SEM-EDS mineralogy, BSE microscopy, fluid inclusion thermometry and stable isotope analysis, to develop new and improved models of calcite distribution. Calcite seems to have attributes of both early and late diagenetic cement. 30 to 40% intergranular volume in calcite cemented beds seems to support pre-compactional growth but high temperature fluid inclusions and the presence of primary oil inclusions suggests late growth. Much calcite may have developed early but it seems to have recrystallized, and possibly undergone redistribution, at close to maximum burial or had a late growth event. Calcite cement probably originated as marine-derived micrite, bioclasts or early marine cement but adopted the isotopic characteristics of high temperature growth as it recrystallized. Quartz grains have corroded outlines in calcite-cemented areas with one sample, with 79 % calcite cement, displaying signs of nearly total replacement of quartz grains by calcite. The flank localisation of calcite remains to be explained although it could be due to primary depositional factors, early diagenetic loss of calcite from crestal regions or late diagenetic loss of calcite from crestal regions. Controversially, the growth of calcite seems to be associated with quartz dissolution although the geochemical and petrophysical cause of this remains obscure. Diagenetic loss of quartz from sandstones cannot easily be explained by conventional modelling approaches and yet seems to be an important phenomenon in Heather sandstones.

Petroleum-rich basins at a mature stage of exploration and production offer many opportunities for large-scale Carbon Capture and Storage (CCS) since oil and gas were demonstrably contained by low-permeability top-sealing rocks, such as shales. For CCS to work, there must be effectively no leakage from the injection site, so the nature of the top-seal is an important aspect for consideration when appraising prospective CCS opportunities. The Lower Cretaceous Rodby Shale and the Palaeocene Lista Shale have acted as seals to oil and gas accumulations (e.g., the Atlantic and Balmoral fields) and may now play a critical role in sealing the Acorn and East Mey subsurface carbon storage sites. The characteristics of these important shales have been little addressed in the hydrocarbon extraction phase, with an understandable focus on reservoir properties and their influence on resource recovery rates. Here, we assess the characteristics of the Rodby and Lista Shales using wireline logs, geomechanical tests, special core analysis (mercury intrusion) and mineralogical and petrographic techniques, with the aim of highlighting key properties that identify them as suitable top-seals. The two shales, defined using the relative gamma log values (or Vshale), have similar mean pore throat radius (approximately 18 nm), splitting tensile strength (approximately 2.5 MPa) and anisotropic values of splitting tensile strength, but they display significant differences in terms of wireline log character, porosity and mineralogy. The Lower Cretaceous Rodby Shale has a mean porosity of approximately 14 %, a mean permeability of 263 nD (2.58 &times, 10&minus, 19 m2), and is calcite rich and has clay minerals that are relatively rich in non-radioactive phases such as kaolinite. The Palaeocene Lista Shale has a mean porosity of approximately 16% a mean permeability of 225 nD (2.21 &times, 19 m2), and is calcite free, but contains abundant quartz silt and is dominated by smectite. The 2% difference in porosity does not seem to equate to a significant difference in permeability. Elastic properties derived from wireline log data show that Young&rsquo, s modulus, material stiffness, is very low (5 GPa) for the most shale (clay mineral)-rich Rodby intervals, with Young&rsquo, s modulus increasing as shale content decreases and as cementation (e.g., calcite) increases. Our work has shown that Young&rsquo, s modulus, which can be used to inform the likeliness of tensile failure, may be predictable based on routine gamma, density and compressive sonic logs in the majority of wells where the less common shear logs were not collected. The predictability of Young&rsquo, s modulus from routine well log data could form a valuable element of CCS-site top-seal appraisals. This study has shown that the Rodby and Lista Shales represent good top-seals to the Acorn and East Mey CCS sites and they can hold CO2 column heights of approximately 380 m. The calcite-rich Rodby Shale may be susceptible to localised carbonate dissolution and increasing porosity and permeability but decreasing tendency to develop fracture permeability in the presence of injected CO2, as brittle calcite dissolves. In contrast, the calcite-free, locally quartz-rich, Lista Shale will be geochemically inert to injected CO2 but retain its innate tendency to develop fracture permeability (where quartz rich) in the presence of injected CO2.

Extraction or injection of fluids within the subsurface causes fluctuations of fluid pressures and thus stress conditions. It is paramount to have knowledge of the geomechanical strength of a system’s lithologies, and the factors that control it, in order to maintain optimal conditions during extraction/injection. If the yield strengths of the reservoir or caprock are overcome, particularly in the near-wellbore region where stress is amplified, these fluctuations could potentially compromise the system, through compactional or dilatational failure. Here we have used a novel combination of methods to determine the geomechanical and petrographic properties of the reservoir and caprock lithologies to assess suitability of the proposed Acorn CO2 Storage Site, offshore north-east Scotland, for long-term injection and storage of CO2. The Acorn CO2 Storage Site has a highly porous and transmissible sandstone reservoir, with bulk mineralogy that will be stable under CO2-rich conditions, making it ideal for receiving at least 152 MT CO2 injected over ∼20 years and storage of >1000 years post-injection, as part of the ACT-Acorn Development Plan. However, due to the high porosity and low cementation of the sandstone reservoir, it has low yield strength and is vulnerable to disaggregation and porosity-reduction if injection rates are too high and stress/pressure conditions exceed their yield strength. The results presented here provide quantitative constraints on the porosity reduction expected should yield occur and place limits on CO2 injection rates. The shale caprock, with a high swelling clay content and very low permeability, present ideal Carbon Capture and Storage seal properties.

Sedimentological studies are important in understanding and predicting reservoir quality, especially in shallow buried sandstones that are dominated by eogenetic processes. Understanding the sedimentological controls on siliciclastic depositional environments will enhance the knowledge and prediction of reservoir architecture and reservoir quality, both of which are essential to resource exploitation and future CCS and hydrogen storage projects. Here, we present a study of sedimentology and depositional mineralogy, as well as controls on the deposition of siliciclastic sandstones, from the shallow-buried, Upper Jurassic Corallian marine sandstones of the Weald Basin, UK. These sandstones host small oil accumulations and, being close to large centres of population, are possible gas storage or carbon capture and storage sites. We used wireline log analysis, high resolution core logging, optical petrography, and SEM-EDS imaging to investigate reservoir architecture and the relative importance of depositional versus secondary diagenetic controls on reservoir quality. Shallow marine conditions, adjacent to a continent experiencing a warm humid climate, are interpreted based on ichnofabrics and mineralogy. Tectonic processes influenced water depth which subsequently controlled both the quantity of detrital bioclastic material (and the resulting calcite cement), and the amount of detrital clay matrix. The eustatic influence on deposition led to the development of a relatively thin intra-Corallian mudstone which compartmentalises the reservoir into discrete upper and lower sand bodies. The results of this study underline the importance of integration of detailed sedimentological and wireline log analysis in improving the prediction of reservoir quality in tectonically active environments for shallow buried, eogenetic-dominated sandstones.

The presence and distribution of clay minerals attached to grain surfaces as coats (also known as rims) are of great interest because they affect petroleum reservoir quality via the inhibition of the porosity-occluding quartz cement during prolonged burial and heating. Being able to predict the distribution of clay-coated sand grains in petroleum reservoirs is thus important to help find and exploit anomalously high porosity sandstones deep in sedimentary basins. The few studies focused on the distribution of clay coats in marginal marine sediments derive from surface sediment-based data sets, with limited emphasis placed on the preservation of the surface trends in sediment undergoing eodiagenesis in the near-surface environments. The post-depositional processes of bioturbation (sediment homogenization) and infiltration of clay into sand-grade sediment have been widely invoked as potential mechanisms that produce clay coats in modern sands and ancient sandstones. However, the potential for such processes to alter surface trends and govern clay-coat distribution in the subsurface remains unconstrained. In this study, we report the development of a novel, quantitative model of clay-coat coverage in order to identify the controlling mechanisms that govern clay-coat distributions. This study has focused on surface and near-surface sediments in the Saltcoats tidal flat deposits of the Ravenglass Estuary, UK. This unique bio-sedimentary study involved geomorphic mapping, core logging, a range of scanning electron microscopy techniques, and quantification of grain-size, clay fraction content, biofilm abundance (total carbohydrate and biomarker analysis), clay-coat coverage, and clay-coat mineralogy. In this study, against established convention, we demonstrate that infiltration and bioturbation do not significantly affect clay-coat grain coverage in near-surface sediments. Instead, we show that the extent, distribution, and mineralogy of clay coats in near-surface sediment are governed by the surface-based hydrological segregation of the clay mineral assemblage and biological clay-coat formation.

Interest in the creation of secondary pore spaces in petroleum reservoirs has increased because of a need to understand deeper and more complex reservoirs. The creation of new secondary porosity that enhances overall reservoir quality in deeply buried carbonate reservoirs is controversial and some recent studies have concluded it is not an important phenomenon. Here we present petrography, geochemistry, fluid inclusion data, and fluid-rock interaction reaction modeling results from Triassic Feixianguan Formation, Sichuan Basin, China, core samples and explore the relative importance of secondary porosity due to thermochemical sulphate reduction (TSR) during deep burial diagenesis. We find that new secondary pores result from the dissolution of anhydrite and possibly from dissolution of the matrix dolomite. Assuming porosity before TSR was 16% and the percentage of anhydrite was 6%, modelling shows that, due to TSR, 1.6% additional porosity was created that led to permeability increasing from 110 mD (range 72–168 mD within a 95% confidence interval) to 264 mD (range 162–432 mD within a 95% confidence interval). Secondary porosity results from the density differences between reactant anhydrite and product calcite, the addition of new water during TSR, and the generation of acidity during the reaction of new H2S with the siderite component in pre-existing dolomite in the reservoir. Fluid pressure was high during TSR, and approached lithostatic pressure in some samples; this transient overpressure may have led to the maintenance of porosity due to the inhibition of compactional processes. An additional 1.6% porosity is significant for reserve calculations, especially considering that it occurs in conjunction with elevated permeability that results in faster flow rates to the production wells.

Many hydrocarbon shows have been reported from potential evaporite-related carbonate reservoirs in the lower to middle Cambrian units in the Tarim Basin. Petrography, facies, and geochemical analyses from outcrop and core samples were integrated to document the effect of diagenetic evolution on these evaporite-related carbonate reservoirs. A simplified depositional model has been developed that reveals a restricted carbonate platform dominated by an evaporatic inner platform lagoon, with shoal and reef facies developed around the platform margins. Grainstones and packstones were deposited at the platform margin and on inner platform shoals, whereas carbonate mudstones and wackestones were deposited in the lagoon associated with evaporites. Early dolomitization and dissolution occurred related to the reflux of evaporated seawater. Breccia-associated fracture porosity caused by a short period of meteoric water-induced dissolution is the predominant type of effective porosity in the anhydrite-bearing dolomudstone reservoir. Thermochemical sulfate reduction (TSR) occurred in the deep subsurface diagenetic environment characterized by high-temperature (100°C–160°C) and high-salinity (16–26 wt. %) aqueous fluid inclusions in TSR calcite that has relatively negative δ13C values (as low as −12‰ Vienna Peedee belemnite) and elevated 87Sr/86Sr values. The porous dolomites contain solution-enlarged pores caused by dissolution of anhydrite and carbonate as a secondary consequence of TSR. This study shows that deeply buried, evaporite-related, ancient carbonate rocks may be effective reservoirs because of a combination of fracture porosity and TSR-induced secondary porosity. Evaporitic Cambrian carbonates buried to over 5000 m (16,500 ft) can thus be considered as targets for future exploration.

Carbon Capture and Storage (CCS) is an essential tool in the fight against climate change. Any prospective storage site must meet various criteria that ensure the effectiveness, safety and economic viability of the storage operations. Finding the most suitable site for the storage of the captured CO2 is an essential part of the CCS chain of activity. This work addresses the site selection of a second site for the Acorn CCS project, a project designed to develop a scalable, full-chain CCS project in the North Sea (offshore northeast Scotland). This secondary site has been designed to serve as a backup and upscaling option for the Acorn Site, and has to satisfy pivotal project requirements such as low cost and high storage potential. The methodology followed included the filtering of 113 input sites from the UK CO2Stored database, according to general and project-specific criteria in a multi-staged approach. This criteria-driven workflow allowed for an early filtering out of the less suitable sites, followed by a more comprehensive comparison and ranking of the 15 most suitable sites. A due diligence assessment was conducted of the top six shortlisted sites to produce detailed assessment of their storage properties and suitability, including new geological interpretation and capacity calculations for each site. With the new knowledge generated during this process, a critical comparison of the sites led to selection of East Mey as the most suitable site, due to its outstanding storage characteristics and long-lasting hydrocarbon-production history, that ensure excellent data availability to risk-assess storage structures. A workshop session was held to present methods and results to independent stakeholders; feedback informed the final selection criteria. This paper provides an example of a criteria-driven approach to site selection that can be applied elsewhere., Project ACT-Acorn is gratefully thanked for funding this study. ACT Acorn, project 271500, received funding from BEIS (UK), RCN (Norway) and RVO (Netherland), and was co-funded by the European Commission under the ERA-Net instrument of the Horizon 2020 programme. ACT Grant number 691712. J. Alcalde is funded by MICINN (Juan de la Cierva fellowship - IJC2018-036074-I). S. Ghanbari is currently supported by the Energi Simulation. Energi Simulation is also thanked for funding the chair in reactive transport simulation held by E. Mackay.

The Triassic stratigraphy of the UK contains many important reservoir rock units, present in all major offshore and onshore basins, that are rich in oil, gas and water resources. The Ormskirk Sandstone Formation (Sherwood Sandstone Group) and Tarporley Siltstone Formation (Mercia Mudstone Group) represent the main reservoirs found in one of the UK's earliest producing oilfields, at an unusually shallow depth of 30–90 m. In this study, environments of deposition, maximum burial depth, and reservoir quality have been evaluated from well Formby-7, drilled in 2012, using modern analytical techniques. Wireline data and core analysis data were made available by Aurora Energy Resources for the purposes of this study. Formby-7 was continuously cored so that the whole section was logged for sedimentary structures and grain size. Optical analysis of thin sections was conducted, along with SEM-EDS, using thin sections from core plugs. The Ormskirk Sandstone Formation was deposited in a proximal setting by a braided, dryland river with aeolian influence; the Tarporley Siltstone Formation was deposited in a more distal setting on the margins of a playa environment. The study found that the reservoir quality is excellent in the deeper Ormskirk sediments, but relatively poor in the overlying Tarporley sediments. Good reservoir quality present in the Ormskirk Sandstone Formation is linked to early depositional textures, grain size (medium sand) and general lack of pore-filling cements. In the Tarporley, reservoir quality is poor due to the grain size (very fine sand) and the variable presence of pore-filling gypsum associated with playa deposits. Minor feldspar diagenesis (both dissolution and precipitation) occurred in both the Sherwood and Mercia sediments. The small degree of mechanical compaction and lack of any signs of mesodiagenesis suggest that the clastic sediments in the Formby-7 well have not been buried deeper than about 1000 m. The findings reported here can be used to help the understanding of UK Triassic sedimentology and reservoir quality for oil and gas, geothermal energy, CCS (carbon capture storage) and water supply.

Clay-coated grains can inhibit ubiquitous, porosity-occluding quartz cement in deeply buried sandstones and thus lead to anomalously high porosity. A moderate amount of clay that is distributed as grain coats is good for reservoir quality in deeply buried sandstones. Being able to predict the distribution of clay-coated sand grains in petroleum reservoirs is thus important to help find and exploit anomalously good reservoir quality. Here we have adopted a high-resolution, analogue approach, using the Ravenglass Estuary marginal-shallow marine system, in NW England, U.K. Extensive geomorphic mapping, grain-size analysis, and bioturbation-intensity counts were linked to a range of scanning electron microscopy techniques to characterize the distribution and origin of clay-coated sand grains in surface sediment. Our work shows that grain coats are common in this marginal–shallow marine system, but they are heterogeneously distributed as a function of grain size, clay fraction, and depositional facies. The distribution and characteristics of detrital-clay-coated grains can be predicted with knowledge of specific depositional environment, clay fraction percentage, and grain size. The most extensive detrital-clay-coated grains are found in sediment composed of fine-grained sand containing 3.5 to 13.0% clay fraction, associated with inner-estuary tidal-flat facies. Thus, against common convention, the work presented here suggests that, in deeply buried prospects, the best porosity might be found in fine-grained, clay-bearing inner-tidal-flat-facies sands and not in coarse, clean channel-fill and bar facies.

Research to date has identified cost and lack of support from stakeholders as two key barriers to the development of a carbon dioxide capture and storage (CCS) industry that is capable of effectively mitigating climate change. This paper responds to these challenges through systematic evaluation of the research and development process for the Acorn CCS project, a project designed to develop a scalable, full-chain CCS project on the north-east coast of the UK. Through assessment of Acorn's publicly-available outputs, we identify strategies which may help to enhance the viability of early-stage CCS projects. Initial capital costs can be minimised by infrastructure re-use, particularly pipelines, and by re-use of data describing the subsurface acquired during oil and gas exploration activity. Also, development of the project in separate stages of activity (e.g. different phases of infrastructure re-use and investment into new infrastructure) enables cost reduction for future build-out phases. Additionally, engagement of regional-level policy makers may help to build stakeholder support by situating CCS within regional decarbonisation narratives. We argue that these insights may be translated to general objectives for any CCS project sharing similar characteristics such as legacy infrastructure, industrial clusters and an involved stakeholder-base that is engaged with the fossil fuel industry. © 2019, The authors want to thank the entire ACT Acorn team for their support. The ACT Acorn project was funded by Accelerating CCS Technologies under Horizon 2020. Alcalde is currently funded by EIT Raw Materials – SIT4ME project (17024).

Rapid supply and deposition of 1000's of meters of Miocene and Pliocene sediment tend to lead to a different set of controls on reservoir quality than older, more slowly buried sandstones. Here we have studied Miocene fluvial-deltaic Bhuban Formation sandstones, from the Surma Group, Bengal Basin, buried to >3,000 m and >110 °C, using a combination of petrographic, geochemical and petrophysical methods in order to understand the controls on Miocene sandstone reservoir quality to facilitate improved prediction of porosity and permeability. The main conclusions of the study are that mechanical compaction processes are the dominant control on porosity-loss although early calcite growth has led to locally-negligible porosity in some sandstones. Mechanical compaction occurred by grain rearrangement, ductile grain compaction and brittle grain fracturing. Calcite cement, occupying up to 41% intergranular volume, was derived from a combination of dissolved and recrystallized bioclasts, an influx of organic-derived carbon dioxide and plagioclase alteration. Clay minerals present include smectite-illite, kaolinite and chlorite. The smectitic clay was probably restricted to low energy depositional environments and it locally diminishes permeability disproportionate to the degree of porosity-loss. Kaolinite is probably the result of feldspar alteration resulting from the influx of organic-derived carbon dioxide. Quartz cement is present in small amounts, despite the relatively high temperature, due to a combination of limited time available in these young sandstones, grain-coating chlorite and low water saturations in these gas-bearing reservoir sandstones. Reservoir quality can now be predicted by considering primary sediment supply and primary depositional environment, the magnitude of the detrital bioclast fraction and the influx of organic-derived carbon dioxide.

Cambrian dolostone reservoirs in the Tarim Basin, China, have significant potential for future discoveries of petroleum, although exploration and production planning is hampered by limited understanding of the occurrence and distribution of dolomite in such ancient rocks buried to nearly 8 km. The study herein accessed new drill core samples which provide an opportunity to understand the dolomitization process in deep basins and its impact on Cambrian carbonate reservoirs. This study documents the origin of the dolostone reservoirs using a combination of petrology, fluid‐inclusion microthermometry, and stable and radiogenic‐isotopes of outcrop and core samples. An initial microbial dolomitization event occurred in restricted lagoon environments and is characterized by depleted δ13C values. Dolomicrite from lagoonal and sabkha facies, some fabric‐retentive dolomite and fabric‐obliterative dolomite in the peloidal shoal and reef facies show the highest δ18O values. These dolomites represent relatively early reflux dolomitization. The local occurrence of K‐feldspar in dolomicrite indicates that some radiogenic strontium was contributed via terrigenous input. Most fabric‐retentive dolomite may have precipitated from seawater at slightly elevated temperatures, suggested by petrological and isotopic data. Most fabric‐obliterative dolomite, and medium to coarse dolomite cement, formed between 90°C and 130°C from marine evaporitic brine. Saddle dolomite formed by hydrothermal dolomitization at temperatures up to 170°C, and involved the mixing of connate brines with Sr‐ enriched hydrothermal fluids. Intercrystalline, moldic, and breccia porosities are due to the early stages of dolomitization. Macroscopic, intergranular, vuggy, fracture and dissolution porosity are due to burial‐related dissolution and regional hydrothermal events. This work has shown that old (for example, Cambrian or even Precambrian) sucrosic dolomite with associated anhydrite, buried to as much as 8000 m, can still have a high potential for hosting substantial hydrocarbon resources and should be globally targeted for future exploration.

During thermochemical sulfate reduction (TSR), H2S generated by reactions between hydrocarbons and aqueous sulfate back-reacts with remaining oil-phase compounds forming new organosulfur compounds (OSCs) that have similar δ34S values to the original sulfate. Using Compound Specific Sulfur Isotope Analysis (CSSIA) of alkylthiaadamantanes (TAs), alkyldibenzothiophenes (DBTs), alkylbenzothiophenes (BTs) and alkylthiolanes (TLs), we have here attempted to differentiate OSCs due to primary generation and those due to TSR in oils from the Tarim Basin, China. These oils were generated from Cambrian source rocks and accumulated in Cambrian and Ordovician reservoirs. Based on compound specific sulfur isotope and carbon isotope data, TAs concentrations and DBT/phenanthrene ratios, the oils fall into four groups, reflecting different extents of source rock signal, alteration by TSR, mixing events, and secondary generation of H2S. Thermally stable TAs, that were produced following TSR, rapidly dominate kerogen-derived TAs at low to moderate degrees of TSR. Less thermally stable TLs and BTs were created as soon as TSR commenced, rapidly adopted TSR-δ34S values, but they do not survive at high concentrations unless TSR is advanced and ongoing. The presence of TLs and BTs shows that TSR is still active. Secondary DBTs were produced in significant amounts, sufficient to dominate kerogen-derived DBTs, only when TSR was at an advanced extent. The difference in sulfur isotopes between (i) TLs and DBTs and (ii) BTs and DBTs and (iii) TAs and DBTs, represents the extent of TSR while the presence of TAs at greater than 20 μg/g represents the occurrence of TSR. The output of this study shows that compound specific sulfur isotopes of different organosulfur compounds, with different thermal stabilities and formation pathways, not only differentiate between oils of TSR and non-TSR origin, but can also reveal information about relative timing of secondary charge events and migration pathways.

Detrital grain-coating clay minerals have been identified as precursors of diagenetic grain-coating clay minerals that inhibit quartz cementation and preserve good reservoir quality properties in deeply buried sandstone reservoirs. Between initial and final deposition, detrital grain coats are likely to be affected by sediment transport processes. To date, it has not been demonstrated that detrital grain-coating clays are able to survive sediment transport. Flume experiments simulating open-channel flow conditions were performed using sediments from the Ravenglass estuary (Cumbria, UK), where the distribution and characteristics of modern detrital grain-coating clays is well established. Scanning electron microscopy and automated mineralogy techniques were employed to study the sediment before and after transport to determine the stability of the detrital grain-coating clays. The experimental results show that detrital grain-coating clays are still present after sediment transport in turbulent flows with velocities up to 0.5 m s−1. The stability of the detrital grain-coating clays was enhanced by (1) high initial clay coat coverage, (2) turbulence characteristics of the flow, and (3) entrapment of the detrital grain-coating clays in bedforms. This work documents the first quantifiable evidence that estuary-derived, detrital clay coats are routinely preserved after sediment transport. Clay coat-rich estuarine sediments can therefore act as the source of clay coated grains found in cleaner estuarine sandstones and may even survive transport out into open marine settings.

Deeply-buried carbonate-reservoirs from the Lower Triassic Feixianguan Formation in the Sichuan Basin of China host extensive natural gas resources. These reservoirs are predominantly found in oolitic shoals, with the reservoir quality of dolomitized zones being higher than that of undolomitized limestone counterparts. Here we present a combination of petrographic, isotopic, fluid inclusion, and quantitative porosity data in order to understand and predict the diagenetic processes that have impacted the reservoir quality of dolostones and limestones. The porosity of limestones has been reduced to ∼7.5% due to calcite cementation, whereas the porosity in oolitic dolostones is not cemented with calcite and typically has ∼23.5% porosity. Dolomitization and concurrent early-diagenetic gypsum growth played crucial roles on the development and preservation of high porosity in the oolitic dolostone, first by stabilizing the rock fabric to inhibit loss of porosity during burial, and secondly through the generation of new porosity by dissolution of carbonate and anhydrite. A negative shift of δ 18 O and salinity values ( 13 C values (∼−20‰ VPDB) and δ 18 O (∼−10‰ VPDB) together with elevated calcite precipitation temperatures (>110 °C). It is likely that TSR was responsible for the formation of enlarged dissolution vugs that increased porosity by ∼2% in dolostones due to: i) anhydrite dissolution, ii) production of significant amounts of water resulting in formation water undersaturated with respect to calcite and dolomite, iii) generation of H 2 S, and CO 2 , and the consequent reaction of H 2 S with the siderite (FeCO 3 ) component in calcite and dolomite. This study demonstrates the importance of diagenesis in the formation of deeply-buried, high-quality reservoirs in ooid-dominated grainstones influenced by the presence of evaporites. Our results should be useful for guiding future exploration and reservoir developments in similar paleogeographic and diagenetic settings.

The impact of burial diagenesis (especially deep burial-related processes such as thermochemical sulfate reduction, TSR) on the distribution of rare earth elements and yttrium (REY) in diagenetic minerals in carbonate reservoir has gained little attention even though they may be unique indicators of the diagenetic system being closed or open to external influx of material. Trace element and REY concentrations, 87 Sr/ 86 Sr, δ 18 O and δ 13 C have been determined for limestone, host dolomite, pore-filling calcite (calcite-2), and late stage fracture-filling calcite (calcite-3), barite (barite-2) and anhydrite (anhydrite-3) from Lower Triassic Feixianguan Formation reservoirs in northeast Sichuan Basin, China. Calcite-2, calcite-3, barite-2, and anhydrite-3 precipitated during deep burial (from 110 °C to 220 °C), demonstrated by petrology and fluid inclusion thermometry. Sr isotope analysis revealed that diagenetic carbonate minerals and anhydrite have largely identical 87 Sr/ 86 Sr ratios to Triassic seawater, indicating negligible input of Sr from terrigenous sources and probably a relatively closed diagenetic environment for precipitation of these minerals. Carbon isotope analysis showed that calcite-2 has relatively low δ 13 C values (down to − 18.9‰ V-PDB), suggesting that they are TSR calcites with the carbonate derived from oxidized, isotopically-light hydrocarbons. Unlike the seawater-like REY patterns of the limestone and dolomites, calcite-3 and anhydrite-3 are enriched in rare earth elements (ΣREE) and show light rare earth element enrichment and heavy rare earth element depletion, exhibiting a chevron-like pattern of shale normalized REY trends. In contrast, TSR calcite (calcite-2) has similar ΣREE to the host dolomite but a relatively flat REY SN pattern, suggesting strong variations in elemental and REE compositions of the burial fluids. Significantly, TSR calcite shows a prominent positive Eu anomaly and an unusually high-chondritic Y/Ho ratio. Both yttrium versus holmium fractionation and Eu 2 + oxidation to Eu 3 + must have occurred during thermochemical sulfate reduction. Hence, a positive Eu anomaly and an elevated Y/Ho ratio may be used as effective proxies to differentiate calcite resulting from TSR from ordinary calcite cement. This is especially useful when carbon isotope analysis cannot be used to give an unambiguous interpretation of the origin of the calcite.

Up until now, it has been assumed that oil in the Palaeozoic reservoirs of the Tazhong Uplift was derived from Upper Ordovician source rocks. Oils recently produced from the Middle and Lower Cambrian in wells ZS1 and ZS5 provide clues concerning the source rocks of the oils in the Tazhong Uplift, Tarim Basin, China. For this study, molecular composition, bulk and individual n -alkane δ 13 C and individual alkyl-dibenzothiophene δ 34 S values were determined for the potential source rocks and for oils from Cambrian and Ordovician reservoirs to determine the sources of the oils and to address whether δ 13 C and δ 34 S values can be used effectively for oil–source rock correlation purposes. The ZS1 and ZS5 Cambrian oils, and six other oils from Ordovician reservoirs, were not significantly altered by TSR. The ZS1 oils and most of the other oils, have a “V” shape in the distribution of C 27 –C 29 steranes, bulk and individual n -alkane δ 13 C values predominantly between −31‰ to −35‰ VPDB, and bulk and individual alkyldibenzothiophene δ 34 S values between 15‰ to 23‰ VCDT. These characteristics are similar to those for some Cambrian source rocks with kerogen δ 13 C values between −34.1‰ and −35.3‰ and δ 34 S values between 10.4‰ and 21.6‰. The oil produced from the Lower Ordovician in well YM2 has similar features to the ZS1 Cambrian oils. These new lines of evidence indicate that most of the oils in the Tazhong Uplift, contrary to previous interpretations, were probably derived from the Cambrian source rocks, and not from the Upper Ordovician. Conversely, the δ 13 C and δ 34 S values of ZS1C Cambrian oils have been shown to shift to more positive values due to thermochemical sulfate reduction (TSR). Thus, δ 13 C and δ 34 S values can be used as effective tools to demonstrate oil–source rock correlation, but only because there has been little or no TSR in this part of the section.