The porosity and permeability of sandstone and carbonate reservoirs (known as reservoir quality) are essential inputs for successful oil and gas resource exploration and exploitation. This chapter introduces basic concepts, analytical and modelling techniques and some of the key controversies to be discussed in 20 research papers that were initially presented at a Geological Society conference in 2014 titled ‘Reservoir Quality of Clastic and Carbonate Rocks: Analysis, Modelling and Prediction’. Reservoir quality in both sandstones and carbonates is studied using a wide range of techniques: log analysis and petrophysical core analysis, core description, routine petrographic tools and, ideally, less routine techniques such as stable isotope analysis, fluid inclusion analysis and other geochemical approaches. Sandstone and carbonate reservoirs both benefit from the study of modern analogues to constrain the primary character of sediment before they become a hydrocarbon reservoir. Prediction of sandstone and carbonate reservoir properties also benefits from running constrained experiments to simulate diagenetic processes during burial, compaction and heating. There are many common controls on sandstone and carbonate reservoir quality, including environment of deposition, rate of deposition and rate and magnitude of sea-level change, and many eogenetic processes. Compactional and mesogenetic processes tend to affect sandstone and carbonate somewhat differently but are both influenced by rate of burial, and the thermal and pressure history of a basin. Key differences in sandstone and carbonate reservoir quality include the specific influence of stratigraphic age on seawater composition (calcite v. aragonite oceans), the greater role of compaction in sandstones and the greater reactivity and geochemical openness of carbonate systems. Some of the key controversies in sandstone and carbonate reservoir quality focus on the role of petroleum emplacement on diagenesis and porosity loss, the role of effective stress in chemical compaction (pressure solution) and the degree of geochemical openness of reservoirs during diagenesis and cementation. This collection of papers contains case study-based examples of sandstone and carbonate reservoir quality prediction as well as modern analogue, outcrop analogue, modelling and advanced analytical approaches.

Saline aquifers have been used for CO₂ storage as a dedicated greenhouse gas mitigation strategy since 1996. Depleted gas fields are now being planned for large-scale CCS projects. Although basalt host reservoirs are also going to be used, saline aquifers and depleted gas fields will make up most of the global geological repositories for CO₂. At present, depleted gas fields and saline aquifers seem to be treated as if they are a single entity, but they have distinct differences that are examined here. Depleted gas fields have far more pre-existing information about the reservoir, top-seal caprock, internal architecture of the site, and about fluid flow properties than saline aquifers due to the long history of hydrocarbon project development and fluid production. The fluid pressure evolution paths for saline aquifers and depleted gas fields are distinctly different because, unlike saline aquifers, depleted gas fields are likely to be below hydrostatic pressure before CO₂ injection commences. Depressurised depleted gas fields may require an initial injection of gas-phase CO₂ instead of dense-phase CO₂ typical of saline aquifers, but the greater pressure difference may allow higher initial injection rates in depleted gas fields than saline aquifers. Depressurised depleted gas fields may lead to CO₂-injection-related stress paths that are distinct from saline aquifers depending on the geomechanical properties of the reservoir. CO₂ trapping in saline aquifers will be dominated by buoyancy processes with residual CO₂ and dissolved CO₂ developing over time whereas depleted gas fields will be dominated by a sinking body of CO₂ that forms a cushion below the remaining methane. Saline aquifers tend to have a relatively limited ability to fill pores with CO₂ (i.e., low storage efficiency factors between 2 and 20%) as the injected CO₂ is controlled by buoyancy and viscosity differences with the saline brine. In contrast, depleted gas fields may have storage efficiency factors up to 80% as the reservoir will contain sub-hydrostatic pressure methane that is easy to displace. Saline aquifers have a greater risk of halite-scale and minor dissolution of reservoir minerals than depleted gas fields as the former contain vastly more of the aqueous medium needed for such processes compared to the latter. Depleted gas fields have some different leakage risks than saline aquifers mostly related to the different fluid pressure histories, depressurisation-related alteration of geomechanical properties, and the greater number of wells typical of depleted gas fields than saline aquifers. Depleted gas fields and saline aquifers also have some different monitoring opportunities. The high-density, electrically conductive brine replaced by CO₂ in saline aquifers permits seismic and resistivity imaging, but these forms of imaging are less feasible in depleted gas fields. Monitoring boreholes are less likely to be used in saline aquifers than depleted gas fields as the latter typically have numerous pre-existing exploration and production well penetrations. The significance of this analysis is that saline aquifers and depleted gas fields must be treated differently although the ultimate objective is the same: to permanently store CO₂ to mitigate greenhouse gas emissions and minimise global heating.

Natural gas is found in Upper Permian and Lower Triassic dolomite reservoirs of the NE Sichuan Basin, China. Studying the mechanisms for porosity‐modifying dolomitization and predicting its spatial distribution is of great importance for exploration and field appraisal. Subsurface core samples from the oolitic Lower Triassic Feixianguan Formation and outcrop samples reef carbonate Upper Permian Changxing Formation were studied using cathodoluminescence (CL), electron microprobe, fluid inclusion and isotope studies (δ¹⁸O, δ¹³C and ⁸⁷Sr/⁸⁶Sr), in an attempt to determine the origin of the dolomitizing fluids. Trace element and isotope data show that Lower Triassic seawater was most likely responsible for dolomitization of both the Permian and Triassic rocks. Sr/Ca molar ratios, calculated for the diagenetic fluid, suggest seawater was involved in dolomitization. Strontium isotope data suggest that seawater ⁸⁷Sr/⁸⁶Sr during the Jialingjiang (Lower Triassic) reached 0.7078; this ratio is recorded ubiquitously in both Lower Triassic oolitic dolomite and the underlying Lower Permian reef dolomite. In the Permian Changxing Formation, elevated Triassic ⁸⁷Sr/⁸⁶Sr values have overprinted the significantly lower ⁸⁷Sr/⁸⁶Sr ratio characteristic of Upper Permian seawater. Fluid inclusion analysis led to the conclusion that dolomitization must have commenced at a temperature lower than about 50°C. Integrating the sedimentology, petrology and geochemistry data, we conclude that coeval Lower Triassic (Feixianguan or slightly younger) seawater caused dolomitization by a reflux‐seepage process for both the Lower Triassic and Upper Permian units. There is no evidence for deep burial or meteoric‐marine mixing‐zone dolomitization. It is likely that evaporating seawater initially flowed into the highly porous oolitic Feixianguan Formation in a sabkha/lagoonal setting and precipitated anhydrite nodules and beds. Concomitant dolomitization, in the underlying Permian reef carbonates, continued during seepage even after the supply of sulphate was exhausted, leading to an absence of anhydrite in Permian Changxing Formation.

The dolomite-hosted, Lower Triassic Feixianguan Formation from the northeast Sichuan Basin, China, is an economically important reservoir that contains sour natural gas. These reservoirs were initially filled with oil, later replaced by gas during burial to 7000 m (22,965 ft) followed by uplift to about 4000 m (13,123 ft). We have studied the souring process (thermochemical sulfate reduction [TSR]) and diagenetic evolution of the Feixianguan Formation using detailed petrology, fluid-inclusion studies, and stable-isotope data from carbonate minerals. Pre-TSR diagenesis included (in time order) the eodiagenetic main stage of dolomitization by a reflux mechanism; fracture-related calcite cementation; barite, quartz, celestite, and fluorite mineralization; and a dolomite recrystallization stage. Thermochemical sulfate reduction resulted in anhydrite replacement by calcite, petroleum destruction, formation of sulfur-rich pyrobitumen and elemental sulfur, and generation of large volumes of H2S and CO2. Diagenesis during TSR can be subdivided into oil-stage TSR and gas-stage TSR, with oil-stage TSR defined by the presence of primary oil and bitumen inclusions in the TSR calcite. Based on aqueous inclusion homogenization temperatures, oil-stage TSR commenced at a temperature of 116°C, with a mode between 130°C and 140°C. Gas-stage TSR started at a temperature of 135°C and continued to maximum burial temperatures of about 220°C. Trace amounts of pyrite, barite, quartz, and celestite grew during TSR. Post-TSR diagenesis was dominated by fracture-related calcite precipitation as well as celestite and anhydrite crystallization. Formation water salinity increased from depositional values (3.5 wt. %) up to 24 wt. % during pre-TSR dolomite recrystallization probably because of an influx of evaporite-associated water from the overlying Jialingjiang Formation, although pre-TSR barite, quartz, celestite, and fluorite mineralization was associated with a transient decrease in water salinity. During TSR, formation water salinity decreased from 26 wt. % to as low as 4 wt. % as a result of water being produced during TSR reactions.