Abstract: 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.

Abstract: The lacustrine carbonate reservoirs of the South Atlantic host significant accumulations of chemically reactive and Al-free Mg-silicate minerals (e.g. stevensite, kerolite and talc). Petrographic data from units such as the Cretaceous Barra Velha Formation in the Santos Basin suggest that Mg-silicate minerals strongly influenced, and perhaps created, much of the observed secondary porosity. The diagenetic interactions between reactive Mg-silicate minerals and carbonate sediments are, however, poorly known. Here we develop a conceptual model for the origin of secondary porosity in the Barra Velha Formation guided by considerations of the chemistry that triggers Mg-silicate crystallization, as well as the geochemical and mineralogical factors that act as prerequisites for rapid Mg-silicate dissolution during early and late diagenesis. We conclude that sub-littoral zones of volcanically influenced rift lakes would have acted as the locus for widespread Mg-silicate accumulation and preservation. Organic-rich profundal sediments, however, would be especially prone to Mg-silicate dissolution and secondary porosity development. Here, organic matter diagenesis (especially methanogenesis) plays a major role in modifying the dissolved inorganic carbon budget and the pH of sediment porewaters, which preferentially destabilizes and then dissolves Mg-silicates. Together, the sedimentological, stratigraphic and geochemical predictions of the model explain many enigmatic features of the Barra Velha Formation, providing a novel framework for understanding how Mg-silicate–carbonate interactions might generate secondary porosity more broadly in other lacustrine carbonate reservoirs across the South Atlantic.

Abstract: Microporosity in carbonate reservoirs is generated by the complex interplay between depositional and diagenetic processes. This petrographical, SEM, fluid-inclusion and isotopic study of a Lower Cretaceous carbonate reservoir, Abu Dhabi, UAE, revealed that: (1) micritization of ooids and skeletal fragments, which resulted in spheroidal (rounded) micrite, accounts for most microporosity in peloidal packstones and grainstones; and (2) transformation of spheroidal micrite into subhedral/euhedral micrite and microspar, known as aggrading neomorphism, could happen via precipitation of syntaxial calcite overgrowths around micrite (micro-overgrowths) and not only, as suggested previously in the literature, by recrystallization involving the dissolution (of micrite) and reprecipitation (of microspar). Precipitation of calcite cement around micrite (i.e. destruction of microporosity) is more extensive in the water zone than in the oil zone, which is possibly contributing to the lower porosity and permeability of the carbonate reservoir in the water zone. Similarity in bulk oxygen isotopic values of micritized packstones and grainstones in the water and oil zones (average δ 18 O V-PDB = −7.2‰ and −7.8‰, respectively) is attributed to: (1) a small difference in temperatures between the crest (oil zone) and the flanks (water zone); and (2) calcite precipitation around micrite occurred prior and subsequent to oil emplacement. Bulk carbon and strontium isotopic compositions of micritized packstones and grainstones in the water and oil zones (average δ 13 C V-PDB = +3.7‰ and average 87 Sr/ 86 Sr ratios = 0.707469) indicate that calcite cement was derived from marine porewaters and/or dissolution of the host limestones. The minimum formation temperatures of bulk micrite/microspar, which are inferred based on paragenetic relationships, fluid-inclusion microthermometry and oxygen isotope data, are around 58–78°C.

Abstract: The Panna–Mukta fields host hydrocarbons in the Bassein Formation Eocene–Oligocene ramp limestones. The pore system is almost wholly secondary, comprising microporosity, mouldic porosity, vugs, solution-enlarged stylolites and fractures. Although petrographical evidence points to dissolution after extensive late cementation, the presence of a high permeability layer close to a palaeokarstic surface at the Eocene–Oligocene boundary has raised the possibility that this secondary porosity could be related to subaerial exposure. However, the Panna–Mukta reservoirs show a strong correlation between secondary matrix porosity and stylolite density measured from cores. Stylolites only developed in ‘clean’ limestones lacking argillaceous material, whereas more argillaceous limestones in the succession are characterized by dissolution seams and have poor reservoir quality. These cleaner limestones occur preferentially below the Eocene–Oligocene boundary, representing an upwards-shallowing sequence, whereas the argillaceous limestones occur further below the Eocene–Oligocene boundary in the lower part of the same shallowing-upwards sequence and in the transgressive limestones at the base of the Bassein A. This secondary porosity distribution suggests movement of corrosive fluids along pre-existing stylolites. Despite an apparent link between porosity distribution and an unconformity, secondary porosity development was mesogenetic and related to the distribution of facies that favoured stylolites that acted as conduits for the flow of corrosive fluids. The Bassein Formation reservoirs show unequivocal evidence of significant porosity development by mesogenetic dissolution but the exact process or processes by which such porosity creation occurs requires further work.

Abstract: An integrated sedimentological and petrophysical approach was implemented to define the role of facies diversity and cyclicity on the reservoir quality of the Mishrif Formation in several oil fields in southern Iraq. The reservoir quality in most regressive cycles was enhanced upwards from deep-marine facies towards the shallower shelf-margin facies. The change in reservoir quality could be detected in the facies stacked systematically within the regressive cycles, which was also easily recognized using the porosity logs. The impact of early diagenetic overprints was quite obvious in developing both reservoir and non-reservoir rock types within the Mishrif Formation in the study area. A simple rock-typing nomenclature was proposed based on the available data in order to classify the existing reservoir (R) and non-reservoir (S) rock types. The best-recognized reservoir rock types were rudistid microfacies with grain-dominated fabrics (including both grainstone (R1) and grain-dominated packstone (R2)), which were subjected to an early diagenetic dissolution process, usually located beneath discontinuity surfaces. Such reservoir units or rock types have a regional extent within the southern Mesopotamian Basin, as they have often developed during the Mishrif shelf-margin progradation. In addition, the other important reservoir rock type was a microbialite (i.e. peloidal mud-dominated packstone (R3)), which was additionally characterized by micropores within the mud-dominated portion of the facies. However, owing to the variable intensity of the diagenetic effects and differences in the depositional texture components, the reservoir quality in this rock type could vary regionally. The regional distribution of the rudistid grainstone and grain-dominated packstone reservoir rock types (R1 and R2) was mostly related to the palaeogeographical highs that existed during deposition. However, such reservoir rock types could pinch out within the depositional sequences, showing their potential to become stratigraphic traps outside the structural crest of the field. The delineation of the reservoir rock types within a sequence-stratigraphic framework can be quite beneficial for reservoir prediction and exploration within and outside of the field.

Abstract: Accurate determination of the thermal history of sedimentary basins is critical to constrain the timing of diagenetic processes. Here, clumped isotope palaeothermometry is used to estimate minimum burial depth of the Lower Cretaceous Qishn Formation in east central Oman. Fossil oysters were collected in a soft argillaceous unit, thin-sectioned, and studied under petrographical and cathodoluminescence microscopy, revealing a variable state of shell preservations with early silica replacement of carbonate and late-stage calcite cementation. Clumped isotopes values varied from 0.602 to 0.666‰, with the best-preserved oyster shell yielding a temperature of 37 ± 4°C and a calculated oxygen isotope ratio in seawater (δ 18 O seawater ) compatible with Cretaceous seawater having experienced moderate evaporation (1.0–1.5‰ VSMOW). The new minimum estimates for the burial depth of the Qishn Formation is 1.0–1.2 km, based on the temperature difference between the well-preserved oyster and the partially neomorphosed oyster recording the highest burial temperature (63 ± 4°C). This is in excess of what was predicted by previous studies (<400 m), but compatible with conodonts alteration index temperatures (<80°C). This study highlights the potential of clumped isotopes as a quantitative tool to estimate temperature and burial depth in fine-grained carbonate succession where fluid inclusions are absent, and offers a new tool to constrain the thermal histories of sedimentary basins.

Abstract: The occurrence and distribution of minerals in modern sedimentary systems hold many clues to help unravel the origin and distribution of reservoir quality-controlling minerals in ancient and deeply buried sandstones, but few quantitative studies have been undertaken. Here we have used a range of techniques including X-ray diffraction, scanning electron microscopy and fully automated mineralogical QEMSCAN analysis to provide a comprehensive understanding of mineral composition and distribution within the post-glacial, clastic sediments of the Ravenglass Estuary, NW England. The Ravenglass Estuary is fed by two main rivers: one drains a granite-dominated hinterland, the other drains a hinterland that contains andesite and Triassic red bed sandstones. The granite-supplied arm has slightly more quartz-rich and Fe mineral-poor sediment than the andesite- and red bed-supplied sediment. The provenance signals are muted for feldspar and mica minerals heavy-mineral garnet populations seem to be sensitive to provenance. Detrital K-feldspar grains are preferentially associated with illite-dominated clay mineral coats, whereas all plagioclase mineral grains are preferentially associated with kaolinite-dominated clay mineral coats. This can be explained by rapid early diagenesis in the sediment with K-feldspar grain surfaces replaced by illite and plagioclase grain surfaces replaced by kaolinite. The andesite- and red bed-supplied sediment contains twice the amount of Fe minerals, which are dominated by chlorite, than the granite-supplied sediment. Chlorite rarely is associated with grain coatings on feldspar grains, possibly because it is predominantly a detrital mineral. Detrital Fe minerals seem to be locally replaced by pyrite due to bacterial sulphate reduction, suggesting that some early diagenetic processes may serve to lock away iron and prevent it from creating Fe-rich clay minerals.

Abstract: Many siliciclastic reservoirs contain millimetre-scale diagenetic and structural phenomena affecting fluid flow. We identified three major types of small-scale flow barriers in a clastic Rotliegend hydrocarbon reservoir: cataclastic deformation bands; dissolution seams; and bedding-parallel cementation. Deformation bands of various orientations were analysed on resistivity image logs and in core material. They are mainly conjugates, and can be used to validate seismically observable faults and infer subseismic faults. Bedding-parallel dissolution seams are related to compaction and post-date at least one set of deformation bands. Bedding-parallel cementation is accumulated in coarser-grained layers and depends on the amount of clay coatings. Apparent permeability data related to petrographical image interpretation visualizes the impact of flow barriers on reservoir heterogeneity. Transmissibility multiplier calculations indicate the small efficiency of the studied deformation bands on flow properties in the reservoir. Deformation bands reduce the host-rock permeability by a maximum of two orders of magnitude. However, host-rock anisotropies are inferred to reduce the permeability by a maximum of four orders of magnitude. The relative timing of these flow barriers, as well as the assessment of reservoir heterogeneities, are the basis for state-of-the-art reservoir prediction modelling.

Abstract: Deformation bands significantly alter the local petrophysical properties of sandstone reservoirs, although it is not known how the intrinsically variable characteristics of sandstones (e.g. grain size, sorting and mineralogy) influence the nature and distribution of deformation bands. To address this, cataclastic deformation bands within fine- and coarse-grained Triassic Sherwood Sandstone at Thurstaston, UK were analysed, for the first time, using a suite of petrographical techniques, outcrop studies, helium porosimetry and image analysis. Deformation bands are more abundant in the coarse-grained sandstone than in the underlying fine-grained sandstone. North- and south-dipping conjugate sets of cataclastic bands in the coarse-grained sandstone broadly increase in density (defined by number/m 2 ) when approaching faults. Microstructural analysis revealed that primary grain size controls deformation band density. Deformation bands in both coarse and fine sandstones led to significantly reduced porosity, and so can represent barriers or baffles to lateral fluid flow. Microstructural data show preferential cataclasis of K-feldspar grains within the host rock and deformation band. The study is of direct relevance to the prediction of reservoir quality in several petroleum-bearing Lower Triassic reservoirs in the near offshore, as deformation band development occurred prior to Carboniferous source-rock maturation and petroleum migration.

Abstract: Many carbonate reservoirs are located on top, or down the flanks, of extant structural highs or syndepositional palaeo-highs. This study examines diagenesis in Pennsylvanian oolitic reservoirs close to the crest and down the flank of a long-lived anticline. It illustrates that the position of the best reservoir quality shifted back and forth during successive diagenetic events. Cement stratigraphy shows that early diagenesis did not enhance reservoir character significantly. Most oomoldic porosity formed penecontemporaneously with compaction. Fluid-inclusion and stable isotope data indicate that late cements precipitated during burial conditions by refluxing brines and later hydrothermal fluids. After initial burial, greater permeability existed downdip, where smaller amounts of early meteoric cement allowed for compaction. Subsequent reflux cementation initially degraded downdip reservoirs preferentially and then progressed updip, resulting in relatively uniform reservoir porosity. Later hydrothermal events are most important in affecting the distribution of the highest quality present-day reservoir. Highest porosity is preserved in wells down the flanks of the structure, where hydrothermal cements are not as prevalent. Understanding the effect of diagenesis on location of the best reservoir in relation to palaeotopographical and structural highs allows for the prediction of reservoir quality using seismic and mapping data typically available in the subsurface.

Abstract: The mechanical strength, porosity and permeability of chalk are affected by chemical and mineralogical changes induced by fluids that are chemically out of equilibrium with the host rock. Here, two high-porosity Upper Cretaceous chalk cores from Liège were tested at effective stresses beyond yield at 130°C during flooding with MgCl 2 and NaCl brines. Core L1 (flooded by MgCl 2 brine) deformed more than L2 (flooded with NaCl brine), with volumetric strains of 9.4% and 5.1%, respectively. The porosity losses estimated from strain measurements alone are 5.82% for L1 and 3.01% for L2. However, this approach does not account for dissolution and precipitation reactions. Porosity calculations that are based on strain measurements in combination with (i) the weight difference between saturated and dry cores and (ii) the solid density measurement before and after flooding show an average porosity reduction of 3.69% between the two methods for L1. This discrepancy was not observed for core L2 (with the NaCl brine). The rock and effluent chemistry show that Ca 2+ dissolved and Mg 2+ is retained within the core for the L1 experiment. Therefore, accurate porosity calculations in chalk cores that are flooded by non-equilibrium brines (e.g. MgCl 2 ) require both the volumetric strain and chemical alteration to be considered.

Abstract: Reaction transport modelling (RTM) has been successfully used to simulate dolomitization and to predict the lateral extension of dolomitized bodies as potential hydrocarbon reservoirs in the subsurface as well as to give insights into the dolomitization process itself. Geological configurations that have been tested include reflux dolomitization, thermal convection and dolomitization in compactional burial settings. In this study the hydrothermal dolomitization model has been tested with a RTM approach where a limestone reservoir in an intermediate burial setting is fluxed in the presence of deep feeding faults. Hydrothermal fluids migrate upwards from the deep basin areas through extensional fault conduits reaching more permeable levels in the reservoir. The fluids enter the primary interparticle porosity and dolomitize the limestone creating moldic and vuggy porosity. The simulations demonstrate the importance of faulting in this dolomitization process. An effective control on dolomitization is thus exerted by the permeability distribution. Moreover, the type and reactivity of the fluids entering the limestone reservoir exert important controls on the extent of the dolomite bodies.

Abstract: Petroleum exploration and production in the region of the Niger Delta to date has mainly focused on the onshore, deltaic and offshore deep-water Miocene successions. Although Miocene turbidites have been the principal deep-water target, deeper-lying Oligocene sandstones are now being considered for exploration. This study targets an area beneath the Niger Basin slope at a present-day water depth of 800–1500 m. Within this study area, the Miocene to Recent sands above a burial depth of 3600 m show very good reservoir quality with porosities as high as 35% and permeabilities in the Darcy range. The aim of this study is to predict the reservoir quality and properties of the Oligocene sandstones below 3800 m using basin modelling to predict conditions where quartz cementation will take place and quartz cementation models to predict the amount of cementation and hence the potential porosity loss. Modelling results show that the Oligocene sandstones have been exposed to conditions favourable for quartz precipitation, but that less than 14% of the original porosity will have been occluded by quartz cement. These results are in agreement with elemental analysis from both petrophysical and petrological observation of thin sections. Although the deeper-lying Oligocene sandstones are likely to have reduced reservoir quality due to the presence of quartz overgrowth cementation, it appears likely that the volume of cement is relatively low and the Oligocene succession should be considered a viable play.

Abstract: The Vedder (Oligocene) and Kreyenhagen (Eocene) sandstones at the Greeley oil field consist of arkosic to subarkosic arenites and wackes deposited in shallow marine environments. Burial depths of the Vedder sandstones exceed 3150 m and the reservoir temperature is 124°C. The Kreyenhagen sandstones are buried to greater than 3920 m and the reservoir temperature is estimated to be c. 135°C. These sandstones are currently at or very near their deepest burial depths. The textural relationships of the diagenetic minerals suggest syndepositional formation of glauconite, phosphate and pyrite, followed by early precipitation of pore-lining clay coatings and carbonate cements along with framework-grain fracturing and possibly dissolution. With increasing burial, dissolution of the framework grains continued, accompanied by the albitization of feldspars, the formation of K-feldspar and quartz overgrowths, the precipitation of kaolinite and other clays and possibly the precipitation of late carbonate cements. Finally, hydrocarbon migration and the formation of pyrite occurred during late diagenesis. Porosity preservation and reservoir quality are primarily the result of plagioclase dissolution occurring as the strata approached their current burial depths. Mass balance calculations indicate the significant export of aluminium out of the sands. Thus secondary porosity produced by plagioclase dissolution has replaced the primary porosity destroyed by compaction, and now accounts for the majority of the porosity in these rocks.

Abstract: A comprehensive study of the Cambrian–Ordovician Arbuckle Group suggests that multiple fluid migration events have affected reservoir porosity via fractures and preferred stratigraphic horizons. Fluid inclusion homogenization temperatures from late-stage precipitates yield temperatures higher than can be explained by burial conditions or an elevated geothermal gradient. Fluid inclusion melting temperatures yield salinity values that indicate multiple fluids evolving through time. Hydrocarbon fluid inclusions in late-stage baroque dolomite suggest oil migration concurrent with hydrothermal fluid flow. Depleted δ 13 C and δ 18 O values provide evidence for a high-temperature basinal fluid source as well as for the preferential flow of hydrothermal fluids through permeable zones in the Mississippian and Arbuckle Group, where pore systems related to paleokarst are overlain by less permeable units. Radiogenic strontium isotopic data support fluid–rock interaction with siliciclastic material or basement rock at some point during the fluid migration history. Variable 87 Sr/ 86 Sr values suggest multiple sources for the fluids responsible for the cements and a transition from an advective fluid flow system to a vertical fluid flow system. The ancient aquifer system was vertically connected during migration of hydrothermal fluids, and a temperature-controlled vertical density gradient appears to have played an important role in late-stage porosity evolution, focusing the hottest fluids in the upper sections of permeable layers.

Abstract: Current understanding of porosity preservation in deeply buried sandstone reservoirs tends to be focused on how diagenetic grain coatings of clay minerals and microquartz can inhibit macroquartz cementation. However, the importance of overpressure developed during initial (shallow) burial in maintaining high primary porosity during subsequent burial has generally not been appreciated. Where pore fluid pressures are high, and the vertical effective stress is low, the shallow arrest of compaction can allow preservation of high porosity and permeability at depths normally considered uneconomic. The deeply buried fluvial sandstone reservoirs of the Triassic Skagerrak Formation in the Central Graben, North Sea, show anomalously high porosities at depths greater than 3500 metres below sea floor (mbsf ). Pore pressures can exceed 80 MPa in the upper part of the Skagerrak Formation at depths of 4000–5000 mbsf, where temperatures are above 140°C. The Skagerrak reservoirs commonly have high primary porosities of up to 35%, little macroquartz cement and variable amounts of diagenetic chlorite grain coats. This research sheds light on the complex controls on reservoir quality in the fluvial sandstones of the Skagerrak Formation by identifying the role of shallow overpressure in arresting mechanical compaction and the importance of chlorite detrital grain coatings in inhibiting macroquartz cement overgrowth as temperature increases during progressive burial.

Abstract: Late Ordovician ( c. 445 Ma) glacial sandstones form important gas reservoirs in the Illizi Basin, SW Algeria. These reservoirs have a high degree of depositional and diagenetic complexity, such that understanding and predicting reservoir quality (RQ) presents a major challenge to their economic development. Porosity is typically 1–10%, but reaches up to 15% and permeability is typically <10 −15 m 2 (<1 mD), but locally reaches >10 −13 m 2 (>100 mD). The key questions addressed herein concern the development and distribution of this RQ variability, specifically why has good RQ been locally preserved? Primary depositional fabric exerts a strong control on RQ. Muddy sandstones are either highly compacted or pervasively cemented by quartz and microporous illite, and have very poor RQ. Only fine- to medium-grained, moderately well sorted, clean sandstones can contain good RQ, but texturally and mineralogically similar sandstones span a wide range of porosity and permeability. This range is primarily driven by the degree of quartz cementation, with incomplete cementation resulting in the best RQ. Quartz overgrowths in incompletely cemented clean sandstones are patchy and non-luminescent in scanning electron microscopy with cathodoluminescence (SEM-CL), possibly indicating slow growth rates. There is tentative evidence to link incomplete quartz cementation with oil charging of the reservoir. An alternative or additional explanation of RQ preservation may be related to limited silica supply in the centres of the thickest, stacked, clean sandstones, where the better RQ tends to reside. The results of this study imply that sustained high-energy depositional processes, coupled with an early oil charge, are prerequisites for retaining the best RQ. This has important implications for the exploration and development of Late Ordovician glacial sandstones in the Illizi Basin, and potentially similar plays elsewhere.

Abstract: The properties of sandstones are strongly affected by formation of minerals in the pore space during diagenesis. In many sandstones, quartz overgrowths are the most important pore-filling cements and show a characteristic trace element composition. The most important impurities are Al, Li, H and Ge. The Al concentration of quartz may reach up to several 1000 µmol mol −1 and is assumed to reflect the composition of the porewater. Geochemical modelling of the activity ratio of Al and Si revealed a minimum at nearly neutral to slightly acid conditions. This minimum shifts to lower pH with increasing temperatures. Due to complexing, organic acids may strongly affect the Al solubility especially in acidic water at low temperatures. There is a linear correlation between Al and Li, indicating their incorporation in a combined [AlO 4 |Li] centre. Since Li only accounts for 10–30% of the Al concentration, the remaining Al needs to be balanced by H. The ratio of Li/H-compensated Al centres seems to depend on the Li activity and the pH in the aqueous solution. Germanium concentrations in quartz cements are slightly higher than the crustal average and they show a weak correlation with Al. The excess of Ge in authigenic quartz requires pre-enrichment, probably by formation of kaolinite. Possible applications of trace element analyses of authigenic quartz include discrimination of different sources that contribute to the supply of silica, enhanced understanding of inhomogeneities that are related to cementation and possible tracking of fluid migration.

Abstract: There is no consensus about the rate and style of clay mineral diagenesis in progressively buried sandstones v. interbedded mudstones. The diagenetic evolution of interbedded Miocene sandstones and mudstones from the Vienna Basin (Austria) has therefore been compared using core-based studies, petrography, X-ray diffraction and X-ray fluorescence. There was a common provenance for the coarse- and fine-grained sediments, and the primary depositional environment of the host sediment had no direct effect on illitization. The sandstones are mostly lithic arkoses dominated by framework grains of quartz, altered feldspars and carbonate rock fragments. Sandstone porosity has been reduced by quartz overgrowths and calcite cement; their pore-filling authigenic clay minerals consist of mixed-layer illite–smectite, illite, kaolinite and chlorite. In sandstones, smectite illitization progresses with depth; at 2150 m there is a transition from randomly interstratified to regular interstratified illite–smectite. The overall mineralogy of mudstones is surprisingly similar to the sandstones. However, for a given depth, feldspars are more altered to kaolinite, and smectite illitization is more advanced in sandstones than in mudstones. The higher permeability of sandstones allowed faster movement of material and pore fluid necessary for illitization and feldspar alteration than in mudstones. The significance of this work is that it has shown that open-system diagenesis is important for some clay mineral diagenetic reactions in sandstones, while closed-system diagenesis seems to operate for clay mineral diagenesis in mudstones.