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Core samples were collected from three wells, one onshore and two offshore, from Qatar’s Upper Jurassic Arab D reservoir. The samples were subjected to multiproxy petrographic and chemical analyses to identify their micro- and nanoporosity types and understand their evolution and destruction. Based on the petrographic and petrophysical properties of studied rocks, the Arab D succession was divided into seven rock types. Primary microporosity includes intergranular and interplanar, while secondary types include vuggy, intercrystalline, moldic, dissolution, pyrite displacement, microfracture, and microbial boring. Primary micropores were found mainly between the micrite grains in the lime mudstone facies, between the grains or the plates of clay minerals. Secondary micropores result from open and closed diagenetic systems. The open diagenetic system led to the development of dissolution and moldic micropores, while the closed system created pyrite displacement and boring porosity. Mechanical stress due to crystal growth or displacement generated microfractures. Micropores were destroyed either by cementation, clay minerals growth, dolomitization, or microbial pustular overgrowth. Microporosity was important in quantity and varied in nature in the mud-supported rocks. They are similar to macropores in grain-supported sediments but of less importance. The complex lithology of the studied rocks has significantly influenced the development and destruction of the porosity system of the Arab Formation.

Tight and unconventional reservoirs such as shales are rich in clay minerals that give rise to several fluid-rock interactions. The effect of such fluid-rock interactions is manifested at multiscales. The fluid-rock interactions induce changes in various physical responses of the rock, which is termed as multiphysics. An underlying property that influences the multiphysics process is wettability which has remained a conundrum for shale researchers. This chapter provides a detailed perspective on shale wettability in the context of fluid-rock interactions. Pore structural alteration induced by fluid-rock interactions is also discussed specifically from the standpoint of recent advances using digital techniques. The chapter also presents recent developments in explaining the role of pore sizes in causing configurational diffusion of water and oil in shales. Lastly, multiphysics constitutive modeling to predict shale rock responses is discussed. Specifically, new developments regarding the incorporation of sorptive fluid-rock interaction in constitutive models are presented. 2023 Elsevier B.V. The authors would like to acknowledge the support of the Qatar National Research Fund (a member of the Qatar Foundation) through Grant # NPRP12S-0305-190235 and NPRP11S-1228-170138. The authors, particularly M.A.Q.S, H.R., and K.R., also acknowledge the support of the Australian Research Council (ARC) through the Discovery Project Grant (DP200102517). The findings achieved herein are solely the responsibility of the authors. Scopus

SummaryShale, which has pores as small as 10 nm, is economically viable for hydrocarbon recovery when it is fractured. Although the fracture toughness dictates the required energy for the improvement, the existing techniques are not suitable for characterization at scales smaller than 1 cm. Developing practical methods for characterization is crucial because fractures can contribute to an accessible pore volume at different scales. This study proposes a conceptual model to characterize the anisotropic fracture toughness of shale using nanoindentations on a sub-1-cm scale. The conceptual model reveals the complexities of characterizing shales and explains why induced fractures differ from those observed in more-homogeneous media, such as fused silica. Samples from the Wolfcamp Formation were tested using Berkovich and cube-corner tips, and the interpreted fracture toughness values are promising. The conceptual model is the first application of the effective-medium theory for fracture toughness characterization using nanoindentation. In addition, it can quantify fracture toughness variations when using small samples, such as drill cuttings.

Capillary pressure plays an essential role in controlling multiphase flow in porous media and is often difficult to be estimated at subsurface conditions. The Leverett capillary pressure function J provides a convenient tool to address this shortcoming; however, its performance remains poor where there is a large scatter in the scaled data. Our aim, therefore, was to reduce the gaps between J curves and to develop a method that allows accurate scaling of capillary pressure. We developed two mathematical expressions based on permeability and porosity values of 214 rock samples taken from North America and the Middle East. Using the values as grouping features, we used pattern-recognition algorithms in machine learning to cluster the original data into different groups. In each wetting phase saturation, we were able to quantify the gaps between the J curves by determining the ratio of the maximum J to the minimum J. Graphical maps were developed to identify the corresponding group for a new rock sample after which the capillary pressure is estimated using the average J curve of the identified group and the permeability and porosity values of the rock sample. This method also provides better performance than the flow zone indicator (FZI) approach. The proposed technique was validated on six rock types and has successfully generated average capillary pressure curves that capture the trends and values of the experimentally measured data by mercury injection. Moreover, the proposed methodology in this study provides an advanced and a machine-learning-oriented approach for rock typing. In this paper, we provide a reliable and easy-to-use method for capillary pressure estimation in the absence of experimentally measured data by mercury injection. Copyright 2022 Society of Petroleum Engineers We would like to acknowledge the support of Qatar National Research Fund (a member of Qatar Foundation) through Grant # NPRP11S-1228-170138. The findings achieved herein are solely the responsibility of the authors. Scopus

The transport properties of gas deviate from the nominal values, reported without confinements, when it is confined inside a nano-size conduit. This is because the interactions between the gas molecules and the conduit become more important than do those of the gas molecules with each other. The deviation is relevant to shale gas because of the ultra-narrow pore size in the matrix. With this in mind, we determine the critical temperature (Tc) and critical pressure (Pc) for shale formations in North America at the core scale. The shale formations are the Bakken, Barnett, Eagle Ford, Haynesville, Marcellus, Monterey, New Albany, Niobrara, Utica, Wolfcamp, and Woodford. The present study uses the acyclic pore model to account for the effective connectivity of shale samples at the core scale. It also differentiates between the pore-throat and pore-body size distributions. The former is used to derive the critical properties relevant to the fluid flow (displacement), and the latter is used to determine the effective properties relevant to the storage. Our study shows that the displacement-critical properties change significantly, whereas the storage-critical properties do not require modifications. Quantitative corrections of the critical properties for various formations are presented. The results have major applications in developing a realistic reservoir model for shale formations.

Gas shale is the future hydrocarbon reservoir of Qatar. The Qatari geologic section has had important successions of gas shale at different geologic times including the Eocene Midra shale, the Cretaceous Ratawi and Nahr Umr, and the Paleozoic Qusaibah and Unayzah formations. Shale samples were collected from the outcrops of the Midra Shale in Dukhan and Umm Bab areas. Samples were subjected to geochemical analyses using XRD and RXF. Selected samples were examined under SEM and TEM microscopes. All the studied samples contain palygorskite as the main mineral and, in some cases, the only mineral present, as indicated by X-ray diffraction patterns. XRF analysis shows palygorskite range from ideal palygorskite (equal aluminum and magnesium content) to aluminous palygorskite where no magnesium is recorded. The most common other minor minerals are halite, quartz, calcite, and other clay minerals: illite, smectite and sepiolite. The palygorskite chain phyllo silicates results in a fibrous habit with channels running parallel to the fiber length. Images from Transmission Electron Microscopy (TEM) clearly show the presence of bundled lath-like crystals of palygorskite 5 to 20 nm in width and several micrometers in length. The Midra Shale was deposited in a shallow marine shelf that was subjected to clastic influx from the nearby land. Although, the Midra contains many elements that support deposition under marine conditions such as large foraminifera and shark teeth, the presence of fully developed shale horizons indicate a mixed marine-continental depositional setting. Most of the micropores are channels associated with the palygorskite laths as can be seen from the TEM images or some dissolution pores that resulted from halite and gypsum dissolution by meteoric water.

The geometrical properties of the reservoir rocks are usually affected by natural thermodynamics or environmental changes. These factors may modify the distribution and the amount of gas in place in the reservoir. To address these properties, we conduct density functional theory calculations to study the effect of strain on the adsorption of natural gas components, such as CH4, CO2, C2H6, and N2 in tight-gas carbonate reservoirs, which are represented by calcite (104). The simulation results show that, regardless of the strain value (-3% to 3%), all considered gas species are physiosorbed on the surface of a carbonate reservoir with the largest the adsorption energy, (Eads) for CO2 molecules. In addition to their weak interaction with the surface, CH4 molecules show no particular trend in terms of adsorption for the considered values of the applied strain. The effect of strain becomes more pronounced in the case of CO2 and C2H6 molecules. For example, depending on the concentration of the molecules, the Eads per molecule can be increased by more than 25% by applying tensile strain. These findings can be useful for determining the estimated ultimate recovery in carbonaceous tight gas reservoirs by quantifying the geomechanical effects on the adsorbed gas. The authors would like to acknowledge the support of the Qatar National Research Fund (a member of the Qatar Foundation) through Grant # NPRP11S-1228-170138. The findings achieved herein are solely the responsibility of the authors. Also, the authors would like to gratefully acknowledge the computational resources provided by Texas A&M University in Qatar. Scopus