Gas flow through shale

textThe growing demand for energy provides an incentive to pursue unconventional resources. Among these resources, tight gas and shale gas reservoirs have gained significant momentum because recent advances in technology allowed us to produce them at an economical rate. More importantly, they seem likely to contain a significant volume of hydrocarbon. There are, however, many questions concerning hydrocarbon production from these unconventional resources. For instance, in tight gas sandstone, we observe a significant variability in the producibilities of wells in the same field. The heterogeneity is even present in a single well with changes in depth. It is not clear what controls this heterogeneity. In shale gas, the pore connectivity inside the void space is not well explored and hence, a representative pore model is not available. Further, the effects of an adsorbed layer of gas and gas slippage on shale permeability are poorly understood. These effects play a crucial role in assigning a realistic permeability for shale in-situ from a laboratory measurement. In the laboratory, in contrast to in-situ, the core sample lacks the adsorbed layer because the permeability measurements are typically conducted at small pore pressures. Moreover, the gas slippages in laboratory and in-situ conditions are not identical. The present study seeks to investigate these discrepancies. Drainage and imbibition are sensitive to pore connectivity and unconventional gas transport is strongly affected by the connectivity. Hence, there is a strong interest in modeling mercury intrusion capillary pressure (MICP) test because it provides valuable information regarding the pore connectivity. In tight gas sandstone, the main objective of this research is to find a relationship between the estimated ultimate recovery (EUR) and the petrophysical properties measured by drainage/imbibition tests (mercury intrusion, withdrawal, and porous plate) and by resistivity analyses. As a measure of gas likely to be trapped in the matrix during production---and hence a proxy for EUR---we use the ratio of residual mercury saturation after mercury withdrawal (S[subscript gr]) to initial mercury saturation (S[subscript gi]), which is the saturation at the start of withdrawal. Crucially, a multiscale pore-level model is required to explain mercury intrusion capillary pressure measurements in these rocks. The multiscale model comprises a conventional network model and a tree-like pore structure (an acyclic network) that mimic the intergranular (macroporosity) and intragranular (microporosity) void spaces, respectively. Applying the multiscale model to porous plate data, we classify the pore spaces of rocks into macro-dominant, intermediate, and micro-dominant. These classes have progressively less drainage/imbibition hysteresis, which leads to the prediction that significantly more hydrocarbon is recoverable from microporosity than macroporosity. Available field data (production logs) corroborate the higher producibility of the microporosity. The recovery of hydrocarbon from micro-dominant pore structure is superior despite its inferior initial production (IP). Thus, a reservoir or a region in which the fraction of microporosity varies spatially may show only a weak correlation between IP and EUR. In shale gas, we analyze the pore structure of the matrix using mercury intrusion data to provide a more realistic model of pore connectivity. In the present study, we propose two pore models: dead-end pores and Nooks and Crannies. In the first model, the void space consists of many dead-end pores with circular pore throats. The second model supposes that the void space contains pore throats with large aspect ratios that are connected through the rock. We analyze both the scanning electron microscope (SEM) images of the shale and the effect of confining stress on the pore size distribution obtained from the mercury intrusion test to decide which pore model is representative of the in-situ condition. We conclude that the dead-end pores model is more representative. In addition, we study the effects of adsorbed layers of CH₄ and of gas slippage in pore walls on the flow behavior in individual conduits of simple geometry and in networks of such conduits. The network is based on the SEM image and drainage experiment in shale. To represent the effect of adsorbed gas, the effective size of each throat in the network depends on the pressure. The hydraulic conductance of each throat is determined based on the Knudsen number (Kn) criterion. The results indicate that laboratory measurements made with N₂ at ambient temperature and 5-MPa pressure, which is typical for the transient pulse decay method, overestimate the gas permeability in the early life of production by a factor of 4. This ratio increases if the measurement is run at ambient conditions because the low pressure enhances the slippage and reduces the thickness of the adsorbed layer. Moreover, the permeability increases nonlinearly as the in-situ pressure decreases during production. This effect contributes to mitigating the decline in production rates of shale gas wells. Laboratory data available in the literature for methane permeability at pressures below 7 MPa agree with model predictions of the effect of pressure.Petroleum and Geosystems Engineerin

Linking depositional environments and diagenetic processes to porosity evolution and destruction in the Arab Formation reservoirs, Offshore oilfields of Qatar

Introduction: The Jurassic Arab Formation is the main oil reservoir in Qatar. The Formation consists of a succession of limestone, dolomite, and anhydrite. Materials and Methods: A multi-proxy approach has been used to study the Formation. This approach is based on core analysis, thin sections, and log data in selected wells in Qatar. Results: The reservoir has been divided into a set of distinctive petrophysical units. The Arab Formation consists of cyclic sediments of oolitic grainstone/packstone, foraminifera-bearing packstone-wackestone, lagoonal mudstone and dolomite, alternating with anhydrite. The sediments underwent a series of diagenetic processes such as leaching, micritization, cementation, dolomitization and fracturing. The impact of these diagenetic processes on the different depositional fabrics created a complex porosity system. So, in some cases there are preserved depositional porosity such as the intergranular porosity in the oolitic grainstone, but in other cases, diagenetic cementation blocked the same pores and eventually destroyed them. In other cases, diagenesis improved the texture of non-porous depositional texture such as mudstone through incipient dolomitization creating inter-crystalline porosity. Dissolution created vugs and void secondary porosity in otherwise non-porous foraminiferal wackestone and packstone. Therefore, creating a matrix of depositional fabrics versus diagenetic processes enabled the identification of different situation in which porosity where either created or destroyed. Future Directions:By correlating the collected petrographic data with logs, it will become possible to identify certain "facio-diagenetic" signatures on logs which will be very useful in both exploration and production. Studying the micro and nano-porosity will provide a better understanding of the evolution and destruction of its porosity system

Lithologic Characterization and Micropore Structures of Gas Shale Strata: An example from the Midra Shale of Western Qatar

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

Fluid-rock interactions in tight gas reservoirs: Wettability, pore structural alteration, and associated multiphysics transport

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.Scopu