Abstract The coupled analysis of multi-field heat and mass transfer in geothermal reservoirs is a pivotal concern within the realm of geothermal rock exploitation. It holds significant implications for the assessment of thermal energy capacity and the formulation of reservoir optimization strategies in the context of geothermal rock resources. Parameters governing production, along with fracture network characteristics (such as injection well temperature, injection well pressure, fracture width, and fracture network density), exert an influence on enhanced geothermal systems (EGS) heat production. In this study, aiming to comprehend the dynamic heat generation of EGS during prolonged exploitation, a coupling of various fields including permeation within the rock formations of geothermal reservoirs and the deformation of these rocks was achieved. In this study, we formulated the governing equations for the temperature field, stress field, and permeability field within the geothermal reservoir rock. Subsequently, we conducted numerical simulations to investigate the heat transfer process in an enhanced geothermal system. We analyzed the effects of injection well temperature, injection well pressure, primary fracture width, and secondary fracture density on the temperature distribution within the reservoir and the thermal power output of the production well. The research findings underscore that ill-conceived exploitation schemes markedly accelerate the thermal breakthrough rate of production wells, resulting in a diminished rate of geothermal resource extraction from the geothermal reservoir rock. Variations in influent well temperature and secondary fracture density exhibit an approximately linear impact on the output from production wells. Crucially, injection well pressure and primary fracture width emerge as pivotal factors influencing reservoir output response, with excessive widening of primary fractures leading to premature thermal breakthrough in production wells.
Abstract In recent years, there has been significant progress in shale oil exploration in the first member of the Qingshankou Formation (K 2 qn 1 ) in the Qijia‐Gulong Sag, Songliao Basin, Northeast China: It shows good prospects for shale oil. However, the recognized lack of the geochemical and hydrocarbon generation and expulsion characteristics of K 2 qn 1 source rocks limits an accurate evaluation of shale oil resource. This study systematically investigated the geological and geochemical characteristics, hydrocarbon generation and expulsion, and shale oil potential of the K 2 qn 1 source rocks. The results show that the K 2 qn 1 mudstones were mainly deposited in the semideep and deep lacustrine facies under reducing and weak reducing conditions. Compared with the southern Gulong Sag, the northern Qijia Sag has a higher salinity, more abundant prosperous aquatic organisms, and a greater paleoproductivity. The K 2 qn 1 source rocks are pervasive and continuous in the entire sag, with maximum thicknesses greater than 110 m. They have a higher organic matter (OM) abundance (2.40% of the average TOC), are dominated by type I and II 1 kerogen, and are mature (0.8%‐0.1.3% VR ), which indicate that they are good to excellent source rocks and have significant hydrocarbon generation potential. The source rocks in the Qijia Sag have a higher OM abundance, a better OM type, and a lower OM maturity than those in the Gulong Sag. The threshold and peak hydrocarbon expulsion values for marlstone source rocks are 0.85% VR and 0.95% VR , respectively. The volumes of hydrocarbons generated and expulsed from the K 2 qn 1 source rocks are 121.8 × 10 8 t and 46.9 × 10 8 t, respectively, with a retention efficiency of 61.5%. The in‐place and recoverable resources of shale oil are 74.9 × 10 8 t and (12.0‐13.5) × 10 8 t, respectively, indicating that the entire sag has a significant shale oil potential, especially the Qijia Sag.
Heterogeneous wettability is characterized by a spotted-wet or mixed-wet state. It has a great influence on reservoir evaluation and the efficient development of shale gas reservoirs. In this study, reservoir properties of several core plugs from the Permian Shanxi–Taiyuan formations were studied. These formations are typical marine-continental transitional shale located in the Southern North China Basin. To investigate the effects of reservoir properties on heterogeneous wettability, we measured the water–air contact angle and compared it with other properties such as organic petrology, organic geochemistry, mineralogy, and microstructure features, including pore-fractures and surface roughness. The results reveal a negative correlation of vitrinite content with contact angle, in addition to the high clay content and residual polar groups within type III kerogen, indicating that the Shanxi–Taiyuan shales with a high maturity level still have a higher affinity to water. The contact angle of the core samples decreases with increasing surface roughness, partially due to the influence of pore-fracture development. The crossplots indicate that the majority of pore-fractures that exist in the shale preferentially tend to be water-wet. Therefore, the heterogeneous wettability of shale is dominated by the random mixture and arrangement of hydrophilic and hydrophobic components as well as the complexity of the microstructure, such as the rough pore wall. Furthermore, on the basis of improving and examining the Cassie model, a triangle method and a detailed workflow for evaluating the heterogeneous wettability of shale are proposed by comprehensively analyzing "three factors", including pore structure, mineral components, and organic matter. The test results demonstrate that the Shanxi–Taiyuan shales are mainly water-wet (controlled by organic factor) and neutral-wet, which evidently differ from the marine Longmaxi shale with a wide distribution covering the zones of strongly water-wet, weakly water-wet (controlled by pore factor), and weakly water-wet (neutral-wet). The proposed approach can be applied to promptly and comprehensively evaluate and predict the heterogeneous wettability of shales during shale oil and gas exploration.
The gas shale in the Lower Silurian Longmaxi Formation contains a considerable amount of biogenic silica. Various originated silicas in shale, derived from different depositional environment, are commonly associated with different degrees of organic matter enrichment, resulting in different mechanical and physical properties of shale reservoirs. Thin section identification, scanning electron microscopy (SEM), energy dispersive spectroscopy (EDS), total organic carbon (TOC) analysis, X-ray diffraction (XRD) analysis, and X-ray fluorescence (XRF) spectroscopy were used to investigate the Lower Silurian Longmaxi shale from Well Yuye 1 in southeastern Chongqing, China to obtain a better understanding of the origin of silica in the Longmaxi Shale. The results show ubiquitous cryptocrystalline silicas with poorly crystalline morphology, which differs from that of the detrital silica, authigenic silica, and hydrothermal silica, proving that the cryptocrystalline silicas may have a biogenic origin. Major element and mineral composition analysis indicate no correlations between K2O/Al2O3 and SiO2/Al2O3 and between illite and SiO2, and negative correlations between TiO2 and SiO2/Al2O3, between illite and quartz and excess Si, and between Al2O3 and excess Si, and all samples being located in the area of non-hydrothermal origin in the Al-Fe-Mn diagram, excluding silicas of terrigenous detrital origin, clay mineral transformed origin, and hydrothermal origin. Moreover, the fact that almost all samples plot above the illite Si/Al line in the cross-plot of Si versus Al and the mean values of Al/(Al + Fe + Mn) and Si/(Si + Al + Fe + Ca) are close to the values of biogenic silica prove that the silicas are primarily of biogenic origin. Positive correlations between TOC and quartz and excess Si and numerous siliceous organisms are observed, indicating that the silicas are associated with siliceous organisms. The postmortem siliceous organisms underwent silica diagenesis via a dissolution-precipitation mechanism following the sequence of opal-A → opal-CT → cryptocrystalline biogenic silica as the burial depth and temperature increased.
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