Properties Of Shale Research Articles

超临界CO<sub>2</sub>渗流的流-固-热多场耦合机理研究

<p indent="0mm">Clay swelling and dispersion easily occur when encountering water for shale formation, resulting in problems related to wellbore collapse when using water-based fluids, such as drilling fluid or poor fracturing stimulation when using water-based fluids as the fracturing fluid. Supercritical carbon dioxide (ScCO₂) can effectively protect the clay from hydration and avoid formation damage. Based on this, basic research studies have been performed by researchers regarding the exploitation of shale oil and gas resources using ScCO₂. The multi-physics coupling model describing the water seepage process cannot explain the ScCO₂ seepage because of a great variation in the physical properties of CO₂ with temperature and pressure. To construct multi-physics coupling models capable of reflecting the ScCO₂ seepage process when developing oil and gas resources using ScCO₂, the thermal-hydro-mechanical coupling models are established in this study based on the transport and thermodynamic properties of ScCO₂, combined with the law of effect of ScCO₂ dissolution on the mechanical properties of shale. The finite element method is used to study the distribution of formation temperature, pore pressure, and stress with time and location of ScCO₂ seepage, and the comparison of multi-physics fields is performed between ScCO₂ and water seepage. The results indicate that the compared with water seepage, the formation temperature variation of ScCO₂ seepage is greater, the pore pressure is lower, the stress difference near the wellbore in the direction of minimum <italic>in</italic>-<italic>situ</italic> stress is bigger, and the tangential stress in the direction of maximum <italic>in</italic>-<italic>situ</italic> stress is lower. This study can provide theoretical basis for wellbore stability analysis when using ScCO₂ as the drilling fluid and fracturing design and evaluation when using ScCO₂ as the fracturing fluid.

Research on the differential tectonic-thermal evolution of Longmaxi shale in the southern Sichuan Basin

The southern Sichuan Basin in China holds abundant shale gas resources; however, the shale gas bearing property shows great differences due to the multiple stages of tectonic transformation. The key to revealing the shale gas differential enrichment mechanism is to explore the thermal evolution characteristics during tectonic evolution. Therefore, taking the Luzhou and Changning blocks as an example, which have obvious differences in tectonic evolution, the organic geochemical conditions of Longmaxi shale were firstly compared with the test data. Then, the thermal evolution characteristics under the background differential tectonic uplift-erosion were recovered using basin modeling techniques. The results showed that the two blocks contain similar organic geochemical conditions of the Longmaxi shale. Moreover, the hydrocarbon generation condition in Luzhou Block is greater than that in the Changning Block. Influenced by the differential tectonic evolution, the study area experienced a complex burial history and the formation of multiple unconformities. As a result, the present burial depth of Longmaxi Formation in the Luzhou Block is significantly greater than that in the Changning Block. The thermal evolution history of Longmaxi shale in the study area could be divided into three stages, including a low-temperature stage from Caledonian to Hercynian, a middle-temperature stage from Hercynian to Indosinian, and a high-temperature stage from Yanshanian to Himalayan. In addition, it was found that the Himalayan period is the main stage resulting in the differential gas bearing property of Longmaxi shale in the southern Sichuan area. Under the differential structural modification, the peak time of hydrocarbon generation in the Luzhou Block occurred earlier and the conversion rate was slightly higher than that in the Changning Block. Cited as: Zhao, L., Mao, W., Liu, Z., Cheng, S. Research on the differential tectonic-thermal evolution of Longmaxi shale in the southern Sichuan Basin. Advances in Geo-Energy Research, 2023, 7(3): 152-163. https://doi.org/10.46690/ager.2023.03.02

Shale damage simulation considering shale swelling during shale-liquid interaction

Shale-liquid interactions can lead to shale swelling, shale damage and affect the mechanical and other properties of shale. The relationship between shale swelling and shale damage was not well understood. A better understanding of the relationship is essential for drilling and fracturing designs. In this work, we employ shale swelling tests, computed tomography scanning technology and numerical simulation to understand the relationship between shale swelling and shale damage. The experimental results show that the shale swelling is 0.23% after the experiment. When the shale swelling is small, the damage is weak. However, the shale damage growth rate is 495.05% when the shale swelling rate increases by 0.19%, and macrofractures are formed. Using COMSOL with MATLAB, we further explore the relationship between shale damage and shale swelling. The simulation results show that shale swelling has an important effect on shale damage, and this effect is verified by comparing the simulation and experimental results. Shale damage is weak or even absent when shale swelling is not considered, while the distinct shale damage can be observed when shale swelling is considered. The increase of shale swelling leads to the increase in shale damage, which leads to more obvious fractures expansion, resulting in an increase in permeability. When shale swelling is 0.4%, the permeability at the end of the simulation is 322% higher than the initial permeability. The variation in stress at 0.4% shale swelling is 21 times that without considering shale swelling, and the large variations in stress are an important factor in shale damage. The higher the in-situ stress, the lesser is the tendency for shale damage to occur. Shale damage occurs at high injection pressures, even when shale swelling is low. In addition, the more complex the fracture network, the higher is the tendency for shale damage to occur, and the permeability after the simulation was 6% higher than that of bedding model. Therefore, fracturing methods with high injection pressures should be used, and the hydraulic fracturing should be conducted at locations where natural fractures develop to achieve significant shale-liquid interactions and better hydraulic fracturing results.

Statistical Analysis of Controlling Factors on Enhanced Gas Recovery by CO2 Injection in Shale Gas Reservoirs

Development of shale gas reservoirs is the fastest growing area on a large scale globally due to their potential reserves. CO2 has a great affinity to be adsorbed on shale organic surface over CH4. Therefore, CO2 injection into shale reservoirs initiates a potential for enhanced gas recovery and CO2 geological sequestration. The efficiency of CO2 enhanced gas recovery (CO2-EGR) is mainly dominated by several shale properties and engineering design parameters. However, due to the heterogeneity of shale reservoirs and the complexity of modeling the CO2–CH4 displacement process, there are still uncertainties in determining the main factors that control CO2 sequestration and enhanced CH4 recovery in shale reservoirs. Therefore, in view of the previous sensitivity analysis studies, no quantitative framework, accurate CO2-EGR modeling, or design process has been identified. Thus, this work aimed to provide a practical screening tool to manage and predict the efficiency of enhanced gas recovery and CO2 sequestration in shale reservoirs. To meet our objectives, we performed correlation analysis to identify the strength of the relationship between the examined shale properties and engineering design parameters and the efficiency of CO2-EGR. Data for this study was gathered across publications on a wide subset of numerical modeling studies and experimental investigations. The sensitivity of data was further improved by a hybrid approach adopted for handling the missing values to avoid bias in our data set. Our results indicate that CO2 flooding might be the best applicable option for CO2 injection in shale reservoirs, whereas the huff-and-puff scenario does not seem to be a viable option. The efficiency of CO2-EGR increases as the pressure difference between injection pressure and reservoir pressure increases. The results show that shallow shale reservoirs with high fracture permeability, total organic content, and CO2–CH4 preferential adsorption capacity are favorable targets for CO2-EGR. Moreover, our results indicate that a successful hydraulic-fracture network with effective values of fracture permeability and conductivity is essential for a higher CO2-EGR efficiency. Well spacing and fracture half-length are crucial engineering features in CO2-EGR process design that must be carefully optimized due to their negative effect on CH4 production and positive effect on CO2 storage. Our statistical analysis lays a foundation for efficient CO2-EGR design and implementation and presents an important contribution to the field of reaching the target of net-zero CO2 emissions for energy transitions.

Review of the adsorption equilibria of CO2, CH4, and their mixture on coals and shales at high pressures for enhanced CH4 recovery and CO2 sequestration

Producing CH 4 from coal beds and shale reservoirs is an attractive unconventional energy option. Injecting CO 2 into a coal or shale basin can extract more CH 4 and enable the permanent sequestration of CO 2 , and this is called CO 2 -enhanced coal bed methane (CO 2 -ECBM) or CO 2 -enhanced shale gas recovery (CO 2 -ESGR), respectively. Since the injection of captured CO 2 into geological formations (geological CO 2 sequestration, GCS) is considered a feasible strategy for CO 2 sequestration, CO 2 -ECBM and CO 2 -ESGR have received great attention for the mitigation of global warming as well as energy recovery. Coals and shales, which are porous solids mainly containing carbons with silica-based materials, can adsorb a large amount of CO 2 and CH 4 depending on their pore structures/geochemical properties. Therefore, to design and practice CO 2 -ECBM and CO 2 -ESGR, it is important to understand the adsorption of CO 2 and CH 4 on coals and shales. A large number of laboratory experiments have been conducted to estimate the adsorption capacity of CO 2 and CH 4 with the structural characterization of coals and shales. However, the heterogeneous properties of coals and shales make it difficult to develop a prediction model for various types of coals and shales. This study reviews the present state of the adsorption of CO 2 , CH 4 , and their mixture on coals and shales and suggests a future research direction. The experimental results of adsorption on coals and shales from the literature are introduced, and the properties of coals and shales are discussed to understand their influence on adsorption. Then, thermodynamic models of the adsorption are analyzed to elucidate the correlation between the thermodynamic parameters and structural properties of coals and shales. Applications of machine learning (ML) models, which have received significant attention recently, to the prediction of CO 2 /CH 4 adsorption on coals and shales are also reviewed. Finally, the combination of the thermodynamic model and the ML model, known as a hybrid model, is discussed to develop a universal prediction model for CO 2 /CH 4 adsorption on various types of coals and shales.

NANOINDENTATION EXPERIMENTS TO STUDY THE MICROMECHANICAL PROPERTIES OF STRATIFIED SHALE

The micromechanical properties of stratified shale are critical for understanding wellbore stability and hydraulic fracture extension patterns. Based on nanoindentation experiments and data analysis, the mechanical parameters of shale specimens from two laminar directions of the Jimsar Lucaogou Formation in Xinjiang are measured from a microscopic perspective in this paper. The mechanical parameters of multiple indentation points are obtained using grid indentation. The mineral composition of the samples is quantified using field emission scanning electron microscopy (SEM) and XRD ray diffraction. The results show that the shale mechanical parameters have a good linear relationship with each other at the nanoscale. However, the relationship between horizontal bedding and vertical bedding is quite different. The average elastic modulus, average hardness, and average fracture toughness of the parallel laminated specimens are 22.94 GPa, 1.04 GPa, and 1.19 MPa&amp;#183;m&lt;sup&gt;1/2&lt;/sup&gt;, respectively. The average elastic modulus, average hardness, and average fracture toughness of the vertical laminated specimens are 35.23 GPa, 3.47 GPa, and 1.32 MPa&amp;#183;m&lt;sup&gt;1/2&lt;/sup&gt;, respectively. The shale mechanical parameters in the vertical bedding direction are higher than those in the horizontal laminae. The mechanical parameters at the nanoscale are related to the orientation of the laminae. The shale is anisotropic at the nanoscale and the anisotropy of different mechanical parameters behaves differently. The microscopic elastic modulus, hardness, and fracture toughness of shale conform to Weibull distribution. The dispersion of hardness is the highest. The results can help analyze the relationship between shale mechanical properties and laminar orientation.

Experimental study on the thermophysical properties of Jimsar oil shale

Experimental study on the thermophysical properties of Jimsar oil shale

Triaxial high temperature mechanical properties of Longmaxi shale at different depths

Based on the high temperature and confining pressure conditions at different depths, triaxial high temperature mechanical tests were carried out on Longmaxi shale with horizontal and vertical bedding, respectively. The results show that shale?s peak strength and deformation capacity increase with burial depth. The failure mode of shale is a typical brittle failure, and the brittle index can quantitatively describe the brittle mechanical behavior of shale. Because shale has an apparent thin bedding structure, shale with different bedding directions shows pro?nounced anisotropy in mechanical parameters and deformation characteristics. The burial depth and bedding direction significantly impact the energy evolution law of Longmaxi shale during the mechanical process.

Investigation of deformation characteristics impact of water-saturated rocks on the ecology of the coal-mining region

The purpose of the research is to evaluate the deformation properties of water-saturated clay shale to determine the displacements of the earth's surface. The analysis of the impact of mining on the environmental situation of town Shakhty in Rostov region was done. It is noted that the closure of coal mines and pumping termination of underground water led to flooding of the developed spaces of mining enterprises. This led to a change in the mechanical characteristics of clay rocks, their softening and compaction under the influence of rock pressure. Taking into account the significant capacity of clay shale in the structure of the rock mass and the technology of mining coal seams, there are currently surface deformations and the formation of cracks in the structures of buildings. According to the results of experimental studies, the deformation characteristics of clay shale under prolonged moistening have been established, affecting the precipitation of the foundations of buildings and, accordingly, lead to the formation of defects in buildings and structures. The obtained characteristics of fragmented clay shale can be used for modeling the stress-strain state of a rock mass and the development of deformations on the earth's surface by the finite element method.

Micro X-ray fluorescence reveals pore space details and spatially-resolved porosity of rock-based microfluidic devices.

Characterization of microscopic details of the fabric of mudstones and shales (i.e., structure and composition) is important to understand their storage and transport properties. Current characterization methods struggle to probe reliably multiple scales of interest (e.g., pore and fracture) and measure properties at the finest resolution under representative in situ conditions. Micro X-ray fluorescence (μXRF) is a high-performance imaging technique that produces elemental images at sub-10 μm spatial resolution and could offer insight into a diversity of shale properties, such as mineral composition, porosity, and in situ pressure gradients. This study designed and carried out a porosity mapping protocol using model and real-rock microfluidic devices and contrast fluids. Etched silicon micromodels with real-rock pore network patterns served as ideal models to establish a proof of concept. Measurements were performed on a novel μXRF microscope not powered by synchrotron radiation. We registered the μXRF datasets with the binary rock masks used for micromodel fabrication and applied segmentation algorithms to compare porosities. We assessed expected advantages and limitations through a sensitivity analysis and beam study. μXRF is an important new imaging technique for microfluidic applications.

Direct hydrocarbon identification in shale oil reservoirs using fluid dispersion attribute based on an extended frequency-dependent seismic inversion scheme

The identification of hydrocarbons using seismic methods is critical in the prediction of shale oil reservoirs. However, delineating shales of high oil saturation is challenging owing to the similarity in the elastic properties of oil- and water-bearing shales. The complexity of the organic matter properties associated with kerogen and hydrocarbon further complicates the characterization of shale oil reservoirs using seismic methods. Nevertheless, the inelastic shale properties associated with oil saturation can enable the utilization of velocity dispersion for hydrocarbon identification in shales. In this study, a seismic inversion scheme based on the fluid dispersion attribute was proposed for the estimation of hydrocarbon enrichment. In the proposed approach, the conventional frequency-dependent inversion scheme was extended by incorporating the PP-wave reflection coefficient presented in terms of the effective fluid bulk modulus. A rock physics model for shale oil reservoirs was constructed to describe the relationship between hydrocarbon saturation and shale inelasticity. According to the modeling results, the hydrocarbon sensitivity of the frequency-dependent effective fluid bulk modulus is superior to the traditional compressional wave velocity dispersion of shales. Quantitative analysis of the inversion results based on synthetics also reveals that the proposed approach identifies the oil saturation and related hydrocarbon enrichment better than the above-mentioned conventional approach. Meanwhile, in real data applications, actual drilling results validate the superiority of the proposed fluid dispersion attribute as a useful hydrocarbon indicator in shale oil reservoirs.

Effects of Supercritical CO2 Injection on the Shale Pore Structures and Mass Transport Rates

Characterizing the pore structures and transport properties of low-permeability shales is critical for evaluating these formations as potential seals or storage sites for geological CO2 sequestration. Here, we use low-pressure gas adsorption in conjunction with nuclear magnetic resonance (NMR) to characterize the pore-size distribution of shales before and after injection of supercritical CO2. Nitrogen gas was used as the detecting phase for the adsorption experiments and pentane liquid was used for the NMR experiments. We also performed time-resolved NMR and gravimetric microbalance measurements to observe mass transport during desaturation. We use these data to estimate the self-diffusion coefficient of pentane and changes in the saturation state of the pore network. We analyzed samples with a range of compositions from the Wolfcamp shale before and after exposure to supercritical CO2 for 3 days. Integrating the gas adsorption and NMR data shows how supercritical CO2 injection alters the pore-size distribution for pore sizes <1 nm to 1 mm. Our results provide insights on how the pore structure and mass transport properties of different shale lithologies may evolve during storage of supercritical CO2.

Direct Inversion Method of Brittleness Parameters Based on Reweighted Lp-Norm

Brittleness is an important factor that indicates shale properties, as well as fracturability, and it can be well-represented using the elasticity parameter Eρ. Seismic inversion allows direct access to the Eρ ofbrittleness parameters. Seismic inversion is a typical ill-posed problem that has an enormous multiplicity of solutions. In order to invert reservoir brittleness parameters more stably and reliably, a direct inversion method for determining brittleness parameters based on a reweighted Lp-norm is proposed, and the reweighted Lp method is introduced to brittleness parameter inversion for the first time. The alternating direction method of multipliers (ADMM) is used to establish the inversion structure and to optimize the objective function in blocks, which effectively improves the convergence speed. We first introduce a reweighted Lp method and establish a pre-stack inversion objective function based on the reweighted Lp method. Then, theoretical simulation data are applied to compare the inversion outcomes of the new method with those of the traditional method, and the effect of the method in this manuscript is verified. Finally, the feasibility of this method is further verified using actual data for experimental analysis. Through an analysis of the experimental results, we find that this method can be well-applied to seismic pre-stack inversion calculation and provides a new direct inversion method for the determination of brittleness parameters for exploration geophysics.

Sedimentary paleoenvironment and organic matter accumulation model of the Lower Silurian Gaojiabian Formation shales in the Lower Yangtze region, South China

A set of organic-rich shales developed in the lower part of the Lower Silurian Gaojiabian Formation in the Lower Yangtze region, South China. The paleoenvironment and the organic matter (OM) accumulation mechanism in the Lower Yangtze region are rarely studied, restricting the in-depth understanding of the shale gas exploration prospects of this region. This study described the petrological, mineralogical characteristics and geochemical properties of the organic-rich shales of the Gaojiabian Formation in the Lower Yangtze region (Well TD2) using multidisciplinary approaches. The purpose is to study the palaeoenvironment evolution of organic rich shales, and reveal the controlling factors and accumulation mechanism of OM. Two shale sections with high TOC content developing in the lower part of the Gaojiabian Formation were identified through petrological observations and geochemical analysis, namely the lower shale section (LSS) and the upper shale section (USS) with TOC content of 0.79–4.62% and 0.65–2.92%, respectively. The two organic-rich shale sections were formed in a suboxic-anoxic environment. The Cd/Mo, Co × Mn, Mo/TOC values show that the USS and the LSS were formed in a strongly restricted water environment and were not affected by upwelling, and the environment of the USS was more restricted than that of the LSS. The paleoproductivity proxies indicate the two sections have a high-productivity background, and that the LSS has a higher paleoproductivity level than the USS. The terrigenous input shows a long-term growth trend. Compared with the LSS, the USS had more terrigenous input and was closer to the source area. The chemical index of alteration (CIA) indicates that the shale was formed in a warm and humid climate. The index of compositional variability (ICV) shows that the USS has a more mature composition than the LSS and was likely dominated by recycling. The relationships between TOC content and several geochemical proxies indicate that the OM accumulation was mainly controlled by redox condition, paleoproductivity and terrigenous input, whereas these three factors are determined by the combined impact of the sea level and regional tectonic movement. On this basis, this study reconstructed the paleoenvironment and the OM accumulation model. The OM accumulation of the LSS was mainly controlled by relatively high regional sea level affected by global transgression, the anoxic-suboxic water environment, the high paleoproductivity, and a small quantity of terrigenous input, while the OM accumulation of the USS was primarily controlled by the suboxic condition affected by decreased relative sea level resulting from the strengthened regional tectonic movement, the relatively weakened paleoproductivity, and the increased recycled terrigenous input. The above understanding provides important enlightenment for deepening the study of OM enrichment and shale gas exploration direction of the Gaojiabian Formation in the Lower Yangtze region.

Comprehensive characterization of petrophysical properties in shale by solvent extraction experiments and 2D NMR

Shale oil is one of the important unconventional fossil fuels resources. Understanding the petrophysical properties of shale contributes to the exploration and clean production of shale oil resources. 1H nuclear magnetic resonance (NMR) is a potential technique that can provide for shale petrophysical properties. However, current NMR-based technique for shale petrophysical characterization, due to the complexity of shale, usually requires some auxiliary geochemical experiments. Since a multi-step solvent extraction (MSSE) experiment has a merit in separating hydrocarbons and water in shale, in this work, two-dimensional (2D) NMR measurements combined with MSSE experiments were proposed for the first time to study the petrophysical properties of shale. A mixture of dichloromethane and methanol in a ration of 9:1 was prepared as a solvent for the extraction. Sufficient natural air-drying time allows for the removal of dichloromethane while retaining methanol. The comprehensive experiments show that the signal change induced by residual methanol from T1/T2-T2 map, before and after extraction and natural air-drying, can be used to identify pore-fluid and evaluate the mobility of hydrocarbon. For insight into the essence of experimental phenomena, quasi-1D/2D translational diffusion model were employed to analyze the T1/T2 and T2 responses of pore fluids. Wettability characteristics and detailed hydrocarbon mobility of shale were obtained from the theoretical analyses based on the translational diffusion models and T1/T2-T2 map. Combined the experimental results with the theoretical analysis, a comprehensive interpretation scheme was established for shale based on the T1/T2-T2 map, including fluid identification, wettability evaluation, and hydrocarbon mobility characterization.

Study on rock mechanics characteristics of deep shale in Luzhou block and the influence on reservoir fracturing

AbstractThis paper aims to study the influence of deep formation conditions on the mechanical properties of shale, which is of great significance for the engineering application of efficient development of deep shale gas. In this study, a real‐time high‐temperature (25°C–170°C) triaxial compression experiment was first carried out on shale samples. Then, based on the analysis results of rock mineral components and discrete element numerical simulation technology, a thermo‐mechanical coupling model (TMCM) was constructed, and the accuracy of the numerical model was verified. Finally, based on the micromechanical parameters, a numerical fracturing mechanism model considering the influence of temperature, natural fracture density, and fracture length was established, and the influence of current reservoir conditions on hydraulic fracturing was discussed. The results show that confining pressure has a greater effect on rock mechanics than temperature. When the temperature exceeds 110°C, the plasticity of rock samples increases, and the fracture morphology becomes complex. In addition, the increase in temperature promotes the fracture of microcracks to a certain extent. The research results are expected to provide a sufficient theoretical basis for the development and utilization of deep shale gas resources.

Insights into the interaction of a shale with CO2

Abstract. Caprock formations, such as shales, play a key role in safe underground CO2 storage since they serve as a hydromechanical barrier that prevents migration of the injected CO2 to the surface. While their hydromechanical response is important to ensure their sealing capacity, interaction with the injected CO2 involves additional thermo–hydro–chemo–mechanical (THCM) phenomena that may threaten the long-term integrity of the caprock. The low-transport properties of shales make them a suitable caprock material, but at the same time challenging to study due to the very long timescales (months/years) that are required for the various THCM processes to manifest. In this work, the long-term multiphysical interaction of the Opalinus Clay shale with liquid and supercritical CO2 is studied in 3D with live X-ray tomography. Three-dimensional analysis reveals the localised response of the coupled THCM processes that is often indistinguishable with conventional lab testing protocols. To improve spatial and temporal resolution while applying field-representative pressure and temperature conditions, small-sized samples are studied. Long-term injection of liquid CO2 resulted in significant fissuring of calcite-rich zones that were for the first time visualised and quantified from the X-ray images. Additionally, a re-arrangement of the pre-existing micro-fissures in the clay matrix was observed. The volumetric response during direct exposure of an Opalinus Clay sample to supercritical CO2 revealed an initial swelling at pre-fissured zones and initiation of new micro-fissures at areas of direct contact with the anhydrous CO2 due to pore water evaporation. Advanced 3D image analysis showed an increasing CO2 uptake in the caprock material with time, suggesting potential CO2 trapping in the material.

Shale Formation Damage during Fracturing Fluid Imbibition and Flowback Process Considering Adsorbed Methane

Hydraulic fracturing of shale gas reservoirs is characterized by large fracturing fluid consumption, long working cycle and low flowback efficiency. Huge amounts of fracturing fluid retained in shale reservoirs for a long time would definitely cause formation damage and reduce the gas production efficiency. In this work, a pressure decay method was conducted in order to measure the amount of fracturing fluid imbibition and sample permeability under the conditions of formation temperature, pressure and adsorbed methane in real time. Experimental results show that (1) the mass of imbibed fracturing fluid per unit mass of shale sample is 0.00021–0.00439 g/g considering the in-situ pressure, temperature and adsorbed methane. (2) The imbibition and flowback behavior of fracturing fluid are affected by the imbibition or flowback pressure difference, pore structure, pore surface properties, mechanical properties of shale and mineral contents. (3) 0.01 mD and 0.001 mD are the critical initial permeability of shales, which could be used to determine the relationship between the formation damage degree and the flowback pressure difference. This work is beneficial for a real experimental evaluation of shale formation damage induced by fracturing fluid.

Effects of in-situ temperature in deep reservoirs on shale fracture properties

The development of deep shale reservoirs is a major strategic demand to meet national energy requirements. However, the high-temperature characteristics of in-situ reservoirs make it difficult to understand the fracture properties of deep shale clearly, which restricts the development of reservoir stimulation technologies. Based on digital image correlation method and fracture mechanics theory, this study investigates the issue of rock fracture parameters testing in high-temperature environments. This study builds an in-situ high-temperature environment rock fracture visualization test system that can dynamically capture crack-tip initiation and propagation. Further, the influence law of temperature on shale fracture behaviour has been analysed. The results have shown that, under the condition of no confining pressure, with increases in the temperature, the macroscopic material stiffness and fracture toughness of shale increase; this shows that high temperatures inhibit crack initiation and propagation. Further, with increases in the temperature, the temperature-dependent CTOD is positively correlated with the fracture toughness, the simultaneous increase of these two factors leads to the increase of local plasticity in the crack tip region. When considering high-temperature conditions alone, the fracture tip still experiences a small-scale yield state; the research conclusions can provide a reference for studies on deep reservoir fractures.

Insight into Effects of Acid Treatment on Physicochemical Properties of Huadian Oil Shale

Insight into Effects of Acid Treatment on Physicochemical Properties of Huadian Oil Shale