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Pressure and tilt data are jointly inverted to simultaneously map the orientation and dimensions of a hydraulic fracture. The deformation induced by a fracture under internal pressure is modeled using the distributed dislocation technique. The planar fracture is represented by four quarter ellipses, joined at the center and sharing semi-axes. This configuration provides a straightforward model for characterizing asymmetric fracture geometry. The inverse problem of mapping the fracture geometry is formulated using the Bayesian probabilistic method, combining the a priori information on the fracture model with updated information from pressure and tilt data. Solving the nonlinear inverse problem is achieved by pseudo-randomly sampling the posterior probability distribution through the Markov chain Monte Carlo method. The resulting posterior probability distribution is then explored to assess uncertainty, resolution, and correlation between model parameters. Numerical experiments are conducted to verify the accuracy and validity of the proposed analysis method in mapping the fracture geometry using synthetic pressure and tilt data. [ABSTRACT FROM AUTHOR]

Natural Gas Hydrates (NGH) is considered a vast unconventional energy source that holds significant promise in addressing future energy demands. In Shenhu area (located at northern slope of the South China Sea, SCS), there has been conducted a series of further studies of NGH such as exploration, drilling, and twice field production testing. The lithological characteristics of cores from marine sediments and their influence on methane hydrate (MH) formation are relatively unknown and merits further investigation. In this study, we conducted a chain of lithological characterization on the core sediments recovered from Shenhu W17 well, the coring well which located near the 1st NGH field production in SCS. The core sediments are classified as clayey-silt, its median grain size is 6.91 μm, comprising primarily clay minerals, quartz, and calcite. According to X-ray diffraction analysis, the main content of clay minerals is illite-smectite layers, illite, chlorite, and kaolinite, respectively. Porosity of the core sediments is 32.5% and the permeability is 7.8 mD based on mercury intrusion tests. Four types of primary pores are identified based on SEM and QEMSCAN analysis: intergranular pore, intercrystalline pore, intragranular pore, and pores associated with marine fossils. Moreover, the influence of the recovered core sediments (0–40 wt%) on MH formation kinetics were examined with morphology observed to elucidate the MH-core sediments interaction. The induction time was reduced significantly to ∼20 min in the presence of SCS core sediments. A two-stage MH formation behavior is observed with a maximum gas uptake of 134.1 V g · V w −1: (a) an initial MH formation at the gas-liquid interface with MH upward growth and fine-grain sediments migration; and (b) a second stage of significant MH growth with layered formation of MH and core sediments. The capillary channels of MH formed facilities the migration of core sediments, which in turn provides additional gas-liquid contact area for MH formation. The study provides valuable insights on the role Shenhu core sediments in MH formation, which is essential for understanding the spatial heterogeneity of NGH in reservoir and for designing suitable production strategy. [Display omitted] • The mineral composition and pore structure are characterized for Shenhu W17 core sediments. • Various types of pores are identified by SEM and QEMSCAN analysis. • Effect of core sediments on the kinetics and morphology of CH 4 hydrate formation is examined. • The migration of sediments facilities CH 4 hydrate growth resulting in a two-stage growth behavior. [ABSTRACT FROM AUTHOR]

Shale reservoirs, characterized by their relatively low permeability and porosity, often employ hydraulic fracturing techniques to increase production during development. However, conventional large-scale hydraulic fracturing encounters challenges such as excessive water consumption, low flowback rates, and environmental concerns. Given the increasing scarcity of water resources and increased emphasis on sustainability environmental sustainability, hydraulic fracturing no longer meets the requirements for green and environmentally friendly extraction. The utilization of supercritical CO 2 fracturing technology emerges as a promising alternative, offering advantages such as reduced water usage and minimized environmental impact. Additionally, this technology allows for the sequestration of CO 2 underground, presenting an integrated approach to CO 2 geological storage and oil-gas extraction. Supercritical CO 2 possesses many unique physical and chemical properties. However, the micro-mechanisms governing its interaction with rock during fracturing, along with the mechanisms and propagation characteristics of fracture initiation, necessitate further in-depth investigation. This study aims to explore the development mechanisms of supercritical CO 2 fractures under the influence of single factor variables and natural fractures of different sizes (2 m, 4 m, and 6 m). To explore the interaction mechanisms between natural fractures and supercritical CO 2 fractures, single factor variable control experiments were conducted with natural fracture angles of 30 °, 45 °, and 60 °, and in-situ stress deviations of 3, 5, 7, and 9 MPa. Our research delves into the impact of natural fracture inclination angle, in-situ stress deviation, and natural fracture size on supercritical CO 2 fractures development. This comprehensive exploration unveils the intricate interaction mechanisms between natural fractures of different sizes and supercritical CO 2 fractures. Various control chart were studied, considering different natural fracture under diverse ground stresses and inclinations. The findings of this study bear theoretical significance and engineering application for enhancing efficiency in shale gas production. • A single-factor variable control test was performed to examine the interaction mechanisms between natural and hydraulic fractures. • In the numerical simulation of supercritical CO 2 fracturing, the coupling of stress balance equation and fluid continuity equation is mainly used. • this study is a supplement to the supercritical CO 2 fracturing transformation of shale. [ABSTRACT FROM AUTHOR]

The confinement effect in nanopores significantly impacts the phase behavior of fluids in unconventional reservoirs and controls the occurrence and transport of fluids. As a result, the phase behavior, thermodynamic properties and phase equilibrium of bulk gases, in particular, could significantly change due to the surface-molecules interactions. On the one hand, due to the heterogeneous and anisotropic nature of unconventional reservoirs, experimental analysis of the confinement effects is utterly challenging. On the other hand, molecular simulation techniques for characterizing confinement effects are inaccurate since most of them are not verified with experimental data. In this work, we have reviewed the experimental results in the literature focusing on the confinement effect in nanopores. The behavior of confined gases in shale and coal reservoirs can be obtained by analyzing the small-angle neutron/X-ray scattering (SANS/SAXS) data using in-situ measurement and contrast matching small-angle neutron scattering (CM-SANS) methodologies. We reviewed the phase transition of confined carbon dioxide and methane in nanopores where the densities of both would differ from their bulk densities and are known to be pressure- or pore-size-sensitive. The current work investigates the application and future perspectives of utilizing the confinement effect in shale and coal reservoirs for enhancing gas/oil recovery and carbon dioxide sequestration. Additionally, given the recent global interest in hydrogen storage in such reservoirs, our literature review concludes that shale and coal reservoirs might be considered as repositories for hydrogen if the confinement effect of fluids is well understood. • SANS/SAXS is generally employed to evaluate the confinement effect in nanopores of shale and coal. • In-situ and CM-SANS methodologies determine the behavior of confined gases of shale and coal reservoirs. • The phase transitions in confined carbon dioxide and methane fluids in nanopores are reviewed. • The importance of confinement in enhancing gas/oil recovery, CO 2 sequestration and H 2 storage was discussed. [ABSTRACT FROM AUTHOR]

The understanding of the mechanisms that govern spontaneous water imbibition in gas-water systems plays a significant role in operating the hydraulic fracturing and the development of unconventional gas reservoirs. The main purpose of this paper is addressing how the spontaneous imbibition in coal reservoir affects reservoir permeability, and what is the microscopic mechanism of water transport during this process. To solve this problem, air-water co-current imbibition experiments, contact-angle tests and permeability tests were carried out on eight coal plugs originated from three Chinese coalbed methane hot spots. Moreover, NMR spectrometer is introduced as a method for monitoring the volume of water imbibed in pores with different sizes. The results reveal that the water imbibition rate of bituminous coal follows microfracture > micropores > meso/macropores, whereas for anthracite, the imbibition rate is in the order of microfracure > meso/macroproes > micropores. Permeability damage ratio due to the spontaneous imbibition follows a positive exponential relationship with increasing contact angle. Considering the multi-scale pore system and complex pore tortuosity, we established a model to estimate the spontaneous imbibition rate, which agrees well with experimental results at the early stage of imbibition process when the capillary force is dominant. Finally, four successive stages of moisture migration during spontaneous imbibition and spontaneous evaporation were divided based on the movement of the NMR T 2 peak. The implications from this work is important for better understanding the mechanism controlling fluid loss and gas production in unconventional reservoir, which is significant for optimizing the recovery program and minimizing reservoir damage. Image 1 • What factors affect the spontaneous imbibition in coal? • How does the spontaneous imbibition in coal affect gas permeability? • How does moisture migrate in coal during spontaneous imbibition? • Proposed a new model to estimate the spontaneous imbibition rate in coal. • Traced dynamics of spontaneous imbibition and water evaporation in different pores. [ABSTRACT FROM AUTHOR]

Marcolithotypes play a significant role in coal seam porosity and fracture heterogeneity. The optical microscopy, CO 2 and N 2 adsorption, and X-ray CT were used for reconstructing the pore-fracture system of different marcolithotypes. The results show that the microfractures are well developed in the bright coal with the characteristics of high fracture density, good connectivity, and strongest fractal dimension, corresponding to the highest permeability and the best seepage capacity. The adsorption capacity measured with N 2 , CO 2 , and CH 4 indicates that the specific surface area of micropores (<2 nm) increases linearly from the bright to the dull coal, and the bright coal is favorable for gas adsorption by providing more available surface sites. The difference in physical properties of various macrolithotypes causes different logging response characteristics, including the compensated density (DEN), the gamma ray (GR), and the acoustic time (AC). Based on that, the index (N = AC /(GR × DEN)) was put forward to forecast the distribution of coal macrolithotypes quantitatively (N ≤ 1.3, Partings; 1.3 < N ≤ 3, Dull coal; 3 < N ≤ 5, Semi-dull coal; 5 < N ≤ 8, Semi-bright coal; N > 8, Bright coal), and its accuracy was verified by coal cores from different areas, i.e. Fanzhuang, Zhengzhuang, and Hancheng blocks. • Pore-fracture systems of coal macrolithotypes were evaluated via multi-means. • Well logging response of coal macrolithotypes was discussed. • Inversion method for macrolithotypes with well logging information was established. [ABSTRACT FROM AUTHOR]

Water spontaneous imbibition (WSI) induces complicated multi-physical phenomena in shale gas reservoir after the hydraulic fracturing, including the shale matrix swelling, the micro-crack initiation, and the changes of Young's modulus and permeability. Since these phenomena were not fully described in most of the previous numerical models, in this study, a numerical simulation model coupled of WSI, clay-swelling-induced shale deformation and micro-crack initiation was established, solved through a proposed calculation procedure, and validated with the experimental data on shale samples from Lower Silurian Longmaxi formation, Sichuan Basin, China. In addition, the effects of WSI on shale properties and shale gas production were quantitatively studied through four numerical cases. The results show that our proposed model is able to describe the micro-crack generation around the interface between the clay and non-clay minerals due to their different swelling behaviours. Moreover, there are great descrepancies in the evolutions of Young's modulus and permeability between the laboratory and in-situ conditions during the WSI, due to the different boundary conditions, direction of the maximum principle stress and swelling strain, resulting in a large difference in shale gas recovery rate. Consequently, the difference between the laboratory and in-situ conditions should be taken into account to analyse the effect of WSI on shale gas production. • Coupled model for water spontaneous imbibition in shale was presented and validated. • The different swelling behaviors between minerals results in the shale damage. • Boundary conditions impact the prediction of recovery rate after water invasion. [ABSTRACT FROM AUTHOR]

Abstract Shale permeability and its variation under high stress are vital for gas production from deep shale gas reservoirs. Most experiments of stress-dependent permeability for organic-rich shale were conducted under lower stress less than 40 MPa, therefore, shale permeability evolution under high stress is not clear. In this work, the effects of high stress on the permeability and fracture compressibility of shales were investigated experimentally. Moreover, the impact of stress cycling on permeability were also studied. Four shale samples including two intact samples and two fractured samples from Cambrian Niutitang Shale formation and Silurian Longmaxi Shale formation were used. Permeability was measured using Helium under different stress conditions, including different confining pressure, different gas pressure, and constant effective stress. The highest effective stress and gas pressure in this work was 59.5 MPa and 10 MPa, respectively. Fracture compressibilities were calculated using the stress-dependent permeability data. The results show that the permeability of the intact samples and fractured samples decreased by one order of magnitude and three orders of magnitude, respectively, with the effective stress changing from 1.5 MPa to 59.5 MPa. The shale permeability results show a two-stage characteristic and nonlinearly decreasing trend with the increase of effective stress, demonstrating that the fracture compressibility is stress dependent and decreases with stress. The permeability hysteresis occurs between the loading and unloading cycles due to the inelastic compression of the pore. The modelling results also show that the Klinkenberg constant show a positive correlation with effective stress, as effective stress reduces the fracture opening and absolute permeability. Highlights • Permeability is strongly sensitive to stress for shales. • Fracture compressibility decreases with increase of stress. • Fracture compressibility of the fractured shale samples are more sensitive to the effective stress change. • Absolute permeability decreases with effective stress and Klinkenberg constant increases with effective stress. [ABSTRACT FROM AUTHOR]

Assessing the connectivity of pores and the characteristics of microfractures is essential for comprehending gas migration mechanisms and effectively implementing development strategies in deep shale gas plays. The Fuling gas field, a prominent shale gas reservoir in China, holds promise for deep shale development. This requires a better understanding of variations in pore connectivity among shale samples from different depths of the Fuling gas field. To achieve this goal, this study employs innovative methodologies based on mercury intrusion capillary pressure (MICP), a recognized technique for evaluating material pore structures. In this research, we conducted MICP tests on shale samples of varying sizes to examine variations in pore structure and quantify inaccessible pores. Additionally, repeated MICP tests were performed on the same sample to investigate the spatial distribution of residual mercury and distinguish different pore types associated with flow conduits and storage spaces. Furthermore, a directional MICP experiment was carried out to quantitatively characterize the degree of pore development and anisotropy of microfractures by considering the direction of mercury intruding the sample (parallel or perpendicular to lamination). Our findings revealed that deep shale samples exhibited a higher proportion of inaccessible pores compared to mid-deep ones. Regarding accessible pores, a greater proportion of connected pores was observed in the deep shale samples, while the mid-deep shale samples exhibited a lower proportion. The results from the directional MICP experiment indicated that samples with anisotropy in mercury intrusion volume possessed finer and denser microfractures. However, no evidence was found to correlate the ratio of dead-end and connected pores with sample anisotropy. Overall, this study presents a novel approach for experimentally evaluating pore connectivity and microfracture characteristics in shale reservoirs using MICP. The outcomes contribute to enhancing our understanding of shale gas migration mechanisms, particularly in deep ultra-low-permeability reservoirs, and hold significant implications for future developments in the field. • MICP is used in innovative way to investigate shale pore connectivity and anisotropy. • Compared to mid-deep shale, deep shale has more closed spaces but shows better connectivity of accessible pores. • Difference in degree of tectonic uplift and in situ stress will lead to pore connectivity discrepancy in shales. • A higher level of natural fractures developed in the anisotropy samples. [ABSTRACT FROM AUTHOR]

Abstract CO2CRC and its partners are undertaking a feasibility study for a planned CO 2 controlled release and monitoring experiment on a shallow fault at the CO2CRC Otway Research Facility. In this project we plan to image, using a diverse range of geophysical and geochemical CO2 monitoring techniques, the migration of CO 2 up a fault from a controlled release point at approximately 30 m depth. This paper describes the results of site characterisation and modelling work undertaken to date. It also includes a description of the activities planned that will enable for a more detailed characterization of the fault and proposed injection interval. Together these results will enable an assessment as to whether the planned injection experiment is feasible and how it can be optimally designed. [ABSTRACT FROM AUTHOR]

With the increasing demand in natural gas and interest in greenhouse gas sequestration, gas transport mechanism and gas-induced deformation of shale have become important research topics. The shale matrix swells after adsorbing gas, which will impact on the gas transport behaviour in shale. In this paper, the kinetic shale swelling and kinetic gas adsorption in different types of gases at various gas pressures under confining pressure of 20 MPa and temperature of 25 °C were investigated. The gases used in the tests were helium, N 2 , CH 4 and CO 2 . It was found that shale swelling under this experimental conditions has two components: strain caused by poroelasticity and gas adsorption-induced swelling strain. The experimental results show that gas adsorption induced shale swelling and the absolute adsorption amount in different gases are both about one order of magnitude lower than that of coal and are in a trend line with the results of gas adsorption-induced coal swelling, indicating that shale swelling mechanism may be similar to that of coal. The swelling rate of shale has a positive correlation with the mass rate of gas uptake. Moreover the swelling rate of shale in helium is the highest, and that in CO 2 is the lowest due to slow gas diffusion caused by larger CO 2 adsorption-induced swelling and CO 2 phase transition from vapor state to liquid state at the experimental condition in this study. The swelling rate of shale in CH 4 and N 2 are almost the same. Helium-induced swelling rate increases with gas pressure due to the change of effective stress, while the swelling rates of shale in CH 4 , N 2 and CO 2 are positively correlated to the gas pressure in the early stage and negatively correlated in the later stage due to the different adsorbing gas transport mechanism in macropores and micropores. The phase change of CO 2 leads to the change in density and viscosity, resulting in the change of kinetic swelling rate. It was also found in this work that the anisotropy ratio for shale swelling decreases in the order of He, N 2 , CH 4 and CO 2 . Gas adsorption results in a lower anisotropy ratio, which may be related to the more random distribution of the organic matter and clay minerals, where gas adsorption and its induced swelling occur. [ABSTRACT FROM AUTHOR]

Deep coalbed methane (CBM) resource potential is enormous in China, and has become a new field for unconventional natural gas exploration and development. This work discusses the geological conditions (reservoir pressure, formation temperature and ground stress) of deep coal reservoirs in the Eastern margin of the Ordos Basin and their implication on CBM development. Various field test data of CBM wells, including injection/drawdown test data, well temperature test data, and hydraulic fracturing test data were collected from this work and literature to describe the geological conditions of the deep CBM in the study area. From the results, it is found that deep CBM in this area is characterized by high reservoir pressure, high formation temperature, and high ground stress. However, there are diverse geological particularities in the different depth range: (1) Having a wide range of pressure gradient, vast majority of coal reservoirs in the study area are under abnormally low-pressure state, which is more significant in deeper coal seams. (2) Due to the impact of surface runoff, the distribution of geothermal gradient is discrete when the burial depth is less than 700 m, and relatively concentrated when the burial depth is greater than 700 m. (3) In shallow coal reservoirs, ground stress is strongest in the horizontal direction; while in deep coal reservoirs, the strongest ground stress is in the vertical direction. Because of the complex geological conditions associated with deep burial, the balance between CBM adsorption-desorption-seepage and the rheological behavior of coal reservoirs is complex, which has significant influence on the exploration and development of deep CBM in the study area. High pressure in deep coal reservoir often leads a long inefficient desorption stage and a long draining and depressurizing process, which increases production costs. Moreover, the negative temperature effect on gas adsorption indicates that CBM content decreases with increasing depth in deep conditions, and thus the evaluation of deep CBM resources needs to be reconsidered. In addition, different stress states govern fracture patterns, and in deep environments, high ground stress greatly reduces the fracturing improvement of the coal reservoir and significantly affects the deep CBM development. [ABSTRACT FROM AUTHOR]

Sapropelic coal is similar to humic coal in organic matter content, and to shale in kerogen type. Research on the sapropelic coal pore structure can help to understand the differences between humic coal and shale in pore development. In this paper, the pore structures of 21 sapropelic coal samples from Shaanxi, Shanxi, Gansu and Shandong provinces were determined, coupled with proximate analysis, reflectance ( R o ), maceral and fractal analysis, scanning electron microscopy (SEM), mercury porosimetry (MIP), and low-temperature nitrogen adsorption tests. The results indicate that Late Paleozoic and later age sapropelic coals are low rank with R o values ranging from 0.31% to 0.82%, and Early Paleozoic sapropelic coals are high rank with R o values ranging from 2.64% to 5.89%. The low-rank coals are mainly of Types IIa and IIb kerogen containing humic detritus. The high-rank coals are of Type I kerogen composed by bitumen matrix and minerals. According to the normalized pore size distribution (PSD) curves of MIP and low-temperature N 2 adsorption, three pore types (Type I M , Type II M , and Type III M ) for seepage pores and three pore types (Type I N , Type II N , and Type III N ) for adsorption pores are divided, respectively. For seepage pores, all the low-rank sapropelic coals have the Type I M PSD, while the high-rank coals contain Type I M , Type II M and Type III M PSDs. From Type I M via Type II M , to Type III M , the content of mesopores and macropores increases; meanwhile, the fractal dimensions ( D t , derived from the thermodynamics model) also increase. For adsorption pores, from type I N via type II N to type III N , the BET specific surface area (SSA), density function theory (DFT) volume and Frenkele-Halseye-Hill (FHH) fractal dimension ( D f ) successively increase, and the medium pore diameters successively decrease. It was found that the development of the saproplelic coal pore structure was controlled by the integrated effects of coal rank and composition. Generally, the seepage pores of sapropelic coals studied in this work are mainly primary or intergranular pores with weak correlation with the coal composition. However, the development of the adsorption pores has obvious correlations with organic matter content, ash yield rate ( A ad ) and moisture content ( M ad ). [ABSTRACT FROM AUTHOR]

The lower Palaeozoic Cambrian Niutitang shale and Silurian Longmaxi shale in the upper Yangtze region are the two most favourable marine shales in south China. Great achievements on shale gas development and production have already been made in the Longmaxi shale in southeastern Sichuan (SES). However, to date, economic shale gas potential has not been proved in northwestern Hunan (NWH), which is still a virgin area for shale gas exploration. Based on detailed outcrop investigation, laboratory testing and numerical simulation, the shale gas potential of Niutitang shale were evaluated in this work. Comparisons were also made through vertically diachroneity contrasting with the Longmaxi shale in the NWH area and horizontally isochronic contrasting with Niutitang shale in the SES area. Through analysing the evolution of the palaeoenvironment and palaeotectonics of the period from Niutitang to Longmaxi, it was found that: (1) the NWH Niutitang shale was developed in the hydrothermal continental shelf paleoenvironment, which provided a favourable environment for shale deposition, so the thicker and higher total organic carbon (TOC) shale was largely developed during this time; (2) By the influence of hydrothermal igneous leaching, the element Si formed quartz, which improved the brittleness of the Niutitang shale; (3) Induced by intense tectonic movement, natural fractures were highly developed in the Niutitang shale, which improved the reservoir connectivity; and (4) By comprehensively considering the TOC, reservoir property, and gas retention conditions, the Niutitang shale is a promising target for shale gas development in this area. The results from this work warrant further exploration work in the Niutitang shale in the NWH area. [ABSTRACT FROM AUTHOR]

Proppants are typically added in the hydraulic fracture to maintain the fracture aperture and increase conductivity for gas production from coal seams. However, the presence of proppants complicate the permeability behaviour of the coal. Understanding permeability evolution of proppant supported fractures under dynamic stress conditions are necessary to predict the production of coalbed methane. In this work, a series of laboratory experiments were conducted on a cylindrical coal core from Chongqing, China, under hydrostatic condition. Permeabilities at various gas pressures and confining stresses were measured on the original sample, as well as the sample with a proppant supported fracture. Gas adsorption, matrix swelling behaviour were also investigated by injecting non-adsorbing (H e ) and adsorbing (CH 4 ) gases. The results show that proppant supported fracture has little effect on adsorption capacity, as well as the swelling behaviour due to gas adsorption. However, the proppant supported fracture can significantly enhance permeability about 2-3 orders of magnitude higher than original sample depending on proppant type and its distribution in the fracture. Fracture compressibility may be decreased by 1 order of magnitude, suggesting that the permeability for the proppant supported fracture is less sensitive to stress. It was also found that sparsely placed monolayer proppant can have comparable permeability with densely packed multilayer proppant. [ABSTRACT FROM AUTHOR]

The hydraulic fracturing technology is a key for enhancing the permeability of reservoirs during the production of natural gas. Significant progress has been made in hydraulic fracturing theory and practices, however, precise prediction of the fracture patterns in naturally fracture reservoirs still requires further study. The mechanisms influencing the interaction between hydraulic fracture (HF) and natural fracture (NF) should be well understood to achieve a wider application of hydraulic fracturing. In this paper, it is the first time to simulate the details of the interactions between hydraulic fractures (HFs) and natural fractures (NFs) using two-dimensional particle flow code (PFC 2D ) with embedded Smooth Joint Model (SJM). Firstly, the ability of SJM to emulate the natural rock joint was validated, and the fluid-mechanically coupled mechanism was introduced. Secondly, the interactions between a driven HF and a pre-existing NF were simulated considering fracturing fluid injection in a borehole. Lastly, the influence of approach angles and in-situ differential stress were studied. It is found that the model is capable of simulating the variety of interactions between HFs and NFs such as direct crossing, crossing with an offset and HFs arrested by NFs. Under high approach angles and high differential stresses, the HF tend to cross pre-existing NFs; on the contrary, a HF is more favorable to propagate along the NF and re-initiate at the weak point or the tip of NF. Moreover, our numerical results agree well with the analytical results based on the modified Renshaw and Pollards' criterion. Therefore, this numerical method may become a useful and powerful tool for optimizing fracture design in naturally fractured shale gas reservoirs. [ABSTRACT FROM AUTHOR]

Shale gas is an important unconventional natural gas resource, but shale has extremely low permeability. Production of shale gas can be improved by using proppants for hydraulic fracturing and maintaining fracture conductivity, and a better understanding of the permeability and its anisotropy of proppant-supported fractures would be useful in optimising gas production. This paper described experiments on shale permeability and its anisotropy with respect to gas pressure, effective stress and gas type for a natural fracture supported with two sizes of proppant. A cubic sample from the Silurian Longmaxi formation in the Sichuan Basin, China, was used in the study; the testing direction of the sample was altered, and both helium (non-sorbing) and methane (sorbing) were tested. Microscopic X-ray computerised tomography ( μ -CT) scanning was used to reveal the proppant distribution and fracture shape. Finally, an analytical model was applied to describe the permeability with respect to pore pressure and effective stress and the results were used to determine the relationships between initial fracture compressibility, Klinkenberg coefficient and absolute permeability. The permeabilities of propped fractures were found to be a few hundred or even a few thousand times higher than those of the natural fracture under the same experimental conditions, with both the proppant size and the amount of proppants added affecting this increase. The permeability was anisotropic in two horizontal directions. The direction and ratio of permeability anisotropy of the proppant-supported fracture differed from those of the natural fracture, depending on the amount of proppants added and their distribution in the fracture. The model indicated that permeability decreased with effective stress at a given pore pressure, and with pore pressure at a given effective stress. It also suggested that adding proppants will significantly change the absolute permeability but not the initial fracture compressibility. Although the permeability had strong anisotropy, the initial fracture compressibility relationships with absolute permeability were independent of flow direction and followed the same trend. The relationship between the Klinkenberg constant and absolute permeability was found to be well described by a cubic law function. [ABSTRACT FROM AUTHOR]

Unconventional natural gas has become an important source of energy. However, the development of such resources has been challenging as these reservoirs are characterised by low to ultra-low permeabilities. The low permeability does not only present a challenge for commercial gas production, but also for experimental measurements of rock samples. Methods to determine permeability of low permeability rock cores and crushed rock samples directly can be divided into two categories: steady state and unsteady state. Unsteady state methods include the pulse decay, oscillating pressure, and GRI method (pressure fall-off method). In this review we describe and compare each method in detail and discuss the challenges specific to measuring low permeability rocks. A brief overview of alternative permeability measurements is also provided (e.g. indirect measurements, canister desorption test). The review highlights each method's advantages and disadvantages. The steady state method is easy to apply, due to its simple experimental set-up and its straightforward solution using Darcy's law. However, as permeability decreases, flow rate measurements become less accurate. Unsteady state experiments measure pressure and temperature, which can typically be determined more accurately. Furthermore, the set-up of unsteady state experiments can be adapted to increase sensitivity, thus improving measurement accuracy or speed. On the downside, unsteady state experiments are typically more affected by leaks than steady state experiments. The review indicates that steady state and unsteady state methods do not always yield the same results, and that the GRI method measures a different type of permeability to the other experimental methods. The permeating fluid can also significantly affect measurements in very low permeability rocks. Additionally, the experimental measurement of low permeability gas reservoir rocks faces several practical challenges: a lack of universal measuring standards for low and ultra-low permeability media affects comparability between results; different laboratories use different methodolgies for sample preparation; and various analytical solutions have been presented to interpret the experimental data, most of which are based on the validity of Darcy's law and the Klinkenberg effect. The suitability of an experimental method depends on permeability, porosity and adsorption capacity of the rock, and the limitations of the underlying assumptions of the solution. A thorough understanding of the applied experimental and analytical technique, and knowledge of the sample's preparation are necessary to accurately interpret and use any results. [ABSTRACT FROM AUTHOR]

Shale microstructures control the capacity of the formation to store hydrocarbons and its fluid flow. However, microstructural complexity and multiscale heterogeneity is a challenge in a comprehensive understanding of shale plays. As a non-destructive visualization technology, X-ray computed tomography (X-ray CT) scanning can be used to characterize multiscale shale pore structures. Herein, we review recent advancements in X-ray CT scanning for multifaceted characterization of organic rich shale plays. We first introduce the basic principle of X-ray CT scanning technology with a general workflow of image processing, followed by a sequential overview of its current applications in shale pore structure analysis, permeability evaluation, and reservoir in-situ conversion. We understood that a multiscale imaging framework involving micro-CT, nano-CT, focused ion beam scanning electron microscopy (FIB-SEM), and other imaging techniques can offer a powerful approach for assessing shale microstructures. Meanwhile, various contrast agent injections can provide a new entry point for investigating shale pore space. Moreover, digital rock physics (DRP) which is based on 3D visualization of natural samples to reconstruct digital specimens can be used in flow modeling to predict transport properties from molecular to microscale. In addition, microstructures can evolve significantly during geological processes or hydrocarbon exploitation (e.g., pyrolysis, fracturing deformation and chemical reactions), which can be observed with CT scanning. Collectively, this review primarily highlights the applications of X-ray CT scanning in characterization of shale pore structures and their evolution and proposes directions for future research in this realm where a knowledge gap exists. [Display omitted] • Shale microstructures and its properties characterized by CT as well as various contrast agent injections are reviewed. • Application of the X-ray CT scanning in digital rock physics (DRP). • Application of time-resolved X-ray microtomography in observing shale in-situ conversion. • Future application of X-ray CT in permeability evaluation and dynamic microstructural imaging. [ABSTRACT FROM AUTHOR]