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The seepage problem of coal-bed methane (CBM) has attracted increasing attention from the research and industry communities. Coal permeability, which is a key parameter for CBM production, has been extensively studied through both laboratory and field tests, mathematical modeling, and numerical simulations. However, relatively little work has been done to investigate the effect of matrix water content on coal permeability evolution. Because most coal seams contain water, it may have direct impact on the CBM seepage capacity. Therefore, in this paper, CBM seepage at different matrix water contents was investigated experimentally. Results demonstrate that coal permeability decreases with the increase in water content. It was also found that both pore pressure and water content can greatly affect CBM migration characteristics and that the sorption strain and permeability were mostly controlled by pore pressure. In addition, water can have an impact on gas adsorption and sorption-induced deformation, which can further affect seepage channel width, leading to change in coal permeability. In general, coal permeability was observed to decrease exponentially with the increase in water content and pore pressure. Moreover, a coal adsorption model and an adsorption-permeability model were established, considering water content and excess adsorption under constant external stress and triaxial strain conditions. The proposed permeability model showed good agreement with the experimental results. The present study provides for better understanding of coal permeability evolution in a water-bearing condition and for developing an improved model to simulate the CBM migration process under such condition more accurately. [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]

Coalbed methane (CBM) reservoir properties and relationship of properties with burial depth were studied based on the data derived from 204 deep CBM production wells in Qinshui Basin, China. Through the study, it is found that permeability and porosity decrease with the increase of burial depth and the decreasing trend shows step-change characteristics at a critical burial depth. They also show divisional characteristics at certain burial depth. Gas content, geostress, and geotemperature increase with the increase of burial depth, and the increasing trend shows step-change characteristics and also have divisional characteristics at certain burial depth. Based on the previous study on the reservoir property changes with burial depth, three series of critical depth using different parameters are obtained through simulating the critical depth using the BP neural network method. It is found that the critical depth is different when using different parameters. Combined the previous study with the normalization of three different parameter types, the critical depth in Qinshui Basin was defined as shallow coal seam is lower than 650 m and transition band is 650–1000 m, while deep coal seam is deeper than 1000 m. In deep coal seams, the geological conditions and recovery becomes poor, so it can be defined as unfavorable zones. Therefore, other development means, for example, CO2 injection, need to be used to accelerate the deep coal methane development. [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]

The permeability damage of high‐rank coal reservoirs is the main factor affecting the development of coalbed methane (CBM) in the late production stage. Coal core samples from southern Qinshui Basin were saturated with actual formation water, 1/2 salinity formation water, and distilled water to study the swelling of clay minerals. Then, the mechanism of permeability change caused by water sensitivity and its effect on gas production was discussed. The results show that the permeability decrease caused by flow velocity sensitivity did not occur during the water sensitivity experiments. The permeability damage caused by water sensitivity is mainly the static damage from swelling of clay minerals, especially illite/smectite mixed clays and chlorite. During the process of CBM development, the water sensitivity of coal reservoirs will lead to the sharp increase of Na+ concentration and a decrease of Mg2+ concentration in the produced water. Meanwhile, the clay minerals swell due to the adsorption of more Mg2+ and Ca2+, decreasing the reservoir permeability and gas production rate. Water sensitivity experiments on coals collected from Southern Qinshui Basin were conducted and its impact on the productivity of CBM wells was evaluated. Source of CBM well output water and change of water IC were discussed. Mechanism of coal permeability change caused by the water sensitivity was revealed. [ABSTRACT FROM AUTHOR]

Coal is highly anisotropic and heterogeneous, affecting coal permeability. As permeability is one of the most important reservoir properties for coalbed methane production, it is useful to understand the impact of coal anisotropy and heterogeneity on coal permeability. In this work, anisotropic permeability measurements were performed in the laboratory on three cubic samples from the same coal block from the Bowen Basin, Queensland, Australia. The permeability was measured at a series of gas and confining pressures. Cleat compressibility, a measure of permeability sensitivity to stress, was also calculated from the experimental results. Each sample was then scanned using microscopic X-ray computerised tomography after permeability measurements to study its cleat system. The results show that permeability is strongly anisotropic and heterogeneous among the three samples and is correlated with the cleat system. A permeability model, which incorporates stress, gas pressure and swelling effects, is used to describe the experimental results. At last, numerical simulations were conducted to demonstrate the impact of coal permeability heterogeneity on coalbed methane production. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is key for shale gas production and fracture permeability or conductivity is one of the most important parameters for gas production rate. Investigating the proppant distribution and fracture permeability in the field is difficult, therefore, laboratory study is a good alternative. In this work, the effect of the layer number and type of proppant on fracture permeability and compressibility were investigated. A cubic shale sample from the Cambrian Niutitang Formation at Sangzhi, Hunan Province, China, was used in this work. Sands and glass beads of different number of layers were added into an artificial fracture and seven cases, including original sample, non-propped fracture, and four kinds of propped fractures were considered. Permeability at three gas pressure steps and five confining pressure steps were measured in each case at two flow directions. Microscopic X-ray computed tomography was used to detect the distributions of proppant, and the relationship with permeability and its anisotropy was studied. A permeability model combining the stress and Klinkenberg effects was used to match experimental data and a new fracture compressibility model was proposed to predict the change of fracture compressibility with the layer number of proppant. It was found that permeability and compressibility of proppant supported fracture are closely related to proppant packing pattern and layer number, as well as the permeability anisotropy. These results improve our understanding on permeability behaviour for the proppant supported fracture and can assist in the model of fracture permeability and simulation of shale gas production. [ABSTRACT FROM AUTHOR]

Coal reservoirs especially deep unminable coal reservoirs, are viable geological target formations for CO2 storage to mitigate greenhouse gas emissions. An advantage of this process is that a large amount of CO2 can be stored at relatively low pressure, thereby reducing the cost of pumping and injection. Other advantages include the use of existing well infrastructure for CO2 injection and to undertake enhanced recovery of coalbed methane (ECBM), both of which partially offset storage costs. However, ECBM faces difficulties such as low initial injectivity and further permeability loss during injection. Although expensive to perform, ECBM field experiments are essential to bridge laboratory study and large-scale implementation. China is one of the few countries that have performed ECBM field experiments, testing a variety of different geological conditions and injection technologies. These projects began more than a decade ago and have provided valuable experience and knowledge. In this article, we review past and current CO2 ECBM field trials in China and compare with others performed around the world to benefit ECBM research and inform future projects. Key aspects of the ECBM field projects reviewed include the main properties of target coal seams, well technologies, injection programmes, monitoring techniques and key findings. [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]

We investigated the anisotropic permeability in three directions of three cubic shale samples from Lower Silurian Longmaxi Formation in southeastern Sichuan Basin, China. The relationship between anisotropic permeability and fracture structure as characterised by micro-computed tomography (CT) and scanning electron microscope (SEM) Maps was also investigated. At confining pressure of 3 MPa, permeability parallel to bedding of the three shales varies between 37.6 and 3042.4 nanodarcies (nd), while permeability perpendicular to bedding varies between 3.6 and 17.3 nd, using helium and methane. The permeability anisotropy ratio between the parallel and perpendicular to bedding directions varies from 5.2 to 510.5 for the three samples using the two gases. Moreover, permeability in two parallel to bedding directions also shows strong anisotropy. The CT and SEM Maps results suggest that microfractures are critical to permeability in the parallel to bedding direction; they also lead to a higher anisotropy ratio between the parallel and perpendicular to bedding directions, while reducing the anisotropy ratio between the parallel to bedding directions. The helium permeability is 1.4 to 3.3 times that of methane permeability, while the helium to methane permeability ratio decreases with the sample’s total organic carbon content: an observation that requires further investigation. [ABSTRACT FROM AUTHOR]

Coal permeability changes during the course of gas drainage process due to the change in pore pressure, porosity, and desorption. Understanding of coal permeability behaviour enables a better assessment of gas drainage performance. Despite the research carried out to investigate the factors affecting coal permeability, limited study has been conducted on the impact of creep on coal permeability evolution. As coal is generally soft and gas drainage is a lengthy process, the impact of creep on permeability variation can be quite significant. In this study, an improved permeability model was developed by incorporating the viscoelastic creep term of Nishihara model into the constitutive stress-strain equation for anisotropic poroelastic media. The model was then implemented in a fully coupled Finite Element numerical model. Two scenarios under various stress and uniaxial strain conditions were simulated to investigate the impact of creep on coal permeability and gas drainage. A comparison between the results of the simulation of the improved permeability model and the original permeability model were performed. The results show that creep can have a significant impact (up to 25% or more) on coal permeability and gas drainage. This impact is function of coal properties such as directional elastic and viscoelastic moduli and reduction of pore pressure due to continuous desorption of gas. Comparison of improved and original models show that the impact of compaction creep on coal permeability becomes more pronounced owing to further pressure depletion toward the end of gas drainage process. It is also evident that the viscoelastic compaction creep as a result of gas pressure reduction from 6 MPa to 4 MPa induces a 5% decrease in permeability. A reduction of 13% in permeability was also achieved for pressure reduction of 4 MPa (from 6 MPa to 2 MPa). This indicates that coal permeability could be significantly overestimated if the impact of creep was not considered. The time and viscosity coefficient associated with creep were found to have negligible impact on coal permeability. This study proved that creep in coal is an important phenomenon that should be considered when conducting gas drainage performance analysis, particularly for soft coals. The improved permeability model and the fully coupled numerical model can be used to better predict gas drainage performance, and to improve the layout design of gas drainage boreholes. [ABSTRACT FROM AUTHOR]

Although many coal permeability models have been developed in the past decades to describe the coal permeability behaviour under elastic state, few of them address the coal permeability change under plastic and post-failure state which is often the case within the plastic region adjacent to the excavation face in underground coal mining. In this study, a methodology to model permeability change from elastic to post-failure state is developed by using a modified logistic growth function in conjunction with the classic exponential coal permeability correlation. The proposed coal permeability model is a function of mean effective stress which controls the coal compaction and deviatoric effective stress which controls coal fracturing. The coal permeability may increase by up to several orders of magnitude after failure and then reaches a plateau during triaxial tests. The new model is able to capture this behaviour by matching a set of permeability data in transition from elastic to post-failure state under triaxial stress conditions. This modelling approach may be used to better understand coal permeability changes associated with mining activities, which have applications in the prediction of gas emission, risk assessment of coal and gas outburst, and analysis of gas drainage near mining openings. It is anticipated that the current work may attract more attentions on coal permeability modelling under plastic condition, a critical issue for mining safety. [ABSTRACT FROM AUTHOR]

As one of the most important parameters for estimating oil/gas production rate, permeability is sensitive to effective stress which may change significantly with reservoir depletion. Although vast amount of data on permeability–stress correlations have been reported, many of them were proposed based on different situations. This makes it difficult to compare the modeling results of the experimental data and limits the adaption of the findings from one set of testing permeability data to other situations. A unified permeability and effective stress relationship would make it possible to evaluate the permeability behavior under different situations. Recently, the validity of an exponential form permeability correlation to any types of fractured rocks has been confirmed by some of the authors in this paper. In this study, the exponential form model is further extended to describe the permeability change for porous media through theoretical derivation. The unified permeability relationship is then applied to represent the permeability data for a large amount of samples from three typical reservoir rocks, including porous sandstone, idealized fractured coal and randomly fractured shale. The results show that the unified relationship is capable of describing permeability data for both porous and fractured rocks. The distributions of the model parameters are also obtained. This unified relationship provides a benchmark to evaluate the permeability behaviors in different rocks and the modeling results form a practical database for permeability in typical reservoir rocks. The outcome of this work would contribute to many circumstances including interpreting permeability data and making comparison, estimating permeability, coupling into existing reservoir simulators for fluid flow modeling and so on. [ABSTRACT FROM AUTHOR]

Permeability is one of the key petrophysical properties for the coalbed methane (CBM) reservoirs, which directly impact the CBM production rate and the amount of CBM that can be ultimately recovered. Due to the complex and heterogeneous nature of coals, an accurate determination for permeability of coals is required. Coal permeability is often determined by fractures (or cleats), which correlates with the aperture of cleats and cleats frequency. However, the gases flow path in coals covers fractures (or cleats), and pores with pore width $$>$$ 100 nm; thus, the effect of pores on permeability should not be neglected, especially in the process of outgassing for methane release from pores over 100 nm (defined as seepage-pores) in the coal seams. Understanding of this issue is limited. Therefore, the determination of the pore size distribution in coal cores was conducted by using mercury intrusion porosimetry. With a specific interest in larger pores ( $$>$$ 100 nm), the larger pores are linked to their contribution to permeability in coal cores with core permeability by the transient pulse method. Based on 33 coal samples with vitrinite reflectance in the range of 0.54-2.99 %, this work examines the seepage-pores contribution on core permeability by using classic geometry and thermodynamics fractal model. Moreover, a pore fractal permeability model was established to acquire the seepage-pores permeability, which can be used to interpret the permeability evolution of coals during coalification. Coal pore surfaces generally have very high heterogeneity with fractal dimension of 2.75-2.96 from thermodynamics model $$(D_{\mathrm{ts}})$$ , which presents a cubic polynomial relation with coal rank. The fractal dimensions from thermodynamics model show a consistent result, which indicates that the pore size/volume distribution was one of the key parameters affecting seepage-pores permeability. Finally, an ideal coal permeability (including seepage-pores and fractures contributed) evolution model during coalification was proposed and the seepage-pores contributed permeability generally covers $$\sim $$ 10 to $$\sim $$ 30 % of the entire coal permeability. [ABSTRACT FROM AUTHOR]

Coal fines are commonly generated as by-product during coalbed methane production mainly due to the interaction of coal with inseam water flow. A portion of the created coal fines may settle and plug the coal cleats and hydraulic fractures due to the gravity and coal pore size constraint. This could result in the reduction of coal permeability and blockage of coalbed methane wells or gas drainage boreholes. Despite the increasing awareness of the importance of understanding coal fines, limited research has been carried out on the characterization of coal fines creation. This study aimed to numerically characterize the generation process of coal fines in micro-scale coal cleats. The Scanning Electron Microscopy (SEM) images for a coal sample from Bulli Seam of the Sydney Basin in Australia were obtained and analysed to determine the actual cleat geometries and the characteristics of coal fines distribution. Then a fully coupled fluid-structure numerical model was developed to identify the creation process of coal fines at micro-scale. The impact of pertinent production conditions on coal fines generation was studied, including production pressure drawdown, temperature, coal fines Young's modulus and strength. The SEM images revealed that the particle size distributions of the coal fines in the examined cleats were in the order of hundreds of nanometres to several microns. The results of the numerical studies showed the coal fines production increased with pressure build-up, and decreased with increasing coal fines strength with more sensitivity compared with pressure. Critical values for production pressure drawdown were obtained, above which failure area began to expand; threshold values were also determined, below which remarkable reduction of coal fines production was achieved. Coal cleat geometry plays an important role in determining coal fines production. It was noted that exposed microstructures, cleat elbow regions and micro-fracture tips are more likely to generate coal fines. Based on these findings, guidance can be provided on the control of production conditions to mitigate coal fines issue, and new insight into where and how coal fines are created by inseam water flow can be achieved. [ABSTRACT FROM AUTHOR]

Shales have complex microscopic pore structures which significantly affect shale gas production. Effects of microscopic pore structure on flow regimes have been widely investigated. The pressure dependent permeability in shales has been also observed in laboratory and it may cause more significant variation in apparent permeability than flow regimes does. Therefore, numerical models combining flow regimes and pressure dependent permeability are required to describe the gas flow behaviour in shales. In this study, based on literature experimental observations, a numerical simulation model for shale gas transport was built. The model includes the main gas flow characteristics in shale: (1) sequential flow process of different flow regimes for different pores; (2) variation of apparent permeability resulted from both flow regimes and stress variation in shale; (3) permeability change with respect to strain. Nine sets of literature experimental data were used to verify this numerical simulation model, which was shown to be able to accurately describe the data. Using this numerical simulation model, shale gas flow behaviour was analysed and the following conclusions were found: (1) the effect of shale deformation on gas production is significant. Compared with other factors, it is a considerably important factor controlling the apparent permeability evolution during shale reservoir depletion; (2) natural fracture plays a significant role in gas transport inside reservoirs. Although its porosity is much less than those of other pores, it could obviously enhance shale gas recovery rate because of its higher permeability; (3) natural fracture permeability, natural fracture porosity, inorganic pores permeability and Young's modulus have positive correlations with shale gas recovery rate. However, the percentage of adsorbed gas has a negative correlation with shale gas recovery rate. [ABSTRACT FROM AUTHOR]

Reservoir rocks for water, oil and natural gas, as well as for CO 2 storage are often anisotropic in permeability, due to different pore or layering structures in different directions. Therefore, anisotropic permeability is an important parameter to measure when analysing fluid flow performance in reservoirs. Permeability is commonly measured using a triaxial cell, and anisotropic permeability is often traditionally measured using subcored cylindrical samples from a recovered core. However, the sample's heterogeneity can significantly affect the test results. Cubic samples can eliminate the effect of heterogeneity when measuring anisotropic permeability, but sealing is a major challenge that limits the use of this technique. In this work, a 3D-printed membrane was made to hold cubic shale sample. The cubic sample and 3D-printed membrane assembly which simulate a normal cylindrical core was then installed in a rubber sleeve for permeability measurement in a triaxial cell. Re-orienting the sample in the triaxial cell enabled permeability measurements along each directional axis. Using helium gas to demonstrate the technique, our results show that the shale sample taken from the Longmaxi Formation in Sichuan Basin, China has strong permeability anisotropy, with permeability perpendicular to bedding about 4% of that parallel to bedding. Through reservoir simulation using different permeabilities, we demonstrate that anisotropic permeability has a large impact on modelling gas production, suggesting that anisotropic permeability should be routinely measured and applied to the modelling of fluid flow in reservoir rocks with high permeability anisotropy, such as shales. Our measurement technique can be readily applied to any existing triaxial rigs and will benefit future reservoir evaluation and characterisation. [ABSTRACT FROM AUTHOR]

Although permeability data for different gas shales have been reported previously and attempts have been made to match permeability with empirical correlations, theoretical studies of shale permeability modelling are lacking. In this work, the correlation between fracture permeability and effective stress is established for gas shales through theoretical derivation. This model is able to match the permeability data for different gas shales. The matching results for the gas shale studied show that the model coefficient, fracture compressibility, which decreases as initial shale permeability increases, is strongly affected by the flow directions and varies with the shale’s mineralogical composition. Furthermore, the correlation between fracture permeability and reservoir pressure has also been established. Sensitivity study shows that fracture permeability may decrease significantly with the reservoir pressure drawdown. Moreover, the horizontal fracture permeability drop is found to be significantly affected by the Young’s modulus’ anisotropic ratio ( E h / E v ). The insights gained warrant further theoretical and experimental studies to evaluate shale fracture permeability. [ABSTRACT FROM AUTHOR]

An in depth comparison of four permeability models, Palmer and Mansoori (P&M) model, Shi and Durucan (S&D) model, Cui and Bustin (C&B) model and the improved P&M model, developed under uniaxial strain conditions prevailing in coalbed reservoirs, was carried out focusing on the relative influence of the matrix shrinkage term over the compaction term in each model. The ratio of the coefficients of the two terms is shown to have a direct impact on the magnitude of permeability rebound pressure, which is a key parameter controlling the modelled response of coalbed permeability to reservoir drawdown. P&M model and C&B model are found to yield essentially the same permeability rebound pressure, which is significantly lower than that given by S&D model. Cleat porosity change in P&M model has been shown to be controlled by the effective mean stress, indicating that it is essentially a mean stress model (as C&B model). With the introduction of an empirical parameter g (< 0.3) in the model equations to suppress the pressure-dependent effect on permeability, the improved P&M model gives rise to a permeability rebound pressure much larger than the original model does. The performances of the three models are evaluated with reference to a set of recently published horizontal stress and permeability data measured under uniaxial strain conditions to simulate field conditions. The same set of data has been successfully matched using S&D model in an earlier study by the authors. The modelling results in this study show that both C&B and P&M models fail to capture the overall rising trend in the measured permeability, subject to the constraint of the horizontal stress variation recorded under uniaxial strain conditions. This may be attributed to the fact that the total horizontal stress varied with the pore pressure under the uniaxial strain conditions, whereas the total vertical stress remained unchanged during the test. The inability of C&B and P&M models to describe the laboratory permeability data obtained under simulated field conditions, in contrast to the performance of S&D model, suggests that the permeability response of coalbed reservoirs to pore pressure depletion is controlled predominantly by the effective horizontal stress, rather than the effective mean stress. [ABSTRACT FROM AUTHOR]

Abstract: In coal permeability models, it is normally assumed that coal matrix pressure is equalized with the fracture pressure (local equilibrium). In this assumption, coal swells uniformly under constant confining (total) stress conditions commonly used in laboratory measurements. Under these conditions, a uniform swelling will not change the fracture aperture for a matchstick model where only two sets of vertical fractures cut through the whole matrix blocks. However, a uniform swelling changes both the fracture aperture and the spacing (the coal bridge swelling increases the fracture aperture while the matrix swelling changes the spacing only) for a fractured coal model, where fractures do not create a full separation between adjacent matrix blocks but where solid coal bridges are present, is used. Therefore, coal permeability remains unchanged for a matchstick model or increases slightly due to the coal bridge swelling under common laboratory conditions. These conclusions are directly contradictory with most laboratory observations in the literature. This direct contradiction suggests that the local equilibrium condition has not been achieved under common laboratory conditions. If this was the case, the current local equilibrium assumption based approach would be inappropriate for the analysis of laboratory measurements. In our previous studies, we introduced a concept of matrix swelling transition from local to global under stress conditions. In this concept, we recognized the fact that coal permeability evolves as a function of time from the initial equilibrium state (both matrix pressure and fracture pressure are equal to the initial reservoir pressure) to the final equilibrium state (both matrix pressure and fracture pressure are equal to the injection pressure). In this study, we extended this concept to the most complex situations where multiple processes (thermal transport, gas transport and coal deformation) are involved. Based on the concept of matrix swelling transition, we introduced a new concept of Critical Swelling Area that defines the relationship between swelling transition and coal permeability evolution. The combination of swelling transition and Critical Swelling Area concepts can explain why adsorptive types of gas injection reduces coal permeability in the early stage of the injection and may rebound later. [Copyright &y& Elsevier]

Abstract: Coal permeability models based on constrained conditions such as constant volume theory can successfully match unconstrained experimental data and field observations. However, these models have a boundary mismatch because the boundary of permeability models is constrained while experiment boundary is free displacement or unconstrained. What the mechanism is to require such a boundary mismatch has not been well understood. In this study, a full coupled approach was developed to explicitly simulate the interactions of coal matrixes and fractures. In this model, a matrix-fracture model is numerically investigated after incorporating heterogeneous distributions of Young's modulus, Langmuir strain constant in the vicinity of the fracture. The impact of these local heterogeneities of coal mechanical and swelling properties on the permeability evolution is explored. The transient permeability evolution during gas swelling process is investigated and the difference between the final equilibrium permeability and transient permeability is compared. With the heterogeneity assumption, a net reduction of coal permeability is achieved from the initial no-swelling state to the final equilibrium state. This net reduction of coal permeability increases with the fracture (injection) pressure and is in good agreement with laboratorial data under the unconstrained swelling conditions. Coal local heterogeneity in vicinity of fracture can therefore be the mechanism of the above mismatch. [Copyright &y& Elsevier]

Abstract: In this work, the conventional relative permeability model for two phase flow in porous media is improved to describe the relative permeability for coal. The fracture geometry is considered through applying the matchstick model, instead of the bundle of capillary tubes model which is often used as the conceptual model for conventional porous media, to derive the relative permeability model. The effect of porosity change on relative permeability for coal is taken into account by introducing a residual phase saturation model and a shape factor as functions of permeability ratio. In the improved model, the relative permeability is dependent on both the phase saturation and the porosity (or permeability) change. This improved model shows a strong capability to match the experimental data for different coal relative permeability measurements. Furthermore, we evaluate the relative permeability models as a unary function of wetting phase saturation and as a binary function of wetting phase saturation and permeability ratio in a coupled numerical model for water–gas flow in coal seams. The results illustrate that the relative permeability change due to the porosity change can significantly affect the evolution of wetting phase saturation and the gas production rate. [Copyright &y& Elsevier]

Abstract: Although the influence of cross couplings between coal deformation, gas flow and thermal transport has been widely recognized, their impacts on the evolution of coal permeability are still not well understood. CO2 may be injected at −40°C, 60°C lower than that of the targeted coal seams for sequestration. Under these injection conditions, coal matrix may swell due to the thermal expansion and shrink due to the change in adsorption capacity. This uncertainty of swelling/shrinking complicates the prediction of coal permeability. In this study, a fully coupled coal deformation, gas flow and transport, and thermal transport model is developed to evaluate the complex evolution of coal permeability under the combined influence of variable gas pressure and temperature. These combined effects are evaluated through explicit simulations of the dynamic interactions between coal matrix swelling/shrinking and fracture aperture alteration, and translations of these interactions to the evolution of coal permeability. The fully coupled model is applied to evaluate why coal permeability changes instantaneously from reduction to enhancement under the free swelling condition as widely reported in the literature. Our results have revealed the transition of coal matrix swelling from local swelling to macro-swelling as a novel mechanism for the simultaneous switching of coal permeability from the initial reduction to the late recovery. At the initial stage of CO2 injection under variable temperatures, matrix swelling due to gas sorption, thermal expansion and the change in adsorption capacity is localized within the vicinity of the fracture compartment. As the injection continues, the swelling zone is widening further into the matrix and the swelling becomes macro-swelling. When the swelling is localized, coal permeability is controlled by the internal fracture boundary condition and behaves volumetrically; when the swelling becomes macro-swelling, coal permeability is controlled by the external boundary condition. [Copyright &y& Elsevier]

Abstract: Coal permeability is usually anisotropic and the permeability anisotropy ratio along the face cleats to the butt cleats can be up to 17:1 for some coals. The characteristic of the anisotropic coal permeability and its impact on the optimal well design for coalbed methane (CBM) production are important, but have not been well studied. This paper investigates this issue through numerical modeling and reservoir simulations. Various case studies are performed on the two commonly used multi-lateral well patterns including the quad-lateral well and the pinnate lateral well to investigate the impact of permeability anisotropy ratio on the layout of the multi-lateral well. The results demonstrate that the optimal well direction of the quad-lateral well is parallel to the butt cleat direction as expected. However, the optimal main well angle of the pinnate lateral well is significantly affected by the permeability anisotropy ratio. The orientations of the branches of the pinnate lateral well are less sensitive than the branch numbers and this indicates that more gas recovery efficiency can be effectively achieved by drilling more branches but not by varying the branch orientations. These conclusions are drawn by using a widely used stress-based permeability model with the fixed permeability anisotropy ratio. In order to investigate the permeability anisotropy change during the CBM production, a strain-based and a stress-based coal permeability models for isotropic condition are improved to incorporate the permeability anisotropy and to quantitatively study the impact of permeability anisotropy ratio change on lateral well pattern. In order to be consistent with the previous permeability model, we implement the improved stress-based model into the reservoir simulation model. The results show that the permeability anisotropy is not only caused by the initial differences in structure and tortuosity of the coal cleats in the two directions, but also induced by the anisotropic mechanical and swelling properties during the CBM production. The permeability anisotropy ratio change during production may also have a significant impact on the optimal design of the multi-lateral well. [Copyright &y& Elsevier]

Abstract: A series of coal permeability experiments was conducted for coal samples infiltrated both with non-adsorbing and adsorbing gases – all under conditions of constant pressure difference between the confining stress and the pore pressure. The experimental results show that even under controlled stress conditions, coal permeability decreases with respect to pore pressure during the injection of adsorbing gases. This conclusion is apparently not congruent with our conceptual understanding: when coal samples are free to swell/shrink then no effect of swelling/shrinkage strain should be apparent on the permeability under controlled stress conditions. In this study, we developed a phenomenological permeability model to explain this enigmatic behavior of coal permeability evolution under the influence of gas sorption by combining the effect of swelling strain with that of the mechanical effective stress. For the mechanical effective stress effect, we use the concept of natural strain to define its impact on the change in fracture aperture; for the swelling strain effect, we introduce a partition ratio to define the contribution of swelling strain to the fracture aperture reduction. The resulting coal permeability model is defined as a function of both the effective stress and the swelling strain. Compared to other commonly used models under specific boundary conditions, such as Palmer–Mansoori (P–M), Shi–Durucan (S–D) and Cui–Bustin (C–B) models, our model results match the experimental measurements quite well. We match the experimental data with the model results for the correct reason, i.e. the model conditions are consistent with the experimental conditions (both are stress-controlled), while other models only match the data for a different reason (the model condition is uniaxial strain but the experimental condition is stress-controlled). We have also implemented our permeability model into a fully coupled coal deformation and gas transport finite element model to recover the important non-linear responses due to the effective stress effects where mechanical influences are rigorously coupled with the gas transport system. [Copyright &y& Elsevier]

Abstract: As with other reservoir types permeability is a key controlling factor for gas migration in coalbed methane reservoirs. The absolute permeability of coal reservoirs changes significantly during gas production, often initially decreasing but then increasing as the reservoir pressure and gas content is drawn down. It has also been observed to decrease markedly during CO2 injection to enhance coalbed methane recovery. In order to predict gas migration models for coal permeability must represent the mechanisms leading to these observed behaviours. The permeability of coal reservoirs behaves in a similar fashion to other fractured reservoirs with respect to effective stress, decreasing exponentially as the effective stress increases. However a unique effect of coal is that it shrinks with gas desorption and swells with adsorption. Within the reservoir this swelling/shrinkage strain leads to a geomechanical response changing the effective stress and thus the permeability. Modelling coal permeability incorporating the impacts from both effective stress and coal swelling/shrinkage dates back about 25years. Since then a number of permeability models have been developed. In recent years this topic has seen a great deal of activity with a growing body of research on coal permeability behaviour and model development. This article presents a review of coal permeability and the approaches to modelling its behaviour. As an important part of this, the field and laboratory data used to test the models are reviewed in detail. This article also aims to identify some potential areas for future work. [Copyright &y& Elsevier]

Abstract: Permeability is one of the most important parameters for CO2 injection in coal to enhance coalbed methane recovery. Laboratory characterization of coal permeability provides useful information for in situ permeability behavior of coal seams when adsorbing gases such as CO2 are injected. In this study, a series of experiments have been conducted for coal samples using both non-adsorbing and adsorbing gases at various confining stresses and pore pressures. Our observations have showed that even under controlled stress conditions, coal permeability decreases with respect to pore pressure during the injection of adsorbing gases. In order to find out the causes of permeability decrease for adsorbing gases, a non-adsorbing gas (helium) is used to determine the effective stress coefficient. In these experiments using helium, the impact of gas sorption can be neglected and any permeability reduction is considered as due to the variation in the effective stress, which is controlled by the effective stress coefficient. The results show that the effective stress coefficient is pore pressure dependent and less than unity for the coal samples studied. The permeability reduction from helium experiments is then used to calibrate the subsequent flow-through experiments using adsorbing gases, CH4 and CO2. Through this calibration, the sole effect of sorption-induced strain on permeability change is obtained for these adsorbing gas flow-through experiments. In this paper, experimental results and analyses are reported including how the impact of effective stress coefficient is separated from that of the sorption-induced strain on the evolution of coal permeability. [Copyright &y& Elsevier]

Abstract: Coal swelling/shrinkage during gas adsorption/desorption is a well-known phenomenon. For some coals the swelling/shrinkage shows strong anisotropy, with more swelling in the direction perpendicular to the bedding than that parallel to the bedding. Experimental measurements performed in this work on an Australian coal found strong anisotropic swelling behaviour in gases including nitrogen, methane and carbon dioxide, with swelling in the direction perpendicular to the bedding almost double that parallel to the bedding. It is proposed here that this anisotropy is caused by anisotropy in the coal''s mechanical properties and matrix structure. The Pan and Connell coal swelling model, which applies an energy balance approach where the surface energy change caused by adsorption is equal to the elastic energy change of the coal solid, is further developed to describe the anisotropic swelling behaviour incorporating coal property and structure anisotropy. The developed anisotropic swelling model is able to accurately describe the experimental data mentioned above, with one set of parameters to describe the coal''s properties and matrix structure and three gas adsorption isotherms. This developed model is also applied to describe anisotropic swelling measurements from the literature where the model was found to provide excellent agreement with the measurement. The anisotropic coal swelling model is also applied to an anisotropic permeability model to describe permeability behaviour for primary and enhanced coalbed methane recovery. It was found that the permeability calculation applying anisotropic coal swelling differs significantly to the permeability calculated using isotropic volumetric coal swelling strain. This demonstrates that for coals with strong anisotropic swelling, anisotropic swelling and permeability models should be applied to more accurately describe coal permeability behaviour for both primary and enhanced coalbed methane recovery processes. [Copyright &y& Elsevier]

Abstract: Geological storage of CO2 is a viable option for the mitigation of greenhouse gas emissions. Formations such as saline aquifers and coal seams have distinct storage mechanisms; in saline aquifers, the CO2 is mainly stored by compression and/or dissolution in the formation fluid, whereas in coal seams, the CO2 is primarily stored by adsorption. To investigate the impact of CO2 dissolution in formation fluid on CO2 storage in coal and enhanced coalbed methane production, two scenarios are considered (1) CO2 injection and coalbed methane production for a single coal seam, (2) CO2 injection in two coal seams with an aquifer in-between while coalbed methane is produced in the upper coal seam. It is found that although CO2 dissolution in formation water is not the main storage mechanism in coal reservoirs, including CO2 dissolution can lead to significant differences in the simulation results. In addition, including CO2 dissolution leads to more accurate description of the ECBM process through more accurate prediction of water saturation and thus the gas effective permeability, the overall reservoir pressure and gas flow response to CO2 injection. The results also suggest that for CO2 storage in lower rank coals, which usually have higher porosity and permeability, CO2 dissolution in the formation water should be considered in order to more accurately describe the CO2 storage and ECBM behaviour. The results also show that water containing formations in between the coal seams, although often low in porosity and thus insignificant in overall CO2 storage capacity, also have a significant impact on the overall CO2 storage and enhanced coalbed methane recovery behaviours when considering CO2 dissolution modelling in formation waters. [Copyright &y& Elsevier]

Abstract: Although the influence of gas sorption-induced coal deformation on porosity and permeability has been widely recognized, prior studies are all under conditions of no change in overburden stress and effective stress-absent where effective stresses scale inversely with applied pore pressures. Here we extend formalism to couple the transport and sorption of a compressible fluid within a dual-porosity medium where the effects of deformation are rigorously accommodated. This relaxes the prior assumption that total stresses remain constant and allows exploration of the full range of mechanical boundary conditions from invariant stress to restrained displacement. Evolution laws for permeability and related porosity are defined at the micro-scale and applied to both matrix and an assumed orthogonal, regular and continuous fracture system. Permeability and porosity respond to changes in effective stress where sorption-induced strains may build total stresses and elevate effective stresses. Gas accumulation occurs in both free- and adsorbed-phases and due to effective grain and skeletal compressibilities. A finite element model is applied to quantify the net change in permeability, the gas flow, and the resultant deformation in a prototypical coal seam under in situ stresses. Results illustrate how the CO2 injectivity is controlled both by the competition between the effective stress and the gas transport induced volume change within the matrix system and by the dynamic interaction between the matrix system and the fracture system. For typical parameters, initial injection-related increases in permeability due to reduced effective stresses may endure for days to years but are ultimately countered by long-term reductions in permeability which may decline by an order of magnitude. Models suggest the crucial role of stresses and the dynamic interaction between matrix and fractures in correctly conditioning the observed response. [Copyright &y& Elsevier]

Abstract: Coal permeability is highly sensitive to the stress. Meanwhile, coal swells with gas adsorption, and shrinks with gas desorption. Under reservoir conditions these strain changes affect the cleat porosity and thus permeability. Coal permeability models, such as the Palmer and Mansoori and Shi and Durucan models, relate the stress and swelling/shrinkage effect to permeability using an approximate geomechanical approach. Thus in order to apply these models, stress–permeability behaviour, swelling/shrinkage behaviour and the geomechanical properties of the coal must be estimated. This paper presents a methodology for the laboratory characterization of the Palmer and Mansoori and Shi and Durucan permeability models for reservoir simulation of ECBM and CO2 sequestration in coal. In this work a triaxial cell was used to measure gas permeability, adsorption, swelling and geomechanical properties of coal cores at a series of pore pressures and for CH4, CO2 and helium with pore pressures up to 13MPa and confining pressures up to 20MPa. Properties for the permeability models such as cleat compressibility, Young''s modulus, Poisson''s ratio and adsorption-induced swelling are calculated from the experimental measurements. Measurements on an Australian coal are presented. The results show that permeability decreases significantly with confining pressure and pore pressure. The permeability decline with pore pressure is a direct result of adsorption-induced coal swelling. Coal geomechanical properties show some variation with gas pressure and gas species, but there is no direct evidence of coal softening at high CO2 pressures for the coal sample studied. The experimental results also show that cleat compressibility changes with gas species and pressure. Then the measured properties were applied in the Shi and Durucan model to investigate the permeability behaviour during CO2 sequestration in coal. [Copyright &y& Elsevier]

Proppants hold fractures open and increase fracture conductivity but must survive and remain functional during pressure drawdown. The shale reservoir usually suffers a high effective stress during gas depletion whilst most previous experiment works are conducted under a relative low stress level. In this work, permeability evolution was explored in a proppant-supported natural fracture of Longmaxi shale from the Sichuan Basin, China under a large effective stress range (1.5–59.5 MPa). Proppant performance was examined via continuous permeability measurements and by optical microscopy and laser-classifier measurements of particle size distributions (PSD) recored both pre- and post-loading. The permeability of the propped shale fracture is two orders of magnitude higher than that of the non-propped fracture and strongly controlled by the proppant behaviour. Surprisingly, overall permeability of the proppant pack decreases with an increase in thickness of the enclosed proppant. The decrease in the permeability with high stresses is largest for unpropped fractures and decreases with an increase in the number of layers. Most important, the mean compressibility of the non-propped and propped fracture is not constant but reduces with an increase in confining stress. This indicates that the compaction, crushing, embedment and repacking of the proppant particles, because of high effective stress, resulting in a decrease in the porosity of the proppant pack further reducing the compressibility and permeability of the supported fracture. • Permeability evolution was explored in a proppant-supported natural fracture under high (1.5–59.5 MPa) effective stress. • Proppant performance was examined via permeability measurements and particle size distributions (PSD) recored. • Overall permeability of the proppant pack decreases with an increase in thickness of the enclosed proppant. • The mean compressibility of the non-propped and propped fracture reduces with an increase in confining stress. [ABSTRACT FROM AUTHOR]

Microwave heating fracturing is potentially a green stimulation technology for gas shale recovery. However, the mechanism together with permeability evolution of microwave irradiated reservoir remain unclear. To fill this knowledge gap, the responses of Longmaxi shale from the Sichuan Basin, southwest China, to both continuous and intermittent microwave stimulation along variable microwave heating paths were explored. A complex thermally-induced fracture network can be formed gradually without sudden collapse under intermittent microwave irradiation. Changes in the petrophysical parameters of the shale including wave velocity, weight and volume at different intermittent microwave irradiation steps were measured together with temperature variation. The evolution of permeabilities for the two shale samples with alternately parallel and vertical beddings at different effective stresses was analyzed both before and after microwave irradiation. After the last step of intermittent microwave irradiation in this study, the shale permeability increased by two to four orders of magnitude for the shale sample with flow parallel to bedding and one to two orders of magnitude with flow perpendicular to bedding. Microwave treatment accentuates the anisotropy between bedding-parallel and bedding-normal permeabilities. Evolving pore size was measured by high-pressure mercury porosimetry and thermal-induced fracture characteristics and the changes of mineral composition were characterized by SEM combined with Energy Dispersive Spectroscopy (EDS). Thermally- and chemically-induced swelling stresses are mainly responsible for the development of fractures and micro-porosity in the shale. A permeability model with variable compressibility coefficient was adopted to fit the experimental data for shale permeability across a wide range of effective stresses from 2.5 MPa to 59.5 MPa. Shale fracture compressibility decreases in the later stage of microwave irradiation, suggesting the hardening of thermal-induced fractures. • Response of Longmaxi shale to variable microwave heating paths were explored. • The evolutions of permeabilities were analyzed both before and after microwave radiation. • A complex heating-induced fracture network was generated under the intermittent microwave radiation. • After microwave irradiation, the shale permeability increased by two to four orders of magnitude. • Microwave treatment accentuated the anisotropy between bedding-parallel and bedding-normal permeabilities. [ABSTRACT FROM AUTHOR]

The prediction of rock permeability is important in the extraction of oil/gas from tight reservoirs. Permeability is determined by connected pores and their distribution in rocks. The existence of pore can induce stress concentration around pore surface which affects pore strains. In common permeability models, volumetric pore strains are used to quantify the permeability evolution during gas production but pore strain solutions exclude the impact of stress concentration. In this study, the stress concentration around pore surface was considered and corresponding pore surface displacements were calculated. Different from solutions of volumetric pore strain, solutions of stress concentration and pore surface displacement have close relationship with pore geometry. Based on SEM images of tight rocks, the pore shape was assumed as ellipse. An analytical solution for the surface displacement of an ellipse pore was derived and substituted into the permeability definition. Different from common permeability models, this novel permeability model includes pore geometry property. This geometry-based permeability model was verified by experimental data. The comparison between the common model and this geometry-based model was also conducted. The sensitivity study was conducted to investigate impacts of pore geometry and stress variation on permeability evolution. It was illustrated that this geometry-based model is valid and its performance of permeability prediction for tight rocks is better than that of common model. This is because the important factors, such as pore geometry size and stress orientation, are incorporated explicitly. The advantage of this geometry-based model is that the impact of stress orientation (α) on permeability is involved so this geometry-based model is able to predict permeability of reservoirs after hydraulic fracturing where the stress orientation commonly changes. • Impact of stress concentration on permeability is considered by geometry-based permeability model for ellipse pore. • This geometry-based permeability includes extra factors of pore shape, pore geometry size and stress orientation. • Stress vertical to long semiaxis plays a significant role in permeability evolution. • Impact of pore shape on permeability increases with ratio of long semiaxis to short semiaxis. • The stress orientation also affects permeability. [ABSTRACT FROM AUTHOR]

Breakthrough pressure is a key parameter of the caprock sealing ability for gas reservoirs. It has also become an important parameter for gas production from tight reservoirs, such as shale gas reservoirs, as water in these tight formations may require gas to overcome the breakthrough pressure before being produced. Laboratory measurement is essential to obtain the breakthrough pressure because no field methods can accurately estimate it. In this review article, the definition, the experimental methods, and experimental data for breakthrough pressure on tight rocks are reviewed. The advantages and issues of each experimental method are discussed. Furthermore, the relationships between breakthrough pressure and rock properties, especially its permeability, are investigated. It is found that breakthrough pressure has a close relationship with pore structure and most of the experimental data show that it has a power law relationship with absolute permeability. Moreover, water saturation, gas type, and effective stress are all found to have an impact on the breakthrough pressure. Finally, future research topics are proposed, including investigating sample length on breakthrough pressure measurement and developing more theoretically based models for breakthrough pressure with regards to absolute permeability or other measurable rock properties. • Experimental methods on directly measuring breakthrough pressure are reviewed and compared. • Literature data using direct methods were reviewed and summarised. • Power law relationship between breakthrough pressure does not hold for many rocks. • Breakthrough pressure is related to the gas used and effective stress. [ABSTRACT FROM AUTHOR]

Gas apparent permeability is an important parameter for gas flow in the reservoir rocks. It is higher than the absolute permeability measured using liquid. The Klinkenberg equation corrects the liquid permeability to the apparent gas permeability allowing for the pressure dependent effects of interactions between gas molecules and pore walls. However, in this paper it is shown that Klinkenberg equation does not apply for gas flow in the near critical region for real gases. This has important implications for a number of reservoir management applications including carbon geosequestration and gas condensate reservoirs. In this paper, a series of permeability measurements with respect to pressure and temperature are presented on sandstone core samples using carbon dioxide (CO 2), ethane (C 2 H 6) and helium (He). The experimental results show that the apparent permeability is enhanced in the near-critical region. CO 2 apparent permeability at 311 K (critical temperature of 304.25 K) increases about 2.24 times from 7.18 MPa to 8.6 MPa (critical pressure of 7.37 MPa) on the Sandstone Sample M1 and 1.83 times on the Sandstone Sample M2 for the same pressure change. C 2 H 6 apparent permeability at 311 K (critical temperature of 305.35 K) increases 1.83 times from 4.6 MPa to 5.4 MPa (critical pressure of 4.9 MPa) on the Sandstone Sample M1 and 1.59 times on the Sandstone Sample M2 for the same pressure change. These results suggest that the permeability enhancement is stronger for the lower permeability sample. Moreover, the experimental results show that enhancement decreases as temperature increases. Modelling work shows that applying Klinkenberg equation is invalid for describing the apparent gas permeability in near critical region, even with attempts to use different equations to calculate the mean free path required in the Klinkenberg equation. A dual mechanism model, which simultaneously considers convection flow and molecular diffusion, is modified allowing the gas diffusivity to be a function of gas density and it can well describe the gas apparent permeability in the near critical region. It is suggested that the flow is in the viscous flow regime or weak slip flow regime for the near critical gas on the sandstone samples studied in this work, and the enhancement of permeability in the near critical region is attributed to the higher density (concentration) gradient with respect to pressure. • Gas apparent permeability at near the critical region is studied for CO 2 and C 2 H 6 experimentally. • Gas apparent permeability enhanced greatly in near critical region in relation to gas properties. • Klinkenberg correction is found not able to describe this behaviour. • Convection with diffusion is the main cause for the permeability enhancement. [ABSTRACT FROM AUTHOR]

Tectonic coal, formed after the intact coal being subjected to long-term intense squeezing, shearing and deformation, is characterised by brittle or ductile damaged coal body, with the characteristics of low cohesion, low strength and low permeability. Most of the outburst accidents in China occurred in tectonic coal seams due to the difficulties in gas drainage. In this review article, reservoir properties, including pore structure, adsorption, diffusion, permeability and geomechanical properties of the tectonic coal are reviewed in detail and compared with those of the intact coal, as these properties are important for gas drainage. It was found that tectonic coal in general shows larger total pore volume and specific surface area than intact coal for larger pores due to tectonism, however, no significant difference is observed in smaller pores due to the combined opposing effects of metamorphism and tectonism. Diffusion coefficient of tectonic coal is generally higher than that of intact coal, and tectonic coal typical has higher adsorption capacity than intact coal. Compressive strength and elasticity modulus are smaller for tectonic coal than intact coal. Field permeability of tectonic coal is obviously lower than that of intact coal, which is on the contrary to the experimental results from laboratory. It was found that using reconstituted samples for tectonic coal in the laboratory is the main cause for this discrepancy between field and laboratory observations. It is suggested that more work is required on tectonic coal and a few research areas are proposed for future research. [ABSTRACT FROM AUTHOR]

Transformation of pore and fracture structure of coals with supercritical CO 2 (scCO 2) –H 2 O is a key to CO 2 injection and CH 4 production efficiencies during the CO 2 enhanced coalbed methane process. To study the transformation of pores and fractures in the coals with CO 2 , two reservoir conditions, which simulate1000m (45 °C, 10 MPa) and 2000 m (80 °C, 20 MPa) depths, are applied to four types of high metamorphic coals from Qinshui Basin to study the influences of temperature and pressure on pore volume and pore sized distribution change. Nuclear magnetic resonance, high pressure mercury intrusion, X-ray CT scanning and permeability experiments are performed and the effects of scCO 2 on coal permeability and the influencing factors are discussed. The results show that scCO 2 -H 2 O has a positive effect on the improvement on the pore fracture system. It could add or expand pores and fractures, leading to the increase in pore number, porosity, pore volume, pore specific surface area, connected pore volume, and pore throat number. And then, increased the permeability which had a positive correlation with the experimental temperature and pressure. The growth of permeability could be as high as 114.10 times, and it was higher in horizontal to bedding direction than that of the vertical to bedding direction. Coal expansion could lead to the addition and enlargement of micro-fractures and enhance the connectivity between seepage pores and fractures. Mineral dissolution could lead to the formation of a large number of effectively connected and non-effectively connected pores, especially the latter, which was positively correlated with simulated temperature and pressure. In addition, the effectively connected pores tend to develop in vertical original micro-fractures. Moreover, the more complete the reaction is, the more favorable it is to increase the pore volume of fractures. [ABSTRACT FROM AUTHOR]

In this study, a general shale apparent permeability model under the influence of gas sorption was derived based on the theory of poroelasticity. Unlike previous models, the impact of gas adsorption-induced swelling strain was treated as a local phenomenon. This was achieved through the introduction of an internal strain. The internal strain is directionally proportional to the swelling strain. The proportional coefficient has a clear physical meaning and is defined as the ratio of the Langmuir strain constant for shale matrix to the product of the Langmuir strain constant for shale bulk and the shale porosity. The general permeability model was degenerated into a set of specific shale permeability models under common experimental conditions: (1) constant effective stress; (2) constant pore pressure; and (3) constant confining stress. Nineteen groups of experimental data in the literature were used to verify the validity of those models: three for the boundary condition of constant effective stress; five for the condition of constant pore pressure; and eleven for the boundary condition of constant confining stress. The successful matches of these nineteen groups of experimental data with our model results demonstrate the validity of our general shale permeability. These models can be used to analyze the experimental observations of shale permeability under a spectrum of boundary conditions from constant confining stress to constant pore pressure. [ABSTRACT FROM AUTHOR]

The goal of this study is to investigate how coal matrix strains affect the evolution of coal permeability. In previous studies, this impact was quantified through splitting the matrix strain into two parts: one contributes to the internal swelling while the other to the global strain. It was assumed that the difference between the internal swelling strain and the swelling strain of matrix determines the evolution of fracture permeability through a constant splitting factor. This assumption means that the impact of internal swelling strain is always same during the whole gas injection/production process. This study extends this concept through the introduction of a strain splitting function that defines the heterogeneous distribution of internal swelling. The distribution function changes from zero to unity. Zero means that the internal swelling strain has no impact on permeability evolution while unity means 100% of the internal strain contributes to the evolution of coal permeability. Based on this approach, a new permeability model was constructed and a finite element model was built to fully couple the coal deformation and gas transport in coal seam reservoirs. The model was verified against three sets of experimental data under the condition of a constant confining pressure. Model results show that evolution of coal permeability under the condition of a constant confining pressure is primarily controlled by the internal strain at the early stage, by the global strain at the later stage, and by the strain splitting function in-between, and that the impact of the heterogeneous strain distribution on the internal swelling strain vanishes as the swelling capacity of matrix increases. [ABSTRACT FROM AUTHOR]

Hydraulic fracture is the main flow path for gas transport. The proppants are man-made material that filled in the hydraulic fractures to keep them open and allow gas flow through. The permeability change of hydraulic fracture is controlled by the combined effect of compaction and embedment. In this study, we modeled the proppant embedment as a function of effective stress by a transformed Hertz contact model and a proposed power law model which is analogous to the Oliver-Pharr model. The results illustrate that the power law relationship could better fit the experimental data, because the Hertz model becomes invalid when the embedment is large compared to the proppant size. By incorporating the power law correlation into an existing theoretical permeability model as a function of effective stress, a permeability model for the hydraulic fracture filled with proppant packs under combined effect of compaction and embedment is developed. The new model is able to adequately describe the permeability data of proppant packs confined by rock core slices. Although this study puts forward the theoretical basis of the hydraulic permeability modelling under combined effect of compaction and embedment, more fundamental studies are required to investigate the contact behaviour between the proppant packs and the fracture face under various conditions. Therefore, the permeability model could be further improved by introducing the new advanced proppant embedment correlations. [ABSTRACT FROM AUTHOR]

Commercial gas production has been achieved in China's marine shale of the Silurian Longmaxi formation in the eastern Sichuan area, and experience for developing shale gas in complex structural areas has been gathered. A set of Longmaxi Formation shales deposited in the northwestern Hunan area has close relationship with the eastern Sichuan Longmaxi shale on both depositional environment and tectonic evolution. Therefore, it is important to undertake an integrated evaluation of the Longmaxi formation shale in the northwestern Hunan area. This work combined field investigations and the laboratory measurements using outcrop samples to study the petrology, geochemistry, reservoir and adsorption characteristics of the Longmaxi shale in the northwestern Hunan area. The geological settings and reservoir properties were compared with those of the eastern Sichuan Longmaxi shale using publically available data. The results show that the hydrocarbon generation ability, organic matter maturity, sealing capacity and reservoir stimulation effectiveness of the Longmaxi Formation shale in the northwestern Hunan area are comparable to those in the eastern Sichuan area. The Longmaxi shale in the northwestern Hunan area therefore shows early signs of development potential, and the drilling of exploration wells is thus warranted to further evaluate its gas content and other in-situ reservoir properties for possible shale gas development in the near future. [ABSTRACT FROM AUTHOR]

The coal and coalbed methane (CBM) resources are abundant in western Guizhou and eastern Yunnan, South China. However, commercial CBM production in this region has not been achieved. Reservoir properties are the prerequisites in determining the possibility of CBM exploration and its development potential. Thus, to help to select the most favorable block and to prioritize CBM development in the study area, a comprehensive program of experimental work has been carried out to study the physical properties of coal reservoirs in different blocks. Experimental results show that the properties of coal reservoir change significantly with respect to coal rank, and the coal rank in the study area is very uneven, with the vitrinite reflectance ( R o ) of coal samples ranging from 0.68% to 3.31%. In detail, low rank coals have well developed seepage pores but undeveloped adsorption pores, resulting in the low adsorption capacity and high porosity and permeability. With burial depth increase, the metamorphic degree and compaction degree of coals grow accordingly, as a result pores and fractures are gradually closed under stress, leading to a sharp reduction of porosity and permeability in medium rank coals. However, most of the high rank coals in the study area have experienced a large number of tectonic thermal events, which not only increased the metamorphism degree and adsorption capacity, but also improved the porosity and permeability of the coal reservoirs. Based on experimental results, the CBM potentials of coal reservoirs in different blocks in the study area were evaluated using multi-objective and multi-level fuzzy optimization model, and the most prospective zones for CBM production were suggested. [ABSTRACT FROM AUTHOR]

Highlights: [•] Pore characterization using NMR under different confining pressures. [•] Pore compressibility calculation using NMR results. [•] A new pore compressibility model for coal reservoir. [Copyright &y& Elsevier]

Abstract: For the past decades the nuclear magnetic resonance (NMR) technology has gained acceptance as a petrophysical tool for evaluating reservoir properties. Comprehensive reservoir evaluation requires determination of irreducible fluids, movable fluids and permeability. Although the NMR petrophysical properties of coals have been studied for decades, the impact of heat on these properties (pore size distribution, pore structures, porosity and permeability) has not yet been systematically investigated. However, these are key properties for coalbed methane (CBM) generation and production. Therefore, they may have significant implications for the effects of heat from geothermal dynamics and magma intrusion on CBM concentration and transport in coals with different ranks. Thus, NMR experiments for samples treated at different temperatures (from 25°C to 375°C) were designed to study the variation of petrophysical properties of three Chinese coal cores with different ranks. Results show that NMR transverse relaxation (T 2) distributions of the water saturated cores strongly relate to the coal pore structure and coal rank. Furthermore, based on T 2 cutoff time method, five models for calculating the permeability of coals to water were evaluated. The results show that the Schlumberger Doll Research (SDR) model and its improved model provided the best estimation among the five models because these two models are generally able to represent the matrix permeability of the coal, based on the comparison between the results from measured gas permeability and NMR permeability models. Further calculations indicate that the porosity of all three different rank coals have an increasing trend with exposure to temperature, but with different increments for these coals. The low-volatile bituminous coal has the largest increment (9.44%), which is an improvement of more than 200% from its original porosity (4.02%). While the permeability has no similar trend for these three rank coals after heat treatment due to the strong heterogeneity of pore structure in coals. The results may suggest complex microfractures widths change for forming/closing at different heating stages. [Copyright &y& Elsevier]

Abstract: Coal permeability is sensitive to the effective stress and is therefore coupled to the geomechanical behaviour of the seam during gas migration. As coal shrinks with gas desorption and swells with adsorption, understanding this coupling to geomechanical behaviour is central to interpreting coal permeability. Existing coal permeability models, such as those proposed by Shi and Durucan (2004) and Palmer and Mansoori (1996), simplify the geomechanical processes by assuming uni-axial strain and constant vertical stress. However it is difficult to replicate these conditions in laboratory tri-axial permeability testing and during laboratory core flooding tests for enhanced coal bed methane. Often laboratory tests involve a hydrostatic stress state where the pressure in the confining fluid within the tri-axial cell is uniformly applied to the sample exterior. In this experimental arrangement the sample is allowed to undergo tri-axial strain. This paper presents two new analytical permeability model representations, derived from the general linear poroelastic constitutive law, that include the effects of tri-axial strain and stress for coal undergoing gas adsorption induced swelling. A novel approach is presented to the representation of the effect of coal sorption strain on cleat porosity and thus permeability. This involves distinguishing between the sorption strain of the coal matrix, the pores (or cleats) and the bulk coal. The developed model representations are applied to the results from a series of laboratory tests and it is shown that the models can predict the laboratory permeability data. As part of this characterisation the various sorption strains are identified and it is shown that the pore strain is significantly larger than (approximately 50 times) the bulk sorption strain. The models also provide further insight into how coal permeability varies with coal shrinkage and swelling and how the permeability rebound pressure depends upon the effective stress applied. [Copyright &y& Elsevier]

The permeability of CO 2 sequestration is influenced by the characteristics of pore–fracture structures in coal, yet the flow simulation via the pore network model (PNM) and the controls of topology and morphology on permeability remain to be understood. First, the pore–fracture structure of high-volatile bituminous coal (HVBC) is characterized using micro-computed tomography, and the flow characteristics of single-phase CO 2 in the connected pore–fracture network are simulated by the PNM. Second, the surface roughness of the connected pore–fracture is extracted by fractal characterization, and morphological algorithms are applied to accurately present the pore–fracture network structure. Finally, the implications of structural parameters (pore or throat diameter, coordination number, tortuosity, and sphericity) on CO 2 transport are discussed, and the mechanism of pore–fracture structure response due to mineral dissolution in CO 2 injection is analyzed. The results shows that the HVBC sample provides significant pore–fracture space (porosity of 10.87%) and flow path (connectivity of 66.50%) for hydrogen and carbon storage. CO 2 flow simulation results demonstrate anisotropic flow, with higher CO 2 permeability observed in the Z -axis direction (0.061 × 10−3 μm2) compared to the X- and Y-axis directions (0.044 × 10−3 μm2 and 0.059 × 10−3 μm2, respectively). Moreover, the fractures perpendicular to the coal bedding plane in the coal seam with a large tectonic dip strongly influence the flow of CO 2 injection. Fractal analysis reveals a positive correlation between fractal dimension and porosity, indicating that structures with higher surface roughness are not convenient for CO 2 transport. Significant pore angle characteristics (sphericity average of 0.58), high pore–throat connectivity (coordination number average of 4.31), and low capillary resistance (tortuosity average of 1.19) collectively affect the flow of CO 2. Overall, the strongly anisotropic pore–fracture structure contributes to the inhomogeneous flow pattern in CO 2 geosequestration. Changes in pore–fracture structure resulting from mineral dissolution during the early stage of CO 2 –coal matrix interaction in the HVBC reservoir can significantly enhance storage potential. This study contributes to the existing understanding of flow characteristics and provides insights for optimizing CO 2 injection efficiency in carbon geosequestration. • Single-phase CO 2 flow simulation was carried out based on equivalent PNM. • The relationship between surface roughness and porosity was analyzed by fractal. • The effect of structural parameters on CO 2 flow was evaluated. • Structure alterations caused by mineral dissolution in CO 2 injection were discussed. [ABSTRACT FROM AUTHOR]