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Due to the retrograde condensation phenomenon in the development process, the fluid phase change is complex, and it becomes particularly difficult to accurately describe the fluid flow characteristics and residual oil and gas distribution characteristics during the development of condensate gas reservoirs. It is difficult to select the development program and subsequent dynamic adjustment for the efficient, reasonable, and sustainable development of condensate gas reservoirs. In this paper, the phase characteristics of condensate gas reservoirs are clarified; the basic fluid model is created by using computer modeling, using Win-Prop; and in view of the characteristics of the target condensate gas reservoirs, the CMG (Computer Modeling Group) numerical simulation method is applied to study the effects of six factors, the thickness of the reservoir, permeability, porosity, rock compression coefficient, the ratio of the vertical permeability to the horizontal permeability, and the injection of different media, on the development effect through the study of different development parameters of gas condensate reservoirs. The purpose of this study is to provide guidance for the rational development of condensate gas reservoirs in practical production. [ABSTRACT FROM AUTHOR]

Coalbed methane (CBM) productive efficiency and coal mine disasters such as gas outbursts and water inrush are closely correlated with coal seam permeability. Effective prediction of coal seam permeability can provide guidance for CBM production and prevention of coal mine disasters. In this research, a hybrid neural network prediction model integrating a genetic algorithm, an adaptive boosting algorithm, and a back propagation neural network was developed to predict coal seam permeability. Additional momentum and variable learning rate algorithms were used to improve the learning rate and accuracy of the model, and the model structure was optimized, including the number of hidden layer nodes and the transfer function. The input parameters of the prediction model included gas pressure, compressive strength, reservoir temperature, and effective stress. The corresponding output parameter was coal seam permeability. The correlation between the parameters was calculated. Additionally, a comparative analysis between the proposed prediction model and four other prediction models was carried out to demonstrate the advantages of the proposed model. The results indicated that the correlations between compressive strength, gas pressure, reserve temperature, effective stress, and coal seam permeability were 0.334, −0.148 , −0.406 , and −0.785 , respectively. The proposed prediction model had high accuracy compared with the other prediction models, and its coefficient of determination and root mean squared error were 0.999 and 0.021. Thus, the model can predict coal seam permeability more accurately. [ABSTRACT FROM AUTHOR]

Nanoparticles (NPs) have gained significant attention as a functional material due to their ability to effectively enhance pressure reduction in injection processes in ultra-low permeability reservoirs. NPs are typically studied in controlled laboratory conditions, and their behavior in real-world, complex environments such as ultra-low permeability reservoirs, is not well understood due to the limited scope of their applications. This study investigates the efficacy and underlying mechanisms of NPs in decreasing injection pressure under various injection conditions (25e85 °C, 10e25 MPa). The results reveal that under optimal injection conditions, NPs effectively reduce injection pressure by a maximum of 22.77% in core experiment. The pressure reduction rate is found to be positively correlated with oil saturation and permeability, and negatively correlated with temperature and salinity. Furthermore, particle image velocimetry (PIV) experiments (25 °C, atmospheric pressure) indicate that the pressure reduction is achieved by NPs through the reduction of wall shear resistance and wettability change. This work has important implications for the design of water injection strategies in ultra-low permeability reservoirs. [ABSTRACT FROM AUTHOR]

The prediction and distribution of reservoir porosity and permeability are of paramount importance for the exploration and development of regional oil and gas resources. In order to optimize the prediction methods of porosity and permeability and better guide gas field development, it is necessary to identify the most effective approaches. Therefore, based on the extreme gradient boosting (XGBoost) algorithm, laboratory test data of the porosity and permeability of cores from the southern margin of the Ordos Basin were selected as the target labels, conventional logging curves were used as the input feature variables, and the mean absolute error (MAE) and the coefficient of determination (R2) were used as the evaluation indicators. Following the selection of the optimal feature variables and optimization of the hyper-parameters, an XGBoost porosity and permeability prediction model was established. Subsequently, the innovative application of homogeneous clustering (K-means) data preprocessing was applied to enhance the XGBoost model's performance. The results show that logarithmically preprocessed (LOG(PERM)) target labels enhanced the performance of the XGBoost permeability prediction model, with an increase of 0.26 in its test set R2. Furthermore, the application of K-means improved the performance of the XGBoost prediction model, with an increase of 0.15 in the R2 of the model and a decrease of 0.017 in the MAE. Finally, the POR_0/POR_1 grouped porosity model was selected as the final predictive model for porosity in the study area, and the Arctan(PERM)_0/Arctan(PER0M)_1 grouped model was selected as the final predictive model for permeability, which has better prediction accuracy than logging curves. The combination of K-means and the XGBoost modeling method provides a new approach and reference for the efficient and relatively accurate evaluation of porosity and permeability in the study area. [ABSTRACT FROM AUTHOR]

The permeability of shale controls gas transport in shale gas reservoirs. The shale has a complex pore structure at the nanoscale and its permeability is affected by multiple transport and action mechanisms. In this study, a 3D fractal model for predicting the apparent gas permeability of shale matrix is presented, accounting for the effects of the transport mechanisms (bulk gas transport and adsorption gas diffusion) and action mechanisms (gas adsorption, real gas properties, water film, stress dependence, and total organic carbon (TOC) content). The proposed model is validated with the published experimental data. A series of sensitivity analyses are performed to investigate the influence of fractal characteristics and action mechanisms on the apparent permeability caused by each transport mechanism. The results show that the real gas properties, water film, and stress dependence cause different effects on the total apparent permeability of shale under different fractal characteristics. The maximum pore diameter is inversely proportional to the effects of these action mechanisms, and the porosity is positively proportional to the effects of real gas properties and water film but inversely proportional to the effects of stress dependence. An increase in TOC content can cause an improvement in the total apparent permeability. Furthermore, the effects of action mechanisms on the apparent permeability caused by different transport mechanisms are differently affected by the fractal characteristics. Changes in fractal characteristics mainly affect the apparent permeability caused by slip flow in the real gas effect, slip flow and Knudsen diffusion in the water film effect, and all transport mechanisms in the stress dependence effect. [ABSTRACT FROM AUTHOR]

Carbon dioxide (CO2) capture and storage (CCS) is presented as an alternative measure and a promising approach to mitigate the large-scale anthropogenic CO2 emission into the atmosphere. In this context, CO2 sequestration into depleted oil and gas reservoirs is a practical approach as it boosts the recovery and facilitates the permanent storing of CO2 into the candidate sites. However, the estimation of CO2 storage capacity and properties in subsurface is a challenge to kick-start CCS worldwide. Thus, this paper characterizes the reservoirs of a field to tackle the challenge of CO2 emission and storage in Niger Delta. To achieve this work's ultimate goal, the Schulmberger Petrel software was used for evaluation of the structural and petrophysical parameters of six well logs, which includes faults for trapping mechanism, porosity and permeability. Eleven reservoir (A-K) storage units were delineated and reservoir A selected for CO2 storage within sand and shale lithologies. These storage units were furthermore subdivided into three: the shallow, middle and deeper reservoirs. The results demonstrated significant trapping structures, with good closure dependent fault pattern in a major NW-SE trending direction for CO2 storage without leakage. Also, the reservoir of study indicates 0.01 - 0.35 porosity and 0.5 -350MD permeability ranges respectively, which is a good indication of the ability of the reservoir rocks to retain and allow fluid to flow. Thus, reservoir A was chosen to possess the potential of CO2 storage and utilization due to well continuous sand geobody across the wells and its structural ability in Onshore Niger Delta. [ABSTRACT FROM AUTHOR]

The gas–water relative permeability curve plays a crucial role in reservoir simulation and development for condensate gas reservoirs. This paper conducted a series of high-temperature and high-pressure analysis experiments on real gas cores from Wells A and B in Block L of the Yinggehai Basin to investigate the effects of temperature, pressure, and different types of gas media on gas–water seepage. The gas–water relative permeability was simulated in this experiment through variations in temperature, pressure, and gas composition. Temperature has a significant impact on both gas and water relative permeability, particularly on gas relative permeability. As temperature increases, gas relative permeability shows a substantial increase, while water relative permeability remains relatively unchanged. Under the same effective stress, increasing pressure causes downward shifts in both the gas and water relative permeability curves; however, there is a more pronounced decrease in gas relative permeability. Gas composition has minimal influence on the gas–water relative permeability except at higher water saturation where differences become apparent. When water saturation ranges from 80% to 50%, there is no significant variation observed in the measured relative permeability of different displacement gases. However, as water saturation exceeds 80%, distinctions gradually emerge. The relative permeability of nitrogen is approximately 92% lower than that of mixed gas when the bound water saturation reaches 80%. This investigation provides valuable insights into the characteristics of gas–water relative permeability in high-temperature and high-pressure condensate reservoirs within Yinggehai Basin, thereby offering significant contributions to development strategies for similar reservoirs. [ABSTRACT FROM AUTHOR]

Permeability is a critical parameter for effective shale gas extraction. Shale reservoirs are dense, and fluid can hardly flow through shale rock under pressure, greatly limiting the permeability, which is commonly obtained by the steady-state core analysis method. At the same time, shale reservoirs contain abundant clay minerals and micro- and nanopores, resulting in favorable spontaneous imbibition ability. At present, most studies for predicting the absolute rock permeability are based on the imbibition process, while the combined influences of the dynamic capillary pressure, slip effect, and osmotic pressure have been considered in few effective permeability prediction studies. First, an imbibition experiment of an undersaturated shale core was conducted to obtain the spontaneous imbibition coefficient of shale. Furthermore, considering the influences of the slip effect, osmotic pressure, tortuosity, and dynamic capillary pressure, an effective permeability prediction method was established based on the imbibition coefficient of shale reservoirs. Combined with previous experimental data, the permeability calculated by this model is close to the experimental data, and the maximum error is less than 11.6%, verifying the effectiveness of the model. The permeability of the lower Silurian Longmaxi Formation shale in the Changning area, Sichuan, can be obtained by using this method. The results showed the following: (1) the calculated result error with the model results of the literature is 1.43 to 3.57%, which shows good contrast. The established effective permeability prediction method considers more comprehensive factors, requires fewer parameters, involves a clear calculation process, accurately meets the production demand, and agrees better with the real formation conditions. (2) The effects of the osmotic pressure, tortuosity, and slip length on the effective permeability successively decrease. Ignoring the osmotic pressure and slip length could lead to a higher effective permeability, while ignoring the tortuosity could lead to a low effective permeability. (3) The effective permeability of reservoirs can be obtained by using this method with different working fluids, and reservoir damage can be rapidly evaluated, which has guiding significance for selecting reasonable working fluids. The method provides a new way to evaluate the effective permeability of shale reservoirs effectively and quickly. [ABSTRACT FROM AUTHOR]

Introduction: Carbon dioxide (CO2) enhanced gas recovery represents a viable strategy for sequestering CO2 while concurrently augmenting gas production from subsurface reservoirs. Gas reservoirs, as inherent geological formations, are optimal repositories for gaseous compounds, rendering them suitable for CO2 storage. Nevertheless, the economic viability of pure CO2 storage necessitates integration with oil and gas recovery mechanisms to facilitate widespread CO2 utilization. Method: This study addresses the complexities of CO2 enhanced gas recovery through a comprehensive approach that combines theoretical model and numerical simulations. A numerical model is developed to simulate three-component diffusion involving CO2, and methane (CH4) in a two-phase system comprising gas and water. Results: The investigation systematically explores the process of enhanced CH4 extraction and CO2 injection into the reservoir and examines the influencing factors on extraction. Simulation results reveal a power-law decrease in CH4 production rate, stabilizing at a constant extraction rate. Enhanced CH4 extraction benefits from increased porosity, with higher porosity levels leading to greater CH4 extraction. Permeability augmentation positively influences CH4 production, although with diminishing returns beyond a certain threshold. The CO2 injection rate shows a direct proportionality to CH4 production. However, elevated CO2 injection rates may increase reservoir pressure, potentially causing cap rock damage and CO2 gas flushing. Discussion: This study contributes valuable theoretical insights to the field of CO2 enhanced gas recovery engineering, shedding light on the intricate dynamics of multi-component fluid transport processes and their implications for sustainable CO2 utilization. [ABSTRACT FROM AUTHOR]

The coupling relationship between the deformation field, the diffusion field, and the seepage field is an important factor in fluid transport mechanisms in the long-term coalbed methane (CBM) exploitation process. A mathematical model of gas–water two-phase fluid–structure coupling in a double-porosity medium in coal reservoirs is established in this paper. Taking Hancheng Block, a typical production block in Qinshui Basin, as the geological background critical desorption pressure, reservoir permeability anisotropy is considered in the model. COMSOL Multiphysics (COMSOL_6.0) was used to create the model. The accuracy and rationality of the model were verified by comparing field production data with the results of the simulation. Using the simulation, the influence law of various reservoir geological characteristics parameters (Langmuir strain constant, ratio of critical desorption pressure to reservoir pressure of coal seam (CDPRP), elastic modulus, initial water saturation, Langmuir pressure, etc.) on CBM productivity, reservoir pressure, and permeability ratio was discussed, and a thorough analysis of the factors affecting productivity was obtained using the orthogonal test method. The findings of this study indicate that the change in permeability is the result of the superposition effect of many factors. Different stages of drainage have different primary regulating factors. Rock skeleton stress has a consequence on coal matrix permeability in the early drainage stage, and coal matrix shrinkage is primarily impacted in the later drainage stage. Besides the initial water saturation, other reservoir geological parameters (e.g., CDPRP, Langmuir volume, Langmuir strain constant, elastic modulus) have a strong relationship with productivity. When the value of coal geological parameters increases, the degree of productivity release is higher (as the initial water saturation increases, the production decreases correspondingly). Different coal and rock parameters have varying levels of impact on the drainage stage of CBM wells. The influences of the CDPRP, Langmuir volume, Langmuir strain constant, and elastic modulus on gas production are mainly concentrated in the initial and intermediate drainage stages and begin to fall off during the last drainage stage. Per the multi-factor analysis, the main coal–rock parameters affecting the productivity release are the Langmuir strain constant, followed by the CDPRP and other parameters. The analysis findings can offer theoretical guidance for CBM well selection and layer selection and enhance the block's overall CBM development level. The improved productivity prediction model for CBM, which is based on fluid–structure coupling theory, can offer a new technical benchmark for CBM well productivity prediction. [ABSTRACT FROM AUTHOR]

To study the failure of conventional packers in the fracturing and stimulation of low-porosity and low-permeability reservoirs and reduce the failure accidents of packers in the fracturing process, a suitable integrated string packers was selected in the process of fracturing and stimulation in an oilfield in the Middle East as a case study. Three different well types have been established. The wellbore temperature distribution and the axial force of the string can be calculated under the conditions of various wellhead pressures and different displacement, and it is found that the temperature at the bottom of the well can reach 130 °C, and the maximum axial force at the wellhead is 500 kN. At the same time, the applicability of retrievable tubing testing squeeze (RTTS) and hydraulic-set retrievable (RH) packer in different working conditions was evaluated, and it was found that only RTTS packers can meet the needs of the oil field. According to the calculated temperature field and axial force distribution, the stress on different components of the packer under different working conditions is established during the fracturing-stimulation operation. In the worst working conditions, the maximum stress of the packer occurs at the lower part of the central pipe, reaching 303.83 MPa, which is in a safe state. The contact stress on rubber rings can reach 30 MPa, indicating that the sealing performance can meet the requirements of on-site use. The temperature and axial force data calculated by the model provide a theoretical basis for safe well control. At the same time, through model evaluation, it was found that the RTTS packer can be suitable for the fracturing and stimulation needs of the oilfield. The research methods and achievements in the article provide theoretical guidance for evaluating the applicability of packers in the fracturing and stimulation process of low porosity and low permeability reservoirs. [ABSTRACT FROM AUTHOR]

The study of heterogeneous and complex oil and gas reservoirs poses a significant challenge due to the problem of unstable seepage flow. This research investigates the non-linear seepage flow patterns in such reservoirs, with a particular focus on ultra-low permeability tight gas reservoirs, using fractal theory. By analysing the scale invariance in the seepage flow of ultra-low permeability tight gas reservoirs, we have derived a fractal geometric expression based on the capillary pressure curve. This expression was integrated with mercury intrusion porosimetry to study the fractal dimension of ultra-low permeability reservoirs. Our experimental results indicate the presence of fractal characteristics in ultra-low permeability tight gas reservoirs. Based on this, we have investigated the fractal nature of matrix porosity and fractures and their effect on the stress sensitivity of ultra-low permeability tight gas reservoirs. This led to the development of a new fractal model for seepage flow in these reservoirs, which takes into account the non-Darcy flow behaviour of gas in nanoscale pores. The mathematical model was simplified using point source solutions and regular perturbation methods. The analysis shows that the fractal parameters of the matrix and fractures, together with the adsorption coefficients and the permeability modulus, have a significant influence on the dynamic pressure behaviour. The effects of slip and diffusion coefficients and stress sensitivity on the dynamics were also investigated. The pressure dynamics curves of ultra-low permeability tight gas reservoirs show distinct differences from those of homogeneous reservoirs and conventional dual porosity reservoirs. This study not only reveals the unique dynamic pressure characteristics of ultra-low permeability tight gas reservoirs, but also shows that the traditional reservoir models are, under certain conditions, special cases of the model proposed in this paper. [ABSTRACT FROM AUTHOR]

Ultra-low permeability argillaceous sandstone reservoirs have become a significant focus for exploration and development. Saturation is a crucial parameter in evaluating such reservoirs. Due to the low porosity, low permeability, complex pore structure, and strong heterogeneity in ultra-low permeability argillaceous sandstone reservoirs, traditional evaluation methods are unable to achieve the required level of interpretation accuracy. To improve the accuracy of gas saturation calculations in ultra-low permeability argillaceous sandstone gas reservoirs, the conductivity characteristics of the ultra-low permeability argillaceous sandstone gas reservoirs in the Huangliu Formation in the Dongfang area, China, were analyzed through rock physics experimental data and geological information. The results revealed the clay content in the study area to range from 6% to 33.4%. Influenced by burial depth and temperature, kaolinite and montmorillonite transform into illite and chlorite, and the cation exchange capacity is not correlated with the clay content. This suggests that the effects of cation-attached conductivity can be ignored. The regional variation in rock electrical parameters is significant. When the lithology coefficient is a = 1, the consolidation index m varies between 1.25 and 1.75. When the lithology coefficient is b = 1, the saturation index n varies between 1.6 and 1.96. Under the influence of high temperature and pressure, the reservoirs in the study area exhibit two distinct characteristics on the capillary pressure curve, fractal dimension, and effective porosity index intersection diagram, (1) In Class I reservoirs, there is a strong correlation between the formation factor and natural gamma, as well as porosity, and a logarithmic relationship between the saturation exponent and the formation factor; and (2) in Class II reservoirs, there is a strong power-law relationship between the formation factor and porosity, as well as a logarithmic relationship between the saturation exponent and formation factor. Based on experimental and logging data, reservoir classification was conducted using core-scale logging and principal component analysis. Additionally, a saturation interpretation model was developed using multivariate regression, based on rock electrical parameters. The actual application results demonstrate that compared to the fixed rock resistivity saturation model, this model has reduced the average absolute error by 5.9%. The calculated values are consistent with the gas saturation analysis of the core at the pure gas section as determined by cable testing sampling. This model meets the requirements of practical production. The study of this interpretation method is of great significance for the formulation of development plans for ultra-low permeability offshore argillaceous sandstone gas reservoirs. [ABSTRACT FROM AUTHOR]

In order to further expand the understanding of the pore-throat structure of sandstone, a new method is proposed in this paper to reconstruct three-dimensional (3D) virtual sandstone and replicate the natural sandstone pore-throat structure. While reconstructing 3D virtual sandstone, a particle distribution factor M and a dilation filter D were introduced into the site percolation model. The function of M was to control the initial size of the solid particle while ensuring the randomness of the shape of the solid particle, whereas D gave acceptable deformation of the pore-throat structure while changing the porosity (P) of the 3D virtual sandstone. It was found that the virtual sandstone with high similarity to the real sandstone could be reconstructed by changing the combination of M and D regardless of the P, tortuosity, and pore coordination number of the real sandstone. The percolation thresholds of 3D virtual sandstone generated under different M and D were obtained, and the pore connectivity and permeability changes with M, D, and P were also investigated. The proposed method for virtual sandstone generation in this paper provides a novel approach for assessing and predicting the connectivity and permeability of sandstone reservoirs in oil and gas exploration. [ABSTRACT FROM AUTHOR]

This study aimed to develop a novel productivity model for an open-hole horizontal well in a low permeability gas reservoir (LPGR). First, the permeability and pressure gradient were revised by the slippage factor, stress-sensitivity coefficient, and startup pressure gradient (SPG). The mirror reflection method was used to solve the influence of top and bottom boundaries on the seepage field, and we can obtain the internal seepage resistance of the well. Second, the Joukowski transformation method can solve the influence of horizontal boundary on the seepage field so that external seepage resistance can be obtained. Finally, by taking the high-velocity non-Darcy effect (NDE) into account, a novel model, which is suitable for an open-hole horizontal well (OHHW) in low permeability gas reservoirs with a high stress-sensitivity coefficient, was developed. The model was verified using data from wells G3 and G4, and the prediction relative errors of the absolute open flow (AOF) of these two wells were only −0.14% and 0.37%, respectively. Then, by comparing with other different models, the results demonstrate that the model constructed in this work has a clear superiority in productivity analysis; it has some guiding significance for the development of open-hole horizontal gas wells in low permeability gas reservoirs. [ABSTRACT FROM AUTHOR]

Tight sandstone has strong pore heterogeneity and complex pore structure, and the pore structure of tight sandstone varies with different permeability. To study the differences in the pore structure of tight sandstone with different permeability, this study investigated the tight sandstone of the He 8 Member in the Gaoqiao area of the Ordos Basin. Factors influencing pore formation are analyzed through experiments utilizing methods, such as distinguishing casting thin sections, scanning electron microscopy, high‐pressure mercury intrusion, and low‐temperature nitrogen adsorption. The results indicate that in this area, the pores of the tight sandstone are primarily dissolution and intercrystalline pores, with occasional intergranular pores and microcracks. Type Ⅱ samples (permeability > 0.2 × 10−3 μm2) are primarily composed of dissolution and intercrystalline pores, with a few visible intergranular and microcracks. In contrast, Type Ⅰ samples (permeability < 0.2 × 10−3 μm2) mainly consist of micropores and intercrystalline pores, where microcracks are observed locally. Pore size research demonstrates that Type Ⅰ samples have pore size under 1000 nm, with peaks primarily at 4–5 nm. There are also peaks between 10–1000 nm, but without a consistent pattern. For Type Ⅱ samples with sizes smaller than 1000 nm, pore distribution is evident. Peak values when the pore size exceeds 1000 nm. Type Ⅰ samples have fewer micron‐level pores, while Type Ⅱ samples are primarily dissolution pores. The nanopores of Type Ⅰ samples consist of flat pores with good connectivity, whereas those of Type Ⅱ samples are mainly blind pores with poor connectivity. Type Ⅰ samples have larger pore fractal dimensions, more intricate pore morphology, and rougher and irregular pore throat surfaces compared to Type II samples. Hence, the sedimentary environment, diagenesis, and mineral composition affect the pore distribution in tight sandstone. The research findings highlight the variations in the pore structure of tight sandstone with varying permeability, providing crucial guidance for classifying and assessing pore structure in tight sandstone reservoirs. [ABSTRACT FROM AUTHOR]

Tight reservoirs are the focus of unconventional oil and gas resource development, but most tight reservoirs exhibit complex pore structures, strong non-homogeneity, and limited water drive development. Fracturing fluid imbibition is a critically important way to improve the recovery of tight reservoirs. In this paper, an NMR experimental device was used to conduct imbibition experiments in tight reservoirs, and the relationship between temperature, pressure, matrix permeability, and imbibition recovery was investigated. Based on the fracturing fluid imbibition recovery curve, the imbibition process is divided into the fast imbibition stage, slow imbibition stage, and imbibition equilibrium. In addition, based on the pore structure division, the recovery changes of each pore under different experimental conditions were quantitatively analyzed. The results indicate that the highest imbibition recovery is achieved at an experimental pressure of 5 MPa within the range of 0 MPa to 15 MPa. Increasing the experimental pressure can increase the imbibition rate but will not increase imbibition recovery. Within the investigated range in this paper, fracturing fluid imbibition increases with rising temperature and matrix permeability. Moreover, the recovery of each pore gradually increases with the experimental pressure ranging from 0 MPa to 5 MPa. The recovery of each pore is positively correlated with matrix permeability and temperature. During the experiment, micropores contributed the most to the recovery, while macropores contributed the least. The study in this paper guides the efficient development of tight reservoirs. [ABSTRACT FROM AUTHOR]

To solve the difficult problems of gas drainage in coal seams with a high gas content and low permeability, a novel technology based on a series of mechanically over-excavated cavities along drainage boreholes in coal seams to increase permeability was proposed. In this paper, the fluid–solid coupled model of the mechanically over-excavated borehole and the gas drainage in soft coal seams was analyzed, and COMSOL Multiphysics numerical simulation software was used for validation. The influence of the parameters for the mechanically over-excavated borehole (i.e., cavity diameter, cavity length, and interspace between the cavities and cavity number) and the reservoir properties of coal seams (i.e., initial permeability, initial porosity and elastic modulus) on gas drainage were investigated. The results show that the gas drainage volume increases with cavity volume and has little effect when the interspace between the cavities exceeds 0.5 m. This indicates that mechanically over-excavated boreholes can significantly increase the coal seam permeability and gas drainage volume. Based on numerical analyses, a single-wing embedded mechanically over-excavated borehole drill bit was developed. The effectiveness of the drill bit was tested in situ at the Licun Coal Mine of the Shanxi Lu'an Group. The results indicate that the effective gas drainage volume of a mechanically over-excavated borehole is 147% higher than that of an ordinary borehole and is not much different from that of a hydraulic flushing borehole. However, mechanically over-excavated borehole technology has great advantages with respect to operational efficiency and cost. Highlights: The influence of the parameters for the mechanically over-excavated borehole (i.e., cavity diameter, cavity length, interspace between the cavities and cavity number) on gas drainage was studied. The influence of reservoir properties of coal seams (initial permeability, initial porosity and elastic modulus) on gas drainage was studied. Combining the actual coal seam drilling conditions of the Licun Coal Mine of the Shanxi Lu'an Group and considering the economic investment, based on numerical simulation analysis, the optimal cavity diameter was determined. A single-wing embedded over-excavated bit was developed and successfully applied in the #2302 workface of the Licun Coal Mine. [ABSTRACT FROM AUTHOR]

Tight sandstone gas reservoirs generally contain water. Studying the impact of water content on the permeability mechanism of tight gas reservoirs is of positive significance for the rational development of gas reservoirs. Selected cores from a tight sandstone gas reservoir in the Ordos Basin were used to establish the variation in its seepage mechanism under different water saturations. The experimental results show that the gas slip factor in tight water-bearing gas reservoirs decreases as the water saturation increases. The stress sensitivity coefficient and the threshold pressure gradient (TPG) increase with increasing water saturation, characterizing the relationships between stress sensitivity coefficients, TPG, permeability, and water saturation. As the water saturation gradually increases, the relative gas phase permeability of tight sandstone gas reservoirs will sharply decrease. When the water saturation exceeds 80%, the gas phase permeability becomes almost zero, resulting in gas almost ceasing to flow. Through the analysis of experimental results, we defined high-water-cut tight sandstone gas reservoirs and analyzed the permeability characteristics of high-water-cut tight sandstone gas reservoirs in different regions. Combining stress sensitivity coefficients and the TPG with permeability and water saturation relationships, we established a zoning productivity calculation method of fractured horizontal wells in high-water-cut tight sandstone gas reservoirs under complex seepage conditions and validated the practicality of the model through example calculations. [ABSTRACT FROM AUTHOR]

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In view of the common problems of difficult in characterizing pore structure, weak research on reservoir forming limit, and ambiguous meaning of grading evaluation boundary in Chang 7 tight oil reservoirs of the Jiyuan area, Ordos Basin. The pore structure types and reservoir forming limits of tight sandstone were determined by high-pressure mercury injection test and other methods, and the grading criteria were established to evaluate the reservoir quality. The results showed that the Chang 7 tight oil reservoirs have poor petrophysical properties and four types of pore structures, which correspond to different reservoir types respectively. There are three types of the reservoir forming limits in tight sandstone reservoirs, namely the theoretical lower limit, lower limit of oil accumulation, and effective seepage lower limit, with the corresponding porosity limits of 3.5%, 5.5%, and 8.0%, respectively, and the corresponding permeability limits of 0.02 × 10-3 µm2, 0.05 × 10-3 µm2, and 0.20 × 10-3 µm2, respectively. These reservoir forming limits were in good agreement with the classification boundaries of pore structure. Combining the pore structure types with the reservoir forming limits, the Chang 7 tight oil reservoirs can be divided into four classes: I, II, III, and IV, representing easily movable tight reservoir, movable tight reservoir, oil-bearing tight reservoir, and ineffective tight reservoir, respectively. Among them, the classes I and II reservoirs were the sweet spot areas for increasing the reserves and production of tight oil. The method of combining various reservoir forming limits and pore structure types can effectively evaluate reservoir quality, and provide theoretical basis for increasing geological reserves and rolling expansion of oil fields. [ABSTRACT FROM AUTHOR]

Highly rarefied gas flows through a rough channel of finite length with small bumps appended to its surfaces are investigated, by varying the accommodation coefficient α in Maxwell's diffuse-specular boundary condition, the characteristic size and position of the bumps, and the channel length. First, we study the influence of the surface bumps and consider the rarefied gas flow in a unit channel with periodic boundary conditions to remove the end effect. It is found that the surface bumps have a significant impact on the flow permeability. When α is very small (i.e., nearly specular reflection of gas molecules at the channel surface), the apparent gas permeability is dramatically reduced, even in the presence of small bumps, to a value that is almost comparable to the one when fully diffuse gas-surface scattering is assumed. This impact can be taken into account through an effective accommodation coefficient, i.e., the permeability of the rough channel is taken equivalently as that of a smooth channel without bumps but having gas-surface scattering under the effective accommodation coefficient. Second, we study the end effect by connecting a smooth channel of length L 0 to two huge gas reservoirs. It is found that (i) the end correction length is large at small α . Consequently, the mass flow rate barely reduces with increasing L 0 rather than scales down by a factor of 1 / L 0 as predicted by the classical Knudsen diffusion theory; and (ii) the end correction is related to the channel's aspect ratio. Finally, based on the effective accommodation coefficient and end correction, we explain the exotic flow enhancement in graphene angstrom-scale channels observed by Geim's research group (Keerthi et al, Nature 558:420–424, 2018). [ABSTRACT FROM AUTHOR]

Unconventional reservoirs, including gas shales and tight gas sands, have gained prominence in the energy sector due to technological advancements and escalating energy demands. The oil industry is eagerly refining techniques to decipher these reservoirs, aiming to reduce data collection costs and uncertainties in reserve estimations. Characteristically, tight reservoirs exhibit low matrix porosity and ultra-low permeability, necessitating artificial stimulation for enhanced production. The efficacy of the stimulation hinges on the organic material distribution, the rock's mechanical attributes, and the prevailing stress field. Comprehensive petrophysical analysis, integrating standard and specialized logs, core analyses, and dynamic data, is pivotal for a nuanced understanding of these reservoirs. This ensures a reduction in prediction uncertainties, with parameters like shale volume, porosity, and permeability being vital. This article delves into an intricate petrophysical evaluation of the Nene field, a West African unconventional reservoir. It underscores the geological intricacies of the field, the pivotal role of data acquisition, and introduces avant-garde methodologies for depth matching, rock typing, and the estimation of permeability. This research highlights the significance of unconventional reservoir exploration in today's energy milieu, offering a granular understanding of the Nene field's geological challenges and proffering a blueprint for analogous future endeavours in unconventional reservoirs. [ABSTRACT FROM AUTHOR]

The gas content and permeability of coal reservoirs are the main factors affecting the productivity of coalbed methane. To explore the law of gas content and permeability of coal reservoirs in the Zhijin area of Guizhou, taking No.16, No.27 and No.30 coal seams in Wenjiaba mining area of Guizhou as the engineering background, based on the relevant data of coalbed methane exploration in Wenjiaba block, the geological structure, coal seam thickness, coal quality characteristics,coal seam gas content and permeability of the area were studied utilizing geological exploration, analysis of coal components and methane adsorption test. The results show that the average thickness of coal seams in this area is between 1.32 and 1.85 m; the average buried depth of the coal seam is in the range of 301.3–384.2 m; the gas content of No.16 and No.27 coal seams is higher in the syncline core. The gas content of the No.30 coal seam forms a gas-rich center in the south of the mining area. The buried depth and gas content of coal seams in the study area show a strong positive correlation. Under the same pressure conditions, the adsorption capacity of dry ash-free basis is significantly higher than that of air-dried coal. The permeability decreases exponentially with the horizontal maximum principal stress and the horizontal minimum principal stress. The horizontal maximum primary stress and the flat minimum prominent stress increase with the increase of the buried depth of the coal seam. The permeability and coal seam burial depth decrease exponentially. This work can provide engineering reference and theoretical support for selecting high-yield target areas for CBM enrichment in the block. [ABSTRACT FROM AUTHOR]

Gas reservoirs have significant engineering characteristics of injection and extraction. The reservoir cap rock is subjected to cyclic alternating loading and has the potential risk of seal failure. Therefore, it is necessary to study the stress−percolation−damage mechanism of the reservoir cap rock in depleted gas reservoirs. The rock Mechanics Test System (MTS) was used to study the permeability characteristics of a typical mud shale cap layer under different loading and unloading rates, analyze the deformation characteristics and permeability performance evolution law of the rock under the confining pressure alternation, and study the effects of loading and unloading rate, confining pressure and number of cycles on the permeability of the cap rock. The test results show that with the increase in the number of cycles, the hysteresis loop moves in the direction of axial strain increase offset. The overall morphology is presented as an elongated type, and the damage of the specimen is small in the cyclic confining pressure; At the beginning of the cycling period, the permeability decreases with the increase in the confining pressure in the form of a negative exponential. At the later stage of the cycling period, the permeability basically stays unchanged, and is maintained at a low level; At low confining pressure, permeability also decreases in a negative exponential form with the increase in the number of confining pressure cycles; The greater the loading and unloading rate at the beginning of the cycle, the more the permeability decreases; There is a tendency of sealing improvement under cyclic loading in the gas storage of depleted reservoirs with mud shale as the cap layer. The results of the study can provide technical parameters for the evaluation of the cap sealing of gas storage of depleted reservoirs. [ABSTRACT FROM AUTHOR]

Gas extraction quantity from coal seam is the key index to evaluating the effect of eliminating coal and gas outbursts. The prerequisite for increasing the gas extraction quantity and improving the effect of gas control is to make clear the influencing factors of gas extraction. The main factors affecting gas extraction are permeability, gas pressure, and buried depth of coal seam in this paper. The qualitative and quantitative analyses of gas extraction quantity by three factors are carried out according to the test data. The research results show that: (1) In the areas with high permeability and gas pressure, the gas extraction volume shows random characteristics, indicating clear regional differences. (2) The increase of buried depth of coal seam will reduce the fluctuation of gas extraction quantity, resulting in a lower extreme value of gas extraction quantity. The possibility of gas extraction at a lower level will be significantly increased. (3) The correlation analysis shows the change law of the positive correlation coefficient between gas extraction quantity, gas pressure, and permeability, and shows the opposite trend with the increase of the buried depth of coal seam. The results show an important guiding significance for improving the efficiency of gas control. [ABSTRACT FROM AUTHOR]

The small-sized proppant is widely used in the traditional hydraulic fracturing reservoir stimulation, but the theoretical research shows that the large-sized proppant can greatly improve the fracture permeability. Although many scholars have proposed the method of using large-sized proppant, the characteristics of the pressure field change and gas drainage rate during reservoir development are still unclear after pumping large-sized proppant. In this article, to study the change regularity of the reservoir pressure field, two representative proppants are selected: the small-sized proppant and large-sized proppants. First, the Navier–Stokes equations are solved using the numerical simulation method, and the characteristics of the reservoir pressure field are finely reproduced. Then, the production rate is discussed to reveal the huge potential of large-sized proppant for the natural gas development. The results show that under the same conditions, if the particle size of the proppant increases by 5 times, then the reservoir permeability will increase by 27 times approximately, and the single well production efficiency will increase by 17~19 times in the first 3000 days. In addition, a new quantitative model is proposed to evaluate the permeability magnification of the fracture and reservoir when adopting the large-sized proppant. This study further confirms that the method of large-sized proppant proposed by the author in the earlier stage has great potential. This study is helpful for the researchers and engineers to better understand the evolution regularity of the reservoir pressure field and gas production rate in the process of oil and gas exploitation after using the large-sized proppant. [ABSTRACT FROM AUTHOR]

Fractured reservoirs are complex and multi‐scale systems composed of matrix and fractures. Accordingly, modeling flow in such geological media has been a great challenge. In this study, we investigated the effect of scale as well as matrix and fracture network characteristics on the effective permeability (keff) in matrix‐fracture systems under fully saturated conditions. We generated fracture networks, embedded within a matrix of permeability of 10−18 m2, with fracture lengths followed a truncated power‐law distribution with exponent α = 1.5, 2.0, and 2.5. We set fracture permeability equal to 10−16, 10−14, and 10−12 m2 and numerically simulated fluid flow to determine the keff at six fracture densities for 36 fractured reservoirs. Results showed that the effect of α and scale on the keff became more significant as the contrast between matrix and fracture permeabilities increased. We also fit the percolation‐based effective‐medium approximation (P‐EMA) to the simulations and optimized its two parameters critical fracture density and scaling exponent. Results exhibited that both P‐EMA model parameters were scale‐dependent. Through linear regression analysis, we found that the critical fracture density and scaling exponent were highly correlated to other matrix‐fracture system properties and proposed two regression‐based models evaluated using a new six sets of simulations. Comparing the estimated keff values with the simulated ones demonstrated the reliability and predictability of the P‐EMA. The matrix‐fracture systems studied here were finite in size. We also showed that one may extend results to infinitely large reservoirs using the P‐EMA framework. Key Points: Scale‐dependent effective permeability in matrix‐fracture systems is investigated using numerical simulations and theoretical modelingCritical fracture density and scaling exponent are linked to reservoir properties and its size, and results are extended to large systemsTheoretical estimations of effective permeability in six unseen fractured reservoirs agree with numerical simulations well [ABSTRACT FROM AUTHOR]

The object of the study is a laboratory unit for inducing flow to the well using vibration wave draining in carbonate low-permeability reservoirs. Vibratory wave draining is a method used to stimulate flow draining to the well. The method is based on the fact that mechanical waves generated in the soil can cause the opening of microcracks and pores, which leads to an increase in the fluid flow. Vibratory wave scouring can be effectively used to increase fluid flow in low-permeability carbonate reservoirs. Carbonate reservoirs are a common type of reservoir in the oil and gas industry. They often have low permeability, which makes it difficult to extract fluid. With the help of the plunger device developed in the work, a fluid disturbance was created, thereby creating elastic waves in the conventional well (plastic pipe), which were measured using a manual contact vibrometer. This demonstrated the effectiveness of the vibratory method to increase the well productivity and helped to improve the permeability of the rocks, providing better access to challenge the influx of hydrocarbon products. It is shown that with a significant decrease in the permeability of the formation well zone (FWZ), the flow induction should be started only after the restoration works. Otherwise, the well will be significantly hydrodynamically imperfect due to the quality of the reservoir opening, and the flow of production into the well will occur only through a few separate areas of the reservoir with relatively high permeability, which will lead to uneven production of the reservoir and low return of hydrocarbons. Therefore, it is advisable to use the developed method of influencing the productive layer in low-permeability rocks, such as carbonates with layers of clay, siltstones, argillites, and others, with low formation pressures. The obtained results are based on the generation of vibrations that are transmitted to the wellbore. These vibrations can help break up contaminants and fines in carbonate rocks, facilitating the release of hydrocarbon products and improving permeability. [ABSTRACT FROM AUTHOR]

The low-permeability reservoirs have abundant reserves and broad development prospects, and the supplementary energy methods have gradually become a hot research topic. In addition, the technology of enhanced oil recovery through supercritical CO2 injection is becoming increasingly mature; however, the changes in reservoir properties at the microscopic level still need further investigation. In this study, natural rock cores from low-permeability reservoirs were used to simulate reservoir conditions and conduct supercritical CO2 injection experiments for energy supplementation. The study aimed to investigate the changes in reservoir microstructure, minerals, and crude oil properties before and after the experiments. The research results indicate that after supercritical CO2 injection into the reservoir, it dissolves in the formation water to form carbonic acid. Under the effect of dissolution, the porosity of the low-permeability reservoir increases by 1.06–5.68%, and permeability can be improved by 40–60%. The rock becomes more water-wet and less oil-wet. The content of calcite and feldspar in the rock minerals decreases due to the dissolution of carbonic acid, resulting in a reduction in plagioclase and calcite. After the CO2 injection, the light components (C8–C10) in the crude oil in the rock cores decreased by approximately 14.6%, while the heavy components (C16–C39) increased by 6.99%. The viscosity of the crude oil decreases, and its flowability is further enhanced. [ABSTRACT FROM AUTHOR]

The integrity of cement–salt rock interfaces (CSI) in salt cavern gas storage wells may be damaged during circulating gas injection, production, and long-term gas pressure maintenance. In this study, permeability tests were conducted on cement–salt rock samples under cyclic loading confining pressure at different holding times. The cracks and micro-annuli at the interface were visualised using X-ray computed tomography. The bonding strength of the interface after the permeability test was measured in a triaxial environment. The results showed that with an increase in the number of cycles, the cumulative volumetric strain rate and permeability first decreased rapidly and then tended to stabilise, and the decreasing amplitude was positively correlated with the holding time. When the holding times were 10, 30, and 60 min, the permeability change ratios were 0.844, 0.762, and 0.638, respectively, after one cycle and 0.722, 0.444, and 0.420, respectively, after five cycles. The permeability of CSI is mainly influenced by the holding time. The mechanical properties of the CSI specimens with similar permeabilities showed differences at different holding times. Cyclic loading easily degrades the mechanical properties, which can be improved by extending the holding time. The CSI is the main channel for gas leakage, extending the holding time, and increasing the number of cycles can effectively improve the pore structure of CSI and enhance the cement sheath integrity. This study provides a reference for long-term safe operation of salt cavern gas storage wells. Highlights: Permeability tests and triaxial shear bond strength tests after permeability tests were performed on a cement–salt rock interface. The effects of cyclic loading and holding time on the permeability and mechanical properties of the cement–salt rock interface were investigated. Microcracks' distribution within the cement–salt rock interface under cyclic loads was characterised using computed tomography. [ABSTRACT FROM AUTHOR]

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Identifying changes in coal permeability with gas pressure and accurately codifying mean effective stresses in laboratory samples are crucial in predicting gas-flow behavior in coal reservoirs. Traditionally, coal permeability to gas is assessed using the steady-state method, where the equivalent gas pressure in the coal is indexed to the average of upstream and downstream pressures of the coal, while ignoring the nonlinear gas pressure gradient along the gas flow path. For the flow of a compressible gas, the traditional method consistently underestimates the length/volume-averaged pressure and overestimates mean effective stress. The higher the pressure differential within the sample, the greater the error between the true mean pressure for a compressible fluid and that assumed as the average between upstream and downstream pressures under typical reservoir conditions. A correction coefficient for the compressible fluid pressure asymptotes to approximately 1.3%, representing that the error in mean pressure and effective stress can be on the order of approximately 30%, particularly for highly pressure-sensitive permeabilities and compressibilities, further amplifying errors in evaluated reservoir properties. We utilized this volume-averaged pressure and effective stress to correct permeability and compressibility data reported in the literature. Both the corrected initial permeability and the corrected pore compressibility were found to be smaller than the uncorrected values, due to the underestimation of the true mean fluid pressure, resulting in an overestimation of reservoir permeability if not corrected. The correction coefficient for the initial permeability ranges from 0.6 to 0.1 (reservoir values are only approximately 40% to 90% of laboratory values), while the correction coefficient for pore compressibility remains at approximately 0.75 (reservoir values are only approximately 25% of laboratory value). Errors between the uncorrected and corrected parameters are quantified under various factors, such as confining pressure, gas sorption, and temperature. By analyzing the evolutions of the initial permeability and pore compressibility, the coupling mechanisms of mechanical compression, adsorption swelling, and thermal expansion on the pore structure of the coal can be interpreted. These findings can provide insights that are useful for assessing the sensitivity of coal permeability to gas pressure as truly representative of reservoir conditions. [ABSTRACT FROM AUTHOR]

Unconventional gas is a momentous energy source due to its considerable reserves and eco-friendly properties, where relative permeability is a key evaluative parameter of unconventional gas extraction. However, the geo-complexity, multiscale and multieffect of the unconventional gas reservoir challenge the relative permeability evaluation and production enhancement. Here, we establish a gas–water flow model by integrating multifractal theory, covering from nanoscale to macroscale and regarding the effects of slip, gas desorption–diffusion and water film separation, to reliably evaluate the relative permeability evolution during unconventional gas development. Based on our model, we describe the permeability of the unconventional reservoir with an 88% less evaluation error compared to the single fractal Darcy with the literature benchmark. Moreover, we characterize the gas–water relative permeability with a no more than 10% evaluation error based on the experimental data. The slip effect plays the most crucial role in the evaluation precision of relative permeability. We reveal that the permeability of the unconventional gas reservoir is decreased by the increase of generalized fractal dimension which enhances the heterogeneity and tortuosity of pores. We uncover that the slip effect facilitates the relative permeability of gas and water. Besides, the gas desorption–diffusion boosts gas relative permeability while limiting water relative permeability, whereas water film separation enhances water relative permeability but hinders gas relative permeability. This work brings insights into the precise description of multiscale and multieffect gas–water porous flow in unconventional gas development. [ABSTRACT FROM AUTHOR]

Rock microstructure analysis and physical property simulation by means of digital rock physics (DRP) can overcome the deficiencies such as poor quantification and visibility in traditional petrophysical experiments. The establishment of a complete set of DRP is the basis of analyzing the microstructure of unconventional oil and gas reservoirs. In this study, high-rank coal, a material with anisotropic fracture and permeability properties, was tested using x-ray computer tomography scanning to reconstruct the digital core, and the fracture direction and structural characteristics were quantified with respect to the main inertia axis and the Feret diameter, respectively. A method for calculating the fractal dimension and tortuosity based on DRP is presented, and the optimal interaction between the lattice Boltzmann method seepage simulation and DRP is identified. The results show that the average length, width, aperture, and volume of fractures in the direction of face cleat (DFC) are 1.13, 1.10, 1.11, and 1.09 times that in the direction of butt cleat (DBC), respectively, and their surface area, count, fracture porosity, fractal dimension, and tortuosity are 1.17, 1.16, 1.26, 1.04, and 1.10 times that of DBC, respectively. The permeability of DFC was found to be 3.46 times that of DBC. This study presents an effective method for determining the dominant direction of fracture structure and fluid migration that is not limited to pores and fractures in rock but can also be used to characterize the physical properties of skeletons or solid particles in other materials. [ABSTRACT FROM AUTHOR]

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The key to shale gas exploration is the characterization of gas migration under the combination of multiple factors. To address the long-standing energy challenge of rapidly and accurately quantifying the behavior of natural fractures and matrix pores in shale at an engineering scale in interaction with gas migration. This study proposes an interdisciplinary model for shale gas extraction by adopting fractal theory. Five innovative microstructural parameters are developed to characterize the size and scale of natural matrix pores/fractures in shale, so as to investigate the contributions of fractal distributed pores and fractal power-law distributed fractures to shale gas extraction. The present results of the proposed model are consistent with the exploitation state of the UK Bowland Shale #114 well. The evolution of the shale microstructure will lead to changes in gas migration behavior throughout the reservoir and in turn affect shale stress, temperature and gas adsorption–desorption effect, and finally have a significant impact on permeability. It is found that in the present analysis of the entire Bowland Shale, the overall permeability changes by 10.8% with the evolution of fractal distributed pores and by 41.3% with the evolution of fractal power-law fractures. This work provides a new approach for rapidly exploring the behavior of shale fractures and matrix pores at engineering scales. This work also offers a new and practical baseline for shale gas extraction assessment and fossil energy management. [ABSTRACT FROM AUTHOR]

Digital rock physics (DRP) has been widely used as an effective approach for estimating the permeability of porous media. However, conventional implementation of DRP requires the reconstruction of three-dimensional (3D) pore networks, which suffer from intensive memory and underlying uncertainties. Therefore, it is highly significant to develop an approach only based on two-dimensional (2D) cross-sections of parent samples without 3D reconstruction. In this study, we present a novel approach that combines the Kozeny–Carman equation with fractal theory to derive a bridge function that links 2D cross-sectional images and 3D pore structures of parent samples in flow equivalence. Using this bridge function, we predicted the physical properties of the parent samples, including the permeability, bulk porosity, tortuosity, and pore fractal dimension. To validate our model, we performed Lattice Boltzmann (LB) simulations on nine carbonate samples and compared the LB simulation results with our model's predictions. We also compared our predicted results with available data on various porous materials, such as sandstone, glass beads, and carbonate, in the literature. Our findings demonstrate that without reconstructing 3D pore networks, our method provides a reliable estimation of sample permeability using 2D cross-sectional images. This approach not only simplifies the determination of sample permeability in heterogeneous porous media but also sheds new light on the inherent correlations between 2D cross-sectional information and 3D pore structures of parent samples. Moreover, the derived model may be conducible to a better understanding of flow in reservoirs during the extraction of unconventional onshore and offshore oil/gas. [ABSTRACT FROM AUTHOR]

Permeability is a critical factor in evaluating the fluid flow capacity and production performance of natural gas hydrate reservoirs. The similarity of electrical conduction and hydraulic flow makes it possible to predict reservoir permeability using electrical data. Clarifying the relationship between the permeability and resistivity of sediments with different hydrate growth habits contributes to the efficient exploration and development of natural gas hydrate resources. In this work, normalized permeability and the resistivity index models for grain-coating (GC) and pore-filling (PF) hydrates are developed based on the fractal geometry theory, forming a new relationship between normalized permeability and resistivity index. The empirical exponent is determined by fractal dimension. Meanwhile, we selected five sets of 3-D computed tomography (CT) images of quartz sand with different particle sizes, GC and PF hydrate digital rocks are constructed using random simulation methods. The numerical simulation of permeability and resistivity index is carried out, based on the pore microstructure images, the box counting method was used to calculate the fractal dimension and analyse the relationship between pore space and transport paths. Furthermore, the pore radius, throat radius and pore connection number are extracted through the pore network method to study the evolution of pore space. The results show that the tortuosity fractal dimension is a critical parameter in the relationship between normalized permeability and resistivity index. The proposed analytical expressions are validated by laboratory and well log data, and the exponent ranges cover existing hydrate permeability–resistivity index data. The models provide the possibility to predict the normalized permeability of hydrate reservoirs based on electrical data alone. [ABSTRACT FROM AUTHOR]

Air leakage in mine gas drainage drilling is a critical factor that affects gas extraction efficiency. It leads to a rapid decline in gas concentration, resulting in lower extraction efficiency and potential secondary disasters. To address this issue, a fully coupled gas–air mixed flow model is established in this study. The model examines the effects of extraction time, different negative pressures, and gas leakage on gas concentration. Additionally, it reveals the mechanism of air leakage around gas drainage boreholes. The simulation data are then compared with field gas drainage monitoring data to verify the reliability of the model. This verification serves as a basis for extraction regulation and control. The results demonstrate that during the later stages of extraction, the negative pressure decreases, causing a decline in gas concentration. Moreover, higher negative pressure leads to increased air inflow into the borehole, thereby reducing gas concentration. Consequently, selecting an appropriate negative pressure is crucial to improve pumping efficiency. The research findings hold significant guidance in achieving efficient gas mining. [ABSTRACT FROM AUTHOR]

Copyright of Journal of Northeast Petroleum University is the property of Journal of Northeast Petroleum University Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The continuous gas displacement in unconsolidated sandstone gas reservoirs will necessarily result in the pore structure and rock permeability variations, which cannot be neglected in the gas development process. However, the variations have not been comprehensively addressed yet, especially for the rock structure in pore scale. This work presented the quantitative results of pore structure in microscale and permeability variations during gas displacement in unconsolidated sandstone reservoirs through computed tomography (CT) reconstruction analysis. The results indicated that a more than 3% increase in porosity after gas displacement resulted from the enlargement of the pore and throat with a diameter of more than 20 μm and 3 μm, respectively, owing to the release and migration of clay and fine particles, in spite of the distribution frequency decline of both pore and throat with a small diameter. The pore connectivity would be enhanced by the increase of the connected pores as well as the enlargement of the pore and throat sizes. However, the pore-throat coordination number could only change with slight improvement. In terms of permeability and relative permeability changes with pore structure, the improvement of permeability after gas displacement was higher than that of porosity, and the continuous gas displacement would broaden gas-water flow region and lower irreducible water saturation and residual gas saturation, and then, the equal phase relative permeability point would shift to the right. These investigations will contribute to more accurate reserve evaluation and productivity prediction. [ABSTRACT FROM AUTHOR]

The pore structure can affect the storage and flow properties of rock, which is an important research content in the study of unconventional tight reservoirs. This research hopes to clarify the reservoir characteristics and fluid seepage mechanism of the Chang 9 reservoir in the Wucangpu block and provide technical support for the development of horizontal wells with staged fracturing in this block. In this paper, the microscopic pore structure characteristics and producibility of the reservoir in the study area are analyzed in detail by means of constant-rate mercury intrusion and nuclear magnetic resonance. The research results show that the reservoir with permeability less than 0.076 mD is mainly composed of microthroat, the reservoir with permeability of 0.208-0.633 mD has a larger proportion of microthin throat, and the reservoir with permeability of 2.722-3.998 mD has a larger proportion of fine-middle throats. The results show that the oil/gas in the rock sample reservoirs with permeability greater than 1.0 mD is easy to produce. [ABSTRACT FROM AUTHOR]

Low and ultra‐low permeability reservoirs are widely developed in the Upper Triassic Yanchang Formation in the Ordos Basin, and its intricate pore throat structure has a significant impact on the physical properties and heterogeneity of reservoirs. This paper conducted a series of experiments to investigate the petrology, pore structure, fractal characteristics of ultra‐low permeability sandstone reservoirs, and influencing factors of the physical properties. The results show the sixth member of the Yanchang Formation (Chang 6) reservoir in the Xiaojiahe area is dominated by feldspathic sandstone. The main pores are intergranular pores, followed by dissolution pores. The Chang 6 sandstone has been categorized into four types (type I–IV) based on the traits of mercury intrusion curves. The high content of quartz and feldspar in the detrital components is conducive to improving the physical properties of the reservoir. The pore‐throat structure parameters, such as displacement pressure, median pressure, and pore throat radius can characterize the change in physical properties and reservoir quality. According to the capillary pressure fractal model of rapex (Pittman's plot apex radius), demonstrating the ultra‐low permeability, sandstone has a binary structure. The fractal dimensions D2 and Dp are more appropriate for characterizing the heterogeneity of the pore structure. The effects of different pore‐throat size scales on the physical properties of the reservoir have a discrepancy. Relatively large pore throats (r > rapex), non‐nanoscale pore throats (Porr>0.1), and effective movable pore throats (Porem) have significantly positive control effects on permeability and reservoir quality. In contrast, the development of nanoscale pore throats (Porr<0.1) and micropore throats of failure to enter mercury (Porfem) are unfavourable to reservoir performance. In conclusion, combining detrital components, pore‐throat structure, fractal characteristics, and other factors controlled the reservoir quality of ultra‐low permeability sandstone. [ABSTRACT FROM AUTHOR]

The effects of overburden pressure on porosity and permeability are often neglected in formation evaluation, while it has important influences on reservoir storage and flow capacities. The present work focuses on the effects of overburden pressures on porosity changes in carbonate Mishrif Formation, Iraq. The porosities of 73 core plug samples have been measured under 4 overburden pressures. Winland Equation was reconstructed using the pore throat size of 165 samples which were measured by mercury injection. The Winland, FZI, Lorenz, and porosity data ranges rock typing methods have been used to manage the heterogeneity. Winland recognized as the most suitable method, because porosity, permeability and pore throat sizes are considerably affected by overburden pressures. Two factors of porosity and permeability are affected by overburden pressures in FZI method. In data grouping using ranges of porosity, the effective factors reduce to one. Lorenz method groups successive data and so is not effective for grouping the samples. Results showed that the best methods of managing heterogeneity for overburden tests are Winland, FZI, porosity data range, and Lorenz method, respectively. These new findings can help for better understanding of porosity–pressure relationships with respect to the reservoir heterogeneity. [ABSTRACT FROM AUTHOR]

Copyright of China Surfactant Detergent & Cosmetics (1001-1803) is the property of China Surfactant Detergent & Cosmetics Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

We explore an enhanced geothermal system (EGS) reservoir with horizontal wells connecting multiple hydraulic fractures. In particular we follow the implications of complex thermal–hydraulic–mechanical on the thermal unloading of rock matrix on the permeability evolution. The accuracy and reliability of the proposed model is validated/verified against an existing analytical solution and the Fenton Hill demonstration project. Then, the effect of the fracture number on the heat extraction process is discussed. Results show that matrix permeability enhancement induced by the thermal unloading should be considered in the coupling model. Compared with the results from the traditional model, the maximum temperature difference at the production well can reach 20 K. More fractures in the EGS are advantageous for expanding the cooling range along the production well and have a great impact on the temperature. Generally, an EGS with more fractures is prone to obtain a higher production temperature. In the EGS, fracture number plays an important role in considering both the heat transportation rate and the cooling range in a geothermal exploration process. Per the consideration of geothermal exploitation in the matrix and fracture, there is only a slight difference in the heat extraction ratio for the four numerical cases. [ABSTRACT FROM AUTHOR]

Copyright of Journal of China University of Petroleum is the property of China University of Petroleum and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)