Tight Sandstone Gas Reservoirs Research Articles

Forecasting Gas Well Classification Based on a Two-Dimensional Convolutional Neural Network Deep Learning Model

In response to the limitations of existing evaluation methods for gas well types in tight sandstone gas reservoirs, characterized by low indicator dimensions and a reliance on traditional methods with low prediction accuracy, therefore, a novel approach based on a two-dimensional convolutional neural network (2D-CNN) is proposed for predicting gas well types. First, gas well features are hierarchically selected using variance filtering, correlation coefficients, and the XGBoost algorithm. Then, gas well types are determined via spectral clustering, with each gas well labeled accordingly. Finally, the selected features are inputted, and classification labels are outputted into the 2D-CNN, where convolutional layers extract features of gas well indicators, and the pooling layer, which, trained by the backpropagation of CNN, performs secondary dimensionality reduction. A 2D-CNN gas well classification prediction model is constructed, and the softmax function is employed to determine well classifications. This methodology is applied to a specific tight gas reservoir. The study findings indicate the following: (1) Via two rounds of feature selection using the new algorithm, the number of gas well indicator dimensions is reduced from 29 to 15, thereby reducing the computational complexity of the model. (2) Gas wells are categorized into high, medium, and low types, addressing a deep learning multi-class prediction problem. (3) The new method achieves an accuracy of 0.99 and a loss value of 0.03, outperforming BP neural networks, XGBoost, LightGBM, long short-term memory networks (LSTMs), and one-dimensional convolutional neural networks (1D-CNNs). Overall, this innovative approach demonstrates superior efficacy in predicting gas well types, which is particularly valuable for tight sandstone gas reservoirs.

Pore structure characterization and its influence on aqueous phase trapping damage in tight gas sandstone reservoirs.

Aqueous phase trapping (APT), which is one of the most prominent damages, seriously restricts the natural gas production in tight gas sandstone with low permeability. Pore size and microscopic pore structures are the most important factors to determine the water blocking damage. In this paper, 9 core samples from tight gas sandstone with various physical properties were employed, and the pore size distribution (PSD) of the core samples were investigated by high pressure mercury intrusion tests (HPMI). Results showed that the porosity of core samples ranges from 5.68% to 13.7%, and the permeability ranges from 0.00456 to 7.86 mD, which is a typical tight reservoir with strong heterogeneity. According to the HPMI capillary curve, the cores can be divided into two types: Type I and Type II, and the pore sizes of type I are larger than that of type II. Fractal distributions were obtained using HPMI data to further determine the pore structure characteristics of tight reservoirs. The pore structures of tight sandstones display the multifractal fractal feature: D1 corresponding to macro-pores, and D2 corresponding to fractal dimension of micro-pores. Furthermore, APT damage was determined by the permeability recovery ratios (Kr) after gas flooding tests. The correlation of Kr and PSD and fractal dimensions were jointly analyzed in tight gas sandstone. Although positive correlations between pore size parameters and the permeability recovery ratios were observed with relatively weak correlations, for those core samples with very close permeability, pore size parameters (both permeability and PSD) is inadequate in clarifying this damage. The fractal dimension can well describe the complexity and heterogeneity of flow channels in pores, which can become the determining factor to distinguish the flow capacity of tight sandstone. The D2 for samples of type I and type II exhibited a good negative relation with Kr with a correlation coefficient of 0.9878 and 0.7723, respectively. The significance of this finding is that for tight gas sandstone, fractal dimensions, especially the small pore fractal dimension (D2), can be used to predict the possible APT damage very well.

Pore‐throat structure and fractal characteristics of tight gas sandstone reservoirs: A case study of the second member of the Upper Triassic Xujiahe Formation in Zhongba area, western Sichuan depression, China

Pore‐throat structure is a key factor that influences the storage and fluid flow capacity of tight sandstone reservoirs. Taking the tight sandstone reservoir of Xu2 Fm in Zhongba area as an example, the reservoir quality, pore‐throat type and pore size distribution of tight sandstone in the study area were described by casting thin section, scanning electron microscope and high‐pressure mercury injection test. In order to quantitatively characterize the complexity and heterogeneity of pore‐throat structure, fractal analysis was performed using mercury saturation and pore size data. This study mainly reveals the relationship between the geometric shape characteristics and fractal dimension of the binary pore structure of ultra‐low permeability tight sandstone and clarifies the influence of different scale pore throats on reservoir physical properties. The results indicate that the physical properties of the reservoir in the study area are poor, the pores are mainly intergranular pores and dissolution pores, the throat is flake and necked and the pore size distribution range is large. The fractal curve obtained by the mercury saturation method shows a significant turning point, and the pore‐throat system is divided into two types: small‐scale and large‐scale. The fractal dimension of large‐scale pore throat is greater than the three‐dimensional Euclidean space dimension, which does not conform to the fractal theory. The fractal dimension of small‐scale pore throat is closely related to the pore‐throat structure and has obvious fractal characteristics. The geometric shape of binary pore‐throat structure in tight sandstone is the main factor affecting the difference of fractal dimension. The development of small pores in sandstone is positively correlated with the total porosity, but its contribution to permeability is relatively low. The physical properties of tight sandstone are mainly controlled by the development degree of large‐scale pore throat.

Application of multicomponent seismic data to tight gas reservoir characterization: A case study in the Sichuan Basin, China

Combining PP and PS-waves from multicomponent data is an effective hydrocarbon characterization strategy because these two wave types are sensitive to different subsurface properties. We present a case study using multicomponent data to characterize tight sandstone gas reservoirs in the Jurassic Shaximiao Formation, the western Sichuan Basin, China. In the study area, PP data have difficulties to distinguish sandstones, mudstones and gas sand, while recently acquired multicomponent data show potential for the joint characterization of lithology, porosity, and gas saturation from the combination of PP and PS reflections. Sandstones and mudstones show small P-velocity contrasts and large S-velocity contrasts. Thus, PS data provide a more accurate description of sandstones as a substantial proportion of sandstones are undetectable from PP sections. P-impedance is sensitive to sandstone porosity variation, and seismic-predicted porosities based on impedance inversion are in good agreement with log-interpreted porosities. The ratio of P-velocity to S-velocity is sensitive to gas accumulation, and the ratios derived from joint PP-PS prestack inversion are determined to be better than from PP prestack inversion in terms of their agreements with logs and distinct gas-sand boundaries.

Study on the Mechanism of Wellbore Blockage and Scaling Trend Prediction of Keshen Block

Located in the Kuqa foreland basin, Tarim Basin, the Xinkeshen gas field is a rare ultra-deep and ultra-high-pressure fractured tight sandstone gas reservoir. During the development process, the fluid in the well migrates from the bottom hole to the ground. Due to the huge temperature drop and pressure drop in the wellbore, salting-out and scale-out occur in the well to destroy the oil and gas flow channel, resulting in a decrease in gas production in the well and seriously affecting the normal production of the oil field. Aiming at the problem of wellbore scaling and blockage in the Keshen gas field, this paper takes the wellbore of the Keshen block as the research object. After analyzing the composition of produced water and scale in the wellbore, the solution of ‘fixing scale, clarifying mechanism, early prediction, and fine treatment’ is formulated, and the analysis and evaluation technology of the scale formation process and the prediction model of the gas well model are formed. The wellbore blockage in Keshen block is composed of iron oxide, calcium carbonate crystal, calcite crystal, and wellbore steel falling off due to electrochemical corrosion. It is indicated that the scale attached to the steel sheet causes electrochemical corrosion of the steel sheet, resulting in ‘hydrogen embrittlement’, resulting in the bubbling and falling off of the wellbore steel. Through simulation, it is found that the amount of fouling increases with the increase in wellbore depth, and the amount of fouling is 1.97 kg/d at 6800 m, which is in good agreement with the actual situation. Based on the temperature and pressure curves in the wellbore, the simulation results show that the corrosion rate reaches the highest value of 6.37 mm/yr at the depth of 3400 m. Because of the above problems, a polyaspartic acid scale inhibitor with a scale inhibition rate of 98.9% for wells in Keshen block was synthesized. It has important guidance and reference significance for the accurate treatment of scaling problems in the Keshen gas well.

Coupling of source rock gas expulsion intensity and reservoir quality in time and space-a key to determine gas accumulation in Upper Paleozoic tight sandstones of the Mugua gas field, Ordos Basin, China

Research on gas accumulation mechanisms and variations in gas saturation is limited in the newly established Mugua gas field in the Ordos Basin. Understanding these aspects is vital for reduce drilling uncertainty and exploration risk. This study employed a variety of methods, including: (1) the use of organic geochemical examinations to determine the gas expulsion intensity of hydrocarbon source rocks; (2) fluid inclusion analyses to determine the time of gas accumulation; (3) a combination of optical microscopy, scanning electron microscopy observations, pore-simulation and permeability tests, mercury-intrusion capillary pressure experiments, and nuclear magnetic resonance studies to assess the properties of the reservoir quality and identify the tight sandstone rock type; (4) wireline logging and interpretive data analyses to research the gas saturations features; and (5) establish reservoir quality evolution model to systematically study this problem. Integrating fluid inclusion homogenization temperatures with burial and thermal histories indicates that gas accumulation in the Mugua gas fields occurred throughout the Early Jurassic to Late Cretaceous period. Five diagenetic facies have been identified: dissolution, quartz-cemented, clay mineral filling, tightly compacted, and carbonate-cemented facies. The reservoir quality evolution model reveals that the five diagenetic facies experienced densification before the period of gas accumulation. Therefore, for gas accumulation in tight sandstones, it is essential that mature and gas-generating source rocks, provide sufficient expulsion forces to drive gas into the rocks. The mechanism of gas accumulation in the Mugua gas field's tight gas sandstone reservoirs involves the process occurring in sandstones that are either near or interbedded with source rocks, under high pore-fluid pressure generated by gas production. Compared to other Upper Paleozoic gas fields in the Ordos Basin, the gas expulsion intensity in the Mugua gas field is lower, ranging from 6.12–8.39 × 108 m3/km2. Due to the low gas expulsion intensity, the Shihezi 8 Member's tight sandstone reservoirs, situated away from the source rock, typically show low gas saturation. Conversely, the dissolution and quartz-cemented facies within the Benxi, Taiyuan, and Shanxi Formations, intimately interbedded with hydrocarbon source rocks, exhibit good reservoir quality. They offer ideal conditions for gas accumulation, making them prime candidates for exploration and development.

Evaluation of Recovery of Tight Sandstone Gas Reservoirs Based on a Seepage Steady-State Model

As an important indicator for measuring the effectiveness and level of oil and gas field development, recovery rate has always been a focus in the research of oil and gas fields. Reservoirs of tight sandstone gas formations have significant characteristics of low porosity, high permeability, and high water content, which leads to greater difficulty in their development and makes it challenging to evaluate the recovery rate. Newtonian mechanics, as an important component of the mechanical system, is an innovative application of classical mechanics in the field of seepage mechanics when applied to the two-phase flow of gas and water. Firstly, starting from the perspective of mechanics analysis, we derive a steady-state model for gas–water two-phase infiltration and obtain the productivity equation based on this model. Then, according to the steady-state model, we establish a method to calculate the effective control radius of gas reservoirs under different production conditions and reservoir physical properties. Finally, using Matlab 2018a programming based on the productivity equation, we calculate the gas recovery under different conditions during constant pressure drop production and constant production rate production. The results indicate that the effective control radius of the reservoir decreases with an increase in the economic ultimate daily gas production, increases with an increase in production pressure difference, slightly decreases with an increase in startup pressure gradient, and correspondingly increases with an increase in microtube radius and quantity. Regardless of whether it is production with a fixed pressure drop or production with a fixed production rate, the gas recovery decreases as the production pressure drop and bottomhole abandonment pressure increase, but it increases as the proportion of the single-well control radius increases. In production with a fixed pressure drop, the gas recovery remains consistent across different reservoir quality indices. However, in production with a fixed production rate, the gas recovery initially increases rapidly and then gradually slows down as the reservoir quality index increases, and there is an obvious critical permeability (0.1 mD). The research findings are based on the mechanical analysis of porous media, delving into the laws governing fluid flow during infiltration. The derived infiltration model can be used to calculate the effective control radius and evaluate recovery rates, providing practical guidance for reservoir development.

Research on the Scaling Mechanism and Countermeasures of Tight Sandstone Gas Reservoirs Based on Machine Learning

The Sulige gas field is a typical “three lows” (low permeability, low pressure, and low abundance) tight sandstone gas reservoir, with formation pressures often characterized by abnormally high or low pressures. The complex geological features of the reservoir further deviate from conventional understanding, impacting the effective implementation of wellbore blockage removal measures. Therefore, it is imperative to establish the wellbore blockage mechanism, prediction model, and effective prevention measures for the target area. In this study, based on field data, we first experimentally analyzed the water quality and types of blockage in the target area. Subsequently, utilizing a BP neural network model, we established a model for predicting the risk of wellbore blockage and analyzing mitigation measures in the target reservoir. The model’s prediction results, consistent with on-site actual results, demonstrate its reliability and accuracy. Experimental results show that the water quality in the target area is mainly a CaCl2 type, and the predominant scales produced are CaCO3 and BaSO4. Model calculations reveal that temperature, pressure, and ion concentration all influence scaling, with BaSO4 more influenced by pressure and CaCO3 more influenced by temperature. Under the combined effect of temperature, pressure, and ion concentration, different types of scales exhibit distinct trends in scaling quantity. Combining scaling quantity calculations with wellbore contraction ratios, it was found that when the temperature, pressure, and ion concentration are within a certain range, the wellbore contraction rate can be controlled below 4%. At this point, the wellbore scaling risk is minimal, and preventive measures against wellbore scaling can be achieved by adjusting production systems, considering practical production conditions. This study investigates the mechanism of scaling in wellbores of tight sandstone gas reservoirs and proposes a cost-effective scaling prevention measure. This approach can guide the prediction of scaling risks and the implementation of scaling prevention measures for gas wells in tight sandstone reservoirs.

Production forecasting methods for different types of gas reservoirs

Hydrocarbon production in oil and gas fields generally progresses through stages of production ramp-up, plateau (peak), and decline during field development, with the whole process primarily modeled and forecasted using lifecycle models. SINOPEC's conventional gas reservoirs are dominated by carbonates, low-permeability tight sandstone, condensate, volcanic rocks, and medium-to-high-permeability sandstone. This study identifies the optimal production forecasting models by comparing the fitting coefficients of different models and calculating the relative errors in technically recoverable reserves. To improve forecast precision, it suggests substituting exponential smoothing method-derived predictions for anomalous data caused by subjective influences like market dynamics and maintenance activities. The preferred models for carbonate gas reservoir production forecasts are the generalized Weng's, Beta, Class-I generalized mathematical, and Hu-Chen models. The Vapor pressure and Beta models are optimal for forecasting the annual productivity of wells (APW) from gas-bearing low-permeability tight sandstone reservoirs. The Wang-Li, Beta, and Yu QT tb models are apt for moderate-to-small-reserves, single low-permeability tight sandstone gas reservoirs. The Rayleigh, Hu-Chen, and generalized Weng's models are suitable for condensate gas reservoirs. For medium-to-high-permeability sandstone gas reservoirs, the lognormal, generalized gamma, and Beta models are recommended.

Differences in stress sensitivity of natural-artificial fracture networks in tight sandstone gas reservoirs

Abstract The stress sensitivity of fractures has a significant impact on the production characteristics of tight sandstone gas reservoirs. However, there has been a lack of attention to and research on the differences between different types of fracture and their stress sensitivity. Based on the core samples of the Keshen gas reservoir in Xinjiang, China, this paper conducts a comprehensive comparison of the flow capacity, stress sensitivity, and the production characteristics of the structural fracture, diagenetic fracture, and artificial fracture. The findings reveal that the flow capacity of a single structural fracture is higher than that of a diagenetic fracture. Additionally, both structural and diagenetic fractures contribute to increasing the flow capacity of the porous system by 63 and 88%, respectively. The stress sensitivity of fractures varies from strong to weak, structural fractures exhibit a higher sensitivity compared to diagenetic fractures, and artificial fractures demonstrate the weakest stress sensitivity. Based on the fitting formulas of stress-sensitivity curves for different fractures, a new seepage model considering different stress sensitivities was established and numerical simulations were conducted. The numerical simulation results indicate that the gas well with a diagenetic-artificial fracture network yields a higher production, the 10-year production is 35.01% higher than that with a structural-artificial fracture network. This study is of great significance for understanding the production differences of fractured tight sandstone gas reservoirs and provides valuable insights for selecting optimal well locations.

Exploration and Application of Geological Engineering Integrated Foam Drainage Technology in Tight Sandstone Gas Reservoirs

Exploration and Application of Geological Engineering Integrated Foam Drainage Technology in Tight Sandstone Gas Reservoirs

Formation mechanism of the upper Paleozoic tight sandstone gas reservoir in the Daniudi gas field, Ordos Basin, China

The upper Paleozoic gas reservoir in the Daniudi gas field, Ordos Basin, is one of the typical tight sandstone gas reservoirs in China. Research into the sequential order of reservoir densification and gas accumulation is the key to revealing the formation mechanism of tight sandstone gas reservoirs. However, this scientific issue is still a subject of debate in the Daniudi gas field. Based on a series of reservoir experiments and in combination with stratigraphic burial and thermal maturity history, a comprehensive study is conducted on the formation and natural gas accumulation processes of the upper Paleozoic sandstone reservoir in the Daniudi gas field. Study results indicate that the main causes of sandstone reservoir densification of the study area include long-term compaction, multistage quartz cementation and carbonate cementation. In accordance with the time order of reservoir densification and gas accumulation, the formation of tight gas reservoirs can be divided into two types: self-sourced and near-source accumulations. In the former, before sandstone reservoir densification occurs, low-maturity natural gas generated from coal rocks and dark mudstones enter the reservoir quickly, migrate towards structural highs as driven by buoyancy, and then accumulate and form gas reservoir in favourable lithologic traps. In the latter, after tight sandstone reservoirs are formed, high-maturity gas migrates along fractures formed in the Late Cretaceous and accumulate in the nearby reservoir with micro-fractures. The study results provide a new understanding of the formation process of tight sandstone gas reservoirs and provides a reference for the exploration and development of the same type gas reservoirs.

Characteristics of Tight Gas Reservoirs in the Xujiahe Formation in the Western Sichuan Depression: A Systematic Review

In current energy structure adjustments, the prominence of unconventional oil and gas resources continues to grow, with increasing attention being paid to tight gas, a major component of natural gas production. The Xujiahe Formation gas reservoir in the Western Sichuan Depression represents a typical tight gas reservoir and the study of its reservoir characteristics is a key focus for current and future exploration and development efforts. This review employs the PRISMA method to screen and integrate the primary findings of 26 documents spanning the period from 2008 to 2023, with the aim of providing a comprehensive overview of the progress and outcomes of research on the tight gas reservoir characteristics of the Xujiahe Formation in the Western Sichuan Depression. The selected research documents summarize the characteristics of the Xujiahe Formation tight gas reservoir in the Western Sichuan Depression from four perspectives: lithology, physical properties, reservoir space, and the main factors influencing reservoir quality. Through a review of these previous studies, it is evident that existing research has predominantly focused on the relationship between diagenesis and reservoir densification, indicating certain limitations. We also delve into the characteristics of tight gas sandstone reservoirs in the study area, considering their depositional systems, fracture development, cementation, and impact on the exploration and development of tight gas reservoirs. Additionally, we propose measures to stabilize and enhance tight gas production in the Xujiahe Formation in the Western Sichuan Depression. Moreover, we outline the next steps for further research and exploration.

Study on a New System of Water Unlocking in Tight Sandstone Gas Reservoirs

Study on a New System of Water Unlocking in Tight Sandstone Gas Reservoirs

Study on the sedimentary characteristics of braided fluvial fan

As a typical tight sandstone gas reservoir in the Ordos Basin, the second member of the Shanxi Formation in the XQ gas field in the Ordos Basin has had rich gas reservoirs and good development effects in the past. On the basis of previous studies, this paper brings new understanding to the sedimentary model of this area. Nine kinds of single lithofacies and seven kinds of lithofacies combinations are determined. Braided fluvial fan deposits in distributive fluvial systems likely developed in this area. The study area is part of the middle subfacies of this sedimentary facies, and five kinds of sedimentary microfacies environments developed. Finally, establishing sedimentary model based on sedimentary characteristics. The braided fluvial fan sedimentary model based on DFS is of great significance for deepening the understanding of terrestrial sedimentary systems and providing guidance for the exploration and development of oil and gas bearing basins.

Zoning Productivity Calculation Method of Fractured Horizontal Wells in High-Water-Cut Tight Sandstone Gas Reservoirs under Complex Seepage Conditions

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.

Productivity Equation of Fractured Vertical Well with Gas–Water Co-Production in High-Water-Cut Tight Sandstone Gas Reservoir

Due to the high water saturation in high-water-cut tight sandstone gas reservoirs, factors such as threshold pressure gradient (TPG) and stress sensitivity (SS) cannot be overlooked in terms of their impact on seepage parameters. Therefore, this paper primarily investigates the seepage mechanisms in tight, high-water-cut sandstone gas reservoirs. While considering the influence of water saturation on various seepage mechanisms, it establishes a gas well productivity equation under stable seepage conditions and presents an analysis of the influencing factors. In a comparison of the unobstructed flow rates calculated using the productivity equation developed in this paper with those obtained from conventional gas well productivity equations and actual gas well productivity tests, the new equation demonstrates smaller errors. This provides a theoretical basis for evaluating productivity and making rational production allocation decisions in high-water-cut tight sandstone gas reservoirs.

Seepage Model and Pressure Response Characteristics of Non-Orthogonal Multi-Fracture Vertical Wells with Superimposed Sand Body in Tight Gas Reservoirs

Faced with difficulties stemming from the complex interactions between tight gas sand bodies and fractures, when describing and identifying reservoirs, a composite reservoir model was established. By setting the supply boundary to characterize the superposition characteristics of sand bodies, a mathematical model of unstable seepage in fractured vertical wells in tight sandstone gas reservoirs was developed, considering factors such as stress sensitivity, fracture density and fracture symmetry. The seepage law and pressure response characteristics of gas wells in tight sandstone discontinuous reservoirs with stress sensitivity, semi-permeable supply boundary and complex fracture topology were determined, and the reliability of the model was verified. The research results more accurately display the pressure characteristic of a vertical well in the superimposed sand body with complex fractures and provide a more comprehensive model for tight gas production dynamic analysis and well test data analysis, which can more accurately guide the dynamic inversion of reservoir and fracture parameters.

Model of shear strength of ultra-deep fractured sandstone considering fracture morphology

Ultra-Deep fractured tight sandstone gas reservoir, the hotpot unconventional petroleum resources, has been the subject of investigation recently. Due to the presence of natural fractures, drilling in ultra-deep fractured tight sandstone may cause complicated wellbore instabilities, which resulted in a substantial challenge to the efficient exploitation and production of tight gas resources. In order to understand the rock mechanical properties of the ultra-deep fractured tight sandstone under shear stress, tight sandstone core samples were artificially shear-fractured, the 3D characteristics of the fractures were reconstructed by CT scanning, and the fracture aperture and roughness characteristics were systematically evaluated. Simultaneously, triaxial shear strength tests were conducted to evaluate the mechanical properties of fractured rock subjected to varying confining pressures. Considering the contact relationship of the fracture surface during shearing, two indexes of average effective shear angle and contact area ratio were proposed to correct the fracture roughness, and a new fracture shear strength model was constructed, which served as the failure criterion for the fractured formation. The results show that the intact rock has a high compressive strength and can only collapse under conditions of substantial differential stress. Consequently, shear failure of fracture ought to be the primary source of wellbore instability. The fracture aperture's spatial distribution is irregular and conforms to a Gaussian distribution. A clear anisotropy in the fracture roughness is present, and there is less roughness along the initial shear failure path and more roughness perpendicularly. With an increase in normal stress, the fracture's peak shear strength rises, while the friction angle steadily falls. The innovative model's accuracy in predicting shear strength is higher than that of the weak-surface model and the JRC-JCS model.

Model of cross-flow interference index and application for multi-layer commingled production in Sulige tight sandstone gas reservoir, Ordos Basin, China

Multi-layer commingled production is the main feature of gas well development in Sulige tight sandstone gas reservoir, Ordos Basin. Identifying potential interference between layers and devising methods for their characterization are crucial considerations for optimizing the development of gas reservoirs. To address these issues, we designed a physical simulation experiment process and interlayer commingled mining schemes, implementing various interlayer combination modes. The results show that a common occurrence in the process of multi-layer commingled production of tight gas and water layers, whether it involves gas layers production alone or simultaneous production of gas and water layers. This phenomenon involves the crossflow of gas and water between layers, resulting in interlayer interference and a subsequent reduction in gas reservoir recovery. Based on these observations, the concept of an interlayer interference index in multi-layer commingled production in tight sandstone gas reservoirs is proposed. The interference index model is obtained by fitting the multiple linear regression method, showcasing its correlation with the physical properties of the reservoir. High water saturation and a significant permeability ratio of the water layer to the gas layer (exceeding the critical value of 1) can result in the early occurrence of interlayer interference and yield a higher interference index. Furthermore, based on the interference index model, a novel method for productivity evaluation of gas wells in tight gas reservoirs is established. The calculations demonstrate that the interference index curve effectively characterizes the interlayer interference performance of gas wells. The productivity and production performance predictions derived from this model align closely with historical production data, affirming the model's effectiveness and accuracy. Therefore, the interference index model emerges as a valuable tool for predicting the productivity and production performance of gas wells in Sulige tight sandstone gas reservoirs. The research results have important theoretical guidance and practical significance for the efficient development of Sulige tight sandstone gas reservoirs.