Evaluating the adsorbed gas ratio (AGR) in the cumulative/daily production of shale gas is essential for optimizing development strategies, but no widely accepted method exists in the industry. The isotope fractionation method has emerged as a potential tool to achieve this goal. This study conducted isotope fractionation experiments on full-diameter shale under overburden pressure conditions during the shale gas depletion development. The results demonstrate that carbon and hydrogen isotopes during shale gas production exhibit a three-stage fractionation behavior, characterized by "stable (I)-decreasing (II)-increasing (III)". On this basis, an innovative carbon isotope fractionation model for 12CH4 and 13CH4 during mass transport in the dual-porosity medium was established, which effectively reduced the multi-solution of traditional numerical models by simultaneously matching the experimental data of production, pressure, and delta 13C1 value. Quantitative calculations indicate that in Stage I of the isotope fractionation, fracture gas is dominant. In Stage II, the produced gas is contributed by both fracture gas and matrix gas, with free gas dominating the matrix gas and adsorbed gas being secondary (the turning point of Stage II and Stage III (P2) corresponds to an AGR of 48.30% in daily gas production), and a large amount of adsorbed gas still not effectively utilized (P2 corresponds to an adsorbed gas recovery ratio of 18.84%). Starting from Stage III, adsorbed gas gradually replaces free gas and assumes a dominant role. This study is crucial for understanding the dynamic fractionation mechanism during isotopic molecule transport in complex pore-fracture systems and provides technical support for the optimization of development plans.

Water invasion is a core factor constraining efficient development and ultimate recovery in water-drive gas reservoirs. Non-uniform water invasion can reduce recovery by 15%-50% compared with water-free gas reservoirs of the same type. In recent years, the full-life-cycle enhanced gas recovery (EGR) philosophy, staged-technology framework, and integrated drainage-injection co-regulation models have continued to evolve, shifting water-drive gas reservoir development from passive water control toward proactive regulation, and from single-technology interventions toward multi-technology synergy. This paper systematically reviews the mechanisms of water blocking, water sealing, pressure-field imbalance, and relative permeability hysteresis, and their compound amplification effects across four scales. On this basis, it organizes primary, secondary, and tertiary gas recovery into a unified framework, and conducts a comparative analysis of key technologies including optimized regulation for water invasion prevention, intensive water drainage, N2/CO2 injection for energy replenishment, drainage-injection co-regulation, chemical water shutoff, and nano-fluid water-unblocking, along with their field application cases (Kela 2, Keshen 8, Keshen 24, Sebei, Dabei 102). The paper proposes four future breakthrough directions—AI and digital twin integration, cross-generation technology fusion, CCUS-EGR integrated deployment, and expansion toward extreme reservoir conditions—and advocates a paradigm shift in water-drive gas reservoir development from empirical staged treatment to intelligent, full-life-cycle adaptive EGR systems.

Water lock in the near-wellbore region severely constrains the productivity of tight sandstone gas reservoirs. Unlike conventional methods limited by high energy costs and secondary pollution, microwave heating offers a high-efficiency alter native capable of simultaneously reducing flow resistance and inducing fracture-enhanced permeability. This study investigates these mechanisms using Sulige sandstone cores through a combination of CT scanning, XRD, physical experiments, and coupled thermo-hydro-mechanical simulations. Key findings include: (1) Microwave radiation induces pore water vaporization and thermal stress fracturing, significantly improving pore connectivity once a temperature threshold of 500 degrees C is surpassed. (2) Under optimal conditions (800 W, 15min), the stable production period extended by 23-48 times, and ultimate recovery improved by approximately 20-26% across varying water saturations. (3) Numerical modeling, exhibiting high agreement with experimental data, predicts an effective confirm the efficacy of microwave heating in alleviating water lock, offering a robust theoretical and technical basis for optimizing field development strategies.

CO₂ injection into gas reservoirs for enhanced gas recovery (CO₂-EGR) offers the dual benefits of geological carbon storage and increased natural gas production. However, the complex mixing of CO₂ and CH₄ in porous media limits accurate prediction of mixing-zone evolution and displacement efficiency. In this study, a high-temperature and high-pressure full-diameter core-flooding platform was developed, and a dynamic core breakthrough method was applied to tight sandstone and fractured core samples from the Sulige gas field. Longitudinal dispersion coefficients were determined, and the effects of temperature, pressure, water saturation, injection flow rate, and heterogeneity scale on CO₂–CH₄ mixing were systematically evaluated. The results demonstrate that the overall mixing process arises from the coupled contributions of molecular diffusion and convective dispersion. Under typical reservoir conditions, convective dispersion contributes approximately 90% of the total dispersion, whereas the diffusion contribution increases to about 30% under gaseous CO₂ conditions. The high viscosity of liquid CO₂ markedly suppresses mechanical dispersion. The dispersion coefficient increases exponentially with temperature and linearly with injection flow rate, while elevated pressure strongly enhances mixing in fractured cores. Water saturation exhibits a dual effect through changes in pore topology. Once water saturation exceeds 60%, improved channel connectivity caused by reduced tortuosity dominates, leading to a sharp increase in dispersion. Tortuosity was identified as the key geometric parameter governing dispersion-path complexity. Based on this finding, a three-region evaluation framework and a generalized dimensionless dispersion model coupling rock topology with fluid dynamic properties were established. The proposed model enables cross-scale prediction of dispersion intensity and provides a basis for estimating mixing-zone development and CO₂ breakthrough time in field-scale CO₂-EGR operations.

Facing the challenge of extracting residual gas in depleted aquiferous gas reservoirs and water-flooded abandoned gas reservoirs due to abandonment pressure, this study investigates the feasibility of enhancing recovery through nitrogen injection. Based on the concept of development mode transformation in mature gas fields, simulation experiments were designed to evaluate nitrogen injection in pore-water and edge-water gas reservoirs under near-abandonment or water-flooded conditions. The results show that nitrogen injection effectively replenishes reservoir energy, enhances gas seepage capacity, increases the displacement pressure gradient, and significantly improves CH₄ production. In edge-water gas reservoirs, it also reduces water invasion and releases water-blocked gas. In vertically heterogeneous edge-water reservoirs, where high-permeability layers experience water breakthrough, nitrogen injection proves particularly effective in improving recovery from low-permeability layers. This study confirms nitrogen injection as a viable method to enhance recovery in depleted and water-flooded gas reservoirs, especially in heterogeneous formations, offering a new technical approach for efficient development of near-abandoned gas reservoirs.

Accurate characterization of water saturation in tight sandstone gas reservoirs is the key to reservoir evaluation and productivity prediction. In view of the limitations of the traditional Archie formula in describing the strongly heterogeneous pore structure and the insufficient consideration of the coupling effect of pore throat geometry and fractal characteristics in the existing models, this paper innovatively combines the fractal theory with the trapezoidal pore throat model to construct a new water saturation interpretation model. By introducing parameters such as fractal dimension (Df), tortuosity fractal dimension (DT) and trapezoidal factor (phi i), the model systematically quantifies the control mechanism of microscopic pore throat distribution, capillary force field evolution and stress sensitivity (rock elastic modulus E = 1.05 & times; 103 MPa) on water saturation. The model was verified by the sealed coring and nuclear magnetic resonance experimental data of 10 groups of typical tight sandstone cores in Sulige gas field, Ordos Basin. The results show that: (1) The absolute error range between the water saturation calculated by the model and the measured value of the closed coring is 0.89-11.27%, indicating that the model has high accuracy and good applicability. (2) There is a significant negative correlation between reservoir water saturation and reservoir temperature and displacement pressure difference: for every 20 degrees C increase in temperature, water saturation decreases by about 4.5%; when the displacement pressure difference increases by 1 MPa, the water saturation decreases by about 6.3%. (3) The study further shows that under the condition of constant displacement pressure difference, the water saturation of the reservoir is positively correlated with the effective stress and negatively correlated with the maximum/minimum pore throat radius ratio. Rock mechanics parameters also have an impact on water saturation-the lower the elastic modulus, the higher the Poisson's ratio, the greater the reservoir water saturation. The model can accurately predict the water saturation of the reservoir and provide an effective tool and support for the fluid quantitative evaluation and development scheme optimization of tight sandstone gas reservoirs.

CCUS-EGR is becoming the most cost-effective method for energy saving and emission reduction globally. However, the acidic nature of CO2 can alter the reservoir permeability over time, affecting the stability and sustainability of gas injection. To explore this, long-term CO2 injection simulations were conducted on tight sandstone, carbonate rock, and volcanic rock. By applying gas and water permeability calculation methods, the reservoir permeability was monitored in real time throughout the long-term displacement process. Combined with NMR measurements, cross-lithology comparison analysis was conducted to investigate the evolution characteristics of pore structure and flow capacity, as well as the key influencing factors in various lithological reservoir samples. The results show that the influence of long-term CO2 replacement and shut-in well reinjection replacement on the seepage capacity of the rock samples mainly comes from the combined effects of clay expansion, mineral particle settling and plugging, and reaction dredging to increase infiltration, and the process of water-rock reaction involves mineral particles reacting, dissolving, dislodging, transporting, and plugging. The long-term replacement and shut-in well reinjection experimental process of dense sandstone seepage capacity slightly reduced or basically unchanged, due to the greater clay effect; with carbonate rock calcite and dolomite as the main components, CO2-water-rock reaction is dominated by mineral dissolution and clearing channels to increase seepage, with a significant increase in seepage capacity; feldspar is abundant in volcanic rocks, leading to mineral precipitation and pore-blocking during CO2-water-rock reaction. This results in mesopore enlargement and blockage of both micro- and macropores. The channel clearing and permeability enhancement are weaker compared with carbonate reservoirs, with only a slight increase in overall seepage capacity. These findings provide valuable guidance for the efficient implementation of the CCUS-EGR.

Gas-water relative permeability curve is the foundation of gas reservoir dynamic analysis and numerical simulation. It is generally obtained through gas displacing water experiment. Referring to the existing national standards, gas-water relative permeability test is carried out for low-permeability and tight sandstone. The flow is discontinuous and the curve smoothness is poor, which affects the application of gaswater relative permeability curve. Based on the comparative analysis of a large number of mercury injection and NMR experimental results of low-permeability and tight sandstone, a method to characterize the throat radius distribution of low-permeability tight sandstone based on NMR T2 spectrum is explored. Combined with high-speed centrifugal experiment, the calculation formulas of core water saturation, phase relative permeability of gas-water under different centrifugal force are established. A new method of “nuclear magnetic resonance + high-speed centrifugation” for gas-water relative permeability curve test of lowpermeability and tight sandstone is formed, and the test is carried out on Sulige low-permeability tight sandstone core. The results show that: (1) The shape of cumulative distribution curve of throat radius by mercury injection method is basically consistent with that of T2 relaxation time by NMR, and there is a good corresponding relationship between them. (2) The centrifugation process is similar to the gas displacing water process. With the decrease of water saturation, water centrifugation in rock core becomes more and more difficult until it become irreducible. (3) The core relative permeability curve obtained by the new method is consistent with the curve obtained by the standard method and has good repeatability. The new method can be used for gas-water relative permeability tests of low permeability tight sandstone. (4) The test process of the new method is unified and standard and up to 6 cores can be tested at the same time. The calculation results of water saturation and relative permeability curve are reliable and the integral curve is smooth, which greatly improves the test efficiency of gas-water relative permeability curve in lowpermeability and tight sandstone. The new method can be widely used to study the gas-water two-phase seepage law in low-permeability and tight sandstone gas reservoir.

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.

Conventional recovery enhancement techniques are aimed at reducing the abandonment pressure, but there is an upper limit for recovery enhancement due to the energy limitation of reservoirs. Gas injection for energy supplementation has become an effective way to enhance gas recovery by reducing hydrocarbon saturation in gas reservoirs. This review systematically investigates progress in gas injection for enhanced gas recovery in three aspects: experiments, numerical simulations and field examples. It summarizes and analyzes the current research results on gas injection for EGR and explores further prospects for future research. The research results show the following: (1) Based on the differences in the physical properties of CO2, N2 and natural gas, effective cushion gas can be formed in bottom reservoirs after gas injection to achieve the effects of pressurization, energy replenishment and gravity differentiation water resistance. However, further experimental evaluation is needed for the degree of increase in penetration ability. (2) It is more beneficial to inject N2 before CO2 or the mixture of N2 and CO2 in terms of EGR effect and cost. (3) According to numerical simulation studies, water drive and condensate gas reservoirs exhibit significant recovery effects, while CO2-EGR in depleted gas reservoirs is more advantageous for burial and storage; current numerical simulations only focus on mobility mass and saturation changes and lack a mixed-phase percolation model, which leads to insufficient analysis of injection strategies and a lack of distinction among different gas extraction effects. Therefore, a mixed-phase-driven percolation model that can characterize the fluid flow path is worth studying in depth. (4) The De Wijk and Budafa Szinfelleti projects have shown that gas injection into water drive and depleted reservoirs has a large advantage for EGR, as it can enhance recovery by more than 10%. More experiments, simulation studies and demonstration projects are needed to promote the development of gas injection technology for enhanced recovery in the future.

The calculation of the influx index is one of the most contentious issues in dynamic reserve evaluation of gas reservoirs’ development. For the influx index, it is key to obtain information on the pore compressibility coefficient under realistic gas reservoir pressure. So far, little is known about the assessment of the pore compressibility coefficient at a laboratory scale. Here, we combine observations of gas flowmeter, ISCO booster pump, intermediate container, and rock samples to quantify the pore compressibility coefficient from the KL2-13 well in the Kela-2 reservoir. Additionally, the iterative method (combined the static and dynamic methods) is proposed based on the experimentally obtained pore compressibility coefficient (Cf), dynamic reserve (G), water body multiple (β), and material balance equation to calculate the influx index. The combined iterative method adjusts the values of G and N by comparing the results of the static and dynamic methods, and iteratively corrects Cf using a binary search method until the results of the static and dynamic methods are consistent. The results of our study reveal that the influx index calculated by the dynamic and static methods was consistent, and the gas production per unit pressure drop matched the actual production. These results strongly suggest that there exists a correlation between formation pressure and the influx index, wherein the latter exhibits a gradual decrease as the former decreases. Conversely, the displacement index of both the rock and connate water do not demonstrate a significant dependence on pressure. Furthermore, the impact of pressure on the pore compressibility factor and reservoir water compressibility factor appears to be minimal. These findings hold substantial implications for understanding the behavior of gas reservoirs under varying pressure conditions.

Tight sandstone gas reservoirs are characterized by high water saturation, significant seepage resistance, low single-well productivity, rapid decline, and low gas recovery. Enhancing the recovery rate of tight sandstone gas reservoirs is a complex engineering challenge that necessitates thorough, refined, and systematic research into its fundamental theories. This study employs a comprehensive approach integrating mercury injection, nuclear magnetic resonance, micro-model visualization, and simulation experiments of displacement and inter-layer seepage flow, alongside foundational seepage theories, to systematically explore the characteristics of tight sandstone gas reservoirs, seepage patterns, and methods for improving gas recovery. Our findings reveal: (1) Detailed characterization of the microscopic pore characteristics in tight sandstone reservoirs helps disclose the status and mechanisms of gas-water occurrence and the principal mechanisms of water production under gas-water co-sealing conditions, such as gas expansion, energy of water-sealed gas, movable water volume, and displacement pressure gradient; (2) Testing single-phase and gas-water two-phase seepage characteristics under bound water saturation identifies permeability and water saturation as critical parameters influencing gas seepage characteristics; (3) Inter-layer gas-water interaction flow experiments demonstrate the interference in multi-layer commingled production and introduce the concept of an interference index, a predictive model for well productivity and dynamic performance in the Sulige tight sandstone gas reservoir; (4) A model correlating reservoir recovery rates with drive indices has been developed, highlighting that increasing production pressure differential and reducing seepage resistance are the primary strategies for enhancing recovery rates in tight sandstone gas reservoirs, supplemented by six technological countermeasures including water-blocking, water control, and densifying well networks. The research outcomes provide effective guidance for practical measures to enhance recovery in tight sandstone gas reservoirs.

The pore throat size, structure distribution, and lithology of porous media in gas reservoirs are varied, and the gas-water two-phase seepage law is complex, making it difficult to describe the seepage model. Newton's law of motion is a basic law of motion in classical mechanics, and its application in gas-water two-phase seepage modeling is an innovative practice of classical mechanics in seepage mechanics systems. Based on Newton's three laws of motion, a gas-water two-phase seepage model was established from the force analysis of fluid, and the relationship between velocity and pressure difference, pipe radius, water film thickness, viscosity, etc. was derived under the condition that the model reached a stable state, i.e., force balance. The relationship is referred to as the steady-state model. Subsequently. the equivalent permeability representation model was derived based on the steady-state model to calculate the permeability of rock samples with different channel distribution characteristics. The results were consistent with the measured values, and there is a good correspondence between channel distribution characteristics and permeability. The relative permeability calculation method was established based on the steady-state model and capillary pressure curve. The obtained relative permeability curve aligned with the two-phase seepage law and coincides with the relative permeability curve obtained by Poiseuille's law. Finally, a new productivity equation was derived based on the steady-state model, and the Inflow Performance Relationship (IPR) curve calculated by the gas well example was consistent with the traditional equation. The research results were based on the force analysis of fluid in porous media and fundamentally explored the law of fluid flow. The derived seepage model can be used to calculate reservoir permeability, the gas-water relative permeability curve, and gas well productivity analysis and to effectively guide gas reservoir development. The study was a successful application of the basic theory of mechanics in gas-water two-phase seepage in gas reservoirs.

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.

In view of the diversity of gas reservoir classification and the differences of characteristics of geology and development in different gas reservoirs, it is necessary to study the adaptability of gas reservoir classification. This paper analyzes and summarizes the current classification methods of gas reservoirs, studies the microscopic pore characteristics and seepage mechanism of different gas reservoirs. The commonalities and individualities of seepage laws in different gas reservoirs are determined, the key factors that determine the development dynamics and effects of gas reservoirs are proposed, and the gas reservoirs types are divided from the perspective of development. The results show that the development characteristics of gas reservoirs are determined by the seepage law, and the seepage law is determined by the microscopic pore characteristics. Therefore, from the perspective of development, the microscopic pore characteristics are the fundamental of gas reservoir classification. Gas reservoirs can be divided into four types: tight, low permeability, medium and high permeability, and fractured. This classification method can unify the types of gas reservoirs according to the seepage laws of different gas reservoirs, establish corresponding seepage models, evaluate productivity, and predict performance. It is of great significance for rational, efficient and scientific development of gas fields.

It is of engineering interest to explore recovered shale gas composition and its effects on total gas production trend over a long-term extraction period. However, there are previous experimental studies mostly focused on short term development for small scaled cores, which is less convincing to mimic reservoir-scaled shale production process. In addition, the previous production models mostly failed to account for comprehensive gas nonlinear effects. As a result, in this paper, to illustrate the full-life-cycle production decline phenomenon for shale gas reservoir, dynamic physical simulation was performed for more than 3433 days to simulate shale gas transport out of the formations over a relatively long production period. Moreover, a five-region seepage mathematical model was then developed and was subsequently validated by the experimental results and shale well production data. Our findings show that for physical simulation, both the pressure and production declined steadily at an annual rate of less than 5%, and 67% of the total gas in the core was recovered. These test data supported earlier finding that shale gas is of low flow ability and slow pressure decline in the shale matrices. The production model indicated that free gas accounts for the majority of recovered shale gas at the initial stage. Based on a shale gas well example, free gas extraction makes up 90% of produced total gas. The adsorbed gas constitutes a primary gas source during the later stage. Adsorbed gas contributes more than 50% of the gas produced in the seventh year. The 20-year-cumulative adsorbed gas makes up 21% of the EUR for a single shale gas well. The results of this study can provide a reference for optimizing production systems and adjusting development techniques for shale gas wells throughout the combinations of mathematical modeling and experimental approaches.

The gas-water relative permeabilities (GWRPs) of five rock samples were determined under different pore pressures to analyze and model the effects of pore pressure and rock-sample permeability in tight sandstone gas reservoirs. The gas-water permeability curves measured at 10-30 MPa are higher than those at normal pressure, and the co-permeability interval is narrower. At the same water saturation, the relative permeabilities of gas and water decrease with increasing pore pressure, especially that of gas. Under the same pore pressure conditions, with decreasing absolute permeability, gas-water relative permeability decreases, with the difference becoming smaller with increasing pore pressure. Finally, the experimental data for four rock samples was subjected to multiple linear fitting using Origin software, and a mathematical model of gas-water relative permeability was established. The accuracy and applicability of the mathematical model were verified by comparing the gas-water permeability curve calculated by the mathematical model with the experimental results for the fifth rock sample. Our findings provide invaluable information regarding gas-water two-phase seepage during the development of tight sandstone gas reservoirs and make predicting their productivities and production performances more accurate.

The porous media in tight reservoirs are mainly composed of micro- and nanopores, gas seepage through which is complex, making it difficult to study. Physical simulation using micron tubes is an intuitive and effective method to study the seepage mechanism of tight gas. The lattice Boltzmann method (LBM) is the most effective method for the tight gas seepage simulation, and it has been widely used. Microscale gas seepage simulation experiments and LBM simulations of micron tubes with different inner diameters were performed. The results showed that in micron tubes, the gas flow increases nonlinearly with an increasing pressure gradient. Influenced by compression and rarefaction effects, the degree of the nonlinearity of pressure distribution in series micron tubes increases with inlet pressure. The existence of a connecting channel between parallel micron tubes breaks the linear distribution of pressure in the original micron tubes, and the gas forms a raised relative high-pressure area at the connection of the two micron tubes; the wider the channel, the greater the bulge. The average gas flow rate in the whole micron tube increases with the channel width, and the seepage capacity increases instead of decreases. The diameter change of one micron tube has no effect on the gas flow in the other micron tube. Although the two micron tubes are connected, they are still relatively independent individuals. These research results lay a foundation for the correct understanding of the characteristics and laws of tight gas seepage in the pores of reservoirs at the micro- and nanoscales, and they have important theoretical significance for the study of seepage mechanisms in tight gas reservoirs.

Although improving the recovery of water-invaded gas reservoirs has been extensively studied in the natural gas industry, the nature of the efficiency of water-invaded gas recovery remains uncertain. Low-field nuclear magnetic resonance (NMR) can be used to clearly identify changes in water saturation in the core during high-pressure water-invasion gas. Here, we provide four types of water-invasion gas experiments (spontaneous imbibition, atmospheric pressure, high-pressure approximate equilibrium, and depletion development water-invasion gas) to reveal the impact of the water-invasion gas efficiency on the recovery of water-invasion gas reservoirs. NMR suggested that imbibition mainly occurs in medium to large pores and that residual gas remains mainly in large pores. The amount of gas driven out from the large pores by imbibition was much greater than that driven out from the small pores. Our findings indicate that the initial gas saturation, contact surface, and permeability are the main factors controlling the residual gas saturation, suggesting that a reasonable initial water saturation should be established before the water-invasion gas experiments. Additionally, the water-invasion gas efficiency at high pressures can be more reliably obtained than that at normal pressures. After the high-pressure approximate equilibrium water invasion for gas displacement, a large amount of residual gas remains in the relatively larger pores of the core, with a residual gas saturation of 42%. In contrast to conventional experiments, the residual gas saturation and water displacement efficiency of the high-pressure approximate equilibrium water invasion for gas displacement did not exhibit a favorable linear relationship with the permeability. The residual gas saturation ranged from 34 to 43% (avg. 38%), while the water displacement efficiency ranged from 32 to 45% (avg. 40%) in the high-pressure approximate equilibrium water invasion for gas displacement. The residual gas saturation in the depletion development water-invasion gas experiment was 26–40% (average: 33%), with an efficiency ranging from 45 to 50% (average: 48%), indicating that the depletion development experiment is closer to the actual development process of gas reservoirs. Our findings provide novel insights into water-invasion gas efficiency, providing robust estimates of the recovery of water-invasion gas reservoirs.

Shale gas seepage theory provides a scientific basis for dynamically analyzing the physical gas flow processes involved in shale gas extraction and for estimating shale gas production. Conventional experimental techniques and theoretical methods applied in seepage research are unable to accurately illustrate shale gas mass transfer processes at the micro- and nanoscale. In view of these scientific issues, the knowledge of seepage mechanisms and production development design was improved from the perspective of experimental techniques and theoretical models in the paper. First, multiple techniques (e.g., focused ion beam scanning electron microscopy and a combination of mercury intrusion porosimetry and adsorption measurement techniques) were integrated to characterize the micro- and nanopore distribution in shales. Then, molecular dynamics simulations were carried out to analyze the microscale distribution of gas molecules in nanopores. In addition, an upscaled gas flow model for the shale matrix was developed based on molecular dynamics simulations. Finally, the coupled flow and productivity models were set up according to a long-term production physical simulation to identify the production patterns for adsorbed and free gas. The research results show that micropores (diameter: <2 nm) and mesopores (diameter: 2-50 nm) account for more than 70% of all the pores in shales and that they are the primary space hosting adsorbed gas. Molecular simulations reveal that microscopic adsorption layers in organic matter nanopores can be as thick as 0.7 nm and that desorption and diffusion are the main mechanisms behind the migration of gas molecules. An apparent permeability model that comprehensively accounts for adsorption, diffusion, and seepage was developed to address the deficiency of Darcy's law in characterizing gas flowability in shale reservoirs. The productivity model results for a certain gas well show that the production in the first three years accounts for more than 50% of its estimated ultimate recovery and that adsorbed gas contributes more to the annual production than free gas in the eighth year. These research results provide theoretical and technical support for improving the theoretical understanding of shale gas seepage and optimizing shale gas extraction techniques in China.