Development Of Gas Reservoirs Research Articles

Genesis of an Inorganic CO2 Gas Reservoir in the Dehui–Wangfu Fault Depression, Songliao Basin, China

This study systematically examines the origins and formation mechanisms of inorganic CO2 gas reservoirs located within the Dehui–Wangfu Fault in the southeastern uplift region of the Songliao Basin. The research aims to clarify the primary sources of inorganic CO2, along with its migration and accumulation processes. The identification of the Wanjinta gas reservoir within the Dehui–Wangfu Fault Zone, abundant in inorganic CO2, has sparked significant interest in the pivotal roles of volcanism and tectonic activity in gas generation and concentration. To analyze the release characteristics of CO2, this study conducted degassing experiments on volcanic and volcaniclastic rock samples from various boreholes within the fault trap. It evaluated CO2 release behaviors and controlling factors across varying temperatures (150 °C to 600 °C) and particle sizes (20, 40, and 100 µm). The findings indicated a negative correlation between CO2 release and particle size, with a notable transition at 300 °C—marking this temperature as critical for the release of adsorbed and lattice gases. Moreover, volcaniclastic rocks exhibited higher CO2 release compared to volcanic rocks, attributable to their larger specific surface area and higher porosity. At 600 °C, the decomposition of the rock crystal structure results in substantial gas escape. These observations suggest that the inorganic CO2 in this area derives not only from mantle sources but is also influenced by crustal components. Elevated temperatures prompted by tectonic activity and magmatic intrusion facilitated the degassing of the surrounding rocks, allowing released CO2 to migrate upwards through the fracture system and accumulate in the shallow crust, ultimately forming a gas reservoir. This study enhances the understanding of volcanic rock’s roles in inorganic CO2 gas generation and migration, highlighting the fracture system’s critical controlling influence on gas transport and aggregation. The findings indicate that inorganic CO2 gas reservoirs in the Dehui–Wangfu Fault Zone primarily originate from mantle sources with a mixture of crustal gases. This discovery offers new theoretical insights and practical guidance for the exploration and development of gas reservoirs in the Songliao Basin and similar regions.

Effects of supercritical CO2, water, and supercritical CO2-based water on the mechanical properties and fracturability of shale

The study of the effects of supercritical CO2 (ScCO2) under high temperature and high pressure on the mechanical properties and fracturing potential of shale holds significant implications for advancing our understanding of enhanced shale gas extraction and reservoir exploration and development. This study examines the influence of three fluids, i.e. ScCO2, deionized water (DW), and ScCO2+DW, on the mechanical properties and fracturability of shale at immersion pressures of 15 MPa and 45 MPa, with a constant temperature of 100 °C. The key findings are as follows: (1) Uniaxial compressive strength (UCS) of shale decreased by 10.72%, 11.95%, and 23.67% at 15 MPa, and by 42.40%, 46.84%, and 51.65% at 45 MPa after immersion in ScCO2, DW, and ScCO2+DW, respectively, with the most pronounced effect observed in ScCO2+DW; (2) Microstructural analysis revealed that while ScCO2 and DW do not significantly alter the microstructure, immersion in ScCO2+DW results in a more complex surface morphology; (3) Acoustic emission (AE) analysis indicates a reduction in stress for crack damage, with a decreased fractal dimension of AE signals in different fluids. AE energy is primarily generated during the unstable crack propagation stage; (4) A quantitative method employing a multi-factor approach combined with the brittleness index (BI) effectively characterizes shale fracturability. Evaluation results show that ScCO2+DW has a more significant effect on shale fracturability, with fracturability indices of 0.833% and 1.180% following soaking at 15 MPa and 45 MPa, respectively. Higher immersion pressure correlates positively with increased shale fracturability.

Experimental study on the dynamic threshold pressure gradient of high water-bearing tight sandstone gas reservoir

Tight sandstone water-bearing gas reservoirs typically exhibit low porosity and low permeability, with reservoir rocks characterized by complex pore structures, often featuring micron-scale or smaller pore throats. This intricate reservoir structure significantly restricts fluid flow within the reservoir, necessitating a certain threshold pressure gradient (TPG) to be overcome before flow can commence. This study focuses on the Ordos Basin and explores the influence of high water content tight sandstone gas reservoirs on TPG under different water saturation and formation pressure conditions through experiments. A mathematical model of TPG is established using multiple linear regression method. The results show that TPG is primarily affected by water saturation, followed by formation pressure. As the water saturation increases, the TPG of the core decreases, and the change becomes more pronounced when the water saturation exceeds 50%. As formation pressure increases, the weakening of the slippage effect in gas molecules leads to TPG stabilization, especially when local pressure exceeds 25.0 MPa. The research also shows that low-permeability cores exhibit greater TPG variation with pressure changes, while high-permeability cores remain more stable. A mathematical model was developed and validated to predict TPG based on permeability, water saturation, and formation pressure. These findings highlight the need to monitor formation water content during tight sandstone gas reservoir development to optimize production strategies, providing valuable insights for improving reservoir management and guiding future research.

Determination and Application of Stress States Based on Finite Element Techniques: A Case Study of the Longmaxi Formation in the Luzhou Block, Sichuan Basin.

Knowledge of the present-day in situ stress field (PIS) has important theoretical and practical significance for shale gas exploration and development. The Wufeng-Longmaxi Formation in the Luzhou Block serves as the main reservoir of marine shale production in southern China. However, there is no clear understanding of PIS in the Luzhou area, which leads to a series of production problems. To investigate the PIS of deep shale reservoirs in Luzhou, experimental and finite element methods (FEMs) were used. Data obtained from imaging logging data, well deviation data, multipole array acoustic logging (XMAC), and world stress map were used to determine the orientation of the horizontal maximum principal stress (S Hmax). Additionally, acoustic emission experiments were employed to determine the magnitude of three principal stresses. Based on FEM, with the stress of a single well as a constraint, a three-dimensional (3D) stress field model was developed. The results show that the orientation of S Hmax varies from 90 to 120 °E. Further, there are significant differences in stress regimes across the region, with strike-slip/reverse faulting stress regime (S Hmax > S v ≈ S hmin) in the northern region and strike-slip stress regime in the southern region (S Hmax > S v > S hmin). In addition, geomechanical evaluations of wellbore stability and natural activation of fractures were performed. The Luzhou Block mainly develops two groups of natural fractures (NE-SW trending and NW-SE trending), with NW-SE trending being the dominant fracture development orientation. During the fracturing operation, a pore pressure increment larger than 50 MPa is conducive to maintaining a high opening ratio of the reservoir and improving the gas production efficiency. Horizontal wells drilled in the direction of maximum horizontal principal stress in the Wufeng-Longmaxi Formation reduce the probability of wellbore instability. The research results provide a reference for the effective development of deep shale gas reservoirs in southern Sichuan.

Improved Fracture Permeability Evaluation Model for Granite Reservoirs in Marine Environments: A Case Study from the South China Sea

Permeability is a crucial parameter in the exploration and development of oil and gas reservoirs, particularly in unconventional ones, where fractures significantly influence storage capacity and fluid flow. This study investigates the fracture permeability of granite reservoirs in the South China Sea, introducing an enhanced evaluation model for planar fracture permeability based on Darcy’s law and Poiseuille’s law. The model incorporates factors such as fracture heterogeneity, tortuosity, angle, and aperture to improve permeability assessments. Building on a single-fracture model, this research integrates mass transfer equations and trigonometric functions to assess intersecting fractures’ permeability. Numerical simulations explore how tortuosity, angle, and aperture affect individual fracture permeability and the influence of relative positioning in intersecting fractures. The model makes key assumptions, including minimal consideration of horizontal stress and the assumption of unidirectional laminar flow in cross-fractures. Granite outcrop samples were systematically collected, followed by full-diameter core drilling. A range of planar models with varying fracture apertures were designed, and permeability measurements were conducted using the AU-TOSCAN-II multifunctional core scanner with a steady-state gas injection method. The results showed consistency between the improved model and experimental findings regarding the effects of fracture aperture and angle on permeability, confirming the model’s accuracy in reflecting the fractures’ influence on reservoir flow capacity. For intersecting fractures, a comparative analysis of core X-ray computed tomography (X-CT) scanning results and experimental outcomes highlighted discrepancies between actual permeability measurements and theoretical simulations based on tortuosity and aperture variations. Limitations exist, particularly for cross-fractures, where quantifying complexity is challenging, leading to potential discrepancies between simulation and experimental results. Further comparisons between core experiments and logging responses are necessary for model refinement. In response to the challenges associated with evaluating absolute permeability in fractured reservoirs, this study presents a novel theoretical assessment model that considers both single and intersecting fractures. The model’s validity is demonstrated through actual core experiments, confirming the effectiveness of the single-fracture model while highlighting the need for further refinement of the dual-fracture model. The findings provide scientific support for the exploration and development of granite reservoirs in the South China Sea and establish a foundation for permeability predictions in other complex fractured reservoir systems, thereby advancing the field of fracture permeability assessment.

Analysis of the Impact of Clusters on Productivity of Multi-Fracturing Horizontal Well in Shale Gas

Shale gas reservoirs with nanoporous media have become one of the primary resources for natural gas development. The nanopore diameters of shale reservoirs range from 5 to 200 nm, with permeability ranging from 1 × 10−9 to 1 × 10−6 μm2. The natural gas production from shale gas reservoirs is low, necessitating the use of multi-stage hydraulic fracturing in horizontal wells. Segmented multi-cluster perforation fracturing is an effective method for shale gas extraction in these wells. The number of clusters significantly impacts the productivity of horizontal wells. Therefore, it is essential to analyze the impact of cluster numbers on fracture productivity in shale gas reservoir development. In this study, the equivalent flow resistance method was applied to establish a productivity model for multi-stage hydraulic fracturing horizontal wells in shale gas reservoirs considering diffusion and slip. An approximate analytical solution was obtained, and the effects of cluster length, diffusion coefficient, and fracture network permeability on productivity were analyzed. The results show that gas production gradually increases with the increase in the number of clusters and cluster length. However, as the number of clusters increases, the interference between clusters leads to a decrease in the productivity of individual clusters. As the fracture permeability, fracture network permeability, and diffusion coefficient increase, shale gas production also gradually increases. The permeability of the fracture network has the greatest impact on productivity. These research results are beneficial for the design of clusters in horizontal well fracturing and are of great importance for the development and production of shale gas reservoirs.

A Study on the Breakthrough Pressure of Porous Rock Formations in Gas Storage Reservoirs

Breakthrough pressure of natural gas in rock is an important evaluation parameter in gas reservoir development. In this study, experimental measurements of porosity and permeability of the caprock core were carried out. A digital core model was obtained by body rendering of rock CT (Computed Tomography) slices using Avizo software. Then, the grid model was imported into Fluent software for a numerical simulation of natural gas breakthrough pressure in the core. The innovations of this paper include (1) an accurate calculation method of cap breakthrough pressure based on the VOF method; (2) the method performs a perceptual analysis of average pore radius, wettability, roughness height, and viscosity ratio.

Impact of Material Balance Calculation on Trapped Gas in Water-drive Gas Reservoir

Abstract The development of water-drive gas reservoir takes a very important position in China. Not only its recovery is markedly lower than that of dry gas reservoir, but also its residual gas saturation is higher. The main reason has been proven in the lab is water invasion which can generate trapped gas by sealing gas in porous media. However, it is still difficult to calculate the volume of trapped gas theoretically and practically. In order to quantify trapped gas, we designed experiments to simulate the development of water-drive gas reservoir. The experimental system can provide accurate measurements on gas production, water influx, pressure and so on. The results showed that the original material balance equations are not consistent with experimental data when water invasion happens. With water influx increasing, the errors become more obvious. This phenomenon has been repeated for many times in our lab. On basis of this phenomenon and with the analysis of many experimental data, we observed that water influx causes some high pressure trapped gas which is not considered in original material balance equation. By regression analysis, we proposed a correction term which can be added to the original material balance equation to effectively eliminate the disagreements between the results of original equation and the experiments. The modified material balance equation was also verified by field cases. The correction term can be applied to quantify the degree of trapped gas, which is significant to calculate the water influx and to predict production and improves the original material balance equation so that the trapped gas in water-drive gas reservoir can be fully considered. The correction term is proposed through statistical regression analysis based on a large number of experimental data. The modified material balance equation with the correction term can quantify the trapped gas and have a great significant impact on the development of water-drive gas reservoir, especially on the water influx calculation and production prediction.

Optimization of fracturing parameters for horizontal wells in high-sulfur gas reservoirs considering the effect of sulfur deposition

During the development of high-sulfur gas reservoirs, the precipitation and deposition of elemental sulfur can lead to a reduction in reservoir porosity and permeability. Previous studies focus on the well production with optimized operational parameters, but the effect of sulfur deposition is not included, which impacts fracturing parameters, well production, and economic evaluation. Therefore, this work proposes a reasonable approach for parameter optimization considering sulfur. The variation of porosity and permeability are first evaluated during sulfur deposition. After that, fracture half-length, fracture spacing, fracture conductivity, and fracture distribution are optimized with orthogonalization factor analysis, and the influence of sulfur deposition on different fracture parameters are detailed analyzed. The results shown that the fracture half-length and fracture conductivity are greatly affected by sulfur deposition. Finally, net profit value is applied to obtain the optimal fracture spacing interval. With economic evaluation, the optimal fracture spacing interval of 125 m∼ 150 m is determined considering the net profit and the payback period. This work provides a useful economic method for fracture parameter optimization high-sulfur gas reservoirs, which benefits for the development and production of gas reservoirs.

A Deep Learning Structure Correction Method Under the Influence of Special Lithology Body

Abstract In the process of precise exploration and development of oil and gas reservoirs, the accurate implementation of the target layer structure plays a vital role in the increase of oil reserves and the success of drilling. However, with the gradual deepening of the research, it is found that in the overlying strata of oil and gas reservoirs, special lithological bodies with strong heterogeneity and abnormal velocity are usually locally developed, which directly affects the construction of seismic data migration velocity, resulting in structural distortion at the local position of the reservoir in the process of data interpretation. Focusing on the structural change caused by the abnormal velocity, the deep learning algorithm is used to accurately predict the velocity of the special lithologic body and realize the accurate correction of the structure. Firstly, based on the combination of seismic and geological understanding, the geological model of the target layer and the overlying special lithologic body is constructed, and the distribution law of the special lithologic body is identified by the forward simulation method. Then use the well-side seismic trace and P-wave velocity curve to train the velocity data through the deep learning method and apply the training results to the post-stack seismic data to obtain the accurate P-wave velocity body. Finally, the real formation velocity over the target layer is restored to achieve reservoir structure correction. Based on this method, the research experiment was carried out in the M block of the Tarim Basin, and the spatial distribution range of the special lithology body was carved. The data error between the migration velocity body and the abnormal high-velocity body was calculated, and the target layer structure in the study area was corrected.

Application of seismic inversion constrained geological modeling technology in quantitative characterization of thin reservoirs

Abstract With the gradual deepening of petroleum exploration and development, the scale of reservoir research in oil and gas reservoirs is getting smaller and smaller, and the demand for accuracy is getting higher and higher. During the development of clastic reservoirs in the Tarim Basin, the lithology of reservoir sand bodies changes rapidly and the lateral continuity is poor, so it is difficult to effectively identify the space distribution of sand bodies by relying solely on geological logging data. In this study, combined with the advantages of logging curve for vertical identification of sand bodies and seismic data for horizontal distribution identification of reservoirs, the seismic inversion constrained geological modeling technology is proposed to realize the quantitative characterization of thin reservoir sand bodies in developed oil and gas reservoirs :①Through the analysis of sensitive characteristic curve and the extraction of targeted seismic plane attributes, the feasibility evaluation of inversion in the target area is completed, and the seismic inversion results of thin reservoirs are generated. ②Based on the results of seismic inversion simulation, a high-precision 3D lithofacies geological model is constructed by analyzing the applicability of stochastic modeling method. ③ Combined with geological cognition, the physical property characterization of 3D lithofacies geological model is realized by physical property truncated simulation method, and the spatial distribution pattern of effective sand bodies is depicted. Through the application of this method in the study area A, the problem of certain deviation between reservoir inversion driven by conventional frame model and geological cognition is solved. While the spatial recognition ability of sand bodies is further improved, the quantitative characterization of thin reservoir physical properties is realized, which provides effective technical support for the subsequent development of oil and gas reservoirs.

Molecular dynamics of CH4 adsorption and diffusion characteristics through different geometric shale kerogen nanopores

In shale, pore structure plays an extremely significant effect on CH4 storage and transportation in a reservoir, especially for the reservoir involving large amounts of extremely tiny nanopore and variance of microstructure. In this study, three molecular dynamics models for different types of kerogen nanopores such as serration type, arc type and great-wall type are established, validated and implemented to assess the impact of pore structure on CH4 adsorption and diffusion behaviors in kerogen matrix and nanopore at temperature 320 ∼ 380 K, pressure 5 ∼ 20 MPa and pore size 3 ∼ 5 nm. The simulation results demonstrate that the CH4 density in the bulk of serration-type, arc-type and great-wall-type pores is 1.6, 1.3 and 1.9 higher than that inside kerogen molecules. Increasing temperature can weaken the adsorption capacity of kerogen, but the serration-type pore is the most sensitive to temperature. Regardless of the pore type, increasing pressure can significantly enhance the adsorption capacity of kerogen which is almost unaffected by pore size, whereas the CH4 diffusion coefficient increases with pore size. Furthermore, the great-wall-type pore can adsorb more CH4 molecules due to its smooth surface, followed by change in the arc-type and serration-type pores in turn. Among these types of pores, the CH4 diffusion coefficient is the most insensitive to the size of arc-type pore. Hence, the influences of kerogen pore structure under different conditions of temperature, pressure and pore size are quantified in this work to improve a comprehensive understanding of CH4 adsorption and diffusion behaviors in shale, thereby contributing to high-efficient and sustainable development of shale gas reservoirs.

Exploration and Practice of Synergistic and Efficient Development Technology for Gas-Capped Condensate Gas Reservoirs and Oil Rings

Abstract The oil-ringed condensate gas reservoir is one of the more unique and complex types of oil and gas reservoirs. The stable oil and gas interface is crucial for the efficient development of such reservoirs, and the fundamental means of addressing the issue lies in maintaining the dynamic balance between the gas cap and the oil ring. In this paper, we address issues such as the rapid decline in oil ring production, gas cap breakthrough, and increased condensate oil loss exposed during the development of the R carbonate reservoir in the Caspian Sea Basin of Kazakhstan. Using reservoir engineering and numerical simulation methods, we optimized synergistic development ideas and the boundaries of exploitation policies for gas-capped condensate gas reservoirs and oil rings. We formulated reasonable development parameters such as extraction rate, injection-production ratio, barrier water injection ratio, and proposed dynamic control standards for zoning and classification. After implementing the plan, the gas-oil ratio of the oil ring significantly decreased, with a reduction rate of 12 percentage points. The gas production per unit pressure drop increased by 40%. The annual decline rate of condensate oil decreased from 23.6% to 13.8%. All development indicators exhibited characteristics of benign development, providing a theoretical foundation and technical methods for guiding the efficient development of similar oil and gas reservoirs.

A hybrid denoising method for low-field nuclear magnetic resonance data

Low-field nuclear magnetic resonance (NMR) has broad application prospects in the exploration and development of unconventional oil and gas reservoirs. However, NMR instruments tend to acquire echo signals with relatively low signal-to-noise ratio (SNR), resulting in poor accuracy of T2 spectrum inversion. It is crucial to preprocess the low SNR data with denoising methods before inversion. In this paper, a hybrid NMR data denoising method combining empirical mode decomposition-singular value decomposition (EMD-SVD) was proposed. Firstly, the echo data were decomposed with the EMD method to low- and high-frequency intrinsic mode function (IMF) components as well as a residual. Next, the SVD method was employed for the high-frequency IMF components denoising. Finally, the low-frequency IMF components, the denoised high-frequency IMF components, and the residual are summed to form the denoised signal. To validate the effectiveness and feasibility of the EMD-SVD method, numerical simulations, experimental data, and NMR log data processing were conducted. The results indicate that the inverted NMR spectra with the EMD-SVD denoising method exhibit higher quality compared to the EMD method and the SVD method.

Research on DFN Fracture Modeling and Fracturing Network Expansion Simulation Method for Shale Reservoirs

Abstract The degree of natural fracture formation and their link to hydraulic fracturing fractures are critical factors in production in the current large-scale fracturing development of shale gas reservoirs. Any magnitude of fractured reservoir heterogeneity may be described using the Discrete Fracture Network (DFN) model. This paper builds on earlier research by providing an additional summary of the multiscale DFN fracture modeling method, analyzing the fracture occurrence using statistical analysis techniques, analyzing the fracture scale using fractal theory, and determining the fracture development degree by combining the fracture attributes in imaging logging and three-dimensional seismic data. Different-scale fracture network models were developed. Simulating the growth of hydraulic fractures accurately using Mohr Coulomb and Barton Bandis criteria, this study also takes into account the interaction between natural and hydraulic fractures, as well as the physical properties of the rock (e.g., elastic modulus, Poisson’s ratio), closure pressure, crustal stress field, and other factors. The fracture network information, sitmulated reservoir volume, stress shadow and other attributes obtained from fracturing simulation can further analyze and evaluate the effect of fracturing simulation, and optimize the well location deployment plan and construction plan in combination with geological engineering conditions.

Utilization law of shale gas in hydraulic fracturing with the Changning–Weyuan block in China as an example

The process of extracting shale gas, particularly the study of the utilization law of shale reservoirs modified by hydraulic fracturing technology, is crucial for understanding the effective development of shale gas. This understanding can significantly influence the estimated ultimate recovery of reserves. Our study focused on Longmaxi Formation shale in the Changning–Weiyuan block. To investigate the hydraulic fracturing expansion mechanism and utilization law, we employed shale reservoir physical and mechanical characterization, indoor triaxial hydraulic fracturing experiments, and numerical simulations. The findings are as follows. The rupture pressure of hydraulic fractures increases with the peripheral pressure, and high stress is conducive to the formation of internal microfractures. Additionally, a high rate of water injection enhances fracture extensions along the direction of fluid injection. Under varying injection pressures, the length of crack extensions and number of bond damages in shale are positively correlated with the injection pressure. Conversely, under different differential ground stresses, the length of crack extensions and number of bond damages are negatively correlated with the injection pressure. The six main factors affecting the effective utilization of shale gas are as follows: the stimulated reservoir volume, number of hydraulic fracture clusters, fracture length, fracture height, number of fracture stages, and cluster spacing, accounting for 27.13%, 14.74%, 10.31%, 9.58%, 9.53%, and 9.29%, respectively, with a cumulative contribution rate of 80.58%. This study clarifies the hydraulic fracturing mechanisms of shale reservoirs and the laws governing shale gas production, providing technical support for the development of shale gas reservoirs.

Research on oil well production analysis based on long-term slow-release tracer

Abstract Downhole monitoring the production profile is crucial for the development of oil and gas reservoirs. Currently, the commonly methods for monitoring the production profile include logging tools and using tracer monitoring. The tracer monitoring method is more popular in oil field operations due to its wide applicability, simple process, low cost, low risk, and long monitoring time. However, compared to traditional logging tool monitoring methods, tracer monitoring has drawbacks such as data lag, difficulty in downhole installation, and unstable long-term effects. Bohai Oilfield has developed a new type of solid tracer and solved the problem of downhole installation by improving the structure of the downhole screen tube. This tracer uses polymer material as the skeleton. After entering the designated position, the internal tracer can slowly diffuse into the solvent through the pores in the skeleton, achieving slow release and long-term monitoring of the production profile of the oil well. In 2023, this new type was first applied in the D6 well in Bohai Sea, and a half month stable production stage liquid production profile was obtained through sampling. The monitoring results showed that: (1) Solid slow-release tracer monitoring technology can continuously obtain production layer information in complex environments and can be used for short-term rapid water exploration and long-term water production monitoring, identifying water breakthrough time and main water breakthrough location, (2) The distance between water injection well and D6 production wells is small, and the water injection volume in the injection wells is large. The tracer monitoring results show that there is a certain degree of water flooding in all 6 sections of each test layer, (3) The first test layer is the main liquid production section, the first and sixth test layers are the main oil production sections, and the first and second test layers are the main water production sections. The research results can determine the oil and water production situation of each section of oil well, identify the water breakthrough time and water outlet position, and provide a basis for the next development adjustment.

Application of vertical seismic profile multi-component data to tight sandstone gas reservoirs

Abstract Given the complex geological characteristics of the tight gas sandstone in the Shaximiao Formation of the Jurassic in the central Sichuan Basin, including its wide distribution, narrow width, and thin thickness, conventional surface seismic methods face significant challenges in reservoir delineation. To address this challenge, a vertical seismic profile (VSP) survey was conducted in the region in 2022, along with the simultaneous collection of 3D3C surface seismic data. This article mainly elaborates on a case study of using multi-component VSP technology to delineate tight sandstone gas reservoirs. By comparing the processed VSP imaging volume with the surface seismic imaging volume, it was discovered that the frequency width of the VSP image was 8 to 12 Hz higher than that of the surface seismic image. Utilizing the multi-component information in VSP data, it is feasible to more precisely delineate tight gas sandstones, thereby reducing the uncertainty of data interpretation. Based on the conventional data interpretation of these images, an innovative application suggests using the centroid frequency ratio of PSv to PP waves as an indicator for tight sandstone. The results show that this attribute has high sensitivity to this type of reservoir. Combining geological, drilling, and logging data, an interpretation template was established based on VSP data to interpret 3D3C surface seismic data and propose new drilling well locations. The conclusion is that the successful application of VSP technology cannot be achieved without the integration of multiple disciplines. The combined exploration technology of multi-component VSP and 3D3C surface seismic has been demonstrated to have high application value through practical application, significantly improving the success rate of gas wells and providing effective support for the exploration and development of tight sandstone gas reservoirs.

Mechanism of Water Control and Gas Augmentation by Fracturing Interface Modifier in Water-bearing Gas Reservoir

Abstract With the development of oil and gas reservoirs, water containing gas reservoirs have gradually received attention. However, problems such as water production during the production process have reduced gas permeability, leading to a decrease in gas well productivity underground. Phase permeability regulators improve productivity by changing the wettability of rocks and enhancing gas permeability. This article tests the interface performance of a phase permeability regulator and evaluates its temperature resistance, formation water salt resistance, and erosion resistance. The pore bound water saturation of the core before and after modification with the phase permeability regulator, as well as the relative permeability of gas and water phases, are tested. The experimental results show that the phase permeation regulator can reduce the surface tension of water to 22.2 mN/m, and the rock contact angle before and after soaking increases from 26.63 ° to 97.69 °, achieving the transition of rock from hydrophilic to hydrophobic. The surface tension of the phase permeation regulator changes significantly before and after aging at 80-120 °C, and its high-temperature resistance is poor. After mixing with formation water with a salinity of 60000 to 100000, the surface tension increases, and at a salinity of 60000, it increases by 5.1 mN/m. The use of phase permeability regulators for matrix core displacement resulted in a slight increase in displacement pressure, while the formation water remained unchanged after approximately 140 hours of erosion. After modification with phase permeability regulators, the irreducible water saturation of the core decreases by about 25%, and the relative permeability of the gas phase increases, resulting in a significant hydrophobic and gas conducting effect. Phase permeability regulators achieve hydrophobic gas conductivity by changing the wettability of rocks, which can alleviate the problem of water production in shallow and low salinity reservoirs.

A New model of gas-water two-phase seepage based on Newton's law of motion

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.