Reservoir Physical Properties Research Articles

Numerical Simulation of the Coal Measure Gas Accumulation Process in Well Z-7 in Qinshui Basin

The process of coal measure gas accumulation is relatively complex, involving multiple physicochemical processes such as migration, adsorption, desorption, and seepage of multiphase fluids (e.g., methane and water) in coal measure strata. This process is constrained by multiple factors, including geological structure, reservoir physical properties, fluid pressure, and temperature. This study used Well Z-7 in the Qinshui Basin as the research object as well as numerical simulations to reveal the processes of methane generation, migration, accumulation, and dissipation in the geological history. The results indicate that the gas content of the reservoir was basically zero in the early stage (before 25 Ma), and the gas content peaks all appeared after the peak of hydrocarbon generation (after 208 Ma). During the peak gas generation stage, the gas content increased sharply in the early stages. In the later stage, because of the pressurization of the hydrocarbon generation, the caprock broke through and was lost, and the gas content decreased in a zigzag manner. The reservoirs in the middle and upper parts of the coal measure were easily charged, which was consistent with the upward trend of diffusion and dissipation and had a certain relationship with the cumulative breakout and seepage dissipation. The gas contents of coal, shale, and tight sandstone reservoirs were positively correlated with the mature hydrocarbon generation of organic matter in coal seams, with the differences between different reservoirs gradually narrowing over time.

Research Progress of Three-dimensional Geological Modeling and Multi-field Coupling of Fractured Oil and Gas Reservoirs

Fractured oil and gas reservoirs play an important role in oil and gas exploration and development due to their complex fracture network structure. As the main fluid channel in the reservoir, fractures have a significant impact on the migration, accumulation and exploitation efficiency of oil and gas. This paper summarizes the key geological characteristics of fractured reservoirs, including fracture types, distribution rules and main controlling factors of fracture development, and discusses the influence of fractures on reservoir physical properties. Furthermore, the deterministic and stochastic modeling methods of three-dimensional geological modeling of fractured reservoirs and the latest progress of discrete fracture network modeling technology are introduced in detail. In addition, this paper also discusses in detail the application of multi-field coupling model in the numerical simulation of fluid flow in fractured reservoirs, including continuous medium model and discrete medium model, and their advantages and disadvantages in simulating fluid flow in fractured reservoirs. Finally, this paper summarizes the research progress of multi-physics coupling model of fractured reservoirs, and points out the direction and challenges of future research. Through these studies, it can provide theoretical support and technical guidance for oil and gas exploration and development, in order to achieve more effective development and management of fractured reservoirs.

Accumulation sequence and exploration domain of continental whole petroleum system in Sichuan Basin, SW China

Based on the oil and gas exploration in the Sichuan Basin, combined with data such as seismic, logging and geochemistry, the basic geological conditions, hydrocarbon types, hydrocarbon distribution characteristics, source- reservoir relationship and accumulation model of the Upper Triassic–Jurassic continental whole petroleum system in the basin are systematically analyzed. The continental whole petroleum system in the Sichuan Basin develops multiple sets of gas-bearing strata, forming a whole petroleum system centered on the Triassic Xujiahe Formation source rocks. The thick and high-quality source rocks in the Upper Triassic Xujiahe Formation provide sufficient gas source basis for the continental whole petroleum system in the basin. The development of conventional-unconventional reservoirs provides favorable space for hydrocarbon accumulation. The coupling of faults and sandbodies provides a high-quality transport system for gas migration. Source rocks and reservoirs are overlapped vertically, and there are obvious differences in sedimentary environment, reservoir lithology and physical properties, which lead to the orderly development of inner-source shale gas, near-source tight gas, and far-source tight–conventional gas in the Upper Triassic–Jurassic, from bottom to top. The orderly change of geological conditions such as burial depth, reservoir physical properties, formation pressure and hydrocarbon generation intensity in zones controlled the formation of the whole petroleum system consisting of structural gas reservoir in thrust zone, shale gas-tight gas reservoir in depression zone, tight gas reservoir in slope zone, and tight gas–conventional gas reservoir in uplift zone on the plane. Based on the theory and concept of the whole petroleum system, the continental shale gas and tight gas resources in the Sichuan Basin have great potential, especially in the central and western parts with abundant unconventional resources.

Research and Practice of Sand Control Completion Technology Optimization in Western H Oilfield

Abstract In view of the problems of poor reservoir physical properties, high clay content, loose cementation, shallow burial, low compaction degree, low temperature in the middle and deep oil layers during the development process of unconsolidated sandstone reservoirs in the western H oilfield, the original sand control technology has poor adaptability and short sand control validity period., this paper carried out research on the optimization of sand control completion technology. In the study, a series of optimization studies were conducted, including analysis of acoustic time difference in sand producing layers, simulation of sand control formation compaction, optimization of gravel filling particle size, and sand control tools. A high-strength artificial wellbore and cyclic gravel filling sand control completion process suitable for different sand producing well conditions were developed and applied in practice. The research results and on-site practice indicate that the high-strength artificial wellbore sand control completion technology has good adaptability in low-temperature and long wellbore sand production wells; The cyclic gravel filling sand control completion technology has the advantages of simple construction, low cost, and low probability of major repairs in conventional shallow sand producing wells; The complementary advantages of the two processes effectively solve the problem of sand damage in H oilfield. Since 2021, the optimized sand control completion technology has been applied 46 times in H oilfield, with an average recovery oil production of 3.4t per well and an average effective period of over 500 days for sand control. The overall input-output ratio is 1:2.8, achieving good benefits and having high promotion and application value.

Investigation the Impact of Different Injection Agents on Tight Oil Reservoirs of Recovery Performance

Abstract Objectives/Scope: Due to strong water sensitivity and extremely low permeability, conventional water flooding method is not suitable for the Mahu Conglomerate reservoir. In response to the complex reservoir physical properties, different injection agents such as CO2, N2, water and air huff and puff injection were carried out in order to optimize injection parameters for enhanced oil recovery in tight conglomerate reservoirs. Methods, Procedures, Process: By means of NMR, scanning electron microscopy, energy spectrum, pore fluids state in different media after different agents displacement were studied. Displacement and CT testing on different media and post fracturing state were conducted. Through experiments on on-site cores from two different layers, three different injection media (H2O, N2, CO2 and air with different O2 concentration) were tested for enhanced oil recovery. Then, the injection process was performed under different injection pressures. Finally, multiple cycles of enhanced oil recovery tests were conducted corresponding optimal injection pressures. Results, Observations, Conclusions: The remaining oil in the pores is mainly in free and bound states, with a free state of approximately 58% and a bound state of approximately 42%. Four pressures were selected for this test based on the minimum miscibility pressure of CO2 with crude oil: 15MPa, 20MPa, 23MPa, and 25MPa. The recovery factor under different pressures is 6.44%, 8.14%, 10.31%, and 10.38%, respectively. As the huff and puff pressure increases, the recovery of CO2 huff and puff gradually increases, and the increase of recovery is insignificant when the mixture pressure is reached. The gas flooding process involves oil production from large and submicron pores first. As the displacement pressure difference increases, oil production from large pores decreases, with medium pores becoming the main force of oil production, while oil production from nanoscale micropores shows an increasing trend. The increase in oxygen content results in significant development of sub-micron micron scale pores. The gas breakthrough time is long, the capillary force decreases, and air can undergo low-temperature oxidation with crude oil, resulting in an overall oil displacement efficiency of 65.81%. Novel/Additive Information: At present, there is few research on the pore fluid flow and status of oil displacement in tight conglomerate reservoirs with different injection media. This study provides a good understanding of the submicron to nanoscale pore throat structure characteristics of tight oil reservoirs, revealing the state of pore fluids in gravel after displacement by different injection media, and providing support for on-site application of CO2 enhanced oil recovery in tight conglomerate oil reservoirs.

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.

Impact of Reservoir Heterogeneity on Bitumen Content in the Mackay River Oil Sands, Athabasca (Canada)

AbstractThe Lower Cretaceous Manville Group of Upper McMurray Formation is one of the main bitumen reservoirs in Athabasca. In this study, the relationship between reservoirs heterogeneity and bitumen geochemical characteristics were analyzed through core and microscopic observation, lab analysis, petrophysics and logging data. Based on the sedimentology framework, the formation environment of high‐quality oil sand reservoirs and their significance for development were discussed. The results indicate that four types lithofacies were recognized in the Upper McMurray Formation based on their depositional characteristics. Each lithofacies reservoirs has unique physical properties, and is subject to varying degrees of degradation, resulting in diversity of bitumen content and geochemical composition. The tidal bar (TB) or tidal channel (TC) facies reservoir have excellent physical properties, which are evaluated as gas or water intervals due to strong degradation. The reservoir of sand bar (SB) facies was evaluated as oil intervals, due to its poor physical properties and weak degradation. The reservoir of mixed flat (MF) facies is composed of sand intercalated with laminated shale, which is evaluated as poor oil intervals due to its poor connectivity. The shale content in oil sand reservoir is very important for the reservoir physical properties and bitumen degradation degree. In the context of regional biodegradation, oil sand reservoirs with good physical properties will suffer from strong degradation, while oil sand reservoirs with relatively poor physical properties are more conducive to the bitumen preservation.

Super-resolution reconstruction of hydrate-bearing CT images for microscopic detection of pore

The pore structure of marine natural gas-hydrate-bearing sediments is a key factor related to the physical properties of reservoirs. However, the resolution of micro-computed tomography (micro-CT) images is unsuitable for the analysis of pore structures in fine-grained sediments. In this regard, super-resolution (SR) reconstruction technology is expected to improve the spatial resolution of micro-CT images. We present a self-supervised learning method that does not require high-resolution datasets as input images to complete the training and reconstruction processes. This method is an end-to-end network consisting of two subnetworks: an SR network and a downscaling network. We trained on a self-built dataset of hydrate samples from three different particle sizes. Compared with typical methods, the SR results indicate that our method provides high resolution while improving clarity. In addition, it has the highest consistency with the liquid saturation method with the subsequent calculation of porosity parameters. This study contributes to the investigation of seepage and energy transfer in sediments containing natural gas hydrates, which is particularly important for the exploration and development of marine natural gas hydrate resources.

IoT-ENHANCED SHALE OIL AND GAS GREEN DEVELOPMENT: STATUS AND FUTURE

Shale oil and gas, deemed as vital alternative resources to conventional oil and gas, have spurred significant interest in information-based exploration and development technologies within the industry in recent years [1]. China boasts extensive shale oil and gas reserves, with the International Energy Agency (EIA) estimating China's shale oil technology capable of extracting approximately 4.393 billion tonnes, ranking third globally. Additionally, China holds shale gas geological resources of about 134.4 trillion cubic meters, ranking first worldwide, showcasing immense development potential. Shale oil and gas, being unconventional resources, are distributed within the pore and fracture systems of organic-rich shale formations. Compared to conventional oil and gas, shale oil and gas exhibit weaker trap control and stronger distribution continuity, typically characterized by poor reservoir physical properties. Conventional extraction methods often struggle to yield industrial oil and gas flow from shale oil and gas resources, necessitating unconventional development technologies such as reservoir monitoring, directional wells, horizontal wells, and segmental fracturing [2]. However, these technologies come with challenges and risks, including complex production operations, high production data density, and environmental concerns such as surface ecological damage and pollutant emissions, further impacting shale oil and gas production. To facilitate the upgrading process of China's shale oil and gas industry, this paper presents the current status of Internet of Things (IoT) application technologies for shale oil and gas development and proposes a research outlook based on the concept of green development. Against the backdrop of energy transformation, it offers a reference framework for the sustainable development of China's extensive shale oil and gas resources.

Dynamic evolution of reservoir permeability and deformation in geothermal battery energy storage using abandoned mines

Retasking existing subsurface abandoned mines as infrastructure for solar energy storage could be a feasible approach in overcoming the low thermal gradient present in shallow formations. In this work, the potential for thermal storage in the high permeability goaf of abandoned mines through diurnal cyclic injection-then-extraction using coupled thermo-hydro-mechanical modeling was explored by coupling FLAC3D with TOUGH2. The temperature sensibility of reservoir during 30 days of cyclic injection-then-production was examined at various injection temperatures (ranging from 50°C to 250°C) and rates (ranging from 1 kg/s to 10 kg/s) and for representative reservoir physical and thermal properties, including variable thermal expansion coefficients. The simulation results reveal that: The principal mechanisms driving reservoir deformation result from the combined influence of thermal poroelastic and thermal effects. With the change of reservoir temperature, the reservoir is perturbed by pressure and thermal stresses causing permeability evolution. Permeability reduces ∼10% for a maximum injection temperature of 250°C – although effects are reduced the lower injection temperatures. The pore pressure fluctuations for an injection rate of 10 kg/s is ∼6.5 times that for a rate of 1 kg/s. The pressure perturbation of the reservoir during the injection process decreases with the injection rate, and the reservoir is relatively more stable. When the thermal stress becomes predominant, the reservoir volume expands. Uplift displacements 220 m above the hot injection well are trivial an of the order of ∼1.5 mm at a mean temperature of 163°C.

Modifying the Effects around the Well can have an Impact on the Drilling Process

Environmental changes around a well can significantly affect the drilling process. This paper examines the effects of flow rate, bottomhole pressure, sheet permeability, viscosity, pressure gradient and well radius on the drilling process. It is shown that the energy-dynamic instability of the sheet’s near-shiva space, a highly active region in the formation, leads to changes in reservoir rock and fluid properties during the drilling process. These changes include physicochemical transformations such as deposition of asphaltenes, paraffins, and resins, as well as swelling of clay particles, which can disrupt reservoir physical properties and affect hydrocarbon flow. In addition, completion and production techniques and the chemistry of drilling and pressure fluids are particularly critical for low-permeability reservoirs. In this paper, the concept of skin effect is also introduced to assess the impact of process fluids on the bottomhole region, and a new assessment model is proposed. The results of the study are important for improving drilling technology and optimising reservoir development.

Surface morphologic changes and mineral transformation mechanisms after CO2-brine-rock reaction in organic matter-rich ferroan shale

Sequestrating CO2 in shale reservoirs can not only reduce CO2 emission, and enhance oil and gas recovery. Nevertheless, shale reservoirs were normally formed in reducing environments, and are abundant in Fe2+ and organic matter. Fe2+ influence the dissolution and precipitation behavior of minerals within the reservoir. Simultaneously, organic matter occupies the pore spaces within the reservoir, thereby affecting the reservoir physical properties. The CO2-brine-rock reaction experiment was carried out using organic matter-rich ferroan shale in this study. The changes in surface morphology of minerals and organic matter utilizing X-ray Diffraction localization monitoring techniques. Based on the TOUGHREACT, a quantitative analysis was conducted on the dissolution and precipitation of individual components. The results suggest that the carbonates preferentially dissolved at the early stage, resulting in a rougher surface morphology andthe formation ofcracks. During the early stage, ankerite transformed into pyrite and chlorite. As the reaction progresses, an elevation in the solution’s acidity facilitates converts chlorite to pyrite and kaolinite. After the dissolution of dolomite, calcite is the primary secondary mineral. The formation of clay minerals consumes Mg2+, resulting in minimal magnesite. The dissolution of feldspar was weaker than carbonate minerals. Dissolution of plagioclase results in the formation of dawsonite in solution. The dissolution of K-feldspar induces the transformation of smectite to illite. In addition, as the reaction solution acid escalated, the soluble mineral components in the large-particle polymer dissolved and dispersed into small-particle organic matter. The small-particle organic matter absorbs secondary minerals generated to form a cake-like polymer.

Multi-scale nonlinear reservoir flow simulation based on digital core reconstruction

During the exploitation of oil and gas reservoirs, changes in reservoir physical or fluid properties will lead to alterations in formation seepage capacity, subsequently impacting the productivity of oil and gas wells. Therefore, it is crucial to evaluate the variations in reservoir physical and fluid properties as well as their influence on oil and gas well productivity during reservoir exploitation.It employs a descriptive approach to investigate cross-scale (i.e., micro-scale → small-scale → large-scale) fluid seepage phenomena in water flooding. By leveraging digital core reconstruction technology and focusing on micro-pore network simulation, it establishes an analytical framework for studying cross-scale seepage fields, facilitating the exploration of the micro-seepage mechanism that governs non-homogeneous water flooding's impact on liquid production capacity within a reservoir. Integrating constraints from micro-pore network simulation and small-scale core displacement test data, while considering macro-heterogeneity near wellbore areas as flow unit divisions and superposition bases within large-scale reservoirs, it reveals the nonlinear flow characteristics of changes in liquid production capacity in water-flooding oil reservoirs based on microscopic digital core analysis. This approach aligns with findings from small-scale core testing and sweep coefficient correction while also addressing the non-uniform distribution characteristics of physical parameters within large-scale reservoirs.By integrating permeability field characteristics at three levels, this approach optimizes its technical advantages in describing dynamic permeability fields at each level, thereby facilitating precise prediction of water drive oil development effects.

Preparation and Characterization of Responsive Cellulose-Based Gel Microspheres for Enhanced Oil Recovery.

As an important means to enhance oil recovery, ternary composite flooding (ASP flooding for short) technology has achieved remarkable results in Daqing Oilfield. Alkalis, surfactants and polymers are mixed in specific proportions and injected into the reservoir to give full play to the synergistic effect of each component, which can effectively enhance the fluidity of crude oil and greatly improve the oil recovery. At present, the technology for further improving oil recovery after ternary composite flooding is not mature and belongs to the stage of technical exploration. The presence of alkaline substances significantly alters the reservoir's physical properties and causes considerable corrosion to the equipment used in its development. This is detrimental to both the environment and production. Therefore, it is necessary to develop green displacement control agents. In the reservoir environment post-ASP flooding, 2-(methylamino)ethyl methacrylate and glycidyl methacrylate were chosen as monomers to synthesize a polymer responsive to alkali, and then grafted with cellulose nanocrystals to form microspheres of alkali-resistant swelling hydrogel. Cellulose nanocrystals (CNCs) modified with functional groups and other materials were utilized to fabricate hydrogel microspheres. The product's structure was characterized and validated using Fourier transform infrared spectroscopy and X-ray diffraction. The infrared spectrum revealed characteristic absorption peaks of CNCs at 1165 cm-1, 1577 cm-1, 1746 cm-1, and 3342 cm-1. The diffraction spectrum corroborated the findings of the infrared analysis, indicating that the functional modification occurred on the CNC surface. After evaluating the swelling and erosion resistance of the hydrogel microspheres under various alkaline conditions, the optimal particle size for compatibility with the target reservoir was determined to be 6 μm. The potential of cellulose-based gel microspheres to enhance oil recovery was assessed through the evaluation of Zeta potential and laboratory physical simulations of oil displacement. The study revealed that the absolute value of the Zeta potential for gel microspheres exceeds 30 in an alkaline environment with pH values ranging from 7 to 14, exhibiting a phenomenon where stronger alkalinity correlates with a greater absolute value of Zeta potential. The dispersion stability spans from good to excellent. The laboratory oil displacement simulation experiment was conducted using a cellulose-based gel microsphere system following weak alkali ASP flooding within the pH value range from 7 to 10. The experimental interventions yielded recovery rates of 2.98%, 3.20%, 3.31%, and 3.38%, respectively. The study indicates that cellulose-based gel microspheres exhibit good adaptability in alkaline reservoirs. This research offers a theoretical foundation and experimental approaches to enhance oil recovery techniques post-ASP flooding.

Productivity evaluation method of offshore fractured reservoir based on artificial intelligence ChatGPT

Abstract At present, the analogy method is usually used to determine the production capacity. Due to the strong heterogeneity of fractured reservoirs in the Bohai Sea, the prediction error is large and cannot meet the needs of scheme deployment. Therefore, based on the test productivity, the characteristic parameter λ was introduced to characterize fractured reservoir productivity, and the relevant data affecting productivity were preprocessed by the K-nearest algorithm and Z-Score standardization method. Then, the feature vector of parameter λ was selected by the average impurity reduction MDI feature selection method. Finally, in the GPT Building module of ChatGPT, the reservoir parameters and productivity test data are used to train GPT and the deep forest prediction model with parameter λ is built intelligently by GPT. This method is applied to the CFD oilfield productivity evaluation in the Bohai Sea, and the prediction error caused by the difference in reservoir physical properties is reduced. The coincidence rate between prediction and actual is more than 85%, which provides a new idea and method for the productivity evaluation of offshore fractured reservoirs.

Diagenesis of Cenomanian–Early Turonian and the Control of Carbonate Reservoirs in the Northern Central Arabian Basin

The carbonate reservoirs of Cenomanian–Early Turonian in the northeastern Central Arabian Basin hold considerable oil reserves and are great contributors to oil production. Diagenesis have a great impact on carbonate reservoir petrophysical properties, microstructure, and heterogeneity. By integrating cores, cast thin sections, regular core analysis, CT, and isotopes, this study provides an improved understanding of diagenesis in the Cenomanian–Early Turonian and its effect on carbonate reservoirs. The results showed that three diagenetic environments were identified in the Cenomanian–Early Turonian based on texture, structure, cement, crystal form, and crystal size, which were marine environment, meteoric environment, and burial environment. Six diageneses were identified based on residual bioclastic, secondary pores, calcite quantity, dolomite size, and stylolite, namely dissolution, cementation, micritization, dolomitization, compaction, and pressure solution. A micritization model in high energy sediment, a dolomitization model in burrows, and a comprehensive diagenetic model were established. It concluded that dissolution during meteoric environment is most favorable to reservoir physical properties, while cementation is least favorable. The cement content controls the microstructure and petrophysical property. Micritization is detrimental to the petrophysical properties, and the micrite it forms are distributed in the interparticle pores, reducing the reservoir property deposited in high energy environment. Dolomitization is less developed in substrate but widely developed in burrows, which result in the physical properties of the burrows being higher than those of substrate. Compaction and pressure solution have a negative impact on reservoir physical properties.

Shale pore characteristics and their impact on the gas-bearing properties of the Longmaxi Formation in the Luzhou area

Deep shale has the characteristics of large burial depth, rapid changes in reservoir properties, complex pore types and structures, and unstable production. The whole-rock X-ray diffraction (XRD) analysis, reservoir physical property parameter testing, scanning electron microscopy (SEM) analysis, high-pressure mercury intrusion testing, CO2 adsorption experimentation, and low-temperature nitrogen adsorption–desorption testing were performed to study the pore structure characteristics of marine shale reservoirs in the southern Sichuan Basin. The results show that the deep shale of the Wufeng Formation Longyi1 sub-member in the Luzhou area is superior to that of the Weiyuan area in terms of factors controlling shale gas enrichment, such as organic matter abundance, physical properties, gas-bearing properties, and shale reservoir thickness. SEM is utilized to identify six types of pores (mainly organic matter pores). The porosities of the pyrobitumen pores reach 21.04–31.65%, while the porosities of the solid kerogen pores, siliceous mineral dissolution pores, and carbonate dissolution pores are low at 0.48–1.80%. The pores of shale reservoirs are mainly micropores and mesopores, with a small amount of macropores. The total pore volume ranges from 22.0 to 36.40 μL/g, with an average of 27.46 μL/g, the total pore specific surface area ranges from 34.27 to 50.39 m2/g, with an average of 41.12 m2/g. The pore volume and specific surface area of deep shale gas are positively correlated with TOC content, siliceous minerals, and clay minerals. The key period for shale gas enrichment, which matches the evolution process of shale hydrocarbon generation, reservoir capacity, and direct and indirect cap rocks, is from the Middle to Late Triassic to the present. Areas with late structural uplift, small uplift amplitude, and high formation pressure coefficient characteristics favor preserving shale gas with high gas content and production levels.

Characteristics and correlations of rock components, structure, and physical properties of deep clastic reservoirs in the LD-X area of Yinggehai basin, western South China Sea

Deep clastic rocks in the LD area of the western South China Sea have undergone complex and historical processes of burial, thermal evolution, and diagenesis. As important factors affecting the porosity and permeability, rock components and structures can exhibit pronounced differences with complex lithologies in the vertical direction. In this study, we used a comprehensive method to analyze the lithological characteristics through thin-section observation, scanning electron microscopy imaging, cathodoluminescence, back-scattered electron imaging (on microprobe)), X-ray diffraction patterns of clays, grain size measurement, porosity–permeability analyses, and special imaging logging. The clastic rocks in the study area are dominated by quartz, feldspar, and debris, with the main lithology being subfeldspathic sandstone. The fillings are dominated by carbonate cement, and the clays are mostly illite. The sandstone is mostly grain-supported, moderately rounded, and fine-to medium-grained with poor-medium sorting. Porosity values are mostly in the range of 5–15%, whereas permeability values are in the range of 0.05–10.00 mD. Porosity and permeability are positively correlated with the quartz and feldspar contents and grain size and negatively correlated with the rock debris and carbonate cementing materials and sorting coefficient. These different correlations indicate that the rock components are closely related to the physical properties of the reservoirs. Sandstones with better physical properties generally have higher compositional and structural maturities. On this basis, a conceptual model of the evolution of rock components, structure and physical properties in the LD area is developed. It is verified by the logging profile that rock grouping can reflect both the good and bad physical properties, while simultaneously indicating the development patterns of high-quality reservoirs in the study area.

Research and Application of Treatment Measures for Low-Yield and Low-Efficiency Coalbed Methane Wells in Qinshui Basin

China is rich in high-grade coalbed methane resources, accounting for one-third of the total amount of coalbed methane resources. Qinshui Basin is the main high ranking coalbed methane mining basin in China. In the early stage of CBM development, low-production and low-efficiency wells were formed in the process of block development because of an insufficient understanding of reservoir geological conditions. The existence of low-yield and low-efficiency wells with low output and a poor development benefit seriously restricts the efficient development of coalbed methane. In order to improve the overall development efficiency of coalbed methane fields, how to revitalize low-yield and low-efficiency wells is the main problem facing the development process of coalbed methane. With the deepening understanding of the study area geology, the formation of low-yield and low-efficiency wells has been basically identified. With the advancement of development technology, developers have the ability to retrofit some low-producing and inefficient wells. Low-production and low-efficiency wells are widely distributed. It is difficult to find the criteria for classifying low-producing and low-efficiency wells because of the great differences in geological conditions and reservoir physical properties in different blocks. In addition, the causes of a low-production and low-efficiency well are complex, as the same well is often caused by many reasons, and how to identify the causes of low-production and low-efficiency wells is difficult. In recent decades, developers have studied many methods to retrofit low-production wells, but the retrofit results are not satisfactory. How to choose an economical and efficient reservoir reconstruction method to revitalize low-production and low-efficiency wells is particularly important. This paper starts with the definition of low-production and low-efficiency wells in different blocks, combining an economic evaluation and productivity characteristics to judge whether they are low-production and low-efficiency wells, and defines the distribution of low-production and low-efficiency wells in blocks. The reasons for the formation of low-production and low-efficiency wells are analyzed with the geological characteristics, production dynamic performance, and engineering reconstruction effects. This paper makes a comparative analysis of the current relatively mature low-production and low-efficiency well treatment measures, clearly identifies the advantages and disadvantages of different treatment measures, and takes corresponding stimulation measures for different causes of low-production and low-efficiency wells. The research shows that there are 687 low-production and low-efficiency wells in block A, accounting for 69.4% of the total number of wells, and the low-production and low-efficiency wells account for a relatively large proportion; so, it is necessary to treat them. The main causes of low-production and low-efficiency wells are geology, engineering and drainage systems. The geological reason mainly refers to the low gas production of coalbed methane wells influenced by three factors: resource abundance, faults, and collapse columns. According to the different causes, three treatment measures of large-scale secondary fracturing, temporary plugging, and diversion fracturing and foam fracturing are put forward. The research method in this paper is targeted at different geological conditions so it can be used to guide the treatment of low-yield and low-efficiency wells in other CBM blocks, and it has very important significance for revitalizing the existing low-efficiency CBM assets and improving the development efficiency of CBM.

Shear-Wave Velocity Prediction Based on the CNN-BiGRU Integrated Network with Spatiotemporal Attention Mechanism

Shear wave velocity is one of the important parameters reflecting the lithological and physical properties of reservoirs, and it is widely used in the fields of lithology and fluid property identification, reservoir evaluation, seismic data processing, and interpretation. However, due to the high cost and challenge of obtaining shear wave velocity, only a few key wells are measured. Considering the intricate nonlinear mapping relationship between shear wave velocity and conventional logging data, an integrated network incorporating an attention mechanism, a convolutional neural network, and a bidirectional gated recurrent unit (STACBiN) is proposed for predicting shear wave velocity. The impact of conventional logging data on shear wave velocity is analyzed, thus employing the attention mechanism to focus on data correlated with shear wave velocity, which can enable the prediction results of the method proposed superior to those of conventional methods. Additionally, the prediction results of this method are compared with the prediction results of the two-dimensional convolutional neural network (2DCNN) and bidirectional gated recurrent unit (BiGRU). It is verified that the network proposed can effectively predict the shear wave velocity, with minimal error between predicted and true values.