Fractured Gas Research Articles

Optimization of shale gas fracturing parameters based on artificial intelligence algorithm

Resource-rich shale gas plays a pivotal role in new energy types. The key to scientifically and efficiently developing shale gas fields is to clarify the main factors that affect the production of shale gas wells. In this paper, according to the shale gas reservoir characteristic of the Fuling marine Longmaxi Formation, a single-well geological model was established using the reservoir numerical simulation software CMG. Then, 10,000 different reservoir models were randomly generated for different formation physical parameters, completion parameters, and fracturing parameters using the Monte Carlo method, and these 10,000 models were simulated numerically. The machine learning model uses a dataset of 10,000 different geological, completion, and fracturing parameters as input and 10,000 production curves as output. Multiple machine learning regression methods were used to train and test the dataset, and the optimal method (GBDT algorithm) was selected, and the accuracy R2 of the test set of the GBDT prediction model is 0.96. A fracturing parameter optimization workflow was constructed by combining a production prediction model with a particle swarm optimizer (PSO). The process can quickly optimize the fracturing parameters and predict the production for each time by targeting the cumulative gas production under different geological conditions. The optimized parameters are Fracture Spacing, Fracture Width, Intrinsic Permeability, Fracture Half-length, Langmuir Pressure, and Langmuir Volume. The initial predicted cumulative gas production was 4.59 × 108 m3, which was optimized to 4.90 × 108 m3. The proposed PSO-GBDT proxy model can instantly predict the production of shale gas wells with considerable accuracy, reliability, and efficiency, which is a vital tool for optimizing fracture design. This investigation provides a solid foundation for predicting the production of unconventional gas reservoirs and for parameter optimization.

Damage evolution characteristics of heterogeneous fractured sandstone reservoir under different fracturing fluids

AbstractTo investigate the coupling effect of in situ stress and fluid pore pressure and the propagation law of damaged area during hydraulic fracturing and gas fracturing in heterogeneous fractured reservoirs, according to the effective stress principle and the smooth Rankine stress criterion, this paper establishes a coupled fluid–solid‐damage mathematical model of heterogeneous rock layers and carries out numerical simulations on the characteristic field changes of rock layers under water and nitrogen fracturing. The results show that the continuous injection of nitrogen or water can cause an increase in pore pressure in natural fractures and rock matrices, leading to rock damage and an increase in porosity. Under the same parameters, the damage area and length of the rock mass during nitrogen fracturing are larger than those of hydraulic fracturing, and the changes in pore pressure, permeability, and porosity are consistent with the damage area. The pore pressure near the connected natural fractures is relatively high, resulting in tensile strain; the pore pressure at isolated fractures is relatively low, and some even produce compressive strain. During nitrogen fracturing, the damage evolution is less affected by the in situ stress and the matrix permeability, while hydraulic fracturing is more affected by them. The damage area is the smallest when the horizontal in situ stress is equal. When the initial permeability of the matrix is low, the damaged area mainly follows the natural fractures and is distributed in a strip shape. As the permeability of the matrix increases, the fracturing fluid can enter the matrix, and the damaged area is in the shape of a block.

Investigation into a perfect matching between fracture transfer performance and vertical well productivity based on multi-scale and total factor characteristic models

In fractured tight gas reservoirs, complex hydraulically induced fracture networks determine fluid flowing abilities of reservoirs. Thus, characterizing the complex fracture networks and revealing fracture transfer performances become a challenging work because of fracture branching, bending, and reversing in fractured reservoirs. In this paper, a fractal-like tree-shaped fracture model for gas transfer is proposed to optimize flow conductivity, pressure distribution at fracture intersection points, and flow transfer in such a complex fracture network considering the multi-scale effect, and total factor characteristics, including the length ratio, width ratio, branching angle, and branching level. The model is implemented to conduct validation against the experiment data in the literature. Subsequently, applying the proposed fracture model, the productivity equation for a vertical gas well intercepted by the fractal-like tree-shaped fracture network is further formulated. In addition, the good match with productivity simulation validates the accuracy of the developed productivity model for a vertical gas well. As a result, the impacts of the Knudsen number, fracture total factor characteristics, reservoir parameters, etc. on fracture transfer performances and well productivity are examined using the two proposed models. The results demonstrate that optimum fracture transfer performances do not match with the maximum well productivity. In contrast, the well productivity is jointly determined by both inlet flow volume of the fracture network and matrix permeability. Hence, a new formula considering both fracture characteristics and reservoir properties is proposed to match with the optimum fracture total length and maximum well productivity, thereby contributing to high-efficient and economic exploration of tight gas reservoirs.

Research and Application of High-Energy Gas Fracturing Mechanism Based on CT Scanning Technology

Research and Application of High-Energy Gas Fracturing Mechanism Based on CT Scanning Technology

Research Progress on Pressure Sealing Materials for Fractured Gas Reservoirs

To study a kind of plugging material suitable for gas invasion in gas reservoirs fractured pressure plugging material. Gas invasion in carbonate gas reservoirs is frequent and will be accompanied by lost circulation and overflow, which will affect the safety and efficient production of oil and gas wells, and even cause serious safety hazards. In this regard, this paper summarizes the research process and problems encountered in the application of reverse pressure plugging materials in Carbonate rock fractured gas reservoirs. At the same time, it introduces the types of main plugging materials in the world and the research progress of plugging materials (polymer gel plugging technology, ultra-low permeability (non permeability) drilling fluid technology, etc.), the theory of plugging materials (rigid plugging theory, flexible plugging theory, etc.), as well as the characteristics of typical plugging materials and plugging material technology.

Impacts of vertical variation of coal seam structure on hydraulic fracturing and resultant gas and water production: A case study on the Shizhuangnan Block, Southern Qinshui Basin, China

Hydraulic fracturing plays a vital role in the development of coalbed methane (CBM). Coal seam structures can, however, affect the fracturing operations, further affecting gas and water production from the coal seam. Within the research area—the Shizhuangnan Block, Southern Qinshui Basin, China—three types of coal body textures are relevant, including original, cataclastic, and granulated structure. This research describes the impacts of different coal seam types on fracturing operations and gas and water production. The results show that different types of coal seams have different impacts on hydraulic fracturing and the resultant production of gas and water. The coal seams are classified according to the vertical variation characteristics of the coal seam structures. The first type of coal seam (Type I) only develops the original and cataclastic coal structure. The effects of fracturing reconstruction for Type I are good. A high degree of coal breakage and fracture formation is observed. Gas production from CBM wells in Type I coalbeds is usually high because the water in the coal reservoir can be discharged smoothly at an early stage. The second type of coal seam (Type II) develops an additional layer of granulated coal compared with Type I. During the fracturing process, breakage of the coal seam is obvious, and the granulated coal can easily produce fine-grained coal that can block the pores and fractures, which causes an increase and fluctuation of oil pressure and can affect the effectiveness of fracturing. The gas production curve from CBM wells in Type II coal seams is mostly bimodal and water production depends on whether the pulverized coal blocks the pores and fractures. The third type of coal seam (Type III) develops two additional layers of granulated coal compared with Type I, with a greater proportion of granulated coal present. A low degree of coal breakage and fracture formation is observed, and fractures are easily blocked by pulverized coal. The effects of fracturing reconstruction for Type III are bad. Forming an effective seepage channel in this type of coal seam and extending the fracture to the far end is difficult. The gas production from CBM wells in Type III coal seams is usually low, and water production is generally low during the whole drainage period.

Enhancing Fracture Conductivity in Soft Chalk Formations With Diammonium Phosphate Treatment: A Study at High Temperature, Pressure, and Stresses

Summary This study aims to address the problem of fracture hydraulic conductivity decline in soft formations using a diammonium hydrogen phosphate (DAP) solution. A naturally weak carbonate, Austin chalk was chosen as an ideal specimen. Flat chalk samples with reduced elastic modulus and roughness were evaluated before and after aging with 1 M DAP for 72 hours at 75°C and 1,000 psi. The fracture gas conductivity of DAP-aged and untreated samples was measured at various flow rates and stresses while recording sample compaction using linear variable differential transformers (LVDTs). The study found that DAP aging increased the reduced elastic modulus of chalk specimens up to 330% of the original value, improving their resistance to deformation and failure under stress by 200 psi. The hydraulic conductivity of DAP-aged samples was at least twice that of untreated samples, with an extended hydraulic fracture conductivity seven times higher than that of the untreated ones. Scanning electron microscopy (SEM) and energy-dispersive X-ray spectroscopy (EDS) analysis revealed that DAP reacted with the chalk to form hydroxyapatite (HAP), which binds the calcite grains, yielding a stiffer, more deformation-resisting rock surface. Overall, the study demonstrates the potential of chemically enhancing and extending the fracture hydraulic conductivity of weak carbonates using DAP.

Finite-Element Analysis on Energy Dissipation and Sealability of Premium Connections under Dynamic Loads

In the process of high flow rate fracture and high gas production, the sealing performance of the premium connection decreases due to the dynamic load and vibration of downhole tubing strings, which may cause accidents. Existing static analysis methods cannot effectively explain this phenomenon. The main objective of this paper is to propose a novel analytical method for evaluating the sealing performance of a premium connection. In this paper, a dynamic model of sealing surfaces of the premium connection is established based on the vibration equation of elastic rod, and the hysteresis characteristics and energy dissipation mechanism of sealing surfaces are analyzed. Considering the influence of spherical radius, internal pressure, axial cyclic load amplitude, and modal vibration, a spherical-conical premium connection finite element model is established to analyze the influence laws of the connection’s energy dissipation and sealing performance. The results show that the sealing performance of the premium connection under dynamic load can be effectively analyzed by using energy dissipation theory compared with traditional static contact analysis. Compared with the vibration of the tubing string, the dynamic loads caused by the change of fluid pressure and flow rate in the tubing string have a significant influence on the connection’s sealing performance. When the internal pressure and axial cyclic loads are 80 MPa, 400 kN, or 60 MPa and 500 kN respectively, serious plastic deformation occurs in the thread and sealing surfaces, and the energy dissipation of the sealing surfaces increases significantly, which could lead to sealing failure.

3D geological modeling of deep fractured low porosity sandstone gas reservoir in the Kuqa Depression, Tarim Basin

The fractured reservoir is one of the significant petroleum reservoir types in China, representing over one-third of total reserves. The Kuqa Depression in the Tarim Basin is dominated by fractured low-porosity sandstone gas reservoirs with characteristic tight matrix, developed fractures, and edge and bottom water. However, the continued development of these reservoirs has led to various problems, including strong reservoir heterogeneity, low well control, complex gas-water relationships, and early water invasion. Addressing these issues requires a detailed understanding of the reservoir’s geological characteristics. One method for achieving a fine reservoir description is through the use of 3D geological modeling. This high-level, comprehensive characterization technique is widely used throughout the entire life cycle of oil and gas field development. A 3D geological model can accurately predict the actual underground reservoir characteristics and provide a geological basis for later numerical simulation work. Based on a study of the geological characteristics of the Kuqa Depression in the Tarim Basin, a 3D geological modeling technique was developed, which includes structural modeling, facies modeling, petrophysical modeling, and fracture modeling. This technology has been successfully applied to many deep gas reservoirs in the Kuqa Depression of the Tarim Basin, leading to enhanced gas recovery.

Productivity Analysis and Evaluation of Fault-Fracture Zones Controlled by Complex Fracture Networks in Tight Reservoirs: A Case Study of Xujiahe Formation

The development of tight gas reservoirs presents a significant challenge for sustainable development, as it requires specialized techniques that can have adverse environmental and social impacts. To address these challenges, efficient development technologies, such as multistage hydraulic fracturing, have been adopted to enable access to previously inaccessible natural gas resources, increase energy efficiency and security, and minimizing environmental impacts. This paper proposes a novel evaluation method to analyze the post fracturing productivity controlled by complex fault fracture zones in tight reservoirs. In this article, a systematic method to evaluate stimulated reservoir volume (SRV) and fault-fracture zone complexity after stimulation was established, along with the analysis and prediction of productivity through coupled fall-off and well-test analyses. Focusing on the Xujiahe formation in the Tongnanba anticline of northeastern Sichuan Basin, a 3D geological model was developed to analyze planar heterogeneity. The fall-off analytical model, coupled with rock mechanical parameters and fracturing parameters such as injection rates, fracturing fluid viscosity, and the number of clusters within a single stage, was established to investigate the fracture geometric parameters and complexities of each stage. The trilinear flow model was used to solve the well-test analysis model of multi-stage fractured horizontal wells in tight sandstone gas reservoirs, and well-test curves of the heterogeneous tight sandstone gas fracture network model were obtained. The results show that hydraulic fractures connect the natural fractures in fault-fracture zones. An analysis of the relationship between the fracture geometric outcomes of each segment and the net pressure reveals that as the net pressure in the fracture increases, the area ratio of natural fractures to main fractures increases notably, whereas the half length of the main fracture exhibits a decreasing trend. The overall area of natural fractures following stimulation is 7.64 times greater than that of the main fractures and is mainly a result of the extensive development of natural fractures in the target interval. As the opening ratio of natural fractures increases, the length of the main fractures decreases accordingly. Therefore, increasing net pressure within fractures will significantly enhance the complexity of fracturing fractures in shale gas reservoirs. Furthermore, the initial production of Well X1–10, which is largely controlled by fault-fracture zones, and the cumulative gas production after one year, are estimated. The systematic evaluation method in this study proposed a new way to accurately measure fracturing in tight reservoirs, which is a critical and helpful component of sustainable development in the natural gas industry.

Calculation of fracture number and length formed by methane deflagration fracturing technology

The innovative Methane in-situ deflagration fracturing technology offers several benefits. It can prevent formation pollution and eliminates the need for complex treatment procedures for backflow materials. Additionally, it reduces ground transportation expenses and is poised to become a highly effective and eco-friendly waterless fracturing technology. This paper suggests methods for determining the number and length of fractures in oil and gas well stimulation, considering the main influencing factors. The fracture number is calculated using mass conservation principles, while the fracture length is determined using the crack propagation model. The fracturing experiments with large-sized samples were conducted to verify the technical feasibility of the new fracturing technology and fill the gap in large-scale physical model experimental research for deflagration fracturing technology. Following the experiment, compare experimental data with calculated data, and analyze the factors that affect the fracture number and length. The results indicate that both methods are highly feasible and possess strong predictive accuracy. It is advised that to enhance the fracturing effect on formations with high crustal stress, it is beneficial to appropriately increase the peak pressure, reduce the pressure rate, and increase the fracturing time while ensuring that the wellbore remains undamaged. Moreover, these proposed methods are versatile and adaptable, making them suitable for explosive fracturing within hydraulically fractured formations and high-energy gas fracturing technology.

Growth behavior and resource potential evaluation of gas hydrate in core fractures in Qilian Mountain permafrost area, Qinghai-Tibet Plateau

The Qilian Mountain permafrost area located in the northern of Qinghai-Tibet Plateau is a favorable place for natural gas hydrate formation and enrichment, due to its well-developed fractures and abundant gas sources. Understanding the formation and distribution of multi-component gas hydrates in fractures is crucial in accurately evaluating the hydrate reservoir resources in this area. The hydrate formation experiments were carried out using the core samples drilled from hydrate-bearing sediments in Qilian Mountain permafrost area and the multi-component gas with similar composition to natural gas hydrates in Qilian Mountain permafrost area. The formation and distribution characteristics of multi-component gas hydrates in core samples were observed <em>in situ</em> by X-ray Computed Tomography (X-CT) under high pressure and low temperature conditions. Results show that hydrates are mainly formed and distributed in the fractures with good connectivity. The ratios of volume of hydrates formed in fractures to the volume of fractures are about 96.8% and 60.67% in two different core samples. This indicates that the fracture surface may act as a favorable reaction site for hydrate formation in core samples. Based on the field geological data and the experimental results, it is preliminarily estimated that the inventory of methane stored in the fractured gas hydrate in Qilian Mountain permafrost area is about 8.67×10¹³ m³, with a resource abundance of 8.67×10⁸ m³/km². This study demonstrates the great resource potential of fractured gas hydrate and also provides a new way to further understand the prospect of natural gas hydrate and other oil and gas resources in Qilian Mountain permafrost area.

Gas fracturing behavior and breakdown pressure prediction model for granite under different confining pressure and injection rate

Conventional hydraulic fracturing techniques are often found problematic for extracting geothermal energy in hot dry rock (HDR). As an alternative, employing the less viscous gas to replace water as the fracturing fluid showed great potential for more effective fracturing of HDR. In this work, the failure behavior and mechanism of granite during gas fracturing under different confining pressures and gas injection rates are comprehensively examined. It is shown that the breakdown pressure increases with the increase of confining pressure, whereas higher gas injection rate can result in evident decrease of the breakdown pressure. As the confining pressure grows, the acoustic emission (AE) event increases rapidly, with much higher AE counts observed at high gas injection rates than at low injection rates. Comparatively, the AE energy decreases under high confining pressure, due probably to granite transitioning from brittle to ductile. It is interesting that the b-value of AE varies dramatically as the gas injection rate becomes higher with significant fluctuations, indicating the ratio of large fracture and small fracture changes drastically during gas fracturing. In addition, the length of the induced fractures decreases with the increase of confining pressure during gas fracturing, and the length and width of vertical fractures are evidently larger when at high gas injection rate. Last, a novel theoretical predictive model is proposed for estimating breakdown pressure during gas fracturing based on the average tensile stress criteria, which is featured by considering the effect of confining pressure and gas flow behaviors. The theoretical prediction agrees with the experimental results. The present study can provide valuable results for theoretical analysis and engineering applications of gas fracturing in stimulating the HDR reservoirs.

Simulation of fracture propagation law in fractured shale gas reservoirs under temporary plugging and diversion fracturing

Natural fractures (NFs) are developed in shale gas reservoirs, which can easily cause frac hits during hydraulic fracturing and reduce the productivity of infill wells and parent wells. Temporary plugging diverting fracturing (TPDF) can hinder the single forward extension of fracture transition and avoid the communication of hydraulic fractures (HFs) or NFs adjacent to wells. In order to explore the fracture propagation law of TPDF in fractured shale gas reservoirs, this study systematically evaluates the main factors such as stress difference, displacement, and fracturing fluid viscosity on the fracture temporary plugging diversion (TPD) law by means of true triaxial hydraulic fracturing simulation device and cohesive element model in ABAQUS. The findings reveal that (1) the law of fracture initiation and propagation at the engineering scale is similar to that in indoor experiments. Upon the primary fracturing (PF), the smaller the horizontal stress difference, the larger the pumping displacement, and the smaller the viscosity of the fracturing fluid is, the greater the corresponding fracture breakdown pressure and the stronger the rock compression resistance. (2) After TPD secondary fracturing, a small horizontal stress difference and a large pumping displacement facilitate the formation of a vertical complex fracture network structure on the primary fracture. Because of the small size of the indoor rock, viscosity has little effect on the fracture propagation of the TPDF, but the numerical simulation results reveal that the higher the viscosity, the greater the width of the new fracture. In addition, (3) the smaller the angle between the new fracture opened after PF and TPDF, the better the propagation effect of the new fracture. Meanwhile, the farther the temporary plugging zone is from the fracture front end, the wider the new fracture opened after TPDF. The field construction results reveal that the TPDF technology can avoid the effect of HFs, thus preventing frac hits during shale gas reservoir reconstruction. This study not only posits a physical and numerical simulation method for simulating the fracture propagation law of TPDF in fractured shale gas reservoirs but also provides theoretical guidance for applying TPDF to field construction.

Concept and key technology of “multi-scale high-density” fracturing technology: A case study of tight sandstone gas reservoirs in the western Sichuan Basin

There are abundant tight sandstone gas resources in the Sichuan Basin, which are the important objects of reserve and production increase and large-scale development. Due to their discontinuous sandbody distribution, narrow channels, and strong horizontal and vertical heterogeneity, however, conventional fracturing technologies cannot achieve the ideal stimulation effect here. In order to address this difficulty, this paper dissects the geology engineering characteristics of tight sandstone gas reservoirs in the western Sichuan Basin. Starting from the seepage mechanics theory, the concept of “multi-scale high-density” tight gas fracturing technology is put forward by fully referring to the experience of previous multi-round reservoir stimulation in the western Sichuan Basin and the idea of unconventional volume fracturing technology. In addition, its conceptual connotation, key technologies and implementation effects are illustrated. The following research results are obtained. First, the seepage characteristics make it necessary for the efficient production of tight gas reserves to increase fracture density and stimulated reservoir volume (SRV). Second, the “multi-scale high-density” fracturing technology emphasizes the rationality of high-density hydraulic fracture creation and the matching of multi-scale fracture flow capacity, and aims at establishing a multi-level fracture system with effective and steady gas flow in tight reservoirs through fracturing. Third, the “wide, dense, support, stable, and precise” fracturing technology is applied to improve single well production and estimated ultimate recovery (EUR). Fourth, the engineering practice of “multi-scale high-density” fracturing technology in the tight reservoirs of Jurassic Shaximiao Formation and Triassic Xujiahe Formation in the ZJ Gas Field realizes the average single well production rate of 15.6 × 104 m3/d, which is 1.96 times higher than that before the stimulation. Obviously, it provides powerful support for the operation of the ZJ Gas Field into a giant gas field with the reserves of 100 billion cubic meters. In conclusion, the formation of the concept and key technologies of “multi-scale high-density” fracturing technology effectively supports the efficient development of tight gas in the western Sichuan Basin and points out the following research direction of tight gas reservoir stimulation. The research results provide reference and guidance for the large-scale benefit development of tight gas in China.

Stress Sensitivity of Proppant-Containing Fractures and Its Influence on Gas Well Productivity

Formation pressure gradually decreases with fracturing fluid flowback and gas production. Due to the stress sensitivity of the fractures, the permeability of the artificial fractures after fracturing becomes lower, which significantly affects gas well productivity. This paper focuses on two questions: (1) the stress sensitivity of proppant-containing fractures with different roughness and (2) tight gas well productivity considering stress sensitivity. Two types of artificial fracture samples, smooth and rough, are prepared and filled with different proppant concentrations. Then, the changing confining pressure method is used to quantify sample stress sensitivity. On this basis, the productivity equation for the fractured well with finite conductivity that considers fracture and matrix stress sensitivity is derived, and the influence of stress sensitivity on productivity is discussed. The results show that proppant concentration and fracture surface roughness will significantly affect fracture permeability and stress sensitivity; with increasing proppant concentration, fracture permeability increases, stress sensitivity decreases, and well productivity increases; under the same proppant concentration, the stress sensitivity is lower and the gas production is higher for smooth fracture; and when the artificial fracture changes from no proppant to proppant, the productivity of the fracturing well is improved the most.

Numerical investigation on hydraulic fracture propagation and multi-perforation fracturing for horizontal well in Longmaxi shale reservoir

Hydraulic fracturing is one of the key technologies of shale gas extraction. Deeply comprehending the distribution characteristics of hydraulic fracture networks in shale reservoirs is significant for the shale gas fracturing design and production estimation. The efficient description of fluid–solid coupling is essential for modeling the hydraulic fracturing process. In this paper, based on the mechanical parameters from the laboratory test results, the fluid–solid coupling model in PFC2D is improved and employed to establish a DEM model for the hydraulic fracturing of shale reservoirs. The key factors affecting the hydraulic fracture propagation characteristic are investigated, furthermore, based on the geological parameters of Changning shale gas production areas, a multi-perforation fracturing numerical model of the shale reservoir horizontal well is established, and the distribution characteristics of the hydraulic fracture network in staged fracturing are analyzed and revealed. The results indicate that the main factor affecting the formation of a fracture network in the vertical section of the shale reservoirs is the coalescence of interbedding fractures. A large number of secondary interbedding fractures generated by the primary through-bedding fracture can form a complex fracture network, which is exactly the fracture morphology required for hydraulic fracturing in shale gas exploitation. According to the results of hydraulic fracture distribution characteristics under different perforation spacings, the optimal perforation spacing requires that the fractures extend to the maximum range under the premise of hydraulic fracture coalescence can form an effective network and guarantee low economic cost and construction technical difficulties.

RETRACTED: Impact of nozzle size on shale gas productivity in the Longmaxi formation, Sichuan basin, China

High-pressure differentials are critical in the development of shale gas resources; however, excessive stress can cause damage to propped fractures, resulting in decreased production. The manipulation of nozzle sizes and flow pressure adjustments can indirectly control the effective stress on fractures. In this study, we investigated the impact of flow pressure on fracture permeability and gas production in Longmaxi, Sichuan shale gas wells. By utilizing production data from wells and performing permeability evaluation experiments on Longmaxi shale core samples under varying flow pressures, we developed a novel shale gas well deliverability equation to determine the stress sensitivity of propped fractures. The findings of this study suggest that transitioning the nozzle size from small to large during well production and maintaining the flow pressure between 5 and 7.5 MPa is beneficial. If the nozzle size is reduced from large to small to achieve higher initial gas production, the effective stress on the target field should be maintained at 20 MPa. The methodologies introduced in this research offer innovative approaches for evaluating shale fracture permeability and productivity, providing valuable insights and guidance for the selection of nozzle sizes in the development of shale gas wells.

Digital Quantitative Study on Fracture Gas Storage Space for a Three-Layer Composite Residual Mining Area

Quantifying the fracture gas storage space is the key to improving the coalbed methane (CBM) extraction efficiency in residual mining areas (RMAs). In this paper, a new digital quantitative description method of fractures is proposed when using a digital image correlation (DIC) system to monitor strata displacement, which improves the accuracy of fracture statistical data. The results show that with the evolution of RMA from single to three layers, the rock strata area with displacement greater than 3.5 mm increases radially and the maximum fracture rate of the uppermost RMA increases by 64.26%. The fracture rate increases exponentially from top to bottom in a long-distance composite RMA and distributes parabolically in the horizontal partition. The area with the highest average fracture rate (12.65%) in the close-distance composite RMA is defined as the concentrated growth area. The longitudinal fracture rate of a cross-layer fracture area in the three-layer RMA exceeds 60%. The cross-layer fracture area connecting the composite RMA at the open-cut side is a favorable extraction location for surface drilling. The research results will provide theoretical support for the safe and sustainable exploitation of CBM and residual coal in composite RMA.

Experimental evaluation of the flow resistance of CO2 foam fracturing fluids and simulation prediction for fracture propagation

Shale gas fracturing requires huge amounts of water, but most well pads are located mainly in hilly areas where water is scarce. Water supply issues have limited the industrialization of shale gas development. CO2 foam fracturing fluids can meet the requirements for large-scale hydraulic fracturing of shale gas and relieve pressure on water resources. Friction calculations of CO2 foam fracturing fluids in conduit flow are key to the reliability of overall fracturing procedures, affecting fracture targeting and reservoir stimulation effects. Through the analysis of the experimental data of carbon dioxide foam fracturing fluid flow under the simulated reservoir conditions, the influence of pressure, temperature, shear rate, foam quality and other factors on the friction characteristics of CO2 foam fracturing fluid was obtained, and the mathematical calculation model of the friction coefficient of CO2 foam fracturing fluid was established, and the pipe string friction and bottom hole pressure during the fracturing process were obtained, Thus, the shape and extension behavior of hydraulic fractures in the process of carbon dioxide foam fracturing in shale reservoir are simulated and predicted, which provides a theoretical basis for effective evaluation of fracturing effect.