Multistage Fracturing Research Articles

Study on Fracturing Parameters Optimization of Horizontal Wells in Low-Permeability Reservoirs in South China Sea

The oil and gas resources in the deep Paleogene system of the South China Sea are abundant. However, due to its poor reservoir physical properties and strong heterogeneity, the deep Paleogene system needs to be commercially exploited by hydraulic fracturing technology. In view of the challenges of offshore low-permeability reservoirs, large-scale fracturing is not allowed because of the limited operation sites and complex string structure. Taking the H oilfield in the South China Sea as the target, based on the concept of the integration of geologic and engineering techniques, parameters such as the number of fracturing stages and the fracture length were optimized by a numerical simulation, and a study on the slurry rate and fracturing scale was carried out based on the type of fracturing and the pipe string structure. The results show that multistage fracturing technology is available in low-permeability offshore oil fields. It is suggested to adopt networking fracturing technology with a “slick water + high slurry rate” framework. A higher rate is recommended, and the fracturing scale of each stage should be 50 m3 of the sands and 700 m3 of the fluids. This research provides a new model for offshore low-permeability oilfield development.

Field investigation of multi-stage pulse hydraulic fracturing for improving permeability of coal seam in directional long borehole in underground coal mines

Field investigation of multi-stage pulse hydraulic fracturing for improving permeability of coal seam in directional long borehole in underground coal mines

Performance evaluation of microemulsion acid for integrated acid fracturing in Middle Eastern carbonate reservoirs

Considering the characteristics of carbonate reservoirs in the Middle East, a low-viscosity microemulsion acid that can be prepared on site and has an appropriate retardation ability was developed. It was compared with four conventional acid systems (hydrochloric acid, gelled acid, emulsified acid and surfactant acid) through experiments of rotating disk, multistage acid fracturing and core flooding with CT scanning. The micro-etching characteristics and conductivity of fracture surfaces were clarified, and the variation of saturation field during water invasion and flowback of spent acid and the recovery of oil phase relative permeability were quantitatively evaluated. The study shows that the addition of negatively charged agent to the oil core of microemulsion acid can enhance its adsorption capacity on the limestone surface and significantly reduce the H+ mass transfer rate. Moreover, the negatively charged oil core is immiscible with the Ca2 + salt, so that the microemulsion acid can keep an overall structure not be damaged by Ca2 + salt generated during reaction, with adjustable adsorption capacity and stable microemulsion structure. With high vertical permeability along the fracture walls, the microemulsion acid can penetrate into deep fracture wall to form network etching, which helps greatly improve the permeability of reservoirs around the fractures and keep a high conductivity under a high closure pressure. The spent microemulsion acid is miscible with crude oil to form microemulsion. The microemulsion, oil and water are in a nearly miscible state, with basically no water block and low flowback resistance, the flowback of spent acid and the relative permeability of oil are recovered to a high degree.

Accurate Prediction of the Proppant Distribution in a Hydraulically Fractured Stage.

One of the greatest challenges in stimulating a single hydraulic fracturing stage with multiple clusters is ensuring that the proppant is equally distributed across all clusters. In this paper, the Buckingham pi theorem was applied to implement a dimensional analysis to establish an empirical correlation. The experimental correlation was developed by acquiring and integrating the data of various independent variables, such as different proppant characteristics (i.e., size, density, and concentration), using a wide range of internal diameters of the horizontal wellbore and multiple perforation configurations, and utilizing many carrier fluids with different viscosities. This work presents a newly enhanced experimental correlation for the distribution of proppants by incorporating the effect of gravity on proppant particles. The correlation proved its reliability in forecasting the proppant distribution with an average percentage error of less than 10%. The developed correlation has the potential to serve as a tool for forecasting proppant distributions among multiple clusters in multistage hydraulic fracturing treatments in the field.

Enhanced gas production from silty clay hydrate reservoirs using multi-branch wells combined with multi-stage fracturing: Influence of fracture parameters

Natural gas hydrates are typically deposited in low-permeability clayey-silty sediments with low gas production. The two main methods for enhancing gas production are complex structural wells and hydraulic fracturing. However, using only one of those methods does not significantly increase gas production. Herein, a method of combined multi-branch well with multi-stage fracturing was proposed. A novel evaluation method for increased gas production under fracturing was first proposed to reveal the effects of fracturing domain area and number. Then five fracturing distribution models were designed and analyzed. Results indicate that the combined method increased the gas recovery ratio by 829.13% and the hydrate dissociation ratio by 710.34% compared to branching wells because of enlarging pressure propagation and communicating deep thermal fluids. The dissociation of hydrates is enhanced by an increase in the area and the number of fractures, but the rangeability of the increased stimulating effect declines. Different fracture distributions influence production performances at different stages. Short-term production is beneficial when fractures are in the branch well centers. Long-term gas production can be improved when fractures are mainly located at the branch distal end. This novel study has important implications for commercial exploitation at different production stages.

Generation mechanism and influencing factors of fracture networks during alternate fracturing in horizontal wells

Hydraulic fracturing is an effective means to increase natural gas production, and alternating fracturing is a special fracturing method. Compared with sequential fracturing, alternating fracturing is easier to form complex fracture networks. In order to investigate the generation mechanism of complex fracture networks during alternate fracturing, we conducted several multi-stage hydraulic fracturing experiments indoors with different fracturing sequences. Based on the cohesive element method, a numerical hydraulic fracturing model was established, from which the stress interference affected by the fracture spacing and horizontal in-situ stress were analyzed. The results show that: Alternate fracturing is more effective in controlling fracture geometry than sequential fracturing, which is also advantageous in shortening fracture spacing and avoiding the penetration of adjacent fractures. The critical factors affecting the branch fractures are the fracture spacing and the number of main fractures. Alternating fracturing is easier to produce branch fractures perpendicular to the main fracture. The stress interference among main fractures will change or reverse the stress field. The branch fractures closed due to the competition mechanism at the fracture tip are reactivated and extended perpendicular to the main fracture. Alternate fracturing is beneficial in activating microfractures near the main fractures, especially under a larger stress difference. The number of micro-fractures activated by alternating fracturing was more 14% and 21% than the sequential fracturing with the stress difference of 3 MPa and 11 MPa. The increase in stress difference and fracture spacing will decrease the fracture fractal dimension, and the fractal dimension of alternating fracturing is 0.054 more than that of sequential fracturing.

A Review of Macroscopic Modeling for Shale Gas Production: Gas Flow Mechanisms, Multiscale Transport, and Solution Techniques

The boost of shale gas production in the last decade has reformed worldwide energy structure. The macroscale modeling of shale gas production becomes particularly important as the economic development of such resources relies on the deployment of expensive hydraulic fracturing and the reasonable planning of well schedules. A flood of literature was therefore published focused on accurately and efficiently simulating the production performance of shale gas and better accounting for the various geological features or flow mechanisms that control shale gas transport. In this regard, this paper presents a holistic review of the macroscopic modeling of gas transport in shale. The review is carried out from three important points of view, which are the modeling of the gas flow mechanisms, the representation of multiscale transport, and solution techniques for the mathematical models. Firstly, the importance of gas storage and flow mechanisms in shale is discussed, and the various theoretical models used to characterize these effects in the continuum scale are introduced. Then, based on the intricate pore structure and various pore types of shale gas reservoirs, this review summarizes the multiple-porosity models in the literature to represent multiscale gas transport, and discusses the applicability of each model. Finally, the numerical and analytical/semi-analytical approaches used to solve the macroscopic mathematical model governing shale gas production are reviewed, with a focus on the treatment of the complex fracture network formed after multistage hydraulic fracturing.

Tight and Shale Oil Exploration: A Review of the Global Experience and a Case of West Siberia

Shale and tight oil reservoirs, with horizontal wells and hydraulic fractures, typically have a recovery ratio of around 10%. The exploration of tight oil and shale in North America has proven economically viable, thanks to advancements, such as horizontal wells, hydraulic fracturing, and other enhanced oil recovery techniques. Taking inspiration from the global experience (the North American shale experience), the exploration and development of the West Siberian tight and shale reserves was more focused on the reported best practices of the exploration of North American shale. In this study, the advance in the specific areas of shale and tight oil exploration was considered, with more emphasis placed on the progress in the exploration of West Siberian shales. According to the review literature, thermal enhanced recovery methods capable of converting organic matter into hydrocarbons were studied more than other methods of enhanced oil recovery. Aligned with global trends, there has been a growing focus on research aiming to integrate data-driven approaches and pore-scale simulations to enhance recovery from tight and shale formations. Multiple pilot studies have showcased promising prospects for implementing multistage hydraulic fracturing. Nevertheless, there are limited pilot studies dedicated to enhanced oil recovery methods for West Siberian shale.

Application of Acid Fracturing Technology to Improve Water Yield of Deep Carbonate Geothermal Wells

To achieve the “carbon peak” goal, green and low-carbon energy development is the key. The development and utilization of geothermal resources and the development of deep carbonate geothermal wells in China are analyzed. Based on the principle of chemical reaction between hydrochloric acid and the main components of carbonate rock, four rock samples from geothermal wells were dissolved with 15% and 20% hydrochloric acid, respectively. The comparison showed that 15% hydrochloric acid was more economical and effective. The percolation capacity of acid dissolution fractures was tested through percolation capacity experiments, and the optimal amount of acid solution was determined to be 2-8 PV. It was verified that acid dissolution helps improve fracture percolation capacity. Through the on-site testing of acid fracturing technology in the Xiong’an New Area, it has been verified that the on-site implementation of multi-stage acid fracturing has a significant effect on increasing production. Finally, conclusions are drawn. The method of using acid solution dissolution to increase the water yield of deep carbonate geothermal wells is feasible, and the multi-stage acid fracturing technology is suitable for deep wells and can increase the water output of geothermal wells, which has good promotion value.

Development of a Design Method for Casing and Tubing Strings under Complex Alternating Loads

With the escalating intricacy of downhole operational scenarios, encompassing frequent well cycling, acidification, multi-stage fracturing, steam injection, and intensive extraction, the efficacy of traditional casing-string-design methods rooted in strength considerations is progressively unveiling its limitations. Henceforth, it becomes imperative to establish string-design method standards that embrace the entirety of a well’s lifecycle, encompassing the phases of drilling, completion, fracturing, and production operations. Beginning with an analysis of the advantages and limitations of traditional casing-string-design methods, this paper introduces the features of strain and sealing design methods developed for the full lifecycle of the string. The strain design method, a departure from conventional design philosophies, enables the design concept of the controllable deformation of the pipe string. The sealing design method currently stands as the sole standard method for the design of tubing strings. Simultaneously, this paper proposes the establishment of a time dimension-based lifecycle pipe string-design method standard. This approach considers the trend of pipe strength degradation, effectively addressing the safety concerns related to pipe string design in production and operation.

Fracture Modeling of Shale Oil and Gas Reservoirs in Texas

Formation fracturing is the method of choice for developing shale oil and gas reservoirs that constitute a gigantic resource in the U.S.A. and many other countries but are characterized by a low permeability in the nano-Darcy range. The oil production of Texas has increased by about 5 million B/D in 15 years as a result of shale exploitation by massive multistage hydraulic fracturing. The mathematical modeling of this fracturing process is complex and can be approached in several ways. This paper first gives a concise description of the fracturing process as carried out in Texas. Included are the ranges of the key reservoir properties, as well as the injection fluid volumes and pressure, the composition of the injected fluid, proppant type, and volume, and other relevant data. Also included are the number of fracture stages, methods of zonal isolation, and diagnostic techniques used. An important variable considered is flowback, in particular, fluid retention and oil and gas production. High-salinity water production is discussed. Given the above variables, the currently used fracture simulators are briefly considered and compared, both the geomechanics-based and fracture-propagation-based. No single simulator can model the complete process. The directions currently being followed are briefly described. Also discussed is the simulation of the re-fracturing process and its range of success in increasing oil recovery from about the original ~5% to ~8%. Future processes such as plasma fracturing are mentioned, and their future applicability is discussed for further increasing oil recovery.

Enhanced gas production from low-permeability hydrate reservoirs based on embedded discrete fracture models: Influence of branch parameters

The low permeability of marine hydrate reservoirs makes it difficult for trail results to meet the demand for exploitation. Hydraulic fracturing and multi-branch wells are the primary methods for enhancing productivity. This study proposed a new production enhancement method of multi-branch wells combined with multi-stage fracturing (MWMF) based on the embedded discrete fracture model (EDFM). By simulation of the Shenhu area, the multi-physical field evolution of the MWMF production process was first revealed, followed by the systematic analysis of the MWMF production enhancement effect with branch parameters. Results indicated that the cumulative gas production of MWMF increased by 327% compared with only horizontal wells. The production of four-branch wells exhibited a 7% reduction compared to horizontal wells using the MWMF method, suggesting increased branch numbers inhibit production. Increasing branch length was positively correlated with enhanced production. Notably, the influence of branch length on gas production became more pronounced as the number of branches increased. The interface of the three-phase layer (TPL) and hydrate-bearing layer (HBL) was the most suitable location for branch well placement. This novel study provides valuable insights into new applications of the MWMF method in developing low-permeability hydrate reservoirs.

Multi-stage and multi-well fracturing and induced stress evaluation: An experiment study

Multi-stage and multi-well fracturing of horizontal wells are indispensable techniques in developing shale oil and gas. Increasing the stimulated reservoir volume (SRV) is of vital importance for production. However, further research is still required due to the uncertainty of fracture propagation mechanism and the evolution of induced stress. To date, there are few true triaxial hydraulic fracturing physical simulations of large-natural shale samples. By using 13 cubic shale samples (30 × 30 × 30 cm), we investigated the effect of in-situ stress, treatment parameters, and different patterns of multi-well fracturing (staggered or tip-to-tip) on fracture propagation. The pumping pressure data is collected, and the evolution data of the induced stress is measured by a strain gauge which is glued on the rock surface. The fracture geometry is analyzed based on post-fracturing reconstruction, the fracturing data, and the induced stress evolution data. Finally, the suggestions for improving multi-stage and multi-well fracturing treatment are proposed. The results show that: A low overburden stress makes the bedding plane easier to be opened, and it also stops the main hydraulic fracture propagating to the deep reservoir. A high injection rate generates higher net pressure in fracture, and the hydraulic fracture can propagate and cross the bedding plane easily. While using a low injection rate, the liquid can only leak along the bedding plane near the wellbore, leading to a simple fracture geometry. The more fracturing stages, the more complex the fracture network is, and the induced stress data shows an obvious increase. The addition of temporary plugging agent causes a significant increase in pumping pressure and induced stress curves, and the fracture geometry is more complex. Compared with the experiment that has no temporary plugging agent, the induced stress has an increase of 0.7 MPa. In multi-well fracturing experiments, the type of multi-well fracturing (staggered or tip-to-tip) plays an important role on fracture propagation: The fracture complexity in tip-to-tip pattern is significantly lower than that in fracturing staggered pattern because of the “frac-hit”. The longer time interval between treating two wells, the lower the induced stress and the more regular fracture geometry. Further, the fractures that generated in the first well will be reopened by the fluid from the second well when the “frac-connection” occurs between the two wells, causing the induced stress to rise again. The results may provide a reference for the multi-stage and multi-well fracturing design.

Investigation into the Perforation Optimization in Conglomerate Reservoir Based on a Field Test

The Mahu conglomerate reservoir is characterized by strong heterogeneity and the uneven stimulation of the horizontal lateral during hydraulic fracturing. The optimization of the perforation number per cluster is of great value for horizontal well multi-stage fracturing (HWMF) because the suitable perforation number not only promotes the uniform propagation of multiple fractures but also prevents excessive perforation erosion. In this work, a typical well in the Mahu conglomerate reservoir was selected, and a field test of optimizing the perforation number was carried out. The perforation schemes of three, five, and eight perforations per cluster were designed in nine fracturing stages, respectively. The wellhead pressure under different perforation schemes was compared and analyzed with the step-down flow rate test, and the optimal perforation number per cluster in the Mahu conglomerate reservoir was selected as eight. The theoretical calculation results show that eight perforations per cluster can generate the perforation friction of 5 MPa, sufficient to overcome the mechanical property differences among multiple clusters within one stage. The downhole video technology shows that the perforation erosion area is the most uniform with the case of eight perforations per cluster. Moreover, the optical fiber monitoring results show that the perforation number of eight per cluster can realize the simultaneous initiation and uniform propagation of six fractures or five fractures within one stage. This work is of great significance for the efficient development of the Mahu conglomerate reservoir through HWMF.

Evaluation of Fracture Volume and Complexity of Tight Oil Wells Based on Flowback Data

For tight reservoirs, horizontal wells and multi-stage fracturing can generate a complex fracture network that realizes economic and effective development. The volume and complexity of the fracture network are of great significance to accurately predicting the productivity of tight oil wells. In this work, a mathematical model of a multiphase flow is proposed to evaluate the stimulation effect based on the early flowback data. The model showing the early slope of the material balance time (MBT) and production balance pressure (RNP) can help estimate the effective stimulated volume of the horizontal well. The linear flow region can be determined from the slope of the log–log plot of the MBT versus RNP curve, which equals 1. The method is verified by commercial simulation software, and the calculated stimulated volume is consistent with the statistical results of simulation results. Results also show that the flow pattern of the fracture–matrix system can be judged by the slope of the flowback characteristic curve in the early stage of flowback, and then the complexity of the fracture network can also be obtained. The proposed method can provide an avenue to evaluate the fracturing work using the flowback data quickly.

Numerical Simulation Study of Pressure Transfer Based on the Integration of Fracturing, Shut-in and Production in Tight Reservoirs

As an important replacement resource for conventional oil and gas, tight oil and gas are quite abundant. Long horizontal wells and multi-stage fracturing have become key technologies for developing tight oil and gas, and reasonable shut-in measures can improve the utilization efficiency of fracturing fluid. Therefore, it is especially critical to master the pressure transfer law during the shut-in process in tight reservoirs to further improve the energy efficiency of fracturing fluid. However, many studies have mostly focused on the separate design of fracturing, shut-in and production, and have not yet revealed the pressure transfer law during shutting in well based on the integration of fracturing, shut-in and production, which makes it difficult to realize the efficient development of tight oil and gas. Taking the tight oil reservoir in Block M as an example, the geological model of the target block was established using an integrated fracturing development software platform, on which the simulation of fracture extension, well shut-in and production was carried out. The changes in the reservoir pressure field during shutting in well were analyzed, and the influence law of fracturing fluid volume, shut-in time, reservoir original formation pressure and fracture network complexity on the effect of well shut-in were studied to optimize the shut-in system. It was found that the retained fluid increases, the pore pressure of the near-fracture matrix increases, and the diffusion distance of fracturing fluid to the distant matrix increases. The tight oil production increased after shutting in well, and the optimal retained fluid volume of 9600 m3 was actually preferred based on the model. The pore pressure of the near-fracture matrix decreases as the shut-in time increases, the diffusion distance of fracturing fluid to the distant matrix increases, and the pore pressure decreases with an increase in diffusion distance. The tight oil production increased after shutting in well, and the optimal shut-in time was actually preferred to be 90 days based on the model. The increase in formation pressure on abnormal low pressure formation is larger, and the production can be significantly improved after shutting in well. The more complex the fracture network is, the more obvious the non-uniform variation in matrix pore pressure during shutting in well. The research is of great significance for the optimal design of a shut-in system for tight reservoirs and the sustainable development of oil and gas resources in China.

Reservoir and Fracture Characterization for Enhanced Geothermal Systems: A Case Study Using Multifractured Wells at the Utah Frontier Observatory for Research in Geothermal Energy Site

Summary For enhanced geothermal systems (EGS), multistage hydraulic fracturing along a deviated or horizontal well is a key technology used to create a high-conductivity fracture network between injection and production wells in deep, low-permeability geothermal reservoirs. The purpose of the created fracture network is to allow for the efficient transfer of fluid, heated by the geothermal reservoir, from the injection to the production well; therefore, well spacing (between injection and production wells) and hydraulic fracturing must be designed not only to promote connectivity between well pairs but also to mitigate thermal short-circuiting and thermal breakthrough. Analysis of post-fracture pressure decay (PFPD) data measured after each stage of a hydraulic fracturing treatment can be used to provide critical reservoir and fracture parameters required for well and hydraulic fracturing design optimization; this method provides a low-cost alternative and complementary approach to in-situ observation techniques, such as core-through experiments, fiber optics, or image logs in offset wells. Until now, PFPD has primarily been applied to multifractured horizontal wells (MFHWs) completed in low-permeability hydrocarbon reservoirs. The goal of this study is therefore to develop a methodology to estimate fracture and reservoir parameters using stage-by-stage PFPD data associated with EGS projects. An analytical model is proposed herein to estimate fracturing fluid efficiency, fracture length, average fracture aperture, average fracture conductivity, and reservoir permeability for different possible fracture geometries in EGS reservoirs. PFPD data collected for three hydraulic fracture stages in the injection well at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site were analyzed to demonstrate the practical application of the proposed method. The results of this study indicate that, due to the presence of natural fractures in the target (granitic) reservoir, the hydraulic fracturing treatment (using slickwater) in the openhole section resulted in low fracturing fluid efficiency and small hydraulic fractures. In contrast, hydraulic fracturing treatments conducted in the perforated casedhole wellbore resulted in higher fracturing fluid efficiency and created larger hydraulic fractures even with smaller injected volumes. The results of the PFPD analysis were confirmed using a Formation MicroScanner image log and microseismic data collected during each stage of hydraulic fracturing.

Increasing the profitability of production of hard-to-recover oil reserves based on the choice of a rational development system

The article presents a solution to the problem of determining the most effective system for the development of hard-to-recover oil reserves confined to thin-layered clay-bearing reservoirs, based on geological and hydrodynamic modeling. The ratio of oil recovery factor and net discounted income was used as an assessment of the project efficiency. When selecting, the profile was varied - a directional well with hydraulic fracturing and a horizontal well with multi-stage hydraulic fracturing, the method of organizing the system for maintaining reservoir pressure, the density of the well grid and the technological parameters of well completion - the length of the horizontal section and the distance between the hydraulic fracturing sleeves. To confirm the results obtained, an analysis of the operation of the wells launched at the facility was carried out, which showed the convergence of the rate of decline in production rates in the absence of the involvement of the underlying horizon by a hydraulic fracture. Additionally, when choosing a site for pilot work, an option was considered to use the existing well stock to organize a reservoir pressure maintenance system while maintaining the geometry of the development element. According to the calculations, the application of the developed solutions will make it possible to double the oil recovery factor and the net discounted income of the project compared to the base case.

Numerical simulation of proppant transport from a horizontal well into a perforation using computational fluid dynamics

With the increasing global demand for oil and gas, the development of unconventional resources such as shale gas is becoming ever more important. The key to developing unconventional oil and gas resources lies in horizontal wells with multistage fracturing technology. In the process of horizontal well segmentation fracturing, the distribution of the proppant among multiple clusters has a significant influence on the fracturing effect. However, the influence of various factors on the entry of proppant into the perforation and then into the fracture along the wellbore is unclear. In this paper, based on the flow characteristics of proppants in fracturing fluids, we investigate the wellbore–perforation proppant transport using a Eulerian multiphase flow model. The effect of different factors on proppant entry into the perforation in horizontal wells is studied. We first verify that the computational fluid dynamics model satisfies the accuracy requirements for studying the sand-carrying efficiency of proppants in a perforation cluster. Second, the effects of the proppant size, proppant density, fracturing fluid viscosity, perforation diameter, and fracturing fluid flow rate on the proppant transport efficiency are investigated. Finally, a mathematical model of the sand-carrying efficiency is established by multivariate nonlinear fitting. The results show that the proppant size has a more significant effect on proppant settling at low wellbore flow rates. Increasing the diameter of the proppant particles can accelerate proppant settling. Higher wellbore flow rates tend to reduce the sand-carrying efficiency, although using a low-density proppant can mitigate the effect of the wellbore flow rate. At low wellbore flow rates, increasing the perforation size makes it easier for the proppant to enter bottom perforations. Increasing the fluid viscosity helps to distribute the proppant evenly between perforations in different directions, but this effect diminishes as the flow rate increases. Finally, a formula for the wellbore sand-carrying efficiency is obtained and validated, providing a basis for optimizing the distribution of the proppant in the perforation. The results from this paper enhance our understanding of the sand and fluid feeding patterns of each perforation cluster and provide direction for improving the construction process and enhancing the fracture inflow capacity.

Numerical study of the fracture propagation mechanism of staged methane deflagration fracturing for horizontal wells in shale gas reservoirs

The staged methane deflagration fracturing of horizontal wells is a new reservoir stimulation method serving the high-efficiency exploitation of shale gas reservoirs. To study the propagation mechanism of deflagration fracture, a multi-physics field coupling numerical model of deflagration fracturing considering the synergistic effects of stress impact and gas wedging is constructed based on the continuum-discontinuum element method (CDEM). The linear elastic constitutive and the tensile-shear composite constitutive models considering strain softening are applied to the block element and the interface element, respectively, and the cubic law is designated to describe the flow of explosion gas in the fracture element. The CDEM model is solved explicitly and iteratively by dynamic relaxation technology, and a calculation module of deflagration pressure is developed by programming. Then, numerical studies of staged methane deflagration fracturing in horizontal wells under different factors are performed. The results indicate that methane deflagration fracturing could overcome the stress concentration around the well, forming 5–8 main fractures of about 4.7 m in each section. Peak pressure has the most significant effect on the methane deflagration fracturing, with an influence degree of up to 2.72%. When the peak pressure increases from 150 MPa to 340 MPa, the reservoir fracture degree increases by 6.17% and the fracture half-length of σH direction increases by 0.99 m. When the in-situ stress difference increases from 0 to 30 MPa, the main fracture distribution of the staged deflagration fracturing is more crowded and the fracture half-length can increase by about 1.1 m. The increase in the deflagration section number and the deflagration section spacing is conducive to increasing the reservoir fracture degree and the deflagration fracture range. The maximum fracture length in the σH direction of each section is almost equal, which is useful for realizing the uniform extension of fractures in multistage fracturing.