Multistage Fracturing Research Articles

Comparative analysis of numerical modeling of methods for intensifying inflow to the well, including hydrochloric acid treatment

Relevance. The need to enhance oil recovery from horizontal wells under complex geological and technical conditions. The use of more accurate numerical models, including chemical reactions and the modeling of complex fracture systems, allows optimization of well stimulation, significantly improving both economic and technological efficiency. This is particularly important for developing low-permeability reservoirs and operating under challenging conditions. This work examines the numerical modeling of well inflow stimulation methods using various approaches. For acid treatment modeling, approaches based on changes in well productivity and the use of chemical reactions in the hydrodynamic model were applied. The quality of forecasted technological performance was assessed using real data from an analogous well. As a result, in the case of a real field with extended horizontal wells, additional oil production was achieved through different approaches to acid treatment modeling. Multistage hydraulic fracturing was modeled using planar and discrete fracture models, with only minor discrepancies in the hydrodynamic modeling results between these methods. Aim. To assess the effectiveness of various numerical modeling approaches for well inflow stimulation methods, such as acid treatment and aimed at optimizing oil production from extended horizontal wells. Methods. Numerical models were used to evaluate the effectiveness of stimulation methods, focusing on changes in productivity, the impact of chemical reactions, and sensitivity analysis of treatment parameters. Results and conclusions. It was found that the use of negative skin factors significantly increases oil production compared to models accounting for chemical reactions. Sensitivity analysis of acid volume and concentration helped identify optimal parameters for enhancing acid treatment efficiency. Both modeling approaches (planar and discrete fracture systems) yielded comparable results. Multistage hydraulic fracturing demonstrated a 25000-ton increase in oil production over three years, making it a more effective method than acid treatment.

Seismic-based workflow for multi-scale and multi-stage fracture characterization in the Longmaxi Formation, Weiyuan Gas Field, Sichuan Basin

Seismic-based workflow for multi-scale and multi-stage fracture characterization in the Longmaxi Formation, Weiyuan Gas Field, Sichuan Basin

How ADNOC Opened the UAE’s Pre-Khuff Offshore Gas Play Using Advanced Fracturing Tech

A hidden gem may lie beneath one of the world’s latest megaprojects. Next year, the Abu Dhabi National Oil Company (ADNOC) is set to launch production from its largest-ever gas development within the UAE’s shallow-water Ghasha concession. Located some 190 km northwest of Abu Dhabi, the first phase will see gas flow from the Dalma field, followed by production from the Hail and Ghasha fields, with combined output expected to boost the UAE domestic gas supply by 1.5 Bcf/D by decade’s end. Set aside for several decades due to high levels of H2S and CO2, ADNOC is now pushing to make natural gas a bigger part of its energy strategy and has thus proudly positioned this multibillion-dollar project as the world’s largest sour-gas development. As operator, ADNOC holds a 70% stake in the concession alongside partners Eni (10%), PTTEP (10%), OMV (5%), and Lukoil (5%). ADNOC has also committed to making Hail and Ghasha the first major gas fields to operate with net-zero emissions, supported by substantial investments in carbon capture technology and the use of nuclear power. Yet there may be more to Ghasha’s supply-side potential, thanks to a team of engineers and subsurface experts who weren’t ready to give up on a stubborn rock. Discovered in 1979, the Pre-Khuff formation is a gas-rich sandstone that, though free from H2S, presents other challenges that have so far kept it from reaching commercialization. “The Pre-Khuff has performed well across the region—in Saudi Arabia and Qatar—but here in the UAE, we’ve faced 4 decades of unsuccessful attempts to unlock its potential,” said Jasim Ali Alloghani, ADNOC’s subsurface manager for the Gasha concession. He explained the complexities of the Pre-Khuff formation center around its depth, temperature, and tightness. Offshore the UAE, the Pre-Khuff formation is found 16,000 ft below the mudline where temperatures are more than 350°F and reservoir pressures exceed 10,000 psi. The sandstone is also rich in clay, with estimated clay content ranging from 10 to 40%. This leaves the rock with an upper porosity of about 12%, and a permeability range of 0.01 to 1 mD. The difficulties associated with the Pre-Khuff formation intensify from there. With a Young’s modulus of around 10 million psi, the rock is more than twice as stiff as much of the prolific Wolfcamp Shale in the Permian Basin that spans Texas and New Mexico in the US. The formation is also dominated by natural fractures and varying fracture gradients. Additionally, wellbore washouts while drilling in the deep reservoir have hindered geomechanical data acquisition. ADNOC has also found that the state of stress changes both laterally and vertically, i.e., anisotropy, due to the reservoir’s structural deformation. Additionally, ADNOC has faced challenges with designing effective completion designs due to limited technology and expertise. However, ADNOC’s fortunes with the Pre-Khuff shifted in early 2023 when the company executed the first successful multistage hydraulic fracturing treatments ever performed offshore Abu Dhabi. ADNOC reported a five- to 10-fold increase in initial flow rates from Pre-Khuff wells compared with initial attempts.

Pressure Transient Analysis for Fractured Shale Gas Wells Using Trilinear Flow Model

Shale gas, a low-permeability, unconventional resource, requires horizontal drilling and multi-stage fracturing for commercial production. This study develops a trilinear flow model for fractured horizontal wells in shale gas formations, incorporating key mechanisms such as adsorption, desorption, diffusion, wellbore storage, and skin effects. The model delineates seven distinct flow regimes, providing insights into gas migration processes and the factors controlling production. Sensitivity analyses reveal that desorption plays a critical role under low-pressure and low-production conditions, significantly enhancing gas transfer rates from the matrix to the fracture network and contributing to overall production. Monte Carlo simulations further highlight the variability in pressure responses under different input conditions, offering a comprehensive understanding of the model’s behavior in complex reservoir environments. These findings advance the characterization of shale gas flow dynamics and inform the optimization of production strategies.

Mutual feedback and fracturing effect of hydraulic fractures in composite coal−rock reservoirs under different fracturing layer sequence conditions

Multistage fractures in different reservoirs exhibit competitive extension and mutual feeding mechanisms under different fracturing sequence conditions. To better understand these mechanisms for a more efficient extraction of mine gases, a combination of true triaxial physical tests and numerical simulation was performed in this study. The expansion process of hydraulic fractures in different layers and the comprehensive effect of fracturing were analyzed. The directional deflection effect of the induced stress field on the hydraulic fractures can be summarized as follows. In terms of their behavioral pattern, the fractures in the rock seam extended “in the direction of maximum geo-stress and then deflected toward the interface.” The fracture behavior in the coal seams could be divided into two patterns: “deflection toward the interface and then extension along the direction of maximum geo-stress” and “deviation from the interface and then extension along the direction of maximum geo-stress.” The mutual feedback between the fractures manifested in the form of fracture “phase direction” in the case of stratified fracturing and “phase back” in the case of simultaneous fracturing, i.e., the fracture behaviors in the rock seams and in the first type of coal seams were promoted whereas the fracture behavior was inhibited in the second type of coal seams. In addition, the second fracturing process could be characterized by an increase in the fracture initiation pressure, a decrease in the rate of pressure drop, an increase in the fracture extension duration, and a decrease in the fracture width. When using a fracturing sequence of rock followed by coal, the formation of the seam network structure was found to be more favorable. When using a fracturing sequence of coal followed by rock, it was necessary to continue the injection of the hydraulic fluid into the first fracture during the second fracturing process, so as to obtain a higher fracturing yield. This research provides a certain theoretical support for the efficient co-exploitation of three gases, namely coalbed methane, tight gas, and shale gas, from coal composite reservoirs and in the prevention of gas disasters.

TECHNICAL SOLUTIONS FOR DRILLING WELLS IN CHALLENGING CONDITIONS

Abstract. Drilling modern wells in difficult mining and geological conditions poses a number of tasks for engineers that require special solutions. These include instability of borehole walls in difficult geomechanical conditions, drilling of directional wells with long horizontal boreholes and their completion by multi-stage hydraulic fracturing, drilling in conditions of a narrow «window» of drilling mud density, as well as drilling of wells with extended reach from the vertical. The article describes the main difficulties and problems encountered in solving these problems, such as: wellbore collapse, absorption during drilling in difficult geomechanical conditions, the impossibility of running casing strings and liners into wells with a large deviation from the vertical by traditional methods, difficulties in cementing long horizontal liners, running completion for multi-stage hydraulic fracturing of a formation with packers in an open hole, difficulties in drilling in conditions of insignificant difference in pore pressure gradients and hydraulic fracturing. Certain proven solutions are offered to overcome such problems and difficulties, examples of solutions to the described problems are given. Among these solutions are geomechanical modeling with subsequent calculation of wellbore stability, as well as optimization of well trajectories, the product of multi-stage hydraulic fracturing by the Plug & Perf method of isolation and perforation in order to achieve a larger number of stages, as well as solutions for improving the quality of cementing horizontal liners. Pressure-controlled drilling technology and flotation of casing and liners into ERD wells will be considered. It concludes with conclusions about the relevance of the solutions described, the possibility of combining them to increase efficiency or under complex conditions, as well as aspects that require attention when choosing technologies and their implementation, such as the importance of risk assessment and the importance of technical integration of technologies, as well as preliminary calculations and analysis of technology implementation experience.

Numerical simulation of solid diverting particles transport and plugging in large-scale hydraulic fracture

Diversion technology, also known as temporary plugging technology, has become an integral part of hydraulic fracturing in unconventional reservoirs. The solid diverting particles are a common type of chemical diverting agents used in horizontal well multistage fracturing. The transport and plugging of solid diverting particles within the fractures are crucial physical processes in the far-field diversion technology. In this study, in order to clarify the formation of the plugging layer by solid diverting particles in large-scale hydraulic fracture and to offer insights for the quantitative optimization of far-field diversion technology (FFD), an enhanced simplified two-fluid model within the Euler-Euler framework is employed to simulate the transport and plugging process of solid diverting particles within the fracture. And the numerical schemes of the front settlement region, the plugging layer formation region and the rear settlement region are also optimized. The proposed model is verified through comparison with experimental results from visual fracture test device. Based on the numerical results across various particle, pumping and fracture parameters, our findings indicate that: (1) The duration required to form a complete plugging layer can be reduced to 3%∼20% by increasing injection concentration, injection rate, and fracturing fluid viscosity; (2) Increasing the injection concentration (from 10kg/m3 to 30kg/m3) significantly enhances the length of the plugging layer by about 1∼16 times, compensating for the inability to achieve a complete plugging layer with smaller particle sizes. Merely increasing the injection rate alone (from 0.35m3/min to 0.80m3/min) does not remedy the inability of small particles to form a complete plugging layer under identical plugging conditions. Excessive fracturing fluid viscosity (higher than 6mPa·s) impedes the formation of a complete plugging layer with smaller particles. High fracturing fluid leak-off rate (higher than 2.5×10-7m/s) markedly reduces the length of the plugging layer by about 37%∼44%; (3) Achieving a high close packing degree of particles within the plugging layer is facilitated by increasing injection concentration, increasing injection rate, and reducing fluid viscosity; (4) The abrupt variation in fracture width or height along the fracture length affects up to about 18% of the length of the plugging layer at the top of fracture. To ensure large length of the plugging layer at the top of fracture and high close packing degree of particles within the plugging layer, we recommend injection concentration above 10kg/m3, fracturing fluid viscosity below 6mPa·s, and injection rate exceeding 0.35m3/min. For particle size less than 1.8mm, we suggest injection concentration above 20kg/m3, and fracturing fluid viscosity not exceeding 3mPa·s.

Workflow Helps Predict Casing Deformation During Hydraulic Fracturing in Shale Gas

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 4043054, “Casing-Deformation-Risk Prediction With Numerical Simulation During Hydraulic Fracturing in Deep Shale Gas Reservoirs,” by Jianfa Wu, Xuewen Shi, and Qiyong Gou, PetroChina, et al. The paper has not been peer reviewed. _ In this study, a numerical simulation workflow was established based on comprehensive modeling of a time-lapse stress field, hydraulic fracturing simulation, natural fractures, and other weak interfaces to analyze casing-deformation mechanisms of shale gas horizontal wells during the multistage hydraulic fracturing process. The authors write that they aim to guide the prediction of, and provide mitigating solutions for, casing-deformation risks while improving stimulation efficiency. Introduction The burial depth of deep shale gas reservoirs in the southern Sichuan Basin is approximately 3500 to 4500 m. These have complex geological conditions with developed faults and fractures and high in-situ horizontal stresses. During multistage hydraulic fracturing operations in horizontal wells, establishing an effective prediction method for casing-deformation risks in these reservoirs is a challenge. An integrated workflow is proposed to evaluate and predict casing-deformation risks, effectively support hydraulic fracturing operations, and reduce and mitigate casing failure in these reservoirs. Modeling Methodology It is essential to consider the effects of multiscale natural fractures when constructing a 3D stress model. Natural-fracture stability can be evaluated and used to identify unstable fractures that may cause casing failures. The fundamental workflow of predicting and preventing the casing failure is as follows: 1. Build a 3D geological model characterizing the spatial distribution and geometry of faults and natural fractures 2. Construct a 3D stress model to characterize the in-situ stress state 3. Perform numerical simulations of hydraulic fracturing and 4D coupled stress simulation to obtain the stress field during and after hydraulic fracturing 4. Quantitatively analyze the shear slip risks of natural fractures by calculating slip tolerance as an indicator to determine risk levels of casing deformation 5. Optimize and adjust engineering parameters for hydraulic fracturing to reduce and mitigate casing deformation Natural-Fracture Distribution and Model Construction. In this study, natural fractures parameters such as density, strike, inclination, length of extension, and height were obtained. The natural fractures were calibrated and verified with cores and wellbore images. Natural-fracture distribution was then validated with the expected tectonic history and present-day stress regime. In Fig. 1, the left-hand plot depicts the ant-tracking results by seismic attribute, the central plot portrays natural fractures validated by microseismic events, and the right-hand plot illustrates the 3D natural-fracture model. Results showed two major fracture strikes, one in the northeast and the other in the northwest, forming a mesh network distribution that will be used in the stress model, fracturing simulation, and slip analysis.

Experimental and Molecular Dynamics Evaluation of the Effect of a Sulfate Surfactant on the Shale’s Methane Sorption

Shale gas has shown a great potential for exploration and development via advanced horizontal drilling and multistage hydraulic fracturing. Slickwater is a major type of fracking fluid, containing various chemical additives, water, and sand. In this matter, surfactant additives play a significant role in regulating the optimal performance of slickwater. The implication of the change in gas adsorption/desorption behavior of shale rocks and their individual minerals has rarely been experimentally investigated. In this study, the effect of a sulfate surfactant on methane adsorption capacity of a Marcellus shale was evaluated. Molecular dynamics simulation was also applied for gas adsorption assessment on major minerals in shales. Accordingly, the significant alteration of the adsorption energy of illite, quartz, and calcite minerals treated by a surfactant was investigated. Conclusively, the methane sorption capacity of the treated shale sample was reduced and correspondingly, the gas diffusion coefficient increased. Experimentally, the methane sorption analysis showed that the diffusion of the surfactant resulted in significant methane desorption. Besides, the major mineral constituents of shale behaved differently as unveiled by molecular simulation. The methane adsorption energy of calcite was reduced more significantly than quartz and illite when treated with surfactant. And, at the molecular level, the number of adsorbed methane molecules on illite reduced by half after a sulfate surfactant treatment.

Experience in developing carbonate formations with hydraulic fracturing at fields of Gazprom Neft Group

The development of carbonate formations with hydraulic fracturing is a very interesting and controversial process. In contrast to terrigenous formations, zonal stimulation can be performed by both acid and proppant fracturing methods, and the abundance of process variations expands the options even further. Although there is a general concept of choosing hydraulic fracturing technology depending on the geological and physical characteristics of the formation, the qualitative choice is complicated by the fact that effective solutions for one reservoir could not show the same efficiency in similar conditions at another one. For this reason, from the point of view of working with carbonates, to have as extensive experience as possible in various well conditions in order to minimize production risks and costs associated with the choice of approach and zonal stimulation technology. The study aims to provide a technological overview of effective fracturing solutions for carbonate formations, seeking to understand their features and applicability depending on well and geological conditions. An important place is given to the communication of experience in the application of stimulation technologies that have proven themselves at carbonate formations of Gazprom Neft and show the risks and limitations that can be encountered when choosing a particular solution. It describes experience in hydraulic and multistage fracturing, technologies, approaches and their features depending on geological conditions of carbonate formations. The study also outlines the actual experience of using hydraulic fracturing technologies at carbonate formations, their comparative effectiveness, and the most successful practices based on the actual experience of the work performed. Much attention is paid to comparing the effectiveness of acid fracturing, acid-proppant fracturing, and variations of fracturing on viscous acid compositions. The findings not only give an idea of the technological diversity of the types of zonal stimulation, but also highlights their comparative effectiveness in geological and physical conditions of the reservoir. The reflected experience can help to choose more effective solutions in the development of similar formations, reduce risks at early stages of preparation for fracturing and helps in deciding on the choice of stimulation technology, thereby improving the quality and efficiency of fields development.

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

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

Применение новых технологий кислотной обработки пластов для восстановления продуктивности пласта

Oil recovery, measured by the oil recovery factor (ORF), is a key indicator of the efficiency of oil production. In Russia, the ORF decreased to 0.3 while in the United States this indicator increased to 0.4. About 90% of Russian oil is produced by large holdings, the structure of reserves is shifting towards hard-to-recover, which requires the use of new methods to increase oil recovery. Primary and secondary production allows only 20-50% of oil to be extracted, what makes the use of tertiary methods necessary. The development of horizontal wells with multistage hydraulic fracturing contributes to the development of new field sites, but requires careful preparation of wells to minimize risks and cost increases. Cleaning the bottomhole area using acidic formulations is often the only cost-effective way to restore the productivity of a horizontal well. The improved method of acid composition reduction using a guar gel with delayed “crosslinking”, which ensures uniform treatment of all productive zones of the formation is considered in article. The technology allows for continuous multi-stage acid treatment, temporarily blocking highly permeable areas and increasing the coverage of acidic effects on poorly drained areas. The calculation of the diverter volume considers the average efficiency of the liquid after mini-fracturing, adjusting the volume depending on the efficiency of the liquid at each port.

Unconventional Fracture Networks Simulation and Shale Gas Production Prediction by Integration of Petrophysics, Geomechanics and Fracture Characterization

The proficient application of multistage fracturing methods enhances the status of the Duvernay shale formation as a highly esteemed shale reservoir on a global scale. Nevertheless, the challenge is in accurately characterizing unconventional fracture behavior and predicting shale productivity due to the complex distributions of natural fractures, pre-existing faults, and reservoir heterogeneity. The present study puts forth a Geo-Engineering approach to comprehensively investigate the Duvernay shale reservoir in the vicinity of Crooked Lake. To begin with, on the basis of the experimental results and well-logging interpretations, a high-quality petrophysical and geomechanical model is constructed. Subsequently, the establishment of an unconventional fracture model (UFM) takes into account the heterogeneity of the reservoir and the interactions between hydraulic fractures and pre-existing natural fractures/faults and is further validated by 18,040 microseismic events. Finally, the analysis of well productivity is conducted by numerical simulations, revealing that the agreement between the simulated and observed production magnitudes exceeds 89%. This paper will guide the efficient development of increasingly important unconventional shale resources.

Prospects for increasing the productivity of horizontal wells using integrated technologies on the example of objects in the Ural-Volga region

The paper highlights the issues of the efficiency of the operation of horizontal wells with multistage hydraulic fracturing. The experience of repeated hydraulic fracturing with preliminary preparation of the trunk by hydroblasting perforation shows effectiveness in restoring well productivity. The advantage is the possibility of selective injection of acid and proppant in a certain interval, stimulation of previously not involved in the development of layers and interlayers. This approach significantly expands the scope of application of integrated technologies for the intensification of oil production, in particular, with a high level of uncertainty arising during the development of deposits in this region. It is the introduction of relevant and advanced technologies to increase oil production rates of wells that is the source of technology development and their replication at other oil production facilities. During the retrospective analysis, the effectiveness of the work was assessed depending on various geological, physical and technological factors. It was found that the main reasons affecting the effectiveness of the operation are the orientation of the horizontal trunk along the direction of regional stress, an increase in the points of hydroblasting perforation, and the distance to the injection well. The latter, in turn, is the most important indicator in the planning of hydraulic fracturing, especially in weakly cemented carbonate reservoirs. The conducted research in the field of selecting the optimal method of influencing the target oil production facilities of the Ural-Volga region will allow subsoil users to choose the most relevant and effective way to improve the technical and economic performance of enterprises. The identified reasons, which have a significant impact on the final productivity of wells, must be taken into account when solving various tasks of improving oil production processes in long-term oil-bearing territories. Keywords: hydraulic fracturing; hydrosandblast perforation; multi-stage hydraulic fracturing; horizontal well; formation; productivity; proppant; objects of the Ural-Volga region.

Integrated Modeling of Multi-Stage Hydraulic Fracturing of Low-Permeable Reservoirs

Integrated Modeling of Multi-Stage Hydraulic Fracturing of Low-Permeable Reservoirs

Contrasting fracturing and cementation timings during shale gas accumulation and preservation: An example from the Wufeng-Longmaxi shales in the Fuling shale gas field, Sichuan Basin, China

The marine shales in southern China are characterized by high thermal evolution and intensive deformation during multistage burial and uplift. Fracturing and cementation, associated with tectonic activity, diagenesis, hydrocarbon generation and migration processes, are widely and variably distributed in shale reservoirs experiencing different tectonic evolution. In this study, we utilized cross-cutting relationships, fluid inclusion microthermometry, and laser Raman spectroscopy of fluid inclusions, along with U-Pb dating of fracture-filling calcite veins, integrated with burial history modeling, to elucidate the timing and mechanism of fracturing in the Paleozoic Wufeng-Longmaxi shale reservoir, as well as regional variations in the Fuling shale gas field. Bedding-parallel fractures (BFs) in shale reservoirs are filled with calcite and quartz veins. The timing of fracturing, as determined by minimum homogenization temperatures and U-Pb dating, is estimated to have occurred during ca. 191 -122 Ma, during which some short vertical (or high-angle) fractures (VFs) opened around 163.4 Ma and 137 Ma, subsequently sealed by calcite veins, respectively. All calcite and quartz veins within these fractures contain high-density methane inclusions, while shale reservoirs were in a high-over-mature evolutionary stage. This suggests that fracturing was primarily driven by gas generation overpressure during deep burial. In shale reservoirs near fault belt folds, multistage fractures developed, including three stages of intersecting fractures (IFs) and one-stage of long VFs. The timing of fracturing and cementation corresponds to the Yanshanian tectonic uplift (ca. 83 - 69 Ma) with intense tectonic movement likely being the direct cause of fracture opening. The presence of abundant gas inclusions in veins recorded shale gas expulsion during rapid tectonic uplift, reflecting the destruction of shale gas preservation conditions. In contrast, no significant fracturing or cementation processes have been observed in the tectonically gentle zones. The different fracturing and cementation processes indicated that preservation conditions declined with increased fracture openings during uplift, correlating with the gas enrichment.

Feasibility of CO2 storage and enhanced gas recovery in depleted tight sandstone gas reservoirs within multi-stage fracturing horizontal wells

Injecting CO2 when the gas reservoir of tight sandstone is depleted can achieve the dual purposes of greenhouse gas storage and enhanced gas recovery (CS-EGR). To evaluate the feasibility of CO2 injection to enhance gas recovery and understand the production mechanism, a numerical simulation model of CS-EGR in multi-stage fracturing horizontal wells is established. The behavior of gas production and CO2 sequestration is then analyzed through numerical simulation, and the impact of fracture parameters on production performance is examined. Simulation results show that the production rate increases significantly and a large amount of CO2 is stored in the reservoir, proving the technical potential. However, hydraulic fractures accelerate CO2 breakthrough, resulting in lower gas recovery and lower CO2 storage than in gas reservoirs without fracturing. Increasing the length of hydraulic fractures can significantly increase CH4 production, but CO2 breakthrough will advance. Staggered and spaced perforation of hydraulic fractures in injection wells and production wells changes the fluid flow path, which can delay CO2 breakthrough and benefit production efficiency. The fracture network of massive hydraulic fracturing has a positive effect on the CS-EGR. As a result, CH4 production, gas recovery, and CO2 storage increase with the increase in stimulated reservoir volume.

Quantitative Study on the Anticollapse Ability of Casing in Shale Gas Wells under Complex Load Conditions.

Implementing novel technologies, including the "well factory" model and zipper fracturing techniques, has become prevalent in shale gas development. During completion operations such as lowering casing and multistage fracturing, the casing is subjected to many complex loads, reducing its strength and increasing the risk of casing deformation. By establishing a casing wear model and conducting multistage cyclic loading experiments and numerical simulations, we analyzed the change rule of casing anticollapse strength under complex loads, developed a calculation method for casing comprehensive anticollapse ability under complex loads, and applied the method to an illustrative calculation. The study shows that the wear effect during completion has a negligible impact on the strength of the casing. The casing anticollapse strength exhibits a linear decline in correlation with the number of cycles. The zipper fracturing operation resulted in a nonuniform distribution of geo-stress around the well, and the casing anticollapse strength demonstrated a nearly linear decline in correlation with the nonuniformity of geo-stress. In the presence of both internal and external effects, the casing anticollapse strength exhibited a decline exceeding 15%, thereby increasing the risk of casing deformation. This research method can provide computational guidance for preventing casing deformation in field fracturing construction.

Evaluation of Fluid Distribution and Perforation Erosion in Multistage Fracture Treatment

Summary Fracture monitoring and diagnosis by fiber-optic sensing technology provides invaluable information about stimulation efficiency. This technology becomes more critical for multistage fracturing over long horizontal wells. The combined analysis of distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) measurements has been used to map the fluid distribution during hydraulic fracturing, and fracture volume at the cluster level and at the stage level can be estimated from the analysis. In this paper, based on the interpretation of models for DTS and DAS, we extend the application to fluid containment and stage isolation evaluation. In plug and perforation hydraulic fracturing, when a stage is finished pumping, the stage is isolated by a plug, and the next stage is perforated and then fractured. If the plug is not functioning correctly, fracture fluid enters the previous stage, causing an uneven fluid distribution, and possibly more severe perforation erosion. Both DAS and DTS monitoring can record this phenomenon when it happens. Interpretation models are built to quantify the fluid distribution with the effect of plug leakage included. From DTS measurements, cooling below the stage being completed is counted as the fluid from the current stage. Given this information, the reservoir thermal model can estimate the volume of leakage. From the DAS measurement, we interpret the volume distribution based on frequency band energy to compare with the DTS interpretation. Perforation erosion measurements from a downhole camera are used to confirm the estimation. With this approach, we assess the fluid distribution, plug performance, and the importance of stage isolation on perforation erosion during a multistage fracture treatment. The information can then be used to analyze and optimize completion and fracture treatment design. Field examples are presented in the paper to support the discussion, findings, and conclusions. Based on the results of the fluid distribution estimated, we observed that higher injection rate and larger fluid volumes may create more uniformly distributed fluid between clusters in a stage. When considering communication between stages, the DTS and downhole camera show that there is a correlation between fluid distribution and perforation eroded area. An inconsistency of eroded area and fluid received is observed at toe-side clusters from DTS, DAS, and downhole images. This could be caused by a short erosion time at the toe-side clusters. In the completion design, only a few parameters show a strong impact on fluid distribution and perforation erosion.

Propagation of interfered hydraulic fractures by alternated radial-circumferential extensions and its impact on proppant distribution

The fracture extension mechanisms and proppant transport characteristics play key roles for optimizing hydraulic fracturing in unconventional reservoirs. In this work, the visual physical simulation method was used to analyze the 3D dynamic extension processes of multi-stage hydraulic fractures and the subsequent impact on proppant distribution. The interfered fracture in multi-stage hydraulic fracturing exhibit alternated radial-circumferential extension behavior. More specifically, these behavior changes from unilaterally radial initiation, circumferential extension to radial extension. Unilaterally radial initiation results in the formation of both mirror and conchoidal features, while circumferential extension leads to stepped feature, and radial extension gives rise to feather feature. The four features of hydraulic fractures result in four types of non-uniform proppant distribution: uniform, scattered, cluster, and regional distribution. The proppant transport shifted from linear to radial mode, promoting further fracture extension. The effects of segment spacing and proppant injection sequence were studied. The results showed that the influence on the interfered fracture decreases as the segment spacing increases. In addition, the propped fracture area is larger when the small-size proppant is injected first, followed by large-size one. The research can improve understanding and optimization of multi-stage hydraulic fracturing in unconventional oil and gas reservoirs.