Fractured Tight Gas Reservoirs Research Articles

Reservoir accumulation conditions and key exploration & development technologies for Keshen gas field in Tarim Basin

The Keshen gas field is located in the central part of Kuqa foreland thrust belt in Tarim Basin, and is another large gas field discovered in Kuqa depression after Kela 2 gas field. Since the breakthrough in 2008, a number of large and medium scale gas reservoirs including Keshen 2, Keshen 5 and Keshen 8 have been discovered, that are characterized by ultra depth, ultra-high pressure, ultra-low porosity, ultra-low permeability, high temperature and high pressure. With natural gas geological reserves of nearly trillion cubic meters and production capacity of nearly 5.5 billion cubic meters, the Keshen gas field is the main natural gas producing area in Tarim Oilfield. The Keshen gas field is located in a series of thrusting imbrication structures in the Kelasu structural belt of Kuqa foreland thrust belt. The salt roof structure, plastic rheology of salt beds and pre-salt faulted anticlinal structure constitute the large wedge-shaped thrust body. The thick delta sandstone of the Cretaceous Bashijike Formation is widely distributed, and it forms the superior reservoir-caprock combination with overlying Paleogene thick gypsum-salt bed. The deep Jurassic-Triassic oil and gas migrate vertically along fault system formed in Late Himalaya, break through the thick Cretaceous mudstone and move laterally along the fracture system of the pre-salt reservoirs, to form anticline and fault anticline high pressure reservoir groups. Through near ten years of studies, the three-dimensional seismic acquisition and processing technology for complex mountainous areas, extrusion salt-related structural modeling technology and fractured low-porosity sandstone reservoir evaluation technology have been established, which lay a foundation for realization of oil and gas exploration objectives. Logging acquisition and evaluation technology for high temperature, high pressure, ultra-deep and low-porosity sandstone gas reservoirs, and efficient development technology for fractured tight sandstone gas reservoirs have been developed, which provide a technical support for efficient exploration & development and rapid production of the Keshen gas field.

Investigation of the notch angle in hydraulic fracturing using XFEM

This paper analyzes the initiation and propagation of hydraulic fracturing by nonlinear numerical modeling. A notch located at the wellbore stimulates hydraulic fracturing. The notch has a pivotal role in hydraulic fracturing. There is evidence that the notch can affect the required fluid pressure and the fracture propagation and velocity. Therefore, it has been associated with the effectiveness of hydraulic fracturing in tight gas reservoirs. The objective of this study is to explore the effect of the notch angle on hydraulic fracturing. Models in two- and three dimensions are presented and analyzed. These models are used to find the breakdown pressure and stress intensity factors, respectively. The numerical approximation of hydraulically driven fracture propagation is based on the extended finite element method (XFEM). XFEM enriches finite elements and nodes at elements intersected by the crack during the crack propagation. XFEM reproduces the discontinuity in the displacement domain without the discretization of this property directly in the mesh. Therefore, the generated mesh is independent of the crack propagation. The accuracy of the numerical approach is validated by reproducing laboratory-scale hydraulic fracturing tests and comparing results.

Damage Mechanism of Oil-Based Drilling Fluid Flow in Seepage Channels for Fractured Tight Sandstone Gas Reservoirs

Oil-based drilling fluids (OBDFs) have a strong wellbore stabilization effect, but little attention has been paid to the formation damage caused by oil-based drilling fluids based on traditional knowledge, which is a problem that must be solved prior to the application of oil-based drilling fluid. For ultradeep fractured tight sandstone gas reservoirs, the reservoir damage caused by oil-based drilling fluids is worthy of additional research. In this paper, the potential damage factors of oil-based drilling fluids and fractured tight sandstone formations are analyzed theoretically and experimentally. The damage mechanism of oil-based drilling fluids for fractured tight sandstone gas reservoirs is analyzed based on the characteristics of multiphase fluids in seepage channels, the physical and chemical changes of rocks, and the rheological stability of oil-based drilling fluids. Based on the damage mechanism of oil-based drilling fluids, the key problems that must be solved during the damage control of oil-based drilling fluids are analyzed, a detailed description of formation damage characteristics is made, and how to accurately and rapidly form plugging zones is addressed. This research on damage control can provide a reference for solving the damage problems caused by oil-based drilling fluids in fractured tight sandstone gas reservoirs.

Experimental Investigation of the Damage Mechanisms of Drilling Mud in Fractured Tight gas Reservoir

Mud pollution seriously restricts the development of tight gas reservoirs. For the Dabei tight gas field in Tarim Basin, lots of wells show a higher skin factor on the pressure buildup test curves after drilling. Little researches on mud damage have been conducted for the fracture gas reservoir. Based on the previous researches, a dynamic filtration experimental method utilizing full diameter cores is established for fracture-porous cores under reservoir temperature. Twelve sets of dynamic filtration tests with full diameter cores (D = 10 cm) on the established device and some cuttings microscopic analysis on environmental-scanning-electron microscope/energy dispersive X-ray detector (ESEM/EDX) have been conducted. The effects of core type, fracture width, pressure difference, and mud type on mud damage are all investigated. The results show that the fractured cores suffer a more serious damage degree and exhibit lower return permeability ratio, compared with the porous cores. And the damage degree of fractured cores is proportional to the fracture width and pressure difference. The solids invasion is the key factor damaging the fractured cores, while the porous is mainly impaired by the filtrate invasion. This paper provides a scientific, in-depth understanding of the behaviors, laws, and characteristics of mud damage in fractured and porous cores.

Investigation of Formation Damage Induced During Drill-In Process of Ultradeep Fractured Tight Sandstone Gas Reservoirs

Ultradeep fractured tight sandstone gas reservoir is easy to suffer from severe formation damage during the drill-in process, yet few papers have been published on the corresponding formation damage mechanisms. This paper focuses on a typical ultradeep fractured tight sandstone reservoir in the Tarim Basin, China. Fluid sensitivity damage, phase trapping damage, and the formation damage induced by oil-based drill-in fluids were evaluated by a serious of modified experimental methods. As a supplement, the rock physics and surface property were analyzed deeply. Results showed that severe fluid sensitivity damage occurred with a decrease in fluid salinity (critical value: 3/4 formation water salinity (FWS)) and an increase in fluid pH value (critical value: pH = 7.5). The change in water film thickness, the enhancement of hydrophilia, particle detachment, and dissolution of quartz/albite under high formation temperature are the main damage mechanisms. Abnormal low water saturation, mixed wettability, abundant clay minerals, and complex pore structures are contributing to the severe phase trapping damage. The dynamic damage rate of oil-based drill-in fluids is 60.01%, and inadequate loading capacity is the main trigger of lost circulation. Finally, a formation damage control strategy was proposed, and a field test proved its feasibility.

Development of Keshen ultra-deep and ultra-high pressure gas reservoirs in the Kuqa foreland basin, Tarim Basin: Understanding and technical countermeasures

The Keshen Gas Field in the Kuqa foreland basin, Tarim Basin, is a rare fractured tight sandstone gas reservoir with ultra-depth and ultra-high pressure. During its pilot period of gas field development, the development effect is poor with a low development well success rate, a low utilization rate of production capacity and a rapid decline of gas well productivity. In view of these problems, development experiments and technological researches were carried out continuously after the geological characteristics of gas reservoirs, productivity control factors, reservoir connectivity, seepage characteristics, gas and water relations and water invasion laws were studied thoroughly. And consequently, the development countermeasures of “well placement in high position, moderate stimulation and early-stage drainage” were prepared, and five matching development technologies were formed, such as description technology of ultra-deep complex structures, well pattern optimization technology for fractured tight sandstone gas reservoirs, fracture net acid fracturing technology for fractured tight sandstone reservoirs, dynamic monitoring technology for ultra-deep and ultra-high pressure gas wells, wellbore integrity management and evaluation technology for high pressure gas wells. The following remarkable application results were achieved in the process of gas field development. First, the drilling depth error of the target formation drops from 125 m to less than 30 m. Second, the utilization rate of production capacity in the Keshen 8 Block reaches 100%. Third, the average absolute open flow rate is increased by 5 times to 273 × 104 m3/d from 50 × 104 m3/d before the stimulation. Fourth, safe and smooth production under high temperature and high pressure conditions is realized in the Keshen Gas Field. In conclusion, the successful and efficient development of the Keshen Gas Field provides experiences for the development of similar gas reservoirs at home and abroad, and its development countermeasures and matching technologies have important guidance and reference significance.

On multistage hydraulic fracturing in tight gas reservoirs: Montney Formation, Alberta, Canada

The combination of horizontal drilling and multistage hydraulic fracturing technology has unlocked production of petroleum from tight/shale rock. Prediction of single or multistage hydraulic fracturing treatments along horizontal wells in tight formations remains a challenge and thus optimization of these stimulation treatments is difficult. Currently, there are few effective approaches to characterize multistage hydraulic fracturing in tight rock reservoirs. In this paper, we use a three-dimensional tight rock simulator based on the Unconventional Fracture Model (UFM) to understand multistage hydraulic fracturing in the Montney Formation in Alberta, Canada. We use geological and geomechanical properties, stress magnitude and orientation, completion and production data to history match and characterize fracture volume and conductivity in the Montney Formation. Predictions of fractures from the history-matched reservoir model reveal the strong connection between the fracture conductivity and reservoir permeability, elastic rock properties as well as stresses distributions. The field example demonstrates how stress maps and rock properties calculated from density and gamma logs are integrated to yield predictive hydraulic fracturing capability. This study illustrates the critical role of reservoir permeability on fracture extent and conductivity. This workflow can be used to develop strategies for (1) refracturing of existing wells, (2) design and number of perforations, and (3) prediction of fracture propagation in later stages.

Modified Extended Finite Element Methods for Gas Flow in Fractured Reservoirs: A Pseudo-Pressure Approach

Fluid flow in fractured porous media has always been important in different engineering applications especially in hydrology and reservoir engineering. However, by the onset of the hydraulic fracturing revolution, massive fracturing jobs have been implemented in unconventional hydrocarbon resources such as tight gas and shale gas reservoirs that make understanding fluid flow in fractured media more significant. Considering ultralow permeability of these reservoirs, induced complex fracture networks play a significant role in economic production of these resources. Hence, having a robust and fast numerical technique to evaluate flow through complex fracture networks can play a crucial role in the progress of inversion methods to determine fracture geometries in the subsurface. Current methods for tight gas flow in fractured reservoirs, despite their advantages, still have several shortcomings that make their application for real field problems limited. For instance, the dual permeability theory assumes an ideal uniform orthogonal distribution of fractures, which is quite different from field observation; on the other hand, numerical methods like discrete fracture network (DFN) models can portray the irregular distribution of fractures, but requires massive mesh refinements to have the fractures aligned with the grid/element edges, which can greatly increase the computational cost and simulation time. This paper combines the extended finite element methods (XFEM) and the gas pseudo-pressure to simulate gas flow in fractured tight gas reservoirs by incorporating the strong-discontinuity enrichment scheme to capture the weak-discontinuity feature induced by highly permeable fractures. Utilizing pseudo-pressure formulations simplifies the governing equations and reduces the nonlinearity of the problem significantly. This technique can consider multiple fracture sets and their intersection to mimic real fracture networks on a plain structured mesh. Here, we utilize the unified Hagen–Poiseuille-type equation to compute the permeability of tight gas, and finally adopt Newton–Raphson iteration method to solve the highly nonlinear equations. Numerical results illustrate that XFEM is considerably effective in fast calculation of gas flow in fractured porous media.

Post hydraulic fracturing evaluation and productivity prediction method of fractured tight sandstone gas reservoirs supported by geology-engineering integration

Post hydraulic fracturing evaluation and productivity prediction method of fractured tight sandstone gas reservoirs supported by geology-engineering integration

Characteristics of transient production rate performance of horizontal well in fractured tight gas reservoirs with stress-sensitivity effect

Interest in tight gas reservoirs (TGR) has quickly spread worldwide. Most researches on the permeability stress-sensitivity of tight gas reservoirs mainly concentrated on experimental approach, physical modeling or pressure behavior analysis, while transient production rate performance does not attract much attention. This study developed a dual-porosity model of a horizontal well in fractured tight gas reservoirs considering the stress-sensitivity effect. The solution methods include variable substitution, perturbation technique, Laplace transformation, Sturm-Liouville eigenvalue theory, orthogonal transformation and numerical inversion. The results showed that the production rate decreases with the increasing of permeability modulus and the derivative curve will be warped up during the whole system late radial flow stage. The influences of other parameters are also analyzed. The work undertaken here has both theoretical and practical significance in predicting production performance and evaluating underground fluid transport in such formations.

Damage evaluation on oil-based drill-in fluids for ultra-deep fractured tight sandstone gas reservoirs

In order to explore the damage mechanisms and improve the method to evaluate and optimize the performance of formation damage control of oil-based drill-in fluids, this paper took an ultra-deep fractured tight gas reservoir in piedmont configuration, located in the Cretaceous Bashijiqike Fm of the Tarim Basin, as an example. First, evaluation experiments were conducted on the filtrate invasion, the dynamic damage of oil-based drill-in fluids and the loading capacity of filter cakes. Meanwhile, the evaluating methods were optimized for the formation damage control effect of oil-based drill-in fluids in laboratory: pre-processing drill-in fluids before grading analysis; using the dynamic damage method to simulate the damage process for evaluating the percentage of regained permeability; and evaluating the loading capacity of filter cakes. The experimental results show that (1) oil phase trapping damage and solid phase invasion are the main formation damage types; (2) the damage degree of filtrate is the strongest on the matrix; and (3) the dynamic damage degree of oil-based drill-in fluids reaches medium strong to strong on fractures and filter cakes show a good sealing capacity for the fractures less than 100 μm. In conclusion, the filter cakes' loading capacity should be first guaranteed, and both percentage of regained permeability and liquid trapping damage degree should be both considered in the oil-based drill-in fluids prepared for those ultra-deep fractured tight sandstone gas reservoirs.

Integrated techniques for rapid and highly-efficient development and production of ultra-deep tight sand gas reservoirs of Keshen 8 Block in the Tarim Basin

The unusually ultra-deep and ultra-high-pressure gas reservoirs in the Keshen 8 Block on the Kelasu structural belt of the Tarim Basin are also featured by high temperature, well-developed fault fissures, huge thickness, tight matrix, complex oil–water distribution, etc., which brings about great difficulties to reserves evaluation and further development. In view of this, an overall study was made on the fine description of reservoir fractures and their seepage mechanism, technical problems were being tackled on seismic data processing and interpretation of complex and high & steep structural zones, optimal development design, safe & rapid drilling and completion wells, reservoir stimulation, dynamic monitoring, etc. to promote the development level of such ultra-deep tight gas reservoirs, and 22 complete sets of specific techniques were formulated in the fields of high-efficiency well spacing, safe and fast drilling, recovery enhancement by well completion transformation, efficient development of optimization design, and so on. Through the technical progress and innovative management of integrated exploration & development, reserves evaluation and productivity construction have been completed on the Keshen 8 Block in the last three years of the 12th Five-Year Plan period (2011–2015), as a result, rapid and high-efficiency productivity construction is realized, and a new area is explored in the development of ultra-deep and ultra-high-pressure fractured tight sand gas reservoirs. This study is of great reference to the development of similar gas reservoirs at home and abroad.

A semi-analytical mathematical model for predicting well performance of a multistage hydraulically fractured horizontal well in naturally fractured tight sandstone gas reservoir

Multiple fractured horizontal well (MFHW) is one of the key technologies to exploit low permeability reservoirs. The accuracy of productivity evaluation after fracturing not only affects the effectiveness of fracturing treatment, but also affects the optimum design of parameters in horizontal wells. This paper is the first investigation into the semi-analytical mathematical modeling for gas productivity calculation of multi-staged horizontal wells in fractured tight sandstone gas reservoirs that emphatically considers the impact of flow in fracture network (natural fracture system). Herein, a production forecast model of complex hydraulic fractures was created where the impact of nature fractures was simulated, and a semi-analytical solution was obtained by using Gaussian elimination method. As extension of historical work, this novel model could be applicable to more actual conditions such as fractures at arbitrary angles and unequal, asymmetric fractures.In the subsequent work, a numerical simulation of a simple conceptual model has been conducted, which validated the accuracy of this novel model. Then a real case application was successfully implemented. The modeling calculation result and actual production data of well X in Surig gas field is in good accordance. Besides, the impact of reservoir parameters upon production and morphology optimization were specifically analyzed. Using this new model, the production performance decline curves were drawn up based on computing results and were thoroughly analyzed for the sensitivity of reservoir parameters, especially the natural fractures. As presented in the performance curves, the post-frac production is greatly influenced by the change of permeability in fracture network, also confirming the applicability of this new model in fractured tight sandstone gas reservoirs.

Leakoff characteristics and an equivalent leakoff coefficient in fractured tight gas reservoirs

Leakoff prediction and control are key issues in hydraulic fracturing, particularly in fractured tight gas reservoirs. In the presence of natural fractures, leakoff behavior in these reservoirs shows characteristics of dual leakoff and pressure dependence, which is totally different from that in conventional reservoirs. Available models in the literature do not address these characteristics.In this paper, continuing from our previous studies, we further study the leakoff characteristics in fractured tight gas reservoirs in depth. A leakoff conceptual model is proposed with consideration of three leakoff media. The mathematical models in different media are developed by considering the influence of stress sensitivity. Based on this conceptual model, an equivalent leakoff coefficient is derived. Simulation results performed are consistent with field observations. The equivalent leakoff coefficient is also validated to reflect the characteristics of leakoff. The influence of multiple factors on leakoff is studied in detail, indicating that with an increase in the permeability, compressibility, density and pressure, the leakoff velocity increases, and these parameters have a linear relationship with cumulative leakoff, while with an increase in fracturing fluid viscosity, the leakoff velocity decreases, and it has a power function relationship with cumulative leakoff. After considering the stress sensitivity, both the leakoff velocity and cumulative leakoff increase, and the increasing magnitudes depend on pressure, especially in macro natural fractures. Furthermore, a pressure distribution curve also changes from concave to convex with consideration of stress sensitivity in macro natural fractures.

A fully coupled geomechanics and fluid flow model for proppant pack failure and fracture conductivity damage analysis

One reason for observed reductions in the conductivity of hydraulic fractures is failure of the proppant pack. Proppant deformation, crushing, or embedment can decrease the fracture width and conductivity. In this paper, the continuity and momentum balance equations were fully coupled to simulate the transient phenomena involving fluid flow through a deformable porous proppant pack. Porous media displacement, water pressure, and gas pressure were derived as primary unknowns. The governing equation was discretized using the finite element method and solved numerically. In this model, the proppant pack and formation rocks were treated as two different types of continuous porous media (Biot type). Proppant deformation, crushing, and embedment could be identified through the geomechanical model, while the damage effects on gas/oil production would be studied through the fluid-flow model. Analysis of proppant deformation and crushing was based on the proppant pack stress–strain behavior. The displacement of the fracture-formation interface represented both the deformation of proppant and rock solids around fracture surface. Mohr–Coulomb failure was used as the criterion for proppant crushing. Effects of proppant damage were evaluated on proppant pack porosity and permeability. The model can be applied generally in hydraulically fractured reservoirs with proper inputs. In this paper, we used a fractured tight sand gas reservoir as a study case. The pressure distribution as well as proppant pack deformation are illustrated in the paper. Proppant pack mechanical behavior was found to be sensitive to the fluid flow pressure. Proppant near the wellbore has a higher likelihood of being crushed.

A Fully Coupled XFEM-EDFM Model for Multiphase Flow and Geomechanics in Fractured Tight Gas Reservoirs

Unconventional reservoirs are typically comprised of a multicontinuum stimulated formation, with complex fracture networks that have a wide range of length scales and geometries. A timely topic in the simulation of unconventional petroleum resources is in coupling the geomechanics of the fractured media to multiphase fluid flow and transport.We propose a XFEM-EDFM method which couples geomechanics with multiphase flow in fractured tight gas reservoirs. A proppant model is developed to simulate propped hydraulic fractures. The method is verified by analytical solutions. A simulation example with the configuration of two multiple-fractured horizontal wells is investigated. The influence of stress-dependent fracture permeability on cumulative production is analyzed.

Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.

Comprehensive prediction of dynamic fracture width for formation damage control in fractured tight gas reservoir

Developed fractures are beneficial for the economic and efficient development of tight gas reservoir. But they will lead to drill-in fluid loss and induce serious formation damage. Fracture width prediction is the key for reasonable selection of particle size distribution to prevent drill-in fluid loss and control formation damage in fractured tight gas reservoir. However, the reservoir fracture width is not constant but changed with effective stress variation induced by drill-in fluid invasion, which make it more difficult for fracture width prediction. In this paper, we develop a comprehensive method to predict the reservoir dynamic fracture width. This method is based on stress-dependent permeability experiment and finite element simulation which are conducted to determine the in-situ fracture width and dynamic fracture width. The in-situ width is used as the initial condition for the simulation. According to the experiment and simulation results for North-Western Sichuan tight gas reservoir, the in-situ fracture width is 3.28-18.59 µm and the dynamic fracture width is 17.89-763 µm. Based on the dynamic fracture width prediction, reasonable particle size distribution can be designed to prevent drill-in loss and control formation damage effectively. [Received: January 27, 2014; Accepted: September 20, 2014]

Prevention of fracture propagation to control drill-in fluid loss in fractured tight gas reservoir

Developed fractures are beneficial for the economic and efficient development of tight gas reservoir. But they will lead to drill-in fluid loss and induce serious formation damage. Preventing natural fractures propagation is the key to control drill-in fluid loss in the fractured reservoir. Plugging and sealing the fracture loss channel with loss control material (LCM) can improve the fracture propagation pressure (FPP) effectively. However, the main parameters that affect the improved FPP are not clear. To our best knowledge, few papers have been published on the comprehensive parametric analysis for improved FPP to select reasonable LCM and control drill-in loss in fractured tight gas reservoir. In this paper, we develop a mathematic model to analyze the parameters that affect the FPP after plugging. Laboratory experiment is conducted to select reasonable LCM based on the parametric analysis. Study results show that formation stress anisotropy, elastic modulus, fracture length, fracture pressure and plugging location are the main parameters that impact the improved FPP. According to the analysis results, maximum plugging pressure and total loss volume before sealing are proposed as the key indexes for LCM selection. Experiment results show that reasonable combination of rigid granule, fiber and elastic particle can create a synergy effect to effectively control drill-in fluid loss in fracture tight gas reservoir.

Temporary sealing technology to control formation damage induced by drill-in fluid loss in fractured tight gas reservoir

Western Sichuan tight gas reservoir is characteristic of developed natural fractures and ultra low matrix permeability. Developed fractures are beneficial for the economic and efficient development of tight gas reservoir. But they will lead to lost circulation of drill-in fluid and induce serious formation damage. Moreover, the dynamic fracture width which can reach several hundred microns or millimeter level resulting from drill-in fluid invasion increases the difficulty to solve the problem. To our best knowledge, few papers have been published on the technology that gives a synthetic consideration to both lost circulation control and formation damage prevention in fractured tight gas reservoir. In this paper, we develop the temporary sealing technology and propose its key indexes to control drill-in loss in fractured reservoir. Laboratory experiments are conducted to determine the optimal material size, type and concentration to meet the index requirements. Maximum plugging pressure, total loss volume before sealing and permeability recovery rate are the three key indexes for the temporary sealing technology. Results of laboratory experiment considering the three indexes show that the D90 of the bridging particle size distribution should be equal to the maximum dynamic fracture width. The reasonable combination of rigid granule, fiber and elastic particle can create a synergy effect. The optimal concentration for rigid granule, fiber and elastic particle is 5.0%, 3.0% and 2.5% respectively. Based on the temporary sealing technology, the maximum plugging pressure and permeability recovery rate can be improved to 15.0 MPa and 88.6% respectively, and the total loss volume before sealing can be reduced to only 49 mL.