Multistage Hydraulic Fracturing Research Articles

New technologies for developing hard-to-remove oil reserves

Enhancing oil recovery and involving hard-to-recover and residual reserves in the development is currently impossible to solve without the use of modern methods of enhancing oil recovery. One of the main tasks of ensuring effective development of deposits, taking into account the current structure of reserves, is the intensification of oil production. The most effective method for increasing well productivity is multi-stage hydraulic fracturing (MSHF).

Опыт применения горизонтальных скважин с многостадийным гидроразрывом пласта в условиях низкопроницаемых отложений тюменской свиты месторождений ООО «РН-Уватнефтегаз»

Опыт применения горизонтальных скважин с многостадийным гидроразрывом пласта в условиях низкопроницаемых отложений тюменской свиты месторождений ООО «РН-Уватнефтегаз»

Проведение многостадийного гидроразрыва пласта (МГРП) с использованием гибкой насосно-компрессорной трубы (ГНКТ) в слабоконсолидированных терригенных коллекторах

Проведение многостадийного гидроразрыва пласта (МГРП) с использованием гибкой насосно-компрессорной трубы (ГНКТ) в слабоконсолидированных терригенных коллекторах

Effects of cyclic cryogenic treatment on rock physical and mechanical properties of Eagle Ford shale samples - An experimental study

Unconventional reservoirs have ultra-low permeability, and the combination of horizontal wells and multistage transverse hydraulic fracturing have unlocked economical hydrocarbon production from such formations. Fracturing fluid involves large volumes of water that is partially recovered during the flowback stage, and the rest remains in the formation damaging the matrix-fracture interface. In this paper, an alternative waterless stimulation technique has been studied. A cryogenic fluid, liquid nitrogen (LN2), was injected into cores from Eagle Ford formation. The effects of cyclic LN2 on rock physical and dynamic elastic properties were examined. Two cycles of injecting LN2 into cores at the reservoir temperature and pressurizing at different pressures (1.38, 2.76, 4.14 MPa) were implemented. Before and after each cycle, computerized tomography scan, porosity, permeability, and ultrasonic velocities tests were conducted on the samples. The results demonstrated that cyclic cryogenic treatment increases porosity and permeability and decreases ultrasonic velocities of the samples resulting from inducing new cracks and extending and widening the existing ones. Permeability enhancement, which results from the creation of high-permeable pathways allowing the gas to move rapidly across the tested samples, was noticeable (up to 2 orders of magnitude). Whilst, comparing to permeability, the porosity improvement was not significant (up to 26%) owing to the small increase in pore volume compared to the sample's bulk volume. The results showed a direct relationship between injection pressure and porosity and permeability enhancements after the completion of each cycle. Moreover, the reductions in ultrasonic velocities and dynamic elastic properties were insignificant compared to the changes in the porosity and permeability. Additionally, porosity and permeability enhancements and velocities reduction mainly occurred after completing the first cycle. This is because of lowering the thermal stress on samples, which results in reducing the possibility of creating new cracks or propagating and widening the current ones.

An efficient stimulated reservoir area (SRA) estimation method based on octree decomposition of microseismic events

Fracture contact area is the critical factor determining post-treatment production after multi-stage hydraulic fracturing. At present, there are no effective methods for the estimation of the stimulated reservoir area (SRA) of the complex fracture network after stimulation. Conventional methods mostly focused on calculating stimulated reservoir volume (SRV) by using microseismic events directly or indirectly. However, since there is a large number of noise events in microseismic data that can't be removed completely, the SRV results often have huge errors and are inconsistent with practical well production.For this reason, we propose an efficient and robust SRA calculation method based on 3D octree decomposition. The method is able to effectively estimate SRA by generating a multi-level grid structure without reconstructing the fracture network. Through a large number of case simulations based on synthetic events generated by Monte Carlo method, it is found that our method could adapt to the estimation of SRA for different configurations. It could obtain reliable and robust results in the presence of noise events. Specifically, it is indicated that the maximum relative calculation error is less than 20% for mesoscale and large-scale fracture network. The error for small-scale fractures could be reduced below 30% combining with the error reduction approach put forward in this paper. The applicability of our method is also investigated through two horizontal well platforms. Compared with the conventional SRV method, it is found that SRA obtained by our method could better reflect the stimulation effects and is more consistent with real production. It could become a potential and effective index for stimulation evaluation and fracturing operation optimization.

Fracture-Hit Detection Using LF-DAS Signals Measured during Multifracture Propagation in Unconventional Reservoirs

SummaryLow-frequency distributed acoustic sensing (LF-DAS) data are a powerful attribute to detect fracture hits and characterize fracture geometry during multistage hydraulic fracturing treatments in unconventional reservoirs. The DAS data in low-frequency bands linearly correlate with strain and strain rate induced by dynamic fracture propagation. Due to the complexity of multiple-fracture propagation in unconventional reservoirs, the measured signals from different wells exhibit various characteristics. Mechanisms causing the differences are not well understood, which makes the interpretation of real LF-DAS data and detection of fracture hits very challenging. Hence, it is necessary to relate the observed strain/strain-rate signatures to specific fracture patterns based on the physical model of rock deformation during fracture propagation and to quantitatively characterize signatures surrounding fracture hits. In this study, we have applied our in-house fracture propagation model to simulate simultaneous multiple-fracture propagation as well as fracture-induced strain and strain-rate responses along an offset monitor well. Then a general guideline for fracture-hit detection is proposed based on quantitative analysis of strain/strain-rate responses during multiple-fracture propagation. Finally, a set of field examples are presented to demonstrate the potential of LF-DAS data on hydraulic fracturing monitoring.During multiple-fracture propagation, a “heart-shaped” zone with positive strain rates may be identified for each fracture before the fracture hit. Immediately after the fracture encounters the monitor well, part of the fiber within the fracture path keeps being extended, while the fiber sections off the path become compressed. Three 1D features along the channel (location) axis are designed to detect fracture hits. The features are maximum strain rate, the summation of strain rates, and summation of strain-rate amplitudes. Channels with fracture hits usually exhibit significant peak values of the three features. However, the characteristic signatures can be less detectable when the gauge length is close to the cluster spacing. Connections between fracture-hit locations and cluster perforations clearly reflect the fracture propagation direction. The field examples illustrate the complexity of real LF-DAS signals and demonstrate the adequacy of the proposed guideline for fracture-hit detection with multicluster completion. The fractures propagate nearly perpendicular to the horizontal wellbore in this unconventional shale formation. In addition, four to five fractures out of eight perforation clusters can propagate 396.24 m (1,300 ft) and hit the monitor well, and the “heel-biased” fracture pattern is observed (fractures that do not hit the monitor well are usually close to the toe side). Fracturing fluid leaking off into the previous stage can also be diagnosed, which could negatively affect the completion efficiency.

One Stage Forward or Two Stages Back: What Are We Treating? Identification of Internal Casing Erosion during Hydraulic Fracturing—A Montney Case Study Using Ultrasonic and Fiber-Optic Diagnostics

SummaryPlug-and-perforation (plug-and-perf) multistage hydraulic fracturing completions in unconventional reservoirs rely on complete hydraulic isolation from the previous stage to ensure effective treatment of the active stage. Failure to isolate stages can be a result of partially set plugs, plugs set in wellbore debris or deformed casing, unqualified pressure/temperature rating of plugs, and so on. This paper presents a case study with field examples in which unexpected casing erosion occurred at the setting depths of the dissolvable fracturing (frac) plugs during hydraulic fracturing and subsequently resulted in loss of interstage isolation.A 12-well, four-layer, cube pilot was designed with permanent fiber-optic cable to collect distributed acoustic sensing (DAS), distributed temperature sensing (DTS), and distributed strain sensing (DSS) data as well as downhole pressure gauges for development insight and future completion optimization. The cable was mapped, and oriented perforation techniques placed entry holes opposite the fiber along the wellbore, and no loss of communication was observed during perforating operations. However, fiber-optic signal was lost during hydraulic fracturing operations on one or more stages in all four instrumented horizontal wells. Real-time DAS/DTS analysis indicated the fiber breaks were consistently occurring below the lowermost perforation cluster in the stage, at or very near the frac plug setting depth. Step-down tests were also performed and showed significantly enlarged effective treating area. Based on this observation, post-frac downhole imaging tools were deployed to investigate potential casing and perforation erosion.Downhole imaging data clearly showed the casing was severely eroded at several locations. Additional interrogation of the damage with respect to plug design components indicated that damage always occurred near the plug sealing element. By integrating the analysis of DAS/DTS, step-down tests, and ultrasonic imaging, it was determined that the frac plug bypass was creating a loss of casing integrity at the plug set location. Casing integrity loss resulted in multiple fiber-optic cable breaks and lowered the ability to evenly distribute slurry into treatment clusters. Fiber-optic data analysis showed that 50% of the larger outer diameter (OD) dissolvable frac plugs had bypass compared to 100% bypass for the smaller OD high-expansion, dissolvable plugs.To establish key patterns and identify critical variables that influence stimulation effectiveness, it is important to obtain several different diagnostic data sets and perform an integrated evaluation using all available information. This study also reinforces the need for operators and manufacturers to work together to design and qualify frac plugs against realistic downhole conditions, particularly in areas with potential casing deformation issues. Industry innovation is required to enable fracturing operations to continue through deformed casing. This includes advancing equipment, tools, and techniques for plug-and-perf and other multistage completion methods.

Completion Effects on Diagnosing Multistage Facture Treatments with Distributed Temperature Sensing

Summary Distributed temperature sensing (DTS) is a valuable tool to diagnose multistage hydraulic fracture treatments. When a stage interval is shut in, the clusters that take more fluid during pumping warm up more slowly. Therefore, the fluid volume injected into each cluster can be quantitatively interpreted by numerical inversion of the warm-back temperature behavior. This general concept assumes that the different warm-back behavior is controlled by only the injected fluid volume; however, recent observations of DTS data indicate that completion configurations significantly influence the warm-back behavior. This paper investigates the completion effects on the DTS interpretation. In ideal conditions, when a stage is fractured, the upstream stage intervals should show an almost uniform temperature that is close to the injected fluid temperature. This is due to the high fluid velocity of injected fluid in the wellbore, and the upstream intervals have not been perforated (noncommunicating intervals), so the only heat transfer is heat conduction between the wellbore fluid and the surrounding reservoir. But the field DTS data show considerably irregular variations in temperature along the upstream stage intervals. These variations are caused by the completion effects. The nonuniform temperature profile is caused by different heat transfer behavior induced by completion hardware along the production casing string, such as joints, clamps, and blast protectors, and by the sensing cable location in the cement, as well as the cement quality. Because the varying heat transfer behavior impacts the warm-back behavior as well as the temperature profile, the completion effects need to be considered in DTS interpretation. A method of DTS interpretation considering the completion effects to diagnose multistage fracture treatments was developed. Because the heat transfer between a wellbore and a reservoir depends on the overall heat transfer coefficient describing heat conduction through the completion in a forward model, this parameter needs to be tuned all along the wellbore. To calibrate the completion effect, the temperature inversion is conducted using the temperature measured at a stage interval that is upstream of a stage interval currently being treated. Because the interpreted stage interval is not perforated at that time, the thermal behavior at the noncommunicating interval is governed by only the heat conduction through the completion environment. Once the effective values of the overall heat transfer coefficient are estimated along the interpreted stage interval, they can be assumed to be constant physical parameters. Then, the fluid volume distribution is interpreted by using the effective overall heat transfer coefficient profile along each interval. This study provides a field application of the developed interpretation method. The new interpretation method provides more accurate diagnosis of fracture treatments by DTS interpretation.

A Review of Gas Flow and Its Mathematical Models in Shale Gas Reservoirs

The application of horizontal wells with multistage hydraulic fracturing technologies has made the development of shale gas reservoirs become a worldwide economical hotspot in recent years. The gas transport mechanisms in shale gas reservoirs are complicated, due to the multiple types of pores with complex pore structure and special process of gas accumulation and transport. Although there have been many attempts to come up with a suitable and practical mathematical model to characterize the shale gas flow process, no unified model has yet been accepted by academia. In this paper, a comprehensive literature review on the mathematical models developed in recent years for describing gas flow in shale gas reservoirs is summarized. Five models incorporating different transport mechanisms are reviewed, including gas viscous flow in natural fractures or macropores, gas ad-desorption on shale organic, gas slippage, diffusion (Knudsen diffusion, Fick diffusion, and surface diffusion), stress dependence, real gas effect, and adsorption layer effect in the nanoshale matrix system, which is quite different from conventional gas reservoir. This review is very helpful to understand the complex gas flow behaviors in shale gas reservoirs and guide the efficient development of shale gas. In addition to the model description, we depicted the type curves of fractured horizontal well with different seepage models. From the review, it can be found that there is some misunderstanding about the essence of Knudsen/Fick diffusion and slippage, which makes different scholars adopt different weighting methods to consider them. Besides, the contribution of each mechanism on the transport mechanisms is still controversial, which needs further in-depth study in the future.

Well-Log-Based Velocity and Density Models for the Montney Unconventional Resource Play in Northeast British Columbia, Canada, Applicable to Induced Seismicity Monitoring and Research

AbstractWe present detailed velocity and density models for the Montney unconventional resource play in northeast British Columbia, Canada. The new models are specifically essential for robust hypocenter determination in the areas undergoing multistage hydraulic-fracturing operations and for detailed analysis of induced seismicity processes in the region. For the upper 4 km of the sedimentary structure, we review hundreds of well logs and select sonic and density logs from 19 locations to build the representative models. For depths below 4 km, we extend our models using data from the southern Alberta refraction experiment (Clowes et al., 2002). We provide one set of models for the entire Montney play along with two separated sets for the southern and northern areas. Specifically, the models for the southern and northern Montney play are based on logs located in and around the Kiskatinaw Seismic Monitoring and Mitigation Area and the North Peace Ground Motion Monitoring area, respectively. To demonstrate the usefulness of our detailed velocity model, we compare the hypocenter location of earthquakes that occurred within the Montney play as determined with our model and the simple two-layered model (CN01) routinely used by Natural Resources Canada. Locations obtained by our velocity model cluster more tightly with the majority of events having root mean square residual of <0.2 s compared with that of <0.4 s when the CN01 model is used. Cross sections of seismicity versus depth across the area also show significant improvements in the determination of focal depths. Our model results in a reasonable median focal depth of ∼2 km for events in this area, which is consistent with the completion depths of hydraulic-fracturing operations. In comparison, most solutions determined with the CN01 model have fixed focal depths (0 km) due to the lack of depth resolution.

Machine Learning‐Based Analysis of Geological Susceptibility to Induced Seismicity in the Montney Formation, Canada

AbstractWe analyze data from 6,466 multistage horizontal hydraulic fracturing wells drilled into the Montney Formation over a large region in western Canada to evaluate the impact of geological, geomechanical, and tectonic characteristics on the distribution of hydraulic fracturing‐induced seismicity. Logistic regression was used to obtain a machine learning estimate of the seismogenic activation potential of each well. Our results fit the observed spatial variability, including an enigmatic change in seismicity at 120°W that does not correlate with any change in industrial activity. Feature importance analysis provides insight into data types that have the greatest impact on the results. Based on current data, seismogenic activation potential is most strongly influenced by depth of injection and distance of the well to the Cordilleran thrust belt.

An improved cubic law for shale fracture considering the effect of loading path

Massive multi-stage hydraulic fracturing to form one large-scale stimulated reservoir volume (SRV) with a complex fracture network is a key technique in shale gas development. A natural fracture system may contribute significantly to gas production. Fracture apertures are the key parameter for determining flow characteristics of jointed rock media and changes due to loading and unloading behaviour. In this study, a hydraulic aperture model was proposed to describe aperture variation in a complex loading path with a parabolic function. A numerical study of the hydro-mechanical model was conducted to determine the influences of loading path and nonlinear effects on fluid flow at field scale. In this specific simulation, the total flow volume considering the influence of loading path only decreased by 14%, and considering the influence of loading path decreased by 28%, meanwhile influence of two factors resulted in a 39% reduction of the total flow volume. [Received: July 25, 2018; Accepted: July 3, 2019]

Study on the effect of interface failure between casing and cement sheath on casing stress under non-uniform in-situ stress

The interface failure (micro-annulus and de-bonding) at the first interface between cement sheath and formation, or at the second interface between cement sheath and casing can be easily caused by alternating change of internal pressure and temperature in the casing during large-scale multistage hydraulic fracturing in shale-gas well. It is likely to have a great impact on casing stress and pose a potential threat to casing failure, especially the casing under non-uniform in-situ stress (NUS). Hence, based on the generation mechanism of micro-annulus in the first and second interface, the mechanical model coupling the casing and cement sheath as well as formation under non-uniform in-situ stress is presented with due consideration of the effect of interface failure status on casing stress. In the model, the failure interface with micro-annulus is considered by adopting boundary conditions of smooth contact, and the interface without micro-annulus is considered by adopting boundary conditions of ideal complete contact. The stress and displacement equations are derived by the semi analytical method, and the linear algebra equations and analytical solution of the equations are obtained based on the different contact status. The associated calculating program to calculate stress distribution of casing and cement sheath is developed and programmed. The effects of physical parameter and geometrical parameters of formation, cement sheath and casing, contact status of cement sheath boundary and non-uniformity of in-situ stress on casing stress have been systematically investigated.

Casing deformation mechanisms of horizontal wells in Weirong shale gas field during multistage hydraulic fracturing

Casing deformation during hydraulic fracturing has become a serious issue hindering the development of shale gas in Weirong field. Better understanding of the casing deformation in this field is needed. Field data shows that casing deformations herein are strongly correlated with lithologic interfaces, whilst most deformations occur in the half of wellbore near heel. The lithologic interfaces and stress accumulation by fracturing in stages are considered as main potential inducers of casing deformations in the field of interest. Numerical simulations in two scenarios were conducted to investigate casing deformation mechanisms. The results show that a large stress concentration occurs at the lithologic interface, which can cause casing deformations. The shale swelling induced by interactions between fracturing fluids and clays can intensify the influence of lithologic interfaces. Higher injection pressure and formation pressure, larger difference in formation mechanical properties can increase stress concentration at the lithologic interface. Moreover, simulation results also show that the accumulation of induced stresses from hydraulic fractures increase the maximum principal stress near the wellbore. As more frac stages are pumped, stress accumulation increases, resulting in a continuous increase in maximum principal stress, which can cause casing deformations when it exceeds the casing collapse strength. This can explain nonuniform distributions of casing deformations along the wellbore, which is a general feature of casing deformations in shale horizontal wells. The stress accumulation effect increases with an increase in the injection rate and formation elastic modulus. Finally, some countermeasures were recommended to avoid casing deformations. This study provides new understanding of casing deformations of shale horizontal wells, which can be beneficial to the solutions of casing deformations in the field of interest and other similar shale fields.

Probabilistic statistical model for predicting the effectiveness of hydraulic fracturing

The article studies the effectiveness of single-stage and multi-stage hydraulic fracturing technologies using the mathematical statistics method. The studies are based on the geological and physical characteristics of the Shirotny Priob fields which makes it possible to substantiate the methods for choosing the hydraulic fracturing technology. Based on the probabilistic and statistical analysis of field efficiency data, quantitative criteria for the selection of fracture parameters by length, height and amount of injected propane have been established. They can be used to predict the use of multi-stage and single-stage hydraulic fracturing methods. The productive horizon AS12-3 has a complex geological and physical structure and low filtration and storage properties, which complicates its development and contributes to the active formation of hard-to-recover reserves. The one-stage hydraulic fracturing technology is efficient only for 3-4 years. The multistage hydraulic fracturing technology showed is more efficient in comparison with the single-stage one.

Influence of formation activation induced by fracturing fluid on casing deformation during hydraulic fracturing operation in shale gas wells

Sichuan Basin in China is rich in shale gas resources and has great exploration and development capacity. It is the main area of shale gas exploration and production in China. The proved shale gas reserves discovered by Sinopec in Weirong area exceed 100 billion m3, and they play an important role in the development of shale gas in China. In Sichuan Basin, the use of traditional shale gas production methods such as multi-stage hydraulic fracturing is hampered by serious casing deformation. By December 2019, Sinopec performed hydraulic fracturing operations in 20 wells in this area, where casing deformation was encountered in 10 wells, resulting in an increase of up to 5.69% in the proportion of invalid fracture sections. In order to explain the mechanism of casing deformation during hydraulic fracturing, the geological structures of a shale gas production site in Sichuan Basin with frequent casing deformation were examined, and the geological reasons for this deformation were revealed. In addition, a geological model was established to calculate the influence of formation activation induced by fracturing fluid on the casing load, and formation activation during hydraulic fracturing was studied. The results reported in this paper are of great significance for optimizing hydraulic fracturing parameters and reducing the influence of formation activities on the casing of horizontal wells.

Numerical simulation and evaluation of the fracturing and tight gas production with a new dimensionless fracture conductivity (FCD) model

Hydraulic fracturing is an essential technology for the development of unconventional resources such as tight gas. The evaluation of the fracture performance and productivity is important for the design of fracturing operations. However, the traditional dimensionless fracture conductivity is too simple to be applied in real fracturing operations. In this work, we proposed a new model of dimensionless fracture conductivity (FCD), which considers the irregular fracture geometry, proppant position and concentration. It was based on the numerical study of the multistage hydraulic fracturing and production in a tight gas horizontal well of the North German Basin. A self-developed full 3D hydraulic fracturing model, FLAC3Dplus, was combined with a sensitive/reliability analysis and robust design optimization tool optiSLang and reservoir simulator TMVOCMP to achieve an automatic history matching as well as simulation of the gas production. With this tool chain, the four fracturing stages were history matched. The simulation results show that all four fractures have different geometry and proppant distribution, which is mainly due to different stress states and injection schedule. The position and concentration of the proppant play important roles for the later production, which is not considered in the traditional dimensionless fracture conductivity FCD. In comparison, the newly proposed formulation of FCD could predict the productivity more accurately and is better for the posttreatment evaluation.

A parametric study of hydraulic fracturing interference between fracture clusters and stages based on numerical modeling

Shale oil reservoirs are usually developed by horizontal wells completed with multi-stage hydraulic fractures. The fracture interference between clusters in a single stage and between consecutive stages has an impact on the stimulation quality in terms of fracture geometries and fracture widths. This study introduces a non-planar hydraulic fracture model based on the extended finite element method and its use in quantifying the effects of relevant parameters on multi-stage fracture quality in a realistic shale oil scenario. The numerical model is validated with field diagnostics based on vertical seismic profiling. Relevant parameters including stress contrast, fracturing fluid viscosity, cluster density, and fracturing in consecutive stages are quantitatively analyzed in the numerical study. Results show that effects of stress contrast on fracture quality are greater than those of fracturing fluid viscosity, while the effects are more significant in outer fractures instead of the inner fracture. Denser cluster design leads to greater inhibition for the growth of inner fractures which eventually divert them transversely. In fracturing for consecutive stages, the opening of fractures in the subsequent stages is inhibited and the fracture geometries are also altered by the inter-stage interference caused by the previous stage. Based on field data and numerical modeling, this study identifies key parameters and quantifies their effects on inter-fracture and inter-stage interference in multi-stage hydraulic fracturing in horizontal wells.

Investigation of Multistage Hydraulic Fracture Optimization Design Methods in Horizontal Shale Oil Wells in the Ordos Basin

Based on the analysis of the typical Ordos well groups, this study began with the accurate characterization of the fracture geometry by adopting advanced laboratory experiment methods and monitoring techniques. Then, with the integration of fracture geometry characterization and in situ stress distributions, fracture optimizations of the target wells were performed through numerical simulations methods. Finally, this study established a sweet spot prediction and identification method for long horizontal shale oil wells and constructed a set of optimization design methods for multistage hydraulic fracturing. This investigation revealed that the hydraulic fractures in Chang-7 terrestrial shale oil reservoirs exhibited the belt pattern, and the primary fractures generated the secondary fractures, which activated the natural fractures and induced shear failure. Macroscopic fractures were found to be perpendicular to the direction of the minimum principal stress. Secondary fractures and activated natural fractures were distributed around the primary fracture in the form of fracture types I and II. Multicluster perforation optimization techniques, which were based on shale reservoir classification and evaluation, and aimed at activating multiclusters and determining fracture sweet spots, were developed. These were successfully applied to the field operation and achieved production enhancement performance.

A Comprehensive Model for Estimating Stimulated Reservoir Volume Based on Flowback Data in Shale Gas Reservoirs

Stimulated reservoir volume (SRV) which is generated by horizontal drilling with multistage hydraulic fracturing governs the production in the shale gas reservoirs. Although microseismic data has been used to estimate the SRV, it is high-priced and sometimes overestimated. Additionally, the effect of stress sensitivity on SRV is not considered in abnormal overpressure areas. Thus, the objective of this work is to characterize subsurface fracture networks with stress sensitivity of permeability through the shale gas well production data of the early flowback stage. The flowback regions are first identified with the flowback data of two shale gas wells in South China. Then, we measured the permeability stress sensitivity of the core after fracturing, coupled to the dynamic relative permeability (DRP) calculation to obtain an accurate and simple DRP curve. After that, a comprehensive model is built considering dynamic two-phase relative permeability function and stress sensitivity. Finally, we compared the calculated results with the microseismic data. The results show that the proposed model could reasonably predict the SRV using the flowback data after fracturing. Additionally, compared with the microseismic data, the stress sensitivity should be included, especially in the abnormal overpressure block. It is believed that this mathematical model is accurate and useful. The work provides an efficient approach to estimate stimulated reservoir volume in the shale gas reservoirs.