Fractured Shale Gas Reservoirs Research Articles

Three-dimensional fracture space characterization and conductivity evolution analysis of induced un-propped fractures in shale gas reservoirs

Huge numbers of induced unpropped (IU) fractures are generated near propped fractures during hydraulic fracturing in shale gas reservoirs. But it is still unclear how their fracture space and conductivity evolve under in-situ conditions. This paper prepares three types of samples, namely, manually split vertical/parallel to beddings (MSV, MSP) and parallel natural fractures (NFP), to represent the varied IU fractures as well as their surface morphology. Laser scan and reconstruction demonstrate that the initial fracture spaces of MSVs and MSPs are limited as the asperities of newly created surfaces are well-matched, and the NFPs have bigger space due to inhomogeneous geological corrosion. Surface slippage and consequent asperity mismatch increase the fracture width by several times, and the increase is proportional to surface roughness. Under stressful conditions, the slipped MSVs retain the smallest residual space and conductivity due to the newly sharp asperities. Controlled by the bedding structures and clay mineral hydrations, the conductivity of MSPs decreases most after treated with a fracturing fluid. The NFPs remain the highest conductivity, benefitting from their dispersive, gentle, and strong asperities. The results reveal the diverse evolution trends of IU fractures and can provide reliable parameters for fracturing design, post-fracturing evaluation, and productivity forecasting.

Evolution of the damage precursor based on the felicity effect in shale

Damage precursors during hydraulic fracturing in shale gas reservoirs may be better understood if the deformation, failure, and acoustic emission (AE) characteristics under cyclic loading are known. Therefore, the purpose of this paper is to investigate the quantitative damage based on the Felicity effect under constant stress lower limit uniaxial cyclic loading-unloading rates (0.5, 1.0, 1.5, 2.0, and 2.5 kN/s). Variations in the b-value and the spatiotemporal evolution of cumulative AE were also used to observe how shale fractures formed. The findings reveal that during the unloading stage, there are many cumulative AE events when the stress level is low (≤1.50 kN/s) but that this number drops significantly when the stress level increases above (>2.0 kN/s). The AE amplitude, AE counts, and cumulative AE energy of each cycle in a loading-unloading test show an increasing trend, but the rate increases in the last cycle. During the whole process of loading and unloading, the Kaiser effects were present in the 3rd cycle at stress levels (≤1.5 kN/s). Still, the Felicity effect appeared in the 2nd and 1st cycles during 2.0 and 2.5 kN/s cyclic loading. The Kaiser effect occurs in the linear elastic stage, while the Felicity effect occurs in the crack initiation and crack damage stage. Furthermore, the Felicity ratio (FR) variations during shale deformation and failure can be divided into four phases: (Phase I = 1.01 ≥ FR > 0.89), (Phase II = 0.89 ≥ FR > 0.48), (Phase III = 0.48 ≥ FR > 0.23), and (Phase IV = FR ≤ 0.23). The b-value is relatively higher under the loading rate below (≤1.50 kN/s), indicating an increase in the number of small AE events. In contrast, the fact that the b-value is relatively smaller under the loading rate above (>2.0 kN/s) indicates that, the number of large AE events increases the number of cracks and fractures. These findings provide important design references for damaged precursors during hydraulic fracturing in shale gas reservoirs.

Prediction of fractures by using the stress field in medium to deep shale gas reservoirs: A case study of Late Ordovician–early Silurian shale gas reservoirs in the Nanchuan region, South China

Containing representative shale gas reservoirs, the Wufeng–Longmaxi Formations in the Nanchuan region in South China have been modified by three compressional tectonic movements (in the Late Jurassic to Early Cretaceous, Late Cretaceous, and Cenozoic to present). These movements formed deeply buried reservoirs with complex in situ stresses and rapid directional changes, influencing the state of shale gas reservoirs fractures. Numerical modeling applied to model the stress field in the three periods showed that the maximum compressive horizontal principal stress (σHmax), strain rate, and fault slip rate regimes transformed from a thrust and strike-slip regime to a thrust and strike-slip regime to a thrust regime. The σHmax direction changed from NW–SE and WNW–ESE to WNW–ESE and nearly E–W and then to multiple directions. The magnitude of strain rate changed from -16 ∼ -15 to -17.7 ∼ -15.6 to -18.8 ∼ -15.8. The fault slip rate changed from 0 to 0.029 mm/a to 0–0.0026 mm/a to 0–0.0012 mm/a. These data strongly agree with data from drilled wells and outcrops and show that the present-day stress field is the superposed effect of multistage movements. Semiquantitative research was conducted on shale gas fracture openness and fracture development. Fracture openness is favorable when the angle between the σHmax direction and nearby faults is ≤45° and the distance from the fault is >2 km, and fracture development is favorable when the magnitude of the strain rate is <-17.6 and the fault slip rate is <0.00036 mm/a. Accordingly, we predicted fractured shale gas reservoirs.

Optimization method of refracturing timing for old shale gas wells

Based on the elastic theory of porous media, embedded discrete fracture model and finite volume method, and considering the micro-seepage mechanism of shale gas, a fully coupled seepage-geomechanical model suitable for fractured shale gas reservoirs is established, the optimization method of refracturing timing is proposed, and the influencing factors of refracturing timing are analyzed based on the data from shale gas well in Fuling of Sichuan Basin. The results show that due to the depletion of formation pressure, the percentage of the maximum horizontal principal stress reversal area in the total area increases and then decreases with time. The closer the area is to the hydraulic fracture, the shorter the time for the peak of the stress reversal area percentage curve to appear, and the shorter the time for the final zero return (to the initial state). The optimum time of refracturing is affected by matrix permeability, initial stress difference and natural fracture approach angle. The larger the matrix permeability and initial stress difference is, the shorter the time for stress reversal area percentage curve to reach peak and return to the initial state, and the earlier the time to take refracturing measures. The larger the natural fracture approach angle is, the more difficult it is for stress reversal to occur near the fracture, and the earlier the optimum refracturing time is. The more likely the stress reversal occurs at the far end of the artificial fracture, the later the optimal time of refracturing is. Reservoirs with low matrix permeability have a rapid decrease in single well productivity. To ensure economic efficiency, measures such as shut-in or gas injection can be taken to restore the stress, and refracturing can be implemented in advance.

Characterization of Horizontal Fractures in Shale Gas Reservoirs Using a Rock-Physics-Based Method Integrated With SA-PSO Algorithm and CNN

Characterization of Horizontal Fractures in Shale Gas Reservoirs Using a Rock-Physics-Based Method Integrated With SA-PSO Algorithm and CNN

Research on the Capacity of Shale Fracture Network based on Fractal Dimension

The quantitative evaluation method of fracture network capacity after shale fracturing is crucial for optimizing hydraulic fracturing of shale gas reservoirs and improving shale gas recovery. In order to quantitatively evaluate the shape of the shale fracture network after fracturing, the mud shale cores from the Longmaxi Formation were taken to carry out the constant-rate strain method fracturing pressure experiment. The fracture information of the two-dimensional lateral development surface after the core is compressed, and the surface fracture rate, concentrative value and fractal dimension of the fractures after compression are calculated. Through multiple linear regression, it is found that the fractal dimension is positively correlated with the surface fracture rate, which describes the number of fractures, and the concentrative value, which describes the spatial distribution of fractures, and the former has a greater impact on the size of the fractal dimension. Considering the above parameters comprehensively, a fracture network capacity evaluation model is established, which is in good agreement with the rock mechanical characteristics reflected by the strain-stress curve and the reconstructed three-dimensional fracture morphological characteristics. It has a certain guiding significance for shale brittleness research and fractability evaluation.

Intelligent identification and real-time warning method of diverse complex events in horizontal well fracturing

The existing approaches for identifying events in horizontal well fracturing are difficult, time-consuming, inaccurate, and incapable of real-time warning. Through improvement of data analysis and deep learning algorithm, together with the analysis on data and information of horizontal well fracturing in shale gas reservoirs, this paper presents a method for intelligent identification and real-time warning of diverse complex events in horizontal well fracturing. An identification model for “point” events in fracturing is established based on the Att-BiLSTM neural network, along with the broad learning system (BLS) and the BP neural network, and it realizes the intelligent identification of the start/end of fracturing, formation breakdown, instantaneous shut-in, and other events, with an accuracy of over 97%. An identification model for “phase” events in fracturing is established based on enhanced Unet++ network, and it realizes the intelligent identification of pump ball, pre-acid treatment, temporary plugging fracturing, sand plugging, and other events, with an error of less than 0.002. Moreover, a real-time prediction model for fracturing pressure is built based on the Att-BiLSTM neural network, and it realizes the real-time warning of diverse events in fracturing. The proposed method can provide an intelligent, efficient and accurate identification of events in fracturing to support the decision-making.

Brittleness index prediction using modified random forest based on particle swarm optimization of Upper Ordovician Wufeng to Lower Silurian Longmaxi shale gas reservoir in the Weiyuan Shale Gas Field, Sichuan Basin, China

The right placement of fractures helps to enhance gas production in shale gas reservoirs. One parameter that helps to determine the target layers to place hydraulic fractures is the Brittlenex index (BI). However, no universal and appropriate methods can be used to compute BI, with all established correlations being used under different conditions. This paper uses machine learning (ML) methods to predict the BI of Upper Ordovician Wufeng to Lower Silurian Longmaxi formation in the Weiyuan shale gas field, Sichuan Basin, China. Random forest based on particle swarm optimization (PSO-RF) was utilized for the first time to predict BI due to its ability to capture nonlinear relationships between many variables in the dataset, thus giving more accurate results than other models. Collected secondary data from the WY1 well were used for training, whereas WY2 well data were used for testing. The results revealed that PSO-RF outperformed Extreme gradient boosting (XGBoost), Light gradient boosting machine (LightGBM), and K-nearest neighbor (KNN) in predicting BI with high accuracy and minimum errors during training and testing. PSO-RF coefficient of determination (R2), root mean square error (RMSE), and mean absolute errors (MAE) after training and testing were 0.9934 and 0.9533,4.6327 and 15.5308,2.0974 and 5.3896, respectively. In addition, the best-developed PSO-RF model was used to predict BI in WY3 and WY4 wells for model results validation; it was found that the model predicted the BI with high accuracy. This confirms that the developed model can be used to predict the BI of new development wells without depending on laboratory measurements, which are expensive and time-consuming to compute; thus, the developed model can be adopted as an alternative technique to determine the sweet spot for hydraulic fracturing in shale gas reservoirs to enhance gas production.

Simulation and optimization of fracture pattern in temporary plugging fracturing of horizontal shale gas wells

Horizontal well-staged fracturing is a key technology for efficient shale gas production. However, stress shadows between clusters make it difficult to synchronize the initiation and expansion of hydraulic fractures in multi-cluster fracturing. Mine practice has shown that the use of temporary plugging fracturing can promote the balanced expansion of the multi-fractures. This study establishes a numerical model for fracture-opening temporary plugging fracturing based on the three-dimensional discrete lattice method. Then, the impacts of perforation cluster spacing, stress difference, temporary plugging timing, amount of temporary plugging balls (TPBs), and temporary plugging times on the expansion pattern of multi-fractures were simulated. Additionally, the effectiveness of temporary plugging was further verified by laboratory experiments and mine site experiments. The result shows that, decreasing the cluster spacing can significantly increase the extension range of hydraulic fractures, but the uneven propagation of fractures is severe. Meanwhile, the fracture volume differentiation coefficient gradually increased with the increase of the stress difference. When the temporary plugging timing is 2/3 of the overall fracturing duration, the fracture clusters expand evenly and the fracture volume differentiation coefficient reaches the minimum value. Moreover, as the quantity of TPBs increases, the fracture volume differentiation coefficient first decreases and then increases. Finally, to increase the effectiveness of temporary plugging fracturing, the times of temporary plugging should be minimized. The results of this research can help optimize temporary plugging fracturing in shale gas reservoirs.

Identification of natural fractures in shale gas reservoirs using fracture signature function and machine learning models

Identifying fractures is important for optimizing recovery and enhancing oil recovery techniques. Identifying natural fractures using FMI and cores is expensive and unavailable for all wells. Therefore, predictive models based on conventional wireline logs are necessary. Extreme Gradient Boosting, Decision tree, Random Forest, Support Vector Machine, Feed Forward Neural Network, and Recurrent Neural Network were applied to identify natural fractures. This study uses well logs to develop a new Fracture Signature Function equation for determining natural fractures in the shale reservoir. This unsupervised approach requires no special image log to identify natural fractures. However, the class imbalance problem between the fracture and non-fractured zone often restricts the accuracy of the machine learning models, which require a predictive model not dependent upon the special logs and class imbalance problems in the prediction of fractured zones. Synthetic Minority Oversampling (SMOTE) and Random Oversampling (ROS) were applied to solve the class imbalance problem in the data. The results show that the machine learning models did not predict the fracture and non-fracture zones with acceptable accuracy even after applying SMOTE and ROS. Relative to all machine learning models, Random Forest predicted the results with the highest accuracy of 91 % and F1-Score of 17.6 %. The Fracture Signature Function (FSFn'') predicted the natural fractures with high accuracy except in zones with very complex borehole environments. A Forward Neural Network is more efficient in identifying fracture and non-fractured zones in imbalance class problems of the dataset. The Recurrent Neural Network's predictions were biased toward the major class related to the non-fractured zone of the studied interval. The newly developed equation can be used for natural fracture identification in drilling and production strategy design by using the easily available well-log data in class imbalanced conditions.

Reservoir Space Characterization of Ordovician Wulalike Formation in Northwestern Ordos Basin, China

The Ordovician Wulalike Formation in the northwestern Ordos Basin is a new prospect for exploring marine shale gas in China, facing prominent problems such as unclear reservoir conditions and the distribution of enrichment areas. The types of reservoir space, fracture development, porosity composition, and physical properties of the lower Wulalike Formation are discussed through the multi-method identification and quantitative evaluation of reservoir space for appraisal wells. The Wulalike Formation in the study area contained fractured shale reservoirs with matrix pores (mainly inorganic pores) and permeable fractures. The fracture system of the lower Wulalike Formation is dominated by open bed-parallel fractures that are intermittent or continuous individually, with a width of 0.1–0.2 mm and spacing of 0.5–14.0 cm. The fracture-developed intervals generally exhibit bimodal or multimodal features on NMR T2 spectra and have a dual-track feature with a positive amplitude difference in deep and shallow resistivity logs. The length and fracture porosity of fracture-developed intervals varied greatly in different parts of the study area. In the Majiatan-Gufengzhuang area in the southern part of the study area, the fracture development degree generally decreased from west to east. In the Shanghaimiao area in the central part of the study area, fractures were extremely developed, the continuous thickness of the fracture-developed interval was generally more than 20 m, and the average fracture porosity was higher than 1.3%. In the Tiekesumiao area in the northern part of the study area, the fracture development degree was generally lower than that in the central and southern parts of the study area and also showed a decreasing trend from west to east. The lower Wulalike Formation had a total porosity of 2.46–7.08% (avg. 4.71%), roughly similar to the Longmaxi Formation in the Sichuan Basin, of which matrix porosity accounts for 34.0–90.0% (avg. 61.1%) and fracture porosity accounts for 10.0–66.0% (avg. 38.9%). From this, it could be inferred that the shale gas accumulation type of the lower Wulalike Formation in the northwest margin of the basin is mainly a fractured shale gas reservoir controlled by structure, and its “sweet spot area” is mainly controlled by tectonic setting and preservation conditions. This indicates that the Wulalike Formation in the northwestern Ordos Basin has good shale gas exploration prospects, and a large number of fault anticlines or fault noses formed by reverse dipping faults have the potential of favorable exploration targets.

Frac-Hit Prevention Countermeasures in Shale Gas Reservoirs with Natural Fractures

The development of natural fractures (NFs) in shale gas reservoirs is conducive to improving the productivity of shale gas wells. However, NF development leads to high-frequency frac hits between the infill and parent wells, which critically restricts its efficiency. To elucidate the large contribution of hydraulic fractures (HFs) and NFs in frac hits during the production and the development of NF-developed shale gas reservoirs, such reservoirs in the WY area of western China are taken as an example. A total of 197 frac hits well events in this area are systematically classified via the frac-hit discrimination method, and the effects of different factors on HF- and NF- dominated frac hits are classified and studied. Combined with the correlation analysis method and the chart method, the main controlling factors affecting the two types of frac hits are determined, and the corresponding frac-hit prevention countermeasures are proposed. The research demonstrates that (1) the distribution and development of NFs are crucial to production after frac hits. NFs and HFs in the WY area cause 51% and 49%, respectively, of the frac hits. (2) The main controlling factors in NF-dominated frac hits are the approximation angle, fracture linear density, and horizontal stress difference, whereas they are net pressure in fractures, horizontal stress difference, and liquid strength in HF-dominated frac hits. Sensitivity analysis shows that the NF activation difficulty coefficient fluctuates between −35.1% and 47.6%, and the maximum hydraulic fracture length fluctuates between −43.5% and 25.29%. (3) The corresponding frac-hit prevention countermeasures are proposed for the two types of formation mechanisms from different approaches, including frac-hit risk assessment and path planning, production well pressurization and stress diversion, and infill-well fracturing parameter optimization. This paper not only provides a reference for exploring the formation mechanism of frac hits in fractured shale gas reservoirs but also a theoretical basis for the corresponding frac-hit prevention countermeasures.

Numerical simulation of deflagration fracturing in shale gas reservoirs considering the effect of stress wave impact and gas drive

Methane deflagration fracturing is a new reservoir stimulation method that serves the efficient development of shale gas reservoirs. However, the propagation law of deflagration fractures is still unclear. In this paper, a numerical model considering the effect of stress wave impact and gas drive of deflagration fracturing was established based on the continuum–discontinuum element method (CDEM). The correctness of the numerical model was verified by comparing it with a laboratory experiment, the steady and unsteady analytical solutions of gas flow, and the approximate solution of fracture propagation. Then, numerical simulations of methane deflagration fracturing in vertical wells and horizontal wells under different factors were carried out to analyze the fracture mechanism. The results indicate that deflagration fracturing in vertical wells can break through the stress concentration around the borehole; the initial radial fractures are formed under the action of stress wave impact and then propagate substantially under the driving action of high-pressure gas. The in-situ stress difference affects the deflagration fracture propagation and makes the half-fracture length in the direction of maximum principal stress larger than that in the direction of minimum principal stress. The more significant the stress difference is, the more noticeable this deviation will be. When the deflagration peak pressure is high, the reservoir burst degree is large, which is conducive to enlarging the stimulation range of deflagration fracturing. Staged deflagration fracturing in horizontal wells can form 5–8 obvious fractures perpendicular to the horizontal borehole in each explosion section. A large cluster spacing and explosion section length are conducive to expanding the stimulation scope. Moreover, the propagation of deflagration fractures will be induced by the natural fractures, and the natural fracture with a considerable length or a slight angle between the dip angle and the propagation direction of deflagration fractures is more likely to be activated.

Sensitivity Analysis of Geomechanics Influence on The Success of Hydraulic Fracturing in Shale Gas Reservoir

Shale gas has a permeability of &lt;0.1 mD and a porosity of around 2% - 8% to produce gas that rises to the surface through hydraulic fracturing and horizontal drilling. Geomechanics is one of the important factors that influence the success of a hydraulic fracturing job. Technology in fractures makes geomechanics a clear factor in predicting the success or failure of rocks in deformation and knowing the properties that will be faced by fracture fluids which will later be used to see the effectiveness of fracture fluids in resisting fractures. High operational costs need to be studied further to determine the parameters that affect hydraulic fracturing work, especially from the geomechanical aspect to minimize production failures and work safety. The research conducted this time focuses on the sensitivity of geomechanical parameters by using CMG (GEM) reservoir simulations for reservoir models and conducting Response Surface Methodology (RSM) in selection and ease when applied in the field prior to the hydraulic fracturing process. In this sensitivity study carried out on 5 parameters namely stress, Poisson's ratio, Young's modulus, biot coefficient, and pore pressure. The geomechanical parameter that has the most influence on hydraulic fracturing work based on the sensitivity results carried out through 500 data sets using the Analysis of Variance obtained R2 = 0.99 with the results based on the importance value of the pore pressure variable of 3.8. Then Young's modulus is 0.28, stress is 0.12, Poisson's ratio is 0.08, and biot coefficient is 0.04.

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

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

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

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

A Multi-medium and Multi-mechanism model for CO2 injection and storage in fractured shale gas reservoirs

Under the background of “dual-carbon”, it is strategically significant to use shale gas reservoirs for CO2 injection and storage. Injection of CO2 into shale formations can improve natural gas recovery and achieve effective storage of CO2. However, due to the complex characteristics of shale reservoirs, like complex fractures and a variety of flow mechanisms, few work has been done to comprehensively consider those complex characteristics for accurate reservoir simulation of CO2 injection and storage. Therefore, to improve this situation, this paper establishes a fully coupled model of the matrix, natural fracture and hydraulic fracture, which considers multiple mechanisms, including adsorption/desorption, diffusion, stress sensitivity of fracture and stimulated reservoir volume (SRV). The embedded discrete fracture model (EDFM) is applied to describe the transfer flow between matrix-fracture, fracture-fracture and fracture-well. The finite volume and quasi-Newton iterative methods are used to solve the model. The model's reliability and practicability are verified by matching the production history of commercial software in shale gas reservoirs. The effects of various factors on the production curve and CO2 storage characteristics are analyzed, including adsorption/desorption, diffusion, stress sensitivity, well production pressure, CO2 injection rate, CO2 injection opportunity and fracture parameters. The results show that the model is reliable and practical and can be used to study the dynamic performances of enhanced shale gas recovery and CO2 storage.

Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments

Fracturing fluids are widely applied in the hydraulic fracturing of shale gas reservoirs, but the fracturing fluid flowback efficiency is typically less than 50%, severely limiting the shale gas recovery. Additionally, the mechanism and main influencing factors of fracturing fluid flowback are unclear. In this study, microscopic experiments are conducted to simulate the fracturing fluid flowback progress in shale gas reservoirs. The mechanism and factors affecting fracturing fluid flowback/retention in the fracture zone were analyzed and clarified. Results show that the ultimate flowback efficiency of fracturing fluid is positively correlated with the fracturing fluid concentration and the gas driving pressure difference. There are four kinds of mechanisms responsible for fracturing fluid retention in the pore network: viscous resistance, the Jamin effect, the gas blockage effect and the dead end of the pore. Additionally, the ultimate flowback efficiency of the fracturing fluid increases linearly with increasing capillary number. These insights will advance the fundamental understanding of fracturing fluid flowback in shale gas reservoirs and provide useful guidance for shale gas reservoirs development.

Key issues and explorations in shale gas fracturing

During volume fracturing of shale gas reservoirs, hydraulic fractures may readily communicate with natural fractures to propagate forward and induce the formations to slip along the fracture surfaces. The resulted inter-well frac-hit and casing deformation affect the safe and efficient operation of shale gas fracturing. In addition, unpropped fractures caused by small natural fracture width lead to deteriorating fracture conductivity, which in turn impacts the stimulation effect of shale gas reservoirs. This paper discusses the three key issues, i.e. inter-well frac-hit, casing deformation and unpropped microfractures, that impact the economic exploration and exploitation of shale gas, and proposes engineering prevention and control measures through literature review and research on mechanism by integrating theoretical and experimental analysis, which have been applied on site. Firstly, after clarifying the mechanism and main controlling factors of inter-well frac-hit, an evaluation model and prediction method of frac-hit based on machine learning were established. The measures for preventing and controlling inter-well frac-hit, including temporary plugging at fracture tip and shut-in of old wells, were determined after evaluation with the well-cluster fracture model. Secondly, an analysis model of casing deformation caused by fracture shear and slippage was established after stress analysis. According to the analysis of stress on casing intersected with fractures during fracturing, it is ascertained that increase of fluid pressure within natural fractures is the main factor that causes casing deformation. The methods for preventing casing deformation were proposed in terms of fracturing operation and well construction. Thirdly, the mechanism of micro-proppant migration was analyzed by integrating the model of particle migration and the transport experiment in large-scale plate, and the experiment confirms that micro-proppant can effectively improve the fracture conductivity. It is concluded after field application that the prevention and control measures proposed for inter-well frac-hit and casing deformation can mitigate frac-hit and casing deformation significantly, and micro-proppants are conducive to improving post-frac shale gas production. The measures provide a support for large-scale and economic development of deep shale gas.

Simulation study of micro-proppant carrying capacity of supercritical CO2 (Sc-CO2) in secondary fractures of shale gas reservoirs

Micro-proppants with stronger portability have more potential to migrate to the massive micro-sized secondary fractures (SFs) or natural fractures activated by supercritical CO2 (Sc-CO2) fracturing in shale gas reservoirs. However, the transportation behaviour of micro-proppants in massive SFs has been scarcely studied to date. In this study, we report the simulation of micro-proppant migration across a fracture intersection during Sc-CO2 fracturing based on a combination of computational fluid dynamics and the discrete element method. A straight fracture intersection model was first validated against experimental data from an earlier study. Next, the influential factors, including fluid viscosity, cross angle, proppant diameter, fluid velocity and the ratio of proppant diameter to SF, were examined in the transportation behaviour of micro-proppants in Sc-CO2 fracturing. The results show that the poor proppant distribution in SFs is dominated by the ultralow viscosity of Sc-CO2, but the decrease of proppant diameter to 25 μm presents slurry flow behaviour, resulting in a migration distance around 8 times longer than that of 200 μm and much stronger proppant-carrying capacity into SFs. The transportation behaviour of micro-proppants into SFs depends on the suspended proppants concentration and the rolling proppants from the proppant embankment in the primary fracture (PF), determined by the combined effects of different factors. Fast fluid velocity of 0.2 m/s increases the priority of the proppant embankment formation in SFs. Cross angles greater than 45° limit the suspended proppants in SF, and the proppant embankment in the SF dominantly depends on rolling proppants from PF. Greater SF aperture facilitates proppants transportation into the SF due to the reduced bridging effect, but not into the PF. The key findings are optimized proppant-carrying capacity into SFs and improved stimulated volume during Sc-CO2 fracturing in shale reservoirs.