Fractured Shale Reservoirs Research Articles

Analysis of Multi-Fracture Extension Pattern of Horizontal Wells in Shale Reservoirs under Natural Fracture Perturbation

There are many natural fractures in shale reservoirs, changes in hydraulic fracture extension patterns. In the paper, a multi-fracture extension finite element model for horizontal wells in shale reservoirs under the disturbance of natural fractures is established by combining the actual geological parameters and construction parameters of a horizontal well multi-fracturing operation in X oilfield to analyze the effects of the difference in geostress, elastic modulus, angle of natural fractures, and the number of natural fracture groups on the hydraulic fracture extension. The results show that with the increase in ground stress difference and natural fracture angle, hydraulic fractures are more likely to penetrate the natural fractures; with the increase in elastic modulus, the fracture stress and tip stress increase, the volume of rupture unit, the fracture extension width and the pore pressure concentration area decrease, and it is easy to form a long and narrow fracture; with the increase in the number of fracture groups, the connectivity of reservoir fractures increases, the extension of fractures is stronger, and it is easier to form a complex fracture network.

Exploring pore-scale production characteristics of oil shale after CO2 huff ‘n’ puff in fractured shale with varied permeability

Recent studies have indicated that the injection of carbon dioxide (CO2) can lead to increased oil recovery in fractured shale reservoirs following natural depletion. Despite advancements in understanding mass exchange processes in subsurface formations, there remains a knowledge gap concerning the disparities in these processes between the matrix and fractures at the pore scale in formations with varying permeability. This study aims to experimentally investigate the CO2 diffusion behaviors and in situ oil recovery through a CO2 huff ‘n’ puff process in the Jimsar shale oil reservoir. To achieve this, we designed three matrix-fracture models with different permeabilities (0.074 mD, 0.170 mD, and 0.466 mD) and experimented at 30 MPa and 91 °C. The oil concentration in both the matrix and fracture was monitored using a low-field nuclear magnetic resonance (LF-NMR) technique to quantify in situ oil recovery and elucidate mass-exchange behaviors. The results showed that after three cycles of CO2 huff ‘n’ puff, the total recovery degree increased from 30.28% to 34.95% as the matrix permeability of the core samples increased from 0.074 to 0.466 mD, indicating a positive correlation between CO2 extraction efficiency and matrix permeability. Under similar fracture conditions, the increase in matrix permeability further promoted CO2 extraction efficiency during CO2 huff ‘n’ puff. Specifically, the increase in matrix permeability of the core had the greatest effect on the extraction of the first-cycle injection in large pores, which increased from 16.42% to 36.64%. The findings from our research provide valuable insights into the CO2 huff ‘n’ puff effects in different pore sizes following fracturing under varying permeability conditions, shedding light on the mechanisms of CO2-enhanced oil recovery in fractured shale oil reservoirs.

Multiscale Model for Hydrogen Transport and Storage in Shale Reservoirs

Summary Utilizing underground geological structures for hydrogen storage is an effective approach for energy transformation. The depleted shale reservoirs can be considered as promising options for large-scale hydrogen storage because of the vast storage capacity, high containment security, and low operation cost. However, it is challenging to characterize the hydrogen transportation mechanism and estimate hydrogen storage potential in shale formations from multiscale perspectives. In this paper, we propose a multiscale model for hydrogen transport and storage in partially depleted hydraulically fractured shale reservoirs, considering the effects of gas diffusion, adsorption, slip flow, and continuous flow. By the Laplace transformation and Pedrosa substitution, a computationally effective semi-analytical solution was derived and validated with a commercial numerical simulator. A hydrogen storage capacity (HSC) assessment workflow is proposed using a typical shale reservoir in the Appalachian Basin as a case study. The results indicate that the storage capacity can reach up to 31.92×108 m3 at a high constrained injection pressure. In addition, the HSC is strongly controlled by the adsorption property, diffusion coefficient, shale composition, flow capacity between different scale media, and mobility ratio. The influence of most reservoir parameters on storage potential is negligible at low constrained pressure but critical at high constrained pressure. Such a model can be used as a robust pressure predictor and storage capacity estimator for hydrogen storage projects in partially depleted shale reservoirs.

Research on fracture propagation of hydraulic fracturing in a fractured shale reservoir using a novel CDEM-based coupled HM model

Shale reservoirs are usually buried deep, and contain lots of complex natural fractures (NFs) under the influence of tectonic stress and faults. Previous studies usually focus on small-scale reservoir models and there is also a lack of research that completely focuses on NF characteristics. Using the continuous-discontinuous element method (CDEM), a Hydro-Mechanical (HM) coupling model was constructed to explore the propagation mechanism of hydraulic fracture (HF) and the effects of NF characteristics on HF propagation. The results show that as the HF approaches the NFs, the NFs preferentially tend to undergo shear failure, resulting in a decelerated HF propagation rate and an increased injection pressure. After water enters the NFs, the HF rapidly propagates, so the fracture area swiftly increases and the HF has a more tortuous fracture morphology. The NF orientation (α) and the internal friction angle (φ) exhibit a pronounced and distinct effect on HF propagation. Specifically, when α is 30°∼60°, the HF propagation is more tortuous and complex, so it is easier to form a larger transverse reconstruction range. When the NF density (η) is no less than 0.12, the HF tends to open the NFs and form a more tortuous morphology, but a higher η does not necessarily imply a higher fracture complexity. A longer NF (l > 12 m) benefits to improve the longitudinal reservoir reconstruction scope, but has little impact on the overall reconstruction effect. In the presence of stress shadow effect, it is improbable for the HF to completely open the intersecting NFs; instead, it typically opens only a segment or one of them. Consequently, it may be challenging to establish a fracture network with the simultaneous development of primary and branching fractures. Additionally, some water leakage into the inactive NFs gives rise to a decline in both the fracture length and fracture area. The findings can offer theoretical insights for refining the fracturing design in shale reservoirs with NFs.

A multi-mechanism numerical simulation model for CO2-EOR and storage in fractured shale oil reservoirs

Under the policy background and advocacy of carbon capture, utilization, and storage (CCUS), CO2-EOR has become a promising direction in the shale oil reservoir industry. The multi-scale pore structure distribution and fracture structure lead to complex multiphase flow, comprehensively considering multiple mechanisms is crucial for development and CO2 storage in fractured shale reservoirs. In this paper, a multi-mechanism coupled model is developed by MATLAB. Compared to the traditional Eclipse 300 and MATLAB Reservoir Simulation Toolbox (MRST), this model considers the impact of pore structure on fluid phase behavior by the modified Peng–Robinson equation of state (PR-EOS), and the effect simultaneously radiate to Maxwell–Stefan (M–S) diffusion, stress sensitivity, the nano-confinement (N-C) effect. Moreover, a modified embedded discrete fracture model (EDFM) is used to model the complex fractures, which optimizes connection types and half-transmissibility calculation approaches between non-neighboring connections (NNCs). The full implicit equation adopts the finite volume method (FVM) and Newton–Raphson iteration for discretization and solution. The model verification with the Eclipse 300 and MRST is satisfactory. The results show that the interaction between the mechanisms significantly affects the production performance and storage characteristics. The effect of molecular diffusion may be overestimated in oil-dominated (liquid-dominated) shale reservoirs. The well spacing and injection gas rate are the most crucial factors affecting the production by sensitivity analysis. Moreover, the potential gas invasion risk is mentioned. This model provides a reliable theoretical basis for CO2-EOR and sequestration in shale oil reservoirs.

Multi-Fracture Propagation Considering Perforation Erosion with Respect to Multi-Stage Fracturing in Shale Reservoirs

Shale gas is considered a crucial global energy source. Hydraulic fracturing with multiple fractures in horizontal wells has been a crucial method for stimulating shale gas. During multi-stage fracturing, the fracture propagation is non-uniform, and fractures cannot be induced in some clusters due to the influence of stress shadow. To improve the multi-fracture propagation performance, technologies such as limited-entry fracturing are employed. However, perforation erosion limits the effect of the application of these technologies. In this paper, a two-dimensional numerical model that considers perforation erosion is established based on the finite element method. Then, the multi-fracture propagation, taking into account the impact of perforation erosion, is studied under different parameters. The results suggest that perforation erosion leads to a reduction in the perforation friction and exacerbates the uneven propagation of the fractures. The effects of erosion on multi-fracture propagation are heightened with a small perforation diameter and perforation number. However, reducing the perforation number and perforation diameter remains an effective method for promoting uniform fracture propagation. As the cluster spacing is increased, the effects of erosion on multi-fracture propagation are aggravated because of the weakened stress shadow effect. Furthermore, for a given volume of fracturing fluid, although a higher injection rate is associated with a shorter injection time, the effects of erosion on the multi-fracture propagation are more severe at a high injection rate.

Carbon Storage Potential of Shale Reservoirs Based on CO2 Fracturing Technology

The development of shale reservoirs is important in ensuring China’s national energy security by achieving energy independence. Among the key technologies for shale oil production, CO2 fracturing is an effective method that can not only enhance oil recovery but also promote large amounts of CO2 storage, thereby supporting China’s goals of achieving a carbon peak and carbon neutrality. This research paper aims to study the impacts and prospective applications of CO2 fracturing in shale reservoirs, using real exploitation parameters from the GYYP1 well in the Songliao Basin. By utilizing numerical simulation, the dynamics of CO2 production are analyzed. Adsorption and diffusion are identified as pivotal mechanisms for CO2 storage in shale reservoirs. After the analysis of the fracturing process, approximately 22.13% of CO2 is found to be adsorbed, which decreases to 11.06% after ten years due to pressure decline. Diffusion increases the volume of CO2 interacting with a greater extent of shale, thereby enhancing the adsorption mechanism. Over time, the diffusion process results in a remarkable increase of 26.02% in CO2 adsorption, ensuring the long-term and stable storage of CO2 within the shale reservoir. This investigation delves into the contribution of these two crucial mechanisms of CO2 storage in shale reservoirs, ultimately predicting that, by 2030, approximately two million tons of CO2 can be effectively stored in the Daqing Oilfield through CO2 fracturing in shale oil reservoirs. Such an achievement will undoubtedly contribute to the sustainable development of the energy sector and foster the transformation and upgrading of China’s energy structure.

Numerical simulation of CO2-enhanced oil recovery in fractured shale reservoirs using discontinuous and continuous Galerkin finite element methods

Introduction: This study explores the potential of enhancing shale oil recovery and reducing CO2 emissions through CO2 injection in fractured shale reservoirs. The importance of this approach lies in its dual benefit: improving oil extraction efficiency and addressing environmental concerns associated with CO2 emissions.Method: We employed a discrete fracture-matrix model to simulate CO2 flooding in fractured shale reservoirs, utilizing both discontinuous Galerkin (DG) and continuous Galerkin (CG) finite element methods. The DG-CG FEM’s accuracy was validated against the McWhorter problem, ensuring the reliability of the simulation results. Our model also considered various factors, including reservoir heterogeneity, fracture permeability, CO2 injection volume, and gas injection patterns, to analyze their impact on shale oil recovery.Result: Our simulations revealed that fractured reservoirs significantly enhance shale oil production efficiency compared to homogeneous reservoirs, with an approximate 48.9% increase in production. A notable increase in shale oil production, by 15.8%, was observed when fracture permeability was increased by two orders of magnitude. Additionally, a fourfold increase in CO2 injection rate resulted in a 31.5% rise in shale oil production. Implementing a step-by-step reduction in injection volume while maintaining the total CO2 injection constant proved to be more effective than constant-rate injections.Discussion: The study demonstrates the effectiveness of CO2 flooding in fractured shale reservoirs for enhancing shale oil recovery.

Predicting gas flow rate in fractured shale reservoirs using discrete fracture model and GA-BP neural network method

In the process of shale gas exploitation, the hydraulic fracturing technology is generally used to generate the stimulate reservoir volume (SRV). The network connectivity between natural fractures (NFs) and hydraulic fractures (HFs) significantly affects gas production rate in the hydraulic fracturing stage. To study the influence of natural fracture characteristics on gas flow behavior, a discrete fracture model considering matrix and fracture behaviors is developed. It is found that the increase of natural fracture permeability and distribution density leads to the increase of gas production rate, whereas large orientation angle may cause its decrease. To determine the nonlinear relationship between the natural fracture parameters and gas production rate, the method of back propagation (BP) neural network with genetic algorithm (GA) was applied to make intelligent prediction for the shale gas production. The gas flow rate values for different natural fracture parameters (e.g., permeability, density, orientation) were calculated by discrete fracture model, and used as input data for training and prediction in the GA-BP neural network. Results demonstrate the applicability of forecasting model, which is suitable for shale gas prediction during the operation of horizontal wells if more data profiles could be collected.

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.

Impact of fracturing fluid retention and flowback on development effect after large scale fracturing in shale oil wells: A case study from the shale oil of Chang 7 Member, Yanchang Formation, Ordos Basin

In order to reveal the impact of fracturing fluid retention and flowback on the development effect after large-scale fracturing in shale oil wells, and to formulate a reasonable flowback policy, this paper employs a combination of core physical simulation experiments and theoretical analysis. We have designed a specially designed device that can evaluate the development effect of quasi-natural energy in oil reservoirs. The impact of fracturing fluid retention on development is simulated by changing the amount of fracturing fluid injected into the formation in a fractured horizontal well model (referred as injection volume), and the impact on development effect is analyzed by changing the properties of fracturing fluid to adjust the difference in the degree of flowback. Based on the experimental results, the mechanism of fracturing fluid retention and flowback after large-scale fracturing in shale reservoirs is further explored. The results of the experiments show that the flowback rate of fracturing fluid exhibits a monotonic decreasing trend with increasing the volume of injected fluid, as increasing the volume of injected fluid helps to enhance its retention in the formation and reduce the flowback rate. The degree of fracturing fluid flowback is critical to the mobility of crude oil in the tight reservoir. The entering of fracturing fluid into the reservoir slows down the rate of discharge in the fracture network, effectively extending the reach of the fracturing fluid in the tight reservoir and allowing more crude oil to be used, which in turn results in higher crude oil production. However, too much injection fluid may affect the fluid production. Simulation experiments reveal that the use of fracturing fluid retention or controlling the rate of flowback by changing the viscosity of fracturing fluid can be a way to enhance the development effect of horizontal shale oil wells. The results of this paper provide a basis for understanding the mechanism of shale oil development, exploring technical ideas to improve the development effect, and making decisions on the flowback parameters.

Investigation of Natural Weak Interface Properties and Their Impact on Fracture Propagation in Shale Reservoirs

Horizontal well multi-cluster fracturing technology is crucial for the economic development of fractured shale reservoirs. The abundance of natural fractures in shale reservoirs significantly influences the propagation path of hydraulic fractures and determines the formation of complex fracture networks. To investigate the impact of natural weak planes on the geometric parameters of fractures in shale reservoirs, we first conducted tests on the mechanical characteristics of core samples from outcropping shale in the Weiyuan area using the indoor three-point bending method and digital image correlation (DIC) technology, providing data validation for subsequent numerical models. Secondly, considering the interaction between hydraulic and natural weak planes in three-dimensional space, we established a three-dimensional numerical model for horizontal well fracturing to simulate the synchronous competition and expansion of fractures in multi-cluster fracturing. Based on this foundation, we analyzed the influence of formation parameters and engineering parameters on the formation patterns of complex fracture networks. The results indicate that the difference in in situ stress is a significant factor affecting the selection of fracture propagation paths. As the in situ stress difference increases, it becomes more challenging to open natural fractures, leading to a reduced probability of activation of natural weak interfaces. When the cohesive strength of natural fractures is smaller, they are more likely to open and capture hydraulic fractures, thereby increasing shear slip length and fracture network area. Each fracturing stage has an optimal perforation density combination, where a higher density of perforations leads to reduced perforation pressure drop and weaker ability to mitigate inter-cluster stress interference. To achieve a comprehensive and balanced development of multi-clusters, the inter-cluster stress interference can be alleviated by increasing the perforation pressure drop. For dense perforation clusters, higher injection rates and viscosity can be employed to ensure the uniform development of multiple perforation clusters. This study provides new insights into predicting the formation of complex fracture networks in shale reservoirs and offers valuable guidance for optimizing hydraulic fracturing designs.

Optimization of engineering parameters of deflagration fracturing in shale reservoirs based on hybrid proxy model

Engineering parameter optimization of deflagration fracturing in shale reservoirs is operated with single factor analysis and orthogonal experimental design analysis. There are problems of the difficulty to search the global optimal solution, time-consuming optimization and low computation efficiency. To resolve these problems, a method of optimizing engineering parameters of deflagration fracturing based on the hybrid proxy model was proposed in this paper. The parameters with significant effects on deflagration fracturing were selected as variables, and the models for prediction of reservoir burst degree and stimulated area were established based on Radial Basis Function model, Kriging interpolation model and eXtreme Gradient Boosting regression model respectively. A hybrid proxy model based on the roulette method was established by integrating the priorities of these three models. Then, a multi-objective optimization method of deflagration fracturing based on the hybrid proxy model and was established by integrating the Nondominated Sorting Genetic algorithm II with the engineering parameters as variables and the maximum stimulated area and minimum burst degree as objectives. Optimal design of the deflagration fracturing scheme was achieved. The results show that the hybrid proxy model can accurately predict the evaluation index of the fracturing results in vertical and horizontal wells, and the prediction accuracy is maintained at about 0.9. At the same time, compared with numerical model, the proposed method greatly saves the calculation time. The method proposed by this paper provides the solution to the problem of multi-objective optimization of deflagration fracturing engineering parameters, weighs the reservoir failure degree and the stimulation range, and provides guidance for field operation.

A brief review of steam flooding and its applications in fractured oil shale reservoirs

Steam flooding is an important thermal recovery method for heavy oil reservoirs, and convective heating technology is used to fracture oil shale reservoirs with good results. This paper reviews the main prediction methods, optimization approaches for steam flooding performance, and its application in fractured oil shale reservoirs. The prediction methods include experimental, numerical simulation, and statistical models. These provide insights into steam override, heat transfer, and production dynamics. To optimize steam flooding, parameters like quality, temperature, injection rate, and allocation need to be coordinated based on reservoir conditions and monitoring data. Real-time injection control, economic analysis, and sweep efficiency improvements should also be considered in optimization workflows. Although progress has been made, more field studies are needed to establish systematic optimization practices utilizing advanced technologies. This review summarizes the key developments in steam flooding modeling and optimization, providing a reference for further research and field applications.

Micro-mechanical properties of shale due to water/supercritical carbon dioxide-rock interaction

To investigate the impacts of water/supercritical CO2-rock interaction on the micro-mechanical properties of shale, a series of high-temperature and high-pressure immersion experiments were performed on the calcareous laminated shale samples mined from the lower submember of the third member of Paleogene Shahejie Formation in the Jiyang Depression, Bohai Bay Basin. After that, grid nanoindentation tests were conducted to analyze the influence of immersion time, pressure, and temperature on micro-mechanical parameters. Experimental results show that the damage of shale caused by the water/supercritical CO2-rock interaction was mainly featured by the generation of induced fractures in the clay-rich laminae. In the case of soaking with supercritical CO2, the aperture of induced fracture was smaller. Due to the existence of induced fractures, the statistical averages of elastic modulus and hardness both decreased. Meanwhile, compaction and stress-induced tensile fractures could be observed around the laminae. Generally, the longer the soaking time, the higher the soaking pressure and temperature, the more significant the degradation of micro-mechanical parameters is. Compared with water-rock interaction, the supercritical CO2-rock interaction caused a lower degree of mechanical damage on the shale surface. Thus, supercritical CO2 can be used as a fracturing fluid to prevent the surface softening of induced fractures in shale reservoirs.

Characteristics and Evolution of Tectonic Fractures in the Jurassic Lianggaoshan Formation Shale in the Northeast Sichuan Basin

The features and formation stages of natural fractures have significant influences on the fracturing of shale reservoirs and the accumulation of oil and gas. The characteristics and evolution of tectonic fractures in the Lianggaoshan Formation in Northeast Sichuan were investigated based on outcrops, drill cores, geochemical data, and acoustic emission test results. Our results demonstrated that the fracture types of the Lianggaoshan Formation were mainly low-degree bedding-slip fractures, followed by high-degree through-strata shear fractures and vertical tensile fractures. The influences of strike-slip faults on the fractures were stronger than those of thrust faults; fractures in thrust faults were concentrated in the hanging wall. The densities of tensile and shear fractures were inversely proportional to the formation thickness, while the density of interlayer slip fractures was independent of the formation thickness. The density of tectonic fractures was proportional to the quartz content. The fractures of the Lianggaoshan Formation were generated in three stages during uplift: (1) Late Yanshan–Early Himalayan tectonic movement (72~55 Ma), (2) Middle Himalayan tectonic movement (48~32 Ma), (3) Late Himalayan tectonic movement (15 Ma~4 Ma). Fractures greatly improve the oil and gas storage capacity and increase the contents of free and total hydrocarbons. At the same time, they also reduce the breakdown pressure of strata. This study facilitated the prediction of the fracture distribution and oil and gas reservoirs in the Lianggaoshan Formation and provided references for the selection of favourable areas for shale oil and the evaluation of desert sections in the study area.

Unreliable determination of in situ stress orientation by cross multipole array acoustic logging in fractured shale reservoirs

AbstractWith the development of shale gas exploration in China, the use of conventional logging tools has been introduced, and cross multipole array acoustic logging tools have gradually been used to determine the stress orientation in shale. The direction of fast shear waves (FSWs) is generally parallel to the horizontal maximum principal compression stress (SHmax). However, the azimuth of FSWs is found to be parallel to the main strike (but not to the SHmax) direction of structural fractures in shale reservoirs. Outcrop and image logging data indicate that the natural fractures in this area strike NE‒SW. If the shear wave anisotropy is caused by only the stress around the borehole and the FSWs are known to be NE‒SW, SHmaxshould be parallel to NE‒SW; however, according to statistics of land movement in adjacent areas, anelastic strain recovery, earthquake focal mechanism, borehole breakouts, hydraulic fracturing data, deviated well data, and drilling‐induced fracture data in local regions, SHmaxis oriented in the NW‒SE direction, and the directions of FSWs are generally parallel to the structural fracture direction. This contradiction indicates that the development of structural fractures may affect the orientation of FSWs. Therefore, it is not reliable to use XMAC (Cross‐Multipole Array Acoustilog) logging only to determine the direction of in situ stress in fractured shale reservoirs. In addition, the direction of the FSWs in the middle of thick mudstones is NW‒SE, which may represent accurate information about the in situ stress direction.

Numerical Modeling of Natural Fracture Distributions in Shale

AbstractThe production efficiency of shale gas is affected by the interaction between hydraulic and natural fractures. This study presents a simulation of natural fractures in shale reservoirs, based on a discrete fracture network (DFN) method for hydraulic fracturing engineering. Fracture properties of the model are calculated from core fracture data, according to statistical mathematical analysis. The calculation results make full use of the quantitative information of core fracture orientation, density, opening and length, which constitute the direct and extensive data of mining engineering. The reliability and applicability of the model are analyzed with regard to model size and density, a calculation method for dominant size and density being proposed. Then, finite element analysis is applied to a hydraulic fracturing numerical simulation of a shale fractured reservoir in southeastern Chongqing. The hydraulic pressure distribution, fracture propagation, acoustic emission information and in situ stress changes during fracturing are analyzed. The results show the application of fracture statistics in fracture modeling and the influence of fracture distribution on hydraulic fracturing engineering. The present analysis may provide a reference for shale gas exploitation.

Amplitude variation with incidence and azimuth stepwise inversion with coherence-attribute constraints for anisotropic parameters

With the development of 5D (3D + offset + azimuth) seismic technology, the stable acquisition of anisotropy information from wide-azimuth seismic data has become a key scientific problem in the seismic inversion of fractured reservoirs. The amplitude variation with incidence and azimuth (AVAZ) inversion method using wide-azimuth seismic data is an effective way to predict the anisotropic information of the subsurface medium. However, the conventional AVAZ inversion method suffers from too many parameters to be estimated, large variation in contribution, and inversion instability. Therefore, an AVAZ inversion method with coherence-attribute constraints is developed to solve the problem of unstable inversion of anisotropic parameters. First, we use seismic coherence attributes to build a fracture-probability-distribution model containing anisotropic information of the subsurface medium, which can be used to simulate large-scale subsurface fractures and faults. Then, it is added to the objective function as an anisotropic information constraint to improve the reliability and stability of the anisotropic inversion. Furthermore, an AVAZ inversion method in a Bayesian framework is implemented by using wide-azimuth seismic data. Gaussian distribution and a smoothing background model are added to the objective function to improve the reasonableness and stability of the inversion. In addition, we develop a stepwise optimization inversion method for isotropic and anisotropic parameters, prioritizing the inversion of parameters that contribute significantly to the reflection coefficient, and then using the results of the previous inversion as the initial values for the next inversion step to achieve multiparameter inversion. This method can reduce the number of the estimated parameters and thus improve the stability of the inversion of the anisotropic parameters. Field data examples indicate that this method produces suitable inversion results even at moderate levels of noise. Therefore, we can conclude that the proposed method has good applicability and stability in predicting the anisotropy parameters of fractured shale reservoirs.

Multiple Flow Mechanism-Based Numerical Model for CO2 Huff-n-Puff in Shale Gas Reservoirs with Complex Fractures

CO2 huff-n-puff has been proven to be an effective method for enhanced gas recovery. Besides, considering the storage capacity and existing infrastructure, injecting carbon dioxide into shale gas reservoirs is a feasible geological storage option for carbon dioxide. However, the current huff-n-puff simulation model must consider the comprehensive flow mechanism crucial for accurate reservoir and huff-n-puff simulation. Besides, the feasibility of effective CO2 storage by CO2 huff-n-puff in shale gas reservoirs is still being determined. Therefore, a CO2 huff-n-puff numerical model considering gas adsorption/desorption, diffusion, dissolution, stress sensitivity, and stimulated reservoir volume (SRV) is established in this paper. The model’s reliability is verified by matching the production history with commercial software. Finally, the effects of various flow mechanisms on CO2 huff-n-puff and storage in shale gas reservoirs are analyzed. The results show that CO2 huff-n-puff can significantly improve the gas recovery of fractured shale reservoirs and realize the effective storage of part of CO2, where the storage factor can reach 0.62. Considering adsorption/desorption, diffusion, stress sensitivity, dissolution in water, and SRV is beneficial to storing CO2 during huff-n-puff. Adsorption/desorption, diffusion, and SRV can enhance the huff-n-puff effect, while stress sensitivity will weaken. For different mechanisms, adsorption/desorption and SRV can most affect the huff-n-puff and storage effect in shale reservoirs. This work provides a new approach for the simulation of CO2 huff-n-puff and storage, which is beneficial for exploiting the shale gas reservoirs and decreasing CO2 emissions.