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The hydraulic fracture (HF) morphology and corresponding stimulated reservoir volume (SRV) are significantly dependent on the geomechanical factors of the formation. A better understanding of the hydraulic fracturing mechanism under different reservoir attributes is crucial for fracability evaluation and fracturing treatment optimization. In this work, the geomechanical controls on hydraulic fracturing in a heterogeneous formation and its fracability are investigated using a three-dimensional (3D) fully coupled hydraulic–mechanical–damage (HMD) model. Rock heterogeneity, which causes nonlinear progressive failure behavior, is considered in this model by assuming that the mechanical parameters of elements follow a Weibull distribution. The elastic damage mechanics and Darcy’s law describe the damage process and fluid flow in elements, respectively. The element permeability is dependent on its state, which describes the effect of stress on the seepage field. The HF width is conceptually represented by the aperture of fractures, which depends on the failure mechanism of the damaged element. The coupled equations are solved numerically using the finite element method. The model is verified with experimental results of HF network propagation and multi-fracture interference. Then, a series of numerical simulations were performed to investigate the geomechanical controls of HF geometry and SRV in heterogeneous formations. At last, the optimal conditions for the formation of a complex HF network are further discussed according to the numerical results, based on which an improved fracability index is established. The results show that the numerical model can capture the 3D nature of the HFs and reproduce the HF network propagation and multi-fracture interference process. The complex HFs are more likely to generate in formations with high brittleness, large natural fracture (NF) density, small horizontal stress difference, and small fracture toughness. This study provides a reliable numerical method for hydraulic fracturing simulation and offers some reference for the fracability evaluation and fracturing treatment design in heterogeneous formations.

Tight glutenite reservoirs are widely developed in Bohai Bay Basin, East China. They are mostly huge thick and rely on hydraulic fracturing treatment for commercial exploitation. To investigate the propagation behavior of hydraulic fractures in these glutenite reservoirs, the geological feature of reservoirs in Bohai Bay Basin is studied firstly, including the reservoir vertical distribution feature and the heterogeneous lithology. Then, hydraulic fracturing treatments in block Yan 222 are carried out and the fracturing processes are monitored by the microseismic system. Results show the hydraulic fractures generated in the reservoirs are mostly in X shape. The cause of X-shaped hydraulic fractures in this study is mainly ascribed to (I) the reservoir heterogeneity and (II) the stress shadow effect of two close hydraulic fractures propagating in the same orientation, which is confirmed by the following numerical simulation and related research in detail. This study can provide a reference for the research on the fracturing behavior of the deep thick glutenite reservoirs.

The sandstone-mudstone interbedded reservoirs in Bohai Bay Basin, eastern China are typically characterized by high in-situ stress difference, low permeability, and significant heterogeneity. A better understanding of hydraulic fracturing mechanisms and optimization strategies of fracturing treatments is crucial for stimulated reservoir volume (SRV) enhancement and efficient oil recovery. In this study, laboratory tests were conducted on the sandstone and mudstone cores to analyze the mechanical and structural properties. A finite element method (FEM)-based numerical model was developed to simulate the 3D nature of complex hydraulic fracture (HF) propagation. Rock heterogeneity and seepage-stress-damage coupling were both considered to reproduce the fracturing behaviors. A novel approach for SRV simulation was proposed and implemented in the model, which can be used to comprehensively reflect the fracturing performance. A series of numerical simulations were performed to explore the effect of reservoir thickness and treatment parameters on hydraulic fracturing performance. Furthermore, a simultaneous variable injection rate and alternate fluid injection technology were proposed, and the effects of operation procedures on hydraulic fracturing performance were investigated. The results show that HFs tend to present more complex morphology in thick interbedded layers than that in thin interbedded layers under a certain treatment condition. In thin layers, complex HFs can be created when the injection rate is greater than 10 m3/min, while in thick layers, complex HFs can be created when the injection rate is greater than 7 m3/min. With the increase of injection rate, the HF complexity, SRV, and fracture height increase. With the increase of fluid viscosity, the SRV decreases, while the fracture height increases. The simultaneous variable injection rate and alternate fluid injection technology could improve SRV by 19.6%, which appears to be an effective technique to achieve massive fracturing stimulation and fracture height containment for the heterogeneous interbedded reservoirs. The results can provide an insight into the fracturing mechanisms and offer a guideline for fracturing design and treatment optimization in tight sandstone-mudstone interbedded reservoirs.

This paper proposed a coupled hydraulic-mechanical-damage (HMD) geotechnical model for simulating the entire failure process in geological media. In this model, elastic damage mechanics describes the damage process of elements. Darcy's Law and unsteady seepage flow equation describe fluid flow in elements, where compression of fluid and rock are considered. The coupled process is fulfilled by Biot's consolidation theory describing how pore-pressure affects the stress field and the stress/aperture/mesh-dependent permeability that represents the influence of stress on seepage field. The HMD model is implemented in the calculation module of Rock-Failure-Process-Analysis on Petroleum-problems (RFPA-Petrol) codes. The RFPA suite of software codes is based on the idea that the heterogeneity leads to non-linearity and causes progressive failure behavior observed in brittle rock. The capability of RFPA-Petrol simulator is demonstrated by a typical coupled problem related to double fractures propagation during hydraulic fracturing. This simulation successfully reproduces the asynchronous initiation, asymmetric growth and non-equal deflection of fractures in the numerical model. Then this simulator was used to investigate how fracture spacing and horizontal stress ratio influence propagation and reorientation of three hydraulic fractures from a horizontal well. At last, a horizontal well drilled by SHENGLI oilfield is simulated to certificate RFPA-Petrol's ability on field-scale models. It is found that larger fracture spacing and higher initial fracture height will form longer and wider fractured zones. HMD-based RFPA-Petrol is suitable for simulation of laboratory scale and field scale fracture propagation problems.

Hydraulic fracturing performance, affected by multiple factors, was essential to the economic exploitation of oil and gas in heterogeneous unconventional reservoirs. Multifactor analysis can gain insight into the fracturing response of reservoirs and in turn optimize the treatment design. Based on characterizations of the geological setting of a heterogeneous glutenite reservoir, the hydraulic fracture (HF) initiation and propagation process, as well as the stimulated reservoir volume (SRV), were simulated and analyzed using a coupled hydraulic-mechanical-damage model. The Weibull distribution was employed to describe rock heterogeneity. The numerical model was verified with microseism (MS) interpretation results of HF geometry. A multifactor analysis and optimization workflow integrating response surface methodology, central composite design (CCD), and numerical simulations was proposed to investigate the coupling effects of multiple geomechanical and hydrofracturing factors on SRV and identify the optimum design of fracturing treatment. The results showed that the horizontal stress difference and injection rate were the most significant factors to control the SRV. Increasing the injection rate and reducing fluid viscosity may contribute to improving the SRV. It is more difficult to increase the SRV at higher horizontal stress difference than at lower horizontal stress difference. The multifactor analysis and optimization workflow introduced in this work was a practical and effective method to control the HF geometry and improve the SRV. This study provided a deep understanding of the hydraulic fracturing mechanism and possessed theoretical significance for treatment design.

Multi-cluster hydraulic fracturing of long-range horizontal wells is an approach for enhancing the productivity of low-permeability shale reservoirs. In this study, RFPA-Petrol (rock failure process analysis on petroleum problems) is applied for modeling hydraulic fracture propagation in multilayered formations. RFPA-Petrol based on coupled hydraulic-mechanical-damage (HMD) modeling was first tested by modeling a laboratory scale experiment on a physical (cement) model with a single completion. The modeling demonstrated the capability of RFPA-Petrol for simulating hydraulic fracture propagation. Then, we used RFPA-Petrol to investigate how the difference in material properties between oil-bearing layers and interlayers and the fracturing fluid properties influence the propagation of dual fractures in multilayered laboratory-scale models. In this case, the models with geological discontinuities in the vertical direction are strongly heterogeneous and RFPA-Petrol simulations successfully modeled the fracture configurations.

Hydraulic fracturing is an effective stimulation technology for enhancing recovery in deep reservoirs. Multi-factor analysis and fracturing design optimization are essential for the efficient development of deep naturally fractured sandstones. A three-dimensional flow-stress-damage (FSD) coupled model was presented to simulate the hydraulic fracture (HF) propagation and stimulated reservoir volume (SRV). The numerical model was validated with experimental results of the HF-natural fracture (NF) intersection. The sensitivity analysis is conducted to screen the significant factors affecting HF geometry and SRV. The response surface method was employed to investigate the coupling effects of multiple geomechanical and hydraulic factors on SRV by integrating Box-Behnken design and numerical modeling. Subsequently, the SRV was optimized by identifying the optimum combinations of uncertain parameters based on the established response surface model (RSM). The results indicated that the injection rate, NF density, fluid viscosity, and horizontal stress difference are the key factors controlling SRV. It is more difficult to improve SRV by increasing injection rate at higher horizontal stress difference than at lower horizontal stress difference. The proposed method is effective for enhancing the artificial ability to optimize the HF geometry and SRV. The results can provide insight into the fracture geometry control mechanism in deep naturally fractured sandstones, and offer a guideline for treatment design and optimization of well performance.

Hydraulic fracturing is an extensively used technique for development of oil and gas resources. In the shale reservoir, rock brittleness plays an important role during hydraulic fracturing. In this paper, a numerical code known as RFPA (Rock Failure Process Analysis) is introduced and the embedded digital-image-based (DIB) technique is illustrated in detail. Based on this integration, the effects of rock brittleness on the failure mode and stress-strain characteristic of the shale specimens are numerically investigated. It is found that the brittle shale specimen is more likely to rupture with multi crossed failure planes while the ductile specimen is more likely to rupture with a penetrating failure plane, from which we deduce the brittle shale is easier to develop more natural fractures than the ductile shale. The influence of natural fractures on complex hydraulic fracture network is further investigated through numerical simulation and the positive effect of rock brittleness is indirectly verified. It is found that hydraulic fractures are preferable to propagate in brittle minerals, i.e. the hydraulic fractures always choose the brittle minerals as the favorite path to propagate or choose a thin or weak part of ductile minerals to penetrate and is blocked by the ductile minerals. Moreover, the hydraulic fractures generated in the brittle shale are tortuous and appear with multi branches, which is much beneficial to form hydraulic fracture network in contrast to the smooth hydraulic fracture generated in the ductile shale. This is probably one of the causes of that the required treatment pressure in ductile shale layer is higher than that in brittle shale layer.

Natural fractures play a key role in shale gas production. In this study, a digital-image-processing (DIP) technique is employed to characterize the digital images of shale samples with complex natural fractures. Incorporated the DIP technique with FEM code, the propagation behavior of hydraulic fracture in fractured shale reservoirs is numerically investigated. Three digital images of in-situ shale samples are applied for numerical analysis. Numerical results reproduce the propagation of hydraulic fractures. The hydraulic fracturing process can be divided into three stages: (I)stress accumulation stage, (II)fracture steady propagation stage and (III) fracture unsteady propagation stage. The hydraulic fracture morphology is closely dependent on the natural fracture characteristics. More complex hydraulic fracture can be produced in reservoirs with denser natural fractures. Further numerical models are subsequently established to investigate the impact of the in-situ stress anisotropy and rock brittleness on the hydraulic fracture behavior in shale. Reservoirs with lower in-situ stress anisotropy tend to produce more complex hydraulic fractures. Brittle minerals in the shale are more inclined to induce extensive fracture failure and require lower propagation pressure compared to the ductile mineral. The result can provide a reference to the research on the fracture propagation behavior of the shale reservoir during fracturing stimulation.

Tight glutenite reservoirs are typically characterized by highly variable lithology and permeability, low and complex porosity, and strong heterogeneity. Glutenite brittleness is an essential indicator for screening fracture targets, selecting technological parameters, and predicting the hydraulic fracturing effect of tight glutenite reservoir exploitation. Glutenite formations with high brittleness are more likely to be effectively fractured and form complex fractures. Accurate evaluation of glutenite brittleness facilitates the recovery of oil and gas in a tight glutenite reservoir. Accordingly, two brittleness indexes are proposed in this paper based on energy balance and damage evolution analysis of complete stress&ndash, strain curves to evaluate the brittleness of glutenite. Uniaxial and triaxial compression tests of glutenite specimens were carried out and the brittleness indexes were verified by comparison with other existing indexes. The relationships between the mechanical properties and brittleness of glutenite under confining pressure were analyzed based on experimental results and the effects of mechanical and structural parameters on glutenite brittleness are investigated with a numerical approach. The brittleness of glutenite increases with the increase of gravel size and/or volume content. During hydraulic fracturing design, attention should be paid to the brittleness of the matrix and the size and content of gravel. This paper provides a new perspective for glutenite brittleness evaluation from the perspectives of energy dissipation and damage evolution. Our results provide guidance for fracturing layer selection and may also facilitate field operations of tight glutenite fracturing.

Using a true triaxial compression test apparatus, physical model tests are carried out to investigate the fracture propagation in open-hole horizontal wells under hydraulic pressure. The test results indicate that hydraulic fracture propagation is closely related to the direction of the minimum principal stress. When the difference between the maximum and minimum horizontal stresses is maintained at 10.0 MPa and the angle between the horizontal well and the minimum horizontal stress varies from 0° to 90°, the fracturing pattern changes from transversal to longitudinal fractures. To capture the complex hydraulic fractures in heterogeneous rock materials, a three-dimensional numerical code incorporating the seepage-stress-damage coupled model is then employed to study the hydraulic fracture propagation near open-hole horizontal wells. The fracture propagation in horizontal wells under hydraulic fracturing is simulated and the numerical results are in good agreement with the experimental results. The stress ...

To capture the hydraulic fractures in heterogeneous and layered rocks, a numerical code that can consider the coupled effects of fluid flow, damage, and stress field in rocks is presented. Based on the characteristics of a typical thin and inter-bedded sedimentary reservoir, China, a series of simulations on the hydraulic fracturing are performed. In the simulations, three points, i.e., (1) confining stresses, representing the effect of in situ stresses, (2) strength of the interfaces, and (3) material properties of the layers on either side of the interface, are crucial in fracturing across interfaces between two adjacent rock layers. Numerical results show that the hydrofracture propagation within a layered sequence of sedimentary rocks is controlled by changing in situ stresses, interface properties, and lithologies. The path of the hydraulic fracture is characterized by numerous deflections, branchings, and terminations. Four types of potential interaction, i.e., penetration, arrest, T-shaped branching, and offset, between a hydrofracture and an interface within the layered rocks are formed. Discontinuous composite fracture segments resulting from out-of-plane growth of fractures provide a less permeable path for fluids, gas, and oil than a continuous planar composite fracture, which are one of the sources of the high treating pressures and reduced fracture volume.

To better understand the interaction between hydraulic fracture and oriented perforation, a fully coupled finite element method (FEM)-based hydraulic-geomechanical fracture model accommodating gas sorption and damage has been developed. Damage conforms to a maximum stress criterion in tension and to Mohr&ndash, Coulomb limits in shear with heterogeneity represented by a Weibull distribution. Fracturing fluid flow, rock deformation and damage, and fracture propagation are collectively represented to study the complexity of hydraulic fracture initiation with perforations present in the near-wellbore region. The model is rigorously validated against experimental observations replicating failure stresses and styles during uniaxial compression and then hydraulic fracturing. The influences of perforation angle, in situ stress state, initial pore pressure, and properties of the fracturing fluid are fully explored. The numerical results show good agreement with experimental observations and the main features of the hydraulic fracturing process in heterogeneous rock are successfully captured. A larger perforation azimuth (angle) from the direction of the maximum principal stress induces a relatively larger curvature of the fracture during hydraulic fracture reorientation. Hydraulic fractures do not always initiate at the oriented perforations and the fractures induced in hydraulic fracturing are not always even and regular. Hydraulic fractures would initiate both around the wellbore and the oriented perforations when the perforation angle is &gt, 75&deg, For the liquid-based hydraulic fracturing, the critical perforation angle increases from 70&deg, to 80&deg, with an increase in liquid viscosity from 10&minus, 3 Pa&middot, s to 1 Pa&middot, s. While for the gas fracturing, the critical perforation angle remains 62&deg, to 63&deg, This study is of great significance in further understanding the near-wellbore impacts on hydraulic fracture propagation and complexity.

Tight glutenites are typically composed of heterogeneous sandstone and gravel. Due to low or ultra-low permeability, it is difficult to achieve commercial production in tight glutenites without hydraulic fracturing. Efficient exploitation requires an in-depth understanding of the fracturing behavior of these reservoirs. This paper provides a numerical method that integrates the digital image processing (DIP) technique into a numerical code rock failure process analysis (RFPA). This method could consider the glutenite heterogeneities, including intrarock and interrock heterogeneities, and the practicability is verified through two numerical tests. Two-dimensional (2D) simulations show hydraulic fractures (HFs) can penetrate or deflect to propagate along the gravels, depending on the magnitude of stress anisotropy and gravel strength. Three-dimensional (3D) simulations with the consideration of gravel distribution orientation, gravel size and axial ratio show HFs could propagate past the gravel with no deflection, forming a bypass fracture that is not easy to observe in common laboratory experiments. HFs could also deflect to propagate along the gravels. The impacts of the gravel distribution orientation, gravel size and axial ratio are discussed in detail. The main propagation modes of HFs intersecting the gravels are summarized as: (1) penetrating directly, (2) deflecting to propagate along the gravels to form distorted HFs, (3) propagating to bypass the gravels, (4) a combination of (1) and (2), or (2) and (3).