Accurate evaluation of fracability in unconventional reservoirs is essential for optimizing fracturing intervals and assessing productivity. Traditional fracability models, typically based on linear weighted and geometric average methods, suffer from subjective biases and neglect the correlation of factors. It is difficult to characterize and quantify the fracture network modification and the actual fracturing effect. To address these limitations, a new comprehensive fracability evaluation model was proposed based on multiplicative synthesis, incorporating the coupling effects of rock mineral properties, mechanical characteristics, in situ stress, and natural structural planes. The novelty lies in avoiding the weight calculations of factors, ensuring easy distinction of evaluation grades, continuous and monotonous results, and significant practicality and superiority. Brittle mineral content, elastic modulus, and Poisson's ratio were utilized to characterize the mineral and mechanical brittleness. The degree of natural fracture development was quantified through fractal dimensions and grid coverage methods. True triaxial hydraulic fracturing experiments and finite-element-based numerical simulations were used to analyze the spatial morphology and stimulated reservoir volume of hydraulic fractures influenced by fracability, and the model accuracy was validated with on-site microseismic and electromagnetic monitoring. The method was applied to the continuous fracability grading evaluation and sweet-spot prediction of deep sandstone reservoirs in the Junggar Basin. In addition, a three-dimensional block model of lateral heterogeneous fracability based on the distance power inverse method was established, enabling precise identification of geological sweet spots and optimal perforation intervals. The findings provide critical insights for accurately evaluating unconventional reservoir fracability and optimizing fracturing designs.

In recent years, the exploration of oil and gas resources has been continuously extended to deep reservoirs, such as deep sandstone reservoirs in the central Junggar Basin, Western China. Hydraulic fracturing for increasing production is significantly affected by rock brittleness and in-situ stress level. In this study, a geometric mean-based comprehensive index (GMCI) was proposed from experimental analyses. Subsequently, the effect of brittleness on failure modes and acoustic emission (AE) characteristics was analyzed. Finally, a three-dimensional numerical model was established considering pore pressure, in-situ stress, and fractures at the field scale to analyze the hydraulic fracturing in deep sandstone oil reservoirs, which was validated by microseismic monitoring (MS) results. The research results indicate that the brittleness of deep sandstones can be effectively evaluated with the GMCI method. With the increase of confining pressure, the overall trend of the brittleness index decreases; this is consistent with the failure mode in the experiments. With increasing brittle mineral content, the failure modes change from single shear failure to composite failure with multiple fractures, resulting in different AE vibration modes. With increasing burial depth of the reservoir by 400 m, the fracture length and width were reduced by 35.5

Rock brittleness is a crucial mechanical property and essential for fracability evaluation and fracturing scheme design in unconventional reservoirs. However, the influence of inherent anisotropy on deep laminated sandstone’s mechanical properties and brittleness characteristics is rarely investigated. The energy transformation and damage evolution reflected by complete stress-strain curves are analyzed during the entire process of rock rupture under compressions. A new brittleness index is established based on energy evolution during sandstone failure. Its advantages involve comprehensively considering the energy transformation characteristics at both pre-peak and post-peak stages and the capability to characterize the effect of confining pressure and bedding plane (BP) geometry on sandstone brittleness. The triaxial compression tests on sandstones are conducted to validate the reliability and accuracy of the new brittleness index. Numerical simulations are then performed to further investigate the manner in which BP angle, BP density, and confining pressure control the brittleness anisotropy of deep laminated sandstones based on the finite element method. Then the acoustic emission (AE) characteristics of anisotropic sandstone and correlations between AE mode and brittleness index are discussed. The results indicated that the anisotropy of mechanical properties and brittleness of deep laminated sandstones were significantly affected by BP angle, BP density, and confining pressure. With the increase of BP angle, the brittleness index of deep laminated sandstone decreases first and then increases, showing a U-shape variation law, whose maximum and minimum values are obtained at φ =0° and φ =45°, respectively. The AE characteristics were closely related to rock brittleness, which was jointly controlled by BP geometry and confining pressure. The results provide a basis for the brittleness and fracability evaluation and optimum hydraulic fracturing design in deep laminated sandstones.

The tight heterogeneous glutenites are typically characterized by highly variable lithology, low/ultra-low permeability, significant heterogeneity, and a less-developed natural fracture system. It is of great significance for economic development to improve hydraulic fracture complexity and stimulated reservoir volume. To better understand the hydraulic fracturing mechanism, a large-scale experimental test on glutenite specimens was conducted and the hydraulic fracture propagation behaviors and focal mechanism were analyzed. A three-dimensional numerical model was developed to reproduce the hydraulic fracture evolution process and investigate the effects of operating procedures on hydraulic fracture geometry and stimulated reservoir volume. A simultaneous variable injection rate and fluid viscosity technology was proposed to increase the hydraulic fracture complexity and stimulated reservoir volume. The results indicate that four fracturing behaviors can be observed, namely, penetration, deflection, termination, and bifurcating, in the laboratory experiment. Tensile events tend to appear during the initiation stage of hydraulic fracture growth, while shear events and compressive events tend to appear during the non-planar propagation stage. The shear and compressive mechanisms dominate with an increase in the hydraulic fracture complexity. The variable injection rate technology and simultaneous variable injection rate and fluid viscosity technology are effective techniques for fracture geometry control and stimulated reservoir volume enhancement. The key to improve hydraulic fracture complexity is to increase the net pressure in hydraulic fractures, cause evident pressure fluctuations, and activate or communicate a wide range of natural discontinuities. The results can provide a better understanding of the fracture geometry control mechanism in tight heterogeneous glutenites, and offer a guideline for treatment design and optimization of well performance.

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 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.

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.

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.

Hydraulic fracturing, as a key technology of deep energy exploitation, accelerates the rapid development of the modern petroleum industry. To study the mechanisms of hydraulic fracture propagation and rock failure mode of the vertical well hydraulic fracturing, the true triaxial hydraulic fracturing test and numerical simulation are carried out, and the influence of the principal stress difference, water injection displacement, perforation angle and natural fracture on fracture propagation is analyzed. The results show that the fracture propagation mode of limestone is mainly divided into two types: the single vertical fracture and the transverse-longitudinal crossed complex fracture. Under high displacement, the fracturing pressure is larger, and the secondary fracture is more likely to occur, while variable displacement loading is more likely to induce fracture network. Meanwhile, the amplitude of acoustic emission (AE) waveform of limestone during fracturing is between 0.01 and 0.02 mV, and the main frequency is maintained in the range of 230–300 kHz. When perforation angle θ=45°, it is easy to produce the T-type fracture that connects with the natural fracture, while X-type cracks are generated when 0=30°. The results can be used as a reference for further study on the mechanism of limestone hydraulic fracturing.

In order to investigate the propagation behavior of radial well hydraulic fractures, a low-permeability reservoir in Shengli Oilfield was used as the geologic condition, and a series of numerical simulations of radial well guided hydraulic fracturing were carried out based on a numerical method named Rock Failure Process Analysis 3D. The concept of effective stimulation coefficient was proposed in this paper to illustrate the advantage of radial well fracturing. The results show that compared with the traditional hydraulic fracturing, the effective stimulation coefficient through radial well fracturing is increased by 8% and the effectively stimulated area is increased by 60.6%. The viscosity of the fluid has little effect on the effective stimulation coefficient and effective stimulation area, when compared with the injection rate. The effective stimulation coefficient decreases with the increase of injection rate. And the effectively stimulated area improves with the increase of injection rate. In the process of radial well fracturing, it is possible to reduce the ineffective stimulation and construction costs by reasonably reducing the construction injection rate.

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–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.