Hydraulic Fracturing Design Research Articles

Characteristics of Lamination in Deep Marine Shale and Its Influence on Mechanical Properties: A Case Study on the Wufeng-Longmaxi Formation in Sichuan Basin

The extensive development of lamination structures in shale significantly influences its mechanical properties. However, a systematic analysis of how laminae affect the macroscopic mechanical behavior of rocks remains absent. In this study, field emission scanning electron microscopy (FE-SEM), thin section observation, X-ray diffraction (XRD), triaxial compression and Brazilian tests were carried out on the deep marine shale of the Wufeng-Longmaxi Formation in Sichuan Basin. The results reveal four distinct laminasets: grading thin silt–thick mud (GSM1), grading medium thick silt–mud (GSM2), grading thick silt–thin mud (GSM3) and alternating thick silt–thin mud (ASM). GSM3 and ASM laminasets exhibit the weakest mechanical properties and the simplest fracture patterns, while GSM2 demonstrates moderate mechanical properties and more complex fracture patterns. GSM1 shows the highest mechanical strength and the most intricate fracture patterns. Mechanical properties are positively correlated with siliceous mineral content and negatively correlated with clay mineral content and scale of laminae development (average density and thickness), revealing that lamination plays a key role in fracture behavior, with more intensively developed laminasets leading to the concentrated distribution of brittle silty minerals, facilitating microcrack propagation. Moreover, microstructure has an important effect on both mechanical properties and fracture pattern. In grain-supported structures, closely packed silty brittle mineral grains reduce the energy required for crack extension. In matrix-supported structures, widespread silty brittle mineral grains increase energy requirements for crack extension, leading to more irregular and complex fracture networks. This study enhances the understanding of the effects of lamination on the rock mechanical behavior of shales, optimizing hydraulic fracturing design in shale reservoirs.

Optimising Neural Networks for Enhanced Fracture Density Prediction in Surrounding Rock of Coalbed Methane Reservoir

ABSTRACTFractures influence the mechanical strength of coal roof and floor, constraining the design of hydraulic fracturing for coalbed methane production. Currently, the predominant approach involves the integration of petrophysical logging with machine learning for fracture prediction. Nevertheless, challenges exist regarding the model's accuracy. In this study, we present a novel approach to predict fracture density. Our method optimises a back‐propagation (BP) neural network and utilises principal component analysis for feature extraction. We employ logging parameters (density, compensated neutron and acoustic time difference) obtained from Shouyang Block well SY‐1 and fracture density data from electrical imaging logging to construct the FVDC model's dataset. The BP neural network model is optimised using the Sparrow Search algorithm and Tent Chaotic Mapping. The results demonstrate a substantial enhancement over the BP neural network model, with reductions of 80.102% in mean absolute error, 94.182% in mean square error, 75.879% in root mean square error and 79.764% in mean absolute percentage error. When considering accuracy, the optimised model (97.098%) surpasses the support vector regression model (96.478%), the random forest model (94.404%) and the BP neural network model (85.657%). Scalability testing for the optimised model was conducted using data from well SY‐2, yielding a remarkable prediction accuracy of 96.775%. This performance exceeds that of the BP neural network (with an accuracy of 85.102%), as well as the random forest and support vector regression models (with accuracies of 91.234% and 90.384%, respectively). These results underscore the potential of well logging and machine learning in FVDC prediction.

Mechanical properties of shale during pyrolysis: Atomic force microscopy and nano-indentation study

Quantitative characterization of the geo-mechanical properties of shale and organic matter (OM) holds paramount significance in the assessment of shale gas reserves and the design of hydraulic fracturing. However, the mechanical evolution processes during shale hydrocarbon generation and its influencing factors have received limited attention. This study examines the changes in shale mechanical properties during pyrolysis at high temperatures (415–600 °C) and high pressure (50–125 MPa) for mature to over-mature stages. The nanoindentation and in-situ AFM-QNM analysis are utilized to characterize the changes in mechanical properties during evolution. Subsequently, gas adsorption, Fourier Transform infrared spectroscopy (FTIR), and laser Raman spectroscopy (Raman) are used to investigate the factors influencing the mechanical properties of shale and the associated OM, and establish a model for the evolution of the mechanical properties. The results demonstrate that with increasing maturity, the overall Young's modulus of the bulk shale gradually increases from 42.8 GPa to 58.4 GPa for the temperature increment from 415 °C to 600 °C. During the thermal maturation process, the mesopore structure and quartz content of the shale significantly influence its mechanical properties. Young's modulus of OM shows an S-shaped trend, with variations in the micromechanical properties of OM corresponding to stages of hydrocarbon generation. In particular, two peaks of Young's modulus increase are observed during the mature and over-mature stages. In the mature stage, the aromatization of the kerogen leads to substantial detachment of aliphatic side chains and oxygenated functional groups, resulting in a higher degree of aromatization. This reduces the kerogen spacing and consequently increases the Young's modulus. In the over-matured stage, the process of aromatics condensation leads to the orientation and arrangement of aromatic rings, reducing the number of key site vacancies and crystal defects, thereby forming large aromatic clusters and significantly increasing the graphite-like structure. This study will facilitate the analysis of shale matrix deformation mechanisms at the microscale, providing a fundamental theoretical and scientific basis for shale fracturing design, exploration, and development.

Influence of bedding on fracture toughness and failure patterns of anisotropic shale

The initiation and propagation of hydraulic fractures are closely related to the fracture ability of rocks. Such processes in shale reservoirs are, to a certain extent, controlled by bedding. However, the control mechanism of bedding on the anisotropy of fracture toughness and fracturing behavior remains unclear. In this study, a series of numerical notched semi-circular bend (NSCB) tests are conducted using the discrete element method (DEM) to investigate the influence of bedding properties on the anisotropy of fracture toughness and fracture patterns. Based on the DEM framework, a novel simulation method is proposed to accurately identify two key fracture indicators, the fracture process zone (FPZ) and crack tip opening displacement (CTOD), to reveal the fracture driving mechanism. The results show that the fracture toughness of shale is negatively correlated with bedding angles β but positively correlated with bedding spacing and bedding strength. Both the bedding strength and spacing significantly influence the fracture pattern of the specimens with β = 0°–60°, whereas the specimen with β = 90° is scarcely affected by the bedding planes. The evolution of the CTOD and FPZ in shale exhibits distinct phased characteristics. Due to the strong suppression effect of low-angle bedding planes on pre-peak crack deflection, the CTOD and FPZ exhibit opposite trends with respect to bedding angles before and after the peak load. This study facilitates the understanding of the fracture propagation process of anisotropic shale and could provide guidance for hydraulic fracturing design in shale reservoirs.

High-Order Models for Gas Transport in Multiscale Coal Rock.

The coal reservoirs exhibit great heterogeneity and strong anisotropy in multiscale pore/fracture structures. Developing highly accurate multiscale models for real-time prediction of microgaseous flow in complicated porous media with pronounced contrast in transport coefficients is crucial but not yet available, which is time-consuming, expensive, and even computationally impossible. In this study, a multiscale approximate solution of the gas flow and pressure field is derived in this paper for predicting coalbed methane (CBM) transport in macro-microscopic two-scale porous media of typical coal rocks in Guizhou Province, China, and the detailed finite element algorithm is established. The multiscale approximate solutions are constructed from the first- and second-order auxiliary cell functions and low- or high-order derivatives of the homogenized pressure field, which can accurately approximate the solution of the original problem to a certain extent. The numerical accuracy and validity of the multiscale approximate solutions under various working conditions are analyzed in detail by comparing and verifying the results with the direct numerical simulation results of fine-mesh high-precision finite elements. The results show that the homogenized approximate solution can only roughly capture the characteristics of the macroscopic pressure evolution, the first-order approximate solution can partially reproduce the macro-microscopic pressure oscillation phenomenon, and the second-order approximate solution can accurately predict the pressure profile and its evolution law with time in porous media with macro-micro configuration under various complex conditions. The second- and high-order two-scale approximate solutions constructed in this paper exhibit high numerical accuracy and excellent computational efficiency. We also develop multiscale approximate solutions for predicting microgaseous flow at a low reservoir pressure where the slippage effects are very pronounced. Potential applications of our high-order models to the coal reservoirs with a hierarchical matrix and fractures are discussed. The developed multiscale models exhibit excellent applicability to investigating the crossflow effects and coupling mechanisms between the matrix and cleats or fractures with multiple configurations in the CBM and shale gas reservoirs, which is crucial for the effective implementation of hydraulic fracturing technology. This study provides a fundamental understanding of gas transport in multiscale matrix-fracture networks, which helps to improve the optimization design of hydraulic fracturing in tight reservoirs.

The in situ stress prediction of a fractured shale reservoir based on amplitude variation with angle and azimuth inversion: A case study from Southwest China

In situ stress estimation of a shale reservoir is critical for the design of shale hydraulic fracturing and wellbore stability analysis. Fractured shales have orthogonal anisotropy (OA) because of the presence of vertical fractures and lamination. However, the existing in situ stress estimation method mainly focuses on transversely isotropic media. To accommodate orthogonally anisotropic media, an in situ stress estimation method is developed by using amplitude variation with angle and azimuth inversion and linear-slip theory. First, an orthogonal anisotropic medium is introduced to characterize the fractured shale by using a linear-slip model, and then we formulate a reflection coefficient approximation for OA media to perform the seismic inversion. Next, a fracture weakness inversion strategy that incorporates the vertically transverse isotropic background is developed to obtain the stiffness matrix of the media. Finally, the in situ stresses of the OA medium are formulated by using a stress-strain relationship. Inversion tests and a real data application indicate that our method is effective.

A New Correlation for Estimating Static Elastic Properties of Sandstone Formations: Case Study from Rumaila Oilfield

Evaluating the elastic characteristics of reservoir's rocks is crucial for the oil and gas sector to reduce risks throughout drilling and production operations. Elastic parameters are essential for prediction of wellbore stability, estimation of in-situ stresses, optimization of drilling performance and design of hydraulic fracturing. Depending on the type of formation, Elastic parameter is varied dramatically. Thus, a precise way to identify these characteristics is needed. Inaccurate assessment of elastic characteristics can result in excessive expenditure and inappropriate field development plans. Static elastic modulus (Est) can be determined through laboratory testing. Although laboratory measurement is the most precise approach to determine the elastic modulus, it requires a continuous core sample to acquire a complete profile of the formation's elastic characteristics. However, just a portion of the well is typically sampled for cores. On the other hand, wireline log data is applied to determine the dynamic modulus (Edyn), allowing for continuous assessment of elastic properties. Numerous characteristics of the rock, including consolidation, pore pressure and lithology affect the dynamic modulus. Thus, it needs to be converted to Static elastic modulus by empirical formulae. Several empirical equations have been proposed to convert dynamic Young's modulus to static Elastic modulus. Nevertheless, the validity of these relationships is restricted and exclusive to certain areas. This research seeks to establish a relationship between Dynamic modulus and static Elastic modulus for sandstone formation of Rumaila oil field. The suggested correlation provides accurate predictions of the static elastic modulus for the complete sandstone segment. The newly created correlation performed better than the previous correlations in predicting static elastic modulus with average absolute error of 8.69 %, and correlation coefficient of 0.9848. The newly established empirical correlation can assist geo-mechanical engineers in estimating continuous profile of the sandstone formation's static modulus.

A New Approach to a Fracturing Sweet Spot Evaluation Method Based on Combined Weight Coefficient Method—A Case Study in the BZ Oilfield, China

The Sha3 member of the BZ Oilfield in Bohai Sea represents a typical ultra-low permeability thin interbedding reservoir. Hydraulic fracturing is an effective method for increasing oil and gas production. However, the complex geological conditions make it difficult to screen out the optimal frac spot. Consequently, the design of hydraulic fracturing exhibits certain limitations. A novel method for evaluating sweet spots is proposed, based on a refined geological reservoir model that considers the varying degrees of influence that geological and engineering factors have on fracturing effectiveness. This method utilizes grey correlation and hierarchical analysis to quantify and characterize the weight coefficients of each factor, ultimately leading to a combined weight coefficient approach. The results indicate that permeability and fracturing scale are the primary factors that impact the post-frac production of the BZ oilfield, with their respective combined weights being 0.33 and 0.25. The average weight for geological factors is 0.18, while for engineering factors it is 0.15. This suggests that geological factors have a greater influence on production than engineering factors. Furthermore, the correlation coefficient between the dual sweet spot index and the production is 0.96, indicating a strong positive correlation between the two variables. After comparing the predicted and actual production of each well, it was determined that the anastomosis rate is 80%. This finding holds significant guiding significance for selecting the optimal fracturing spot.

Utilizing well-reservoir pseudo-connections for multi-stage hydraulic fracturing modeling in tight gas saturated formations

Purpose. Research is aimed at integrating multi-stage hydraulic fracturing in horizontal wells with hydrodynamic simulation as a mandatory part of planning the mining of any shale oil or gas reservoir. Methods. Geological and hydrodynamic reservoir modeling is part of the research. The properties and geometries of the hydraulic fracture network and its representation in the dynamic reservoir model were assessed. The comparative characterization was carried out based on the two methods of fracture modeling: cell dimension reduction for explicit fracture modeling (LGR – local grid refinement) and implicit fracture modeling method, presented in this paper, with additional pseudo-connections between well and reservoir. Findings. A hydrodynamic model for low-permeable reservoir, produced by horizontal well, hydraulically fractured with 5 stages, has been generated. This model is calibrated to the production history and flowing bottom hole pressure by applying two methods of fracture modeling. Modeling results show that it is possible to replicate historical well production by using both methods. However, the proposed method with pseudo connections has several advantages compared to the generally accepted, local grid refinement (LGR) method. Originality. For the first time, a system of pseudo connections between well and reservoir was constructed to model a multi-stage hydraulic fracturing for a hydrodynamic model of tight reservoir. Hydrodynamic simulation results were refined and calibrated to the history of hydrocarbon production and flowing bottom hole pressure data using the pseudo-connections and LGR methods. The similarity of the results by applying LGR and pseudo-connections methods was revealed. Practical implications. The use of pseudo connections for hydraulic fracturing modeling can reduce simulation run time for cases where multi-stage hydraulic fracturing has already been carried out or is planned in the future. Additionally, the use of this method allows testing a larger number of realizations and scenarios, including hydraulic fracturing design (number of stages, size and conductivity of resulted fracture systems, fracture orientation, etc.), well placement and fracture growth relative to well trajectory. Also, there is no need to rebuild a model every time for each realization, as is the case with the LGR method.

Model for fracture conductivity considering particle size redistribution caused by proppant crushing

Clarifying the dynamic evolution and control mechanisms of fracture conductivity is crucial for optimizing hydraulic fracturing design. Previous studies on fracture conductivity mechanisms in deep shale reservoirs have been insufficient, particularly when considering proppant crushing, rendering existing models inapplicable. Therefore, in this study, the coupled effects of particle size redistribution caused by proppant crushing were considered. A particle crushing model based on fractal theory was introduced. It was combined with the Kozeny–Carman equation, and equations were derived for the evolution of the equivalent diameter of the proppant pile gradation curve and permeability, establishing a new model for predicting the fracture conductivity considering the particle size redistribution caused by proppant crushing. Furthermore, it provides an optimized chart of conductivity that matches the supply conductivity of the reservoir. The results of the study reveal that the fracture conductivity decreases owing to proppant rearrangement, compaction, and crushing, with a more significant decline in the initial compression stage, where the rate of conductivity reduction is 2.5 times that of the compaction stage. Proppant crushing shifts the gradation curve leftward, reducing the equivalent particle diameter and, consequently, the fracture conductivity. By adjusting the crushing ratio, apparent Young's modulus, looseness factor, and proportion of large-particle components of the proppant, the fracture conductivity can be controlled. This provides a theoretical basis for the development of proppant properties and fracturing optimization in deep shale reservoirs.

Effect of size and anisotropy on fracture process zone of coal: An experiment and numerical simulation

The size and properties of the fracture process zone (FPZ) have a significant impact on the fracture toughness of materials. Researching and understanding the characteristics of FPZ contribute to optimizing material performance and enhancing the reliability of engineering structures. In this study, the newly proposed modified semi circular bending (SCB) test method was used to carry out the pure mode I fracture test of coal samples with four sizes and four bedding angles, the development process of FPZ was obtained by using digital image correlation method, and the cohesive zone model considering the bedding plane was established. The influence of size and anisotropy on the development and size of FPZ was studied, and the influence mechanism of FPZ on the size effect and anisotropy of fracture toughness was revealed. The results show that the FPZ length of coal has obvious size effect and anisotropy. The FPZ length increases with the increasing specimen size, and increases first and then decreases with the increasing bedding angle. The FPZ relative length decreases with increasing specimen size, indicating that as the specimen size increases, the influence of specimen boundaries on PFZ gradually decreases, and the size effect of fracture toughness also gradually weakens. The competition between microcrack development driven by principal stress and microcrack development driven by bedding plane results in anisotropy in the development process of FPZ. The anisotropy of FPZ development process results in the anisotropy of FPZ length, fracture toughness and crack propagation path. The research findings can provide valuable guidance for the design of hydraulic fracturing in coal seams.

Investigation on dynamic mechanism of fault slip and casing deformation during multi-fracturing in shale gas wells

Fracturing horizontal well casing deformation has become very prominent, particularly in tectonic stress-concentrated shale gas fields, limiting the efficient development progress of shale gas. The main failure mode of casing shearing deformation had been attributed to fault slip caused by multi-fracturing. The current research did not provide a clear picture of the dynamic evolution relationship between hydraulic fracturing, fault slip, and casing deformation. In this paper, the dynamic model of fault slip induced by formation pressure change is established, incorporating the effects of stress drop, physical change of friction, and casing and cement-sheath resistance loads. The discontinuous displacement approach and explicit/implicit coupling iteration methods are used to reveal the relationships between the effective normal stress, shear stress, friction coefficient, and sliding velocity during the fault slip process. Furthermore, the microscopic process of casing deformation sheared by fault slip is investigated using static equilibrium theory, and a characterization method for determining the amount casing deformation caused by real-scale fault slip is proposed. The results show that three stages exist in the process of casing deformation sheared by fault slip, including trigger activation stage, accelerated slip stage, and deceleration slip stage. Fault slip is clearly influenced by fault strike. To reduce the amount of fault slip, the fault direction with the maximum in-situ stress should be avoided as much as possible. Serious casing deformation still occurs for large-scale activated faults even though the optimization measure of wellbore structure has been well taken. To fundamentally reduce the possibility of casing shear deformation, it is necessary to prevent fault slip through optimizing the design of hydraulic fracturing. This study lays the theoretical groundwork for the casing deformation control method in shale gas wells.

Numerical Simulation of Hydraulic Fracture Propagation on Multilayered Formation Using Limited Entry Fracturing Technique

Hydraulic fracturing is one of the most effective stimulation methods for unconsolidated sandstone reservoirs. However, the design of hydraulic fracturing must take into account the mechanical and stress properties of different geological formations between layers. In this paper, a three-dimensional coupled fluid-solid model using the finite element method is developed to investigate multiple vertical fractures at different depths along a vertical wellbore under different geological and geomechanical conditions. The finite element model does not require further refinement of any new cracks, requiring much smaller degrees of freedom and higher computational efficiency. In addition, new elements were used to account for local pressure drop due to perforation entry friction along the vertical wellbore. Numerical simulation results indicate that hydraulic fracture connections are observed from adjacent layers. Furthermore, the low stress contrast and high Young’s modulus between the layers increases the likelihood of multiple fracture connections. Higher fluid leakage rates increase the likelihood of fracture branching, but decrease the area of fracture coverage near the wellbore. Increasing fluid viscosity is effective in improving the area of fracture coverage near the wellbore. These findings are useful for the design of hydraulic fracturing in multi-layered formations in unconsolidated sandstone formations.

Variation of vertical stress in the McArthur and Beetaloo basins

The McArthur and Beetaloo basins have been the focus of unconventional hydrocarbon exploration, specifically targeting shale gas and tight gas resources. Vertical stress (SV), which is one of the three principal stresses, is a critical parameter in geomechanical analysis of sedimentary basins and has implications in fracture gradient calculation, pore pressure prediction, assessing the present-day stress regime, and hydraulic fracturing design. In addition, variations in vertical stresses can yield additional insights into the tectonic history of an area. In this study, we examine the variability of vertical stress magnitude and vertical stress gradients by employing a systematic analysis of density log and check-shot velocity data obtained from 31 wells located within the McArthur and Beetaloo basins. Our analysis revealed that vertical stress gradients range from 23 to 27 MPa/km (equivalent to ~1.0–1.2 psi/ft), with an average gradient of 25 MPa/km ± 1.0 (1.1 psi/ft). This variability in SV gradients underscores the inadequacy of the commonly assumed 1.0 psi/ft approximation for geomechanical analyses within these basins. The origins of such diverse SV gradients can be attributed to several factors; however, the likely cause of the SV gradient within this region is the presence, thickness, and depth of the shallow high-density volcanic rocks and a complex history of uplift and erosion.

Study on the Damage Mechanism of Coal under Hydraulic Load

Hydraulic fracturing is extensively utilized for the prevention and control of gas outbursts and rockbursts in the deep sections of coal mines. The determination of fracturing construction parameters based on the coal seam conditions and stress environments merits further investigation. This paper constructs a damage analysis model for coal under hydraulic loads, factoring in the influence of the intermediate principal stress, grounded in the unified strength theory analysis approach. It deduces the theoretical analytical equation for the damage distribution of a coal medium subjected to small-flow-rate hydraulic fracturing in underground coal mines. Laboratory experiments yielded the mechanical parameters of coal in the study area and facilitated the fitting of the intermediate principal stress coefficient. Leveraging these datasets, the study probes into the interaction between hydraulic loads and damage radius under assorted influence ranges, porosity, far-field crustal stresses, and brittle damage coefficients. The findings underscore that hydraulic load escalates exponentially with the damage radius. Within the variable range of geological conditions in the test area, the effects of varying influence range, porosity level, far-field stress, and brittle damage coefficient on the outcomes intensify one by one; a larger hydraulic load diminishes the impact of far-field stress variations on the damage radius, inversely to the influence range, porosity, and brittle damage. The damage radius derived through the gas pressure reduction method in field applications corroborates the theoretical calculations, affirming the precision of the theoretical model. These findings render pivotal guidance for the design and efficacy assessment of small-scale hydraulic fracturing in underground coal mines.

Shale hydraulic fracture morphology and inter-well interference rule under multi-wellbore test

Abstract This study conducted a series of true triaxial hydraulic fracturing experiments on Longmaxi Formation shale. We investigated the interaction between internal factors and external factors on the inter-well interference of 400 mm cubic porous specimens. During dual wellbore fracturing at different formations, forming inter-well interference through secondary hydraulic fractures lead to a lower interference intensity and larger stimulated rock area. When adopting a three-layer well layout during three-wellbore fracturing, the vertical distance between the wells is shortened, activating more bedding planes. Regardless of a horizontal well placement with two wellbores or a three-dimensional two-layer well placement with three wellbores, increasing the vertical stress leads to more potent inter-well interference. There is no absolute positive correlation between the stimulated rock area and inter-well interference. It can be influenced by the presence of natural fractures within the formation that can even lead to a reduction in the stimulated area. When the well placement changes from two horizontal wellbores to three-dimensional two-layer sites with three wellbores and the vertical stress increases, the inter-well interference becomes stronger, but the stimulated rock area only increases by 22.6%. These findings provide crucial guidance for the hydraulic fracturing design of shale reservoirs.

Application of the block factor analysis in the implementation of hydraulic fracturing during oil fields development

The relevance of this study is due to the need to optimize the oil production process in the fields of the West Siberian province. At the moment, the actual oil recovery factor often deviates from the design values, which leads to inefficient production and loss of resources. Therefore, the purpose of the study is to develop a meth-odology for optimizing the process of monitoring and regulating an oil field development facility using block factor analysis and de-signing hydraulic fracturing cracks. The work uses methods such as block factor analysis, 3D modeling, hydrodynamic modeling, and mathematical modeling. The result of the study is a developed methodology for optimizing the process of monitoring and regulat-ing an oil field development facility. The article also discusses the main reasons for the deviation of actual oil production from calcu-lated values, including hydraulic fracturing technology. Unsuccess-ful cases of this procedure and their causes were identified. The features of the block factor analysis tool and the proactive analysis method are described, as well as how to use it at the design and modeling stage of hydraulic fracturing to improve the efficiency of the well-stimulation operation. Successful implementation of hy-draulic fracturing allows one to approximate the actual oil recovery factor to design values, which is important for increasing the effi-ciency of production at the field and optimizing the use of re-sources.

Influence of Shale Mineral Composition and Proppant Filling Patterns on Stress Sensitivity in Shale Reservoirs

Shale reservoirs typically exhibit high density, necessitating the use of horizontal wells and hydraulic fracturing techniques for efficient extraction. Proppants are commonly employed in hydraulic fracturing to prevent crack closure. However, limited research has been conducted on the impact of shale mineral composition and proppant filling patterns on shale stress sensitivity. In this study, shale cylindrical core samples from two different lithologies in Jimusaer, Xinjiang in China were selected. The mineral composition and microscopic structures were tested, and a self-designed stress sensitivity testing system was employed to conduct stress sensitivity tests on natural cores and fractured cores with different proppant filling patterns. The experimental results indicate that the stress sensitivity of natural shale porous cores is weaker, with a stress sensitivity coefficient below 0.03, significantly lower than that of fractured cores. The shale mineral composition has a significant impact on stress sensitivity, with the stress sensitivity of clayey argillaceous shale cores, characterized by higher clay mineral content, being higher than that of sandy argillaceous shale, characterized by higher quartz mineral content. This pattern is also applicable to fractured cores filled with proppants, but the difference gradually diminishes with increased proppant concentration. The choice of large particles and high-concentration proppant bedding can enhance crack conductivity. Within the experimental range, the crack conductivity of 20–40 mesh quartz sand is more than three times that of 70–120 mesh quartz sand. At an effective stress of 60 MPa, the conductivity of cores with a proppant concentration of 2 kg/m2 is 3.61 times that of cores with a proppant concentration of 0.3 kg/m2. Under different particle size combinations of proppant filling patterns, the crack conductivity at the crack front with large-particle proppants is 6.21 times that of mixed bedding. This study provides valuable insights for the hydraulic fracturing design of shale reservoirs and optimization of production system parameters in subsequent stages.

Toward real-time fracture detection on image logs using deep convolutional neural network YOLOv5

Fractures in reservoirs have a profound impact on hydrocarbon production operations. The more accurately fractures can be detected, the better the exploration and production processes can be optimized. Therefore, fracture detection is an essential step in understanding the reservoir’s behavior and the stability of the wellbore. The conventional method for detecting fractures is image logging, which captures images of the borehole and fractures. However, the interpretation of these images is a laborious and subjective process that can lead to errors, inaccuracies, and inconsistencies, even when aided by software. Automating this process is essential for expediting operations, minimizing errors, and increasing efficiency. Although there have been some attempts to automate fracture detection, this paper takes a novel approach by proposing the use of YOLOv5 as a deep-learning (DL) tool to detect fractures automatically. YOLOv5 is unique in that it excels at speed, training, and detection while maintaining high accuracy in fracture detection. We observe that YOLOv5 can detect fractures in near real time with a high mean average precision of 98.2, requiring significantly less training than other DL algorithms. Furthermore, our approach overcomes the shortcomings of other fracture detection methods. Our method has many potential benefits, including reducing manual interpretation errors, decreasing the time required for fracture detection, and improving fracture detection accuracy. Our approach can be used in various reservoir engineering applications, such as hydraulic fracturing design, wellbore stability analysis, and reservoir simulation. By using this technique, the efficiency and accuracy of hydrocarbon exploration and production can be significantly improved.

Influence of non-intersecting cemented natural fractures on hydraulic fracture propagation behavior

Fractures in deeply buried or formerly deeply buried rocks commonly contain mineral deposits having varying degrees of strength. Understanding how cement deposits in fractures interact with hydraulic fractures (HFs) is important for hydraulic fracture design for practical engineering applications such as enhanced geothermal fluid circulation or oil and gas production. Using discrete element methods, we describe a fully fluid-solid coupling numerical model simulating hydraulic fracture propagation to investigate the influence of cemented natural fractures (CNFs) that do not intersect the predicted path of hydraulic fractures on HF propagation morphology. The fracture morphology depicted by the numerical model aligns well with analytical solutions, indicating the reliability of the simulation results. Using this model, we delved into the effects of fracture cement strength and position, fracturing fluid viscosity, and induced stress field on the interactive propagation patterns of fractures. The simulation results indicate that the HF is captured by weakly non-intersecting CNF, causing the activation of the CNF and the development of cracks primarily caused by tensile failure. As the HF approaches the CNF, the induced tensile stress region at the fracture tip offsets toward the CNF, resulting in fracture reorientation. When the cementing strength ratio between pre-existing natural fracture and reservoir matrix is less than 0.5, it is beneficial to activate CNF and enhance reservoir permeability. The seepage of low-viscosity fracturing fluid into the reservoir significantly enhances the ability of the HF and non-intersecting CNF to communicate with each other, thereby providing favorable pathways for oil and gas flow. The research findings offer valuable insights into fracture network connectivity and permeability enhancement, contributing to enhanced reservoir stimulation strategies.