Hydraulic Fracture Modeling Research Articles

Injection Temperature Impacts on Reservoir Response during CO2 Storage

Summary Sustained injection of industrial-scale volumes of cold CO2 into warmer subsurface rock will result in extensive cooling which can alter rock mass mechanical behavior and fluid migration characteristics. Advanced simulation tools are available to assess and characterize such phenomena; however, the effective use of these tools requires appropriate injection temperatures and rock thermophysical parameters (in addition to geomechanical and hydraulic properties). The primary objective of this study was to demonstrate the sensitivity of injection-induced tensile fracturing and fault reactivation to injection temperature and reservoir thermophysical properties during CO2 injection operations. This was achieved by (1) compiling and reviewing thermophysical parameter data available for formations in the province of Alberta, Canada, and CO2 injection temperature records for CO2 injection projects in western Canada and (2) using a 3D, physics-based, fully integrated hydraulic fracturing and reservoir simulation numerical model to examine the geomechanical response of several potential CO2 reservoirs in the Alberta Basin as a function of injection temperature, thermal conductivity (TC), and coefficient of linear thermal expansion (CLTE) values. The simulation results indicate that reducing the fluid injection temperature from 15°C (assumed in previous work) to 2°C (conservative value selected based on temperature data reviewed in this work) could trigger extensive vertical (20–130 m high, 100–600 m long) tensile fractures with rapid fracture initiation and full vertical growth within short periods (weeks to months) and continued horizontal length increase. When low values for thermophysical properties are used, the results show that thermally-induced tensile fracturing is unlikely, whereas the use of high values results in extensive tensile fracturing in all simulations. A similar conclusion was reached for the thermally-induced reactivation (unclamping) of proximal, critically-stressed faults. Notably, slip is predicted for all simulations where high thermophysical property values are used. This confirms that accurate determination of minimum fluid injection temperature and thermophysical parameters is important for containment risk assessment for commercial-scale CO2 storage projects. Another significant outcome of this work is the observation that most thermophysical parameters in the available data were measured using experimental conditions and/or temperature paths that are not representative of CO2 injection projects. As such, the development and validation of best practice approaches for accurate assessment of these parameters seem necessary.

Physical Modeling of Hydraulic Fracturing in Cross Boreholes in Nonuniform Stress Field

Physical Modeling of Hydraulic Fracturing in Cross Boreholes in Nonuniform Stress Field

How does the heterogeneous interface influence hydraulic fracturing?

Under the influence of the nonlinear fluid-solid coupling, hydraulic fracture exhibits various propagation modes (such as toughness- or viscosity-dominated), which stem from the competition between the solid deformation and fluid flow. Based on the homogeneous assumption, the basic theoretical analysis has divided toughness and viscosity scales in the tip region. However, regarding more realistic and complex geological conditions, like layered heterogeneity, knowledge of fluid-driven fracture propagation is still unclear. This work establishes a theoretical model and solving approach to reveal the multiscale asymptotic behavior during hydraulic fracture passing through the heterogeneous interface (i.e., discontinuous elastic properties). The influence of material discontinuity, regarded as the remote force, in the near-tip, intermediate, and far-field scales is analyzed by the asymptotic analysis and validated by the numerical solutions. Notably, solutions at the intermediate scale manifest as individual feature owing to the heterogeneity: as the crack in front of the interface, just a specific transition solution governed by the property and position of the interface appears; once the crack tip passes the interface, the interface-governed transition solution and interface solution occur simultaneously and interact as the crack tip moves away from the interface. Such multiscale property results in the interface-governed fluid-solid interaction in the tip region, and finally leads to changes in interface failure and propagation mode. On the one hand, the criterion for interface failure should be modified by simultaneously incorporating the heterogeneity of solid domain and multiscale nature of tip solution, especially for viscosity- or interface-dominated propagation regimes. On the other hand, the propagation mode in a heterogeneous domain is controlled by two characteristics: traditional l/lmk for toughness-viscosity competition associated with c/Lμ for material discontinuity effect proposed in the present work. These insights provide the theoretical foundation for modeling hydraulic fracture propagation in layered heterogeneous domains.

2D Phase-Field Modelling of Hydraulic Fracturing Affected by Cemented Natural Fractures Embedded in Saturated Poroelastic Rocks

AbstractThe interaction between a propagating hydraulic fracture (HF) and a pre-existing natural fracture (NF) embedded in saturated poroelastic rock formations is studied numerically in 2D plane–strain configurations. In this study, the phase-field method is further developed to be employed for modelling the HF propagation and the evolution of tensile and shear failure in geo-materials as gradient-type diffusive damaged zones. The shear slippage and dilation mechanisms inside the cemented NF are modelled using a Mohr–Coulomb–Griffith failure criterion that fitted in the framework of the phase-field fracture using appropriate energy functionals. The most important factors controlling the HF–NF interaction outcome are the approaching angle, differential in-situ stress, and hydro-mechanical characteristics of the NF. It is found out that higher tensile and shear strengths of the cemented NF are in favour of the crossing outcome when the differential stress is high enough to mobilise the resisting shear stresses against the slippage. Small hydraulic aperture (low hydraulic conductivity) for the NF is also in favour of the crossing outcome which helps to restrict the pressurised region local to the HF tip, lowering the possibility of shear slippage in the NF and the HF’s diversion. It is also concluded that the injection rate and the viscosity of fracturing fluid are operative factors to be adjusted for increasing the chance of crossing, a critical element for successful operation of hydraulic fracturing for effective use of subsurface energy resources.

A comprehensive review of numerical simulation methods for hydraulic fracturing

AbstractHydraulic fracturing unlocks previously inaccessible hydrocarbons in unconventional reservoirs by creating artificial pathways in the unconventional reservoir. Numerical simulation expands the scope of hydraulic fracturing design for various reservoir conditions. This review paper explores the synergy between numerical simulation and hydraulic fracturing modeling, focusing on critical elements like geomechanical behavior, geological conditions, and fluid dynamics. Analytical models in hydraulic fracturing design are discussed to underscore their foundational importance. The assumption of constant fracture height limits the application of Perkins–Kern–Nordgren model (PKN) and Kristianovich‐Geertsma‐de Klerk model (KGD). Radial models assume 3D flow but lack reliability in nonradial settings, and the Pseudo 3D model (P3D) shares PKN's assumptions with variable fracture height, sacrificing some details for efficiency. Planar 3D model (PL3D) enhances accuracy by discarding PKN's elastic response assumption but requires extended computation. Unconventional fracture model is effective for complex scenarios but relies on DFN modeling parameters for accuracy. The choice of numerical simulation method in hydraulic fracturing depends on the specific aspect studied, each with its strengths and limitations. For instance, boundary element methods are efficient for exterior problems, finite element modeling suits 3D nonplanar fractures, and the extended finite element method excels in hydraulic and natural fracture interactions. Peridynamics shows potential but needs further development for cost‐effectiveness. PFC and UDEC/3DEC‐based simulations can explore microscopic mechanisms. Combining these methods with other approaches provides a comprehensive study of realistic reservoir conditions. This review guides the selection of a suitable numerical simulation methodology based on the study's scope.

Investigation on failure behavior and hydraulic fracturing mechanism of Longmaxi shale with different bedding properties

Research on the failure behavior and hydraulic fracturing mechanism of Longmaxi shale is vital for deep shale gas exploitation. The anisotropic properties of shale, especially bedding properties, significantly affect its cracking behavior. In this study, by embedding the smooth joint model (SJM) into the parallel bond model (PBM) in two-dimensional particle flow code (PFC2D), uniaxial compression and fluid–solid coupling hydraulic fracturing models with different bedding properties were quantitatively established, and the effects of bedding properties on the failure behavior and hydraulic fracturing mechanism of Longmaxi shale were investigated. The results demonstrated that bedding properties significantly affect the failure pattern, strength response and hydraulic fracture propagation of shale. Shale failure is controlled by bedding inclination, bedding strength, and maximum principal stress, which mainly depends on their competition mechanism. In addition, it is found that the secondary induced fractures associated with primary through-bedding fractures tend to have larger fracture networks compared with those associated with primary along-bedding fractures.

Modelling of hydrofracturing experiments of granite samples

Based on laboratory experiments and numerical modelling, the propagation of hydraulic fracturing fractures in cylindrical granite samples caused by viscous fluid pumping is described. Comparison of simulation results and laboratory measurements show that the fracture hydraulic resistance much greater than the one predicted by the cubic law that is usually used in hydraulic fracture models. If this hydraulic resistance is not taken into account, the pressure, volume and speed of fracture propagation are predicted incorrectly. It is shown that additional hydraulic resistance can be caused by the fracture walls roughness and can be taken into account by velocity correction factor.

Результаты определения коэффициента пористости в нефтенасыщенных глинистых породах

The article studies the wells that opened clayey reservoirs of Paleogene age. When predicting the trajectory of a crack during hydraulic fracturing (HF), it is necessary to take into account the percentage of minerals in the rock, since cracks during hydraulic fracturing are formed at the contacts between mineral grains. This conclusion is indisputable, but obtaining complete information about the percentage of minerals in a rock is an expensive and not always feasible task. At the same time, the physical and mechanical characteristics of clayey rocks are no less significantly influenced by their porosity. Therefore, it is important to note that a reliable determination of the porosity coefficient from the exposed geological section will undoubtedly have a primary positive impact on the reliability of hydraulic fracturing modeling. Based on this, in wells that opened clayey reservoirs, the values of porosity coefficients determined by various methods were analyzed, including the direct one – analysis of core, cuttings and the indirect one – geophysical methods. During the work, a coincidence of the porosity coefficient in the core, cuttings and electrical logging was discovered. Based on the results of the study, it can be concluded that the porosity coefficient determined from acoustic logging (AL) significantly exceeds the values of the porosity coefficient determined from core, cuttings and induction logging. This is due both to the influence of clay content on the acoustic logging readings, and due to the low quality of AC materials induced by erosion of the wellbore. It should be noted that the calculations of porosity coefficients in the above-reference part – in the Batalpashinsky formation based on core and induction logging – coincide almost completely. However, in the sub-reference part of the formation the readings differ slightly. The porosity coefficient calculated is a maximum of 2% lower than the porosity coefficient determined from the core, which is quite acceptable.

Analysis of dynamic thermal behaviors for multi-stage hydraulic fracturing treatments in horizontal shale oil and shale gas wells

Accurate prediction of dynamic thermal behaviors during multi-stage hydraulic fracturing is profound which can avoid performance deterioration of fracturing fluids or failure of fracturing tools caused by severe temperature variation. This paper establishes a transient heat transfer model for multi-stage hydraulic fracturing in horizontal shale oil and shale gas wells (MFHWM), considering the real construction process of multi-stage hydraulic fracturing, the turbulent flow state, the heat source of viscous dissipation and the complex wellbore structure, which enables the accurate simulation of thermal behaviors in the early time of multi-stage hydraulic fracturing with large flow rate. The verification results of measured temperature data and simulation data prove the MFHWM has good precision. Numerical simulations indicate that the temperature distribution exhibits the characteristics of cyclic “cool-down” and “warm-back” and “stair-step” during the multi-stage hydraulic fracturing. In the “cool-down” period, the temperature drops sharply within the first hour and then the deceleration slows down. In the “warm-back” period, the temperature recovers exponentially relying on the shut-in time. The “stair-step” is caused by changing of heat transfer mechanism from convection to conduction. Moreover, the cyclic cooling has little effect on the total temperature drop and subsequent stages are not significantly cooler than previous stages. Besides, primary factors affecting temperature distributions of wellbore-formation system are discussed thoroughly. Results indicate that the viscous heat source cannot be ignored for multi-stage hydraulic fracturing and the temperature difference exhibits cyclic variation when considering and without considering the viscous heat source. In addition, the minimum temperature during each-stage-fracturing operation decreases first and then increases as the injection rate of fracturing fluid increases because of the compromise between the viscous heat source and forced convection. Furthermore, temperature distributions can be controlled by changing the injection temperature of fracturing fluid. As the injection temperature increases, a positive proportional relationship exists between the minimum temperature of fracturing fluid and the injection temperature. MFHWM can be a standalone tool to analyze temperature distributions of multi-stage hydraulic fracturing. It can also be used to provide better boundary conditions for stress analysis model of casing and cement sheath.

Laboratory validation of a new hydro-mechanical energy-based brittleness index model for hydraulic fracturing

Brittleness Index (BI) is a critical parameter characterising the deformation regime of geo-materials, covering the range from purely brittle (fractures) to ductile (plastic flow). A variety of BI models have been developed based on rock properties such as mineralogy, elastic parameters, or constitutive law. However, very few of them are based on the hydro-mechanical interactions emerging in underground engineering applications. In this study, we propose a BI model based on the partitioning of the injection energy EI into non-seismic deformation energy Ed associated with hydraulic fracture propagation. To calculate the Ed, we apply a model for temporal fracturing area (Ad) within the penny-shaped fracture; and we also correlate the wellbore pressure and the three-dimensional strain induced by hydraulic fracturing of the different types of rock samples subjected to true triaxial stress conditions (TTSC), either σv = 6.5 MPa, σH = 3 MPa, σh = 1.5 MPa or σv = 15 MPa, σH = 10 MPa, σh = 5 MPa. As a comparison, the BI is also quantified based on the existing models: (i) acoustic measurement from Rickman et al. (2008), and (ii) the Mohr-Coulomb’s criteria from Papanastasiou et al. (2016). The Ed ranges between 32.4% and 90.6% of the total injection energy EI, which is slightly higher than the value reported from field-scale data (15% to 80%), but comparable to laboratory-derived data (18% to 94%) from literature. The results show that the predictions based on our proposed energy-based BI model are qualitatively consistent with Papanastasiou et al.’s, but less so with Rickman et al.’s. Our BI model is shown to be stress-dependent and capable of capturing the brittle-to-ductile behaviour of geomaterials subjected to hydraulic fracturing. This study demonstrates that our BI model opens a new way for quantifying the brittleness index regarding to realistic fracture propagation scenarios in field.

Guest Editorial: The Engineer of the Future

Recently, at the SPE Annual Technical Conference and Exhibition, I was asked a question about the ‘engineer of the future.’ As we take a pause to turn the page to next year, I believe now is a prescient time to contemplate what’s next for petroleum engineering. Throughout my career, I’ve been able to witness great change in our industry as the shale revolution took hold making horizontal drilling and hydraulic fracturing commonplace, diagnostic and modeling tools improved in access and cost, and data became more timely and readily available. This led to a tremendous period of US energy supply growth and decades-long productivity improvements. Looking forward, I believe there are three trends that engineers should consider: 1) applying “new” tools to solve “old” problems, 2) connecting the dots via hybrid engineering, and 3) organizing, directing, and inserting data predictions into their workflow. These are not only my views but also the views of Devon’s talented engineers. Old problems will meet new solutions. The past decade has been dominated by unconventional horizontal development that was first pioneered in the Barnett Shale for natural gas and shortly thereafter transitioned into oil-focused development in the Bakken and Eagle Ford. Today, the Permian Basin continues to grow in total supply as the stacked pay is developed. Engineers should take stock of the tool set we have acquired during this era with a mindset to deploy these methodologies to tier II unconventional extensions, previously developed or bypassed conventional formations, offshore and international opportunities, enhanced recovery projects such as EOR and refracturing, and new energy opportunities like geothermal. To make these future opportunities competitive and meet the global demand for energy, we will likely need a combination of price, technology, and cost improvements. Engineers are critical to the latter two. To better illustrate these points let’s utilize examples. Drilling rig specification improvements have been coupled with material science and design improvements in bottomhole assemblies. The outcome is improved topdrives and mud pressure systems to power more durable and efficient downhole motors and bits, thus reducing failures, enhancing the efficiency of a rig’s daily footage, and enabling longer laterals. If we pivot to the completion space, our diagnostics for frac geometry have gone from limited and costly to a menu of options that provide fit-for-purpose diagnostics and costs. Devon deployed its first permanent fiber diagnostics in unconventional shale in 2012. Today, the same system is readily available but for a much lower cost. However, more frequently Devon has supplemented this tool with dip-in fiber and a proprietary methodology called sealed wellbore pressure monitoring to gather more frequent data points for frac geometry and design. As our team conducted, in cooperation with the US Department of Energy (DOE), a novel Eagle Ford project capturing horizontal core and completion diagnostics, we recognized that our designs have tremendously improved in efficiency but still have potential to capture more of the resource via initial and secondary fracturing efforts.

Mechanical characteristics and reservoir stimulation mechanisms of the Gulong shale oil reservoirs, the northern Songliao Basin

Shale oil of the Qingshankou Formation of the Gulong Sag, the northern Songliao Basin, represents the first attempt at large-scale development of pure-shale-type shale oil in China. By integrating the multi-scale refined reservoir characterization with macro-micro-scale mechanical testing, it is clarified that the Gulong shale is characterized by high clay mineral content, high rock plasticity, highly-developed bedding, and prominent mechanical anisotropy. A three-dimensional (3D) fracture propagation model of hydraulic fracturing was built for the Gulong shale, which fully captures the hydraulic fracture distribution pattern affected by the high bedding density, in-situ stress, and fracturing treatment parameters. Our research showed that due to influences of bedding, hydraulic fracturing in the Gulong shale forms a complex fracture morphology featuring the main fracture with multiple perpendicular branches that have different lengths (like the outdoor directional TV antenna); however, the vertical propagation of fractures is inhibited, and the fracture height is commonly less than 10 m. The limited stimulated reservoir volume (SRV) is the main problem facing the fracturing stimulation of the Gulong shale oil. Bedding density has vital effects on fracture morphology, so case-specific fracturing designs shall be developed for shale intervals with different bedding development degrees. For reservoirs with well-developed bedding, it is suggested to properly increase the perforation cluster spacing and raise the volume and proportions of viscous fluids of the pad, so as to effectively promote vertical fracture propagation and improve reservoir stimulation performance. This study integrates multi-scale fine reservoir characterization and macro-micro-scale mechanical testing, as well as the construction and numerical simulation of hydraulic fracturing models for high-density layered shale reservoirs, providing a new approach and methodological framework for the fracturing research of high-density layered shale reservoirs.

Technology Focus: Hydraulic Fracturing Modeling (November 2023)

The purpose of hydraulic fracture modeling is to improve engineering decision-making. Success requires practical knowledge, engagement with real data, theoretical understanding, and critical thinking. The payoff is tremendous; design improvements routinely yield major uplifts in well performance and project economics. What types of papers push forward the state of the art for hydraulic fracturing modeling? In the pure development of models, practitioners adopt different philosophies. Some seek faster running models for quicker results. Others focus on integration of physics, trying to capture the essential elements of all key physical processes and how they interact. Still others focus on high-precision answers to narrower aspects of the problem. The appropriate emphasis depends on the context of how and why the model is being used. Many of the most influential papers of the past decade on hydraulic fracture modeling have not been modeling papers at all. Modeling depends on formulating a realistic conceptual model. New types of data collection and new ways of analyzing and interpreting data have given engineers a much clearer picture of what is happening in the subsurface. Extraordinary field-scale data-collection projects have given us calibration data that is not available from any other means. With a firmer foundation of knowledge, engineers can construct models that are not only precise but also, more importantly, accurate, and can apply them to solve practical problems. The work flow—how modeling is integrated with field data, practical knowledge, and engineering decision-making—is just as important as the model itself. Thus, papers that offer practical case studies are valuable because they demonstrate work flows and success stories that others can build upon. Hydraulic fracture modeling continues to be a vital contributor across a range of applications: shale, conventional reservoirs, and developing areas such as enhanced geothermal systems. Recommended additional reading at OnePetro: www.onepetro.org. SPE 212328 Interpretation of Fracture Initiation Points by In-Well Low-Frequency Distributed Acoustic Sensing in Horizontal Wells by Smith Leggett, Texas Tech University, et al. URTeC 3864951 Revealing the Production Drivers for Refracs in the Williston Basin by Alexander Cui, Novi Labs, et al. SPE 214784 Application of Hybrid Physics-Based and Data-Driven Fracture Propagation Modeling for Characterizing Hydraulic Fracture Geometry in Unconventional Reservoirs by K. Aldhayee, Texas A&M University, et al.

Fracture Conductivity Work Flow Models Well Spacing, Completions Design

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2023-3864710, “A Comprehensive Simulation Study of Hydraulic Fracturing Test Site 2 (HFTS-2): Part I—Modeling Pressure-Dependent and Time-Dependent Fracture Conductivity in Fully Calibrated Fracture and Reservoir Models,” by Han Li, Jichao Han, SPE, and Jiasen Tan, SPE, Occidental Petroleum, et al. The paper has not been peer reviewed. _ Combining fracture and reservoir diagnostic analysis with integrated geomechanics and reservoir simulation is an efficient and cost-effective approach to generate realistic fracture geometry, understand fluid flow behavior, and define fracture-conductivity distribution in unconventional reservoirs. The complete paper presents a case study of integrated geomechanical and reservoir simulation with a developed fracture-conductivity-calculation work flow that was validated with diagnostic results to evaluate well spacing and completions design. Introduction This study extends that of previous authors by matching field fracture diagnostics and reservoir simulation using variable fracture conductivity. In the example used by the authors from the Hydraulic Fracturing Test Site 2 (HFTS-2) development, multiple fracture diagnostic methods were used to calibrate hydraulic fracture models. Once the model was calibrated, a new proppant-conductivity algorithm assigned conductivity values along the hydraulic fractures based on a physics-based model calculation of proppant concentration. Multiple mechanisms, such as stress- and pressure-dependent effects, time-dependent conductivity degradation, unpropped fractures, and proppant embedment, can all be considered in the novel fracture-conductivity-calculation methodology. Fracture-Conductivity-Calculation Work Flow The conductivity work flow developed by the authors uses simulated proppant concentration from a fracture model and experimental conductivity measurements of propped and unpropped fractures to define variable conductivity along hydraulic fractures. Conductivity measurements included sets of long-term (50-hour) experimental fracture-conductivity tests with various mesh sizes, proppant types, and closure stresses. The conductivity-calculation work flow developed by the authors was applied to the integrated simulation project of multifractured horizontal wells in the HFTS-2 project. Fig. 1 shows a flow chart of the work flow from fracture propagation modeling through integrated reservoir simulations. In general, the work flow consists of developing a 3D geological model, creating and calibrating parent wells’ hydraulic fracture models, calculating the fracture conductivity based on proppant concentration, history-matching the parent wells’ production and constraints with reservoir simulation, performing fracture-propagation modeling for child wells, and history matching and predicting the estimated ultimate recovery (EUR) for the entire pad. HFTS-2 Project Overview The HFTS-2 is in the Delaware Basin and is a cost-shared, field-based project designed to study hydraulic fracturing processes and production using state-of-the-art diagnostics, including fiber optic (FO) distributed temperature sensing and distributed acoustic sensing (DAS) pressure monitoring, image logs, cores through the fractures, and microseismic monitoring. Many studies have detailed the project overview of the HFTS-2, and this paper’s authors only include the overview of completions in the HFTS-2 project.

An XFEM-based CZM Numerical Strategy for Modeling Hydraulic Fracture Propagation under Different Fracturing Schemes

Segmented and cluster fracturing can improve the efficiency of volume stimulation in shale reservoirs and reduce construction costs. It is important to clarify the propagation characteristics of hydraulic fractures and stress interference under different fracturing techniques to optimize the process of clustered and staged fracturing. For this purpose, we have developed a 2D XFEM-based CZM hydraulic fracturing model. The capability of this model was validated by analytical solutions and then used to study the propagation paths of hydraulic fractures and the characteristics of stress interference under simultaneous fracturing, sequential fracturing, zipper fracturing and multi-cluster fracturing. The results show that in simultaneous fracturing, the middle cluster is compressed by the external position clusters, and the opening width of hydraulic fractures is reduced. In sequential fracturing, the fracture that first initiates create an additional stress field that inhibits the propagation distance of subsequent fractures and the propagation path of hydraulic fractures is also affected in the stress shadow region. Zipper fracturing can effectively alleviate stress interference between multiple fractures, and internal fractures can also propagate a certain distance. In multi-cluster fracturing, the fluid rate into the internal fractures may be limited, and fracture propagation is also limited by stress interference. Therefore, it is necessary to optimize the parameters of clusters to ensure that all clusters can initiate fractures normally. The research results are important for the parameter optimization of clustered and staged fracturing, especially for well factory fracturing mode.

Numerical simulation of hydraulic fracture extension patterns at the interface of coal-measure composite rock mass with Cohesive Zone Model

This study presents the development of a numerical computational model for hydraulic fracturing of coal-measure rock mass. The model is based on the B-K hybrid fracture energy criterion and is implemented using the extended finite element method (XFEM) and cohesive zone model (CZM) in the ABAQUS software. The study took into account the elastic-plastic damage properties of the coal-measure rock mass, as well as the combined effects of tensile and shear damage during the start and expansion of hydraulic fractures. The expansion trajectories and fracture morphology of hydraulic fractures at the interface of coal-measure rock mass under different lithological combinations (lithological strength differences) and ground stress conditions are revealed, and the main controlling factors affecting the expansion across the bedding are clarified. The study provides valuable insights into the management of hydraulic fracturing in the challenging context of hard roof coal mines, the stimulation of coal-measure gas co-production reservoirs, and the development of effective fracturing stimulation strategies for shale oil reservoirs interlayered with thin sandstone, and it can promote the development of industrial production technology for coal-measure gas and shale oil and gas resources, and is beneficial to increase the proportion of clean energy in China's energy consumption structure, and thus promoting a further reduction in the carbon emissions from energy consumption.

DEM-based study of hydraulic fracturing mechanism under high internal water pressure

To solve the problem of fracturing due to high water pressure when pumping in the diversion tunnel, the mechanism of hydraulic fracturing (HF) in the tunnel under high internal water pressure is studied. A numerical model of HF considering water-rock interaction is established using the PFC2D discrete element simulation software. The HF mechanism of surrounding rock under high internal water pressure is studied, and the development process of hydraulic cracks is obtained. The influence of surrounding rock parameters on fracturing is analyzed and the law between principal stress and crack development is investigated. The high-pressure water injection test under different tunnel diameters is also carried out. Numerical test research shows that under the action of high internal water pressure, the surrounding rock at the cavity wall splits first, and the water entering the crack generates water pressure on the crack sidewall, which in turn generates tensile stress at the crack tip and further causes the crack expansion. The crack length is exponentially related to the internal water pressure. The high internal water pressure decays gradually with the crack extension distance and stabilizes when the crack extension reaches a certain length because the water pressure is less than the tensile strength of the surrounding rock. The fracturing results indicate that the process of HF damage is tensile types, and the increase of cohesion plays a suppressive role in crack opening, while the internal friction angle has little effect on the HF effect. The influence of principal stress on the HF result shows that the direction of HF is along the direction of major principal stress. The major principal stress promotes the cracking, while the minor principal stress inhibits the crack growth. By simulating the water injection test for different hole diameters of the diversion tunnel, it is found that the fracturing distance of the surrounding rock increases approximately linearly with the increase of the hole diameter. The test results can provide a basis for the design and construction of high-pressure tunnels such as pumped storage power plants.

Подходы к разработке гидроразрыва пласта и оптимизация к повышению продуктивности скважин

The issues of the approach and optimization of the productivity of wells due to the hydraulic effective measures to increase the intensity of oil inflow at the Kudinovsky field are considered. The solution of the problem for selecting the optimal fracture geometry of the hydraulic fracturing is based on the selection of hydraulic fracturing technology which takes into account various features of the formation and the design of the well. As a result of the analysis the technology of hydraulic fracturing was justified and proposed. In the course of the study the methods of theoretical and empirical knowledge were applied. These methods consist in the classification and analysis of existing hydraulic fracturing models, in the application of mathematical and numerical modeling of the operation of a well with fracturing fractures and in the measurement and analysis of field data of the operation of wells with hydraulic fracturing. The results of the research may indicate the prospects of this direction and may be recommended for use in the development of oil-saturated deposits.

Generation mechanism and influencing factors of fracture networks during alternate fracturing in horizontal wells

Hydraulic fracturing is an effective means to increase natural gas production, and alternating fracturing is a special fracturing method. Compared with sequential fracturing, alternating fracturing is easier to form complex fracture networks. In order to investigate the generation mechanism of complex fracture networks during alternate fracturing, we conducted several multi-stage hydraulic fracturing experiments indoors with different fracturing sequences. Based on the cohesive element method, a numerical hydraulic fracturing model was established, from which the stress interference affected by the fracture spacing and horizontal in-situ stress were analyzed. The results show that: Alternate fracturing is more effective in controlling fracture geometry than sequential fracturing, which is also advantageous in shortening fracture spacing and avoiding the penetration of adjacent fractures. The critical factors affecting the branch fractures are the fracture spacing and the number of main fractures. Alternating fracturing is easier to produce branch fractures perpendicular to the main fracture. The stress interference among main fractures will change or reverse the stress field. The branch fractures closed due to the competition mechanism at the fracture tip are reactivated and extended perpendicular to the main fracture. Alternate fracturing is beneficial in activating microfractures near the main fractures, especially under a larger stress difference. The number of micro-fractures activated by alternating fracturing was more 14% and 21% than the sequential fracturing with the stress difference of 3 MPa and 11 MPa. The increase in stress difference and fracture spacing will decrease the fracture fractal dimension, and the fractal dimension of alternating fracturing is 0.054 more than that of sequential fracturing.

Criteria for discriminating layer-penetration fracturing considering pressure drop and interfaces

Accurately predicting fracture height growth in a stratified reservoir presents a significant challenge. In this study, we have developed a semi-analytical prediction model for fracture height growth that accounts for pressure drop effects and considers the influence of bedding interfaces, all based on the principles of equilibrium height theory. The methodology involves solving intricate nonlinear equations and generating fracture height profiles, systematically investigating the effects of various factors: in-situ stress, fracture toughness, fluid density, and perforation location on fracture height. Sensitivity analysis of the model has revealed findings: (1) The presence of a stress barrier leads to a substantial increase in the induced stress required for fracture height growth. In particular, the stress barrier inhibits growth on one side while promoting it on the opposite side. (2) The influence of the fracture toughness barrier on fracture height growth, while significant, is overshadowed by that of the stress barrier. An increase in the fracture toughness of the rock decelerates the rate of fracture height growth but simultaneously raises the required induced stress for layer penetration. (3) Increasing the density of the fracturing fluid exerts a dual effect, slowing the growth rate of the upper fracture tip while accelerating the advancement of the lower fracture tip. Higher fluid density, under constant perforating pressure, results in a noticeable reduction in overall fracture height. (4) Fracture growth from the low-stress layer to the high-stress layer required an increase in induced stress. The research findings not only provide essential data on fracture height profiles, enhancing the applicability of the pseudo-3D hydraulic fracture propagation model, but also contribute to the refinement of governing equations within hydraulic fracture modeling.