Hydraulic Fracture Propagation Research Articles

Propagation and distribution of shear and tensile hydraulic fractures affected by frictional coal beddings.

As a typical sedimentary rock, coal seams are usually rich in bedding planes, which significantly affect the propagation process of hydraulic fracture (HF) network and reservoir permeability. In this study, the profile characteristics and the bedding roughness of the coal seam at depth of 2800m from Daniudi Gas Field in China is investigated. The failure mechanism of shear-expansion effect under low pressure and dynamic shear under high pressure of coal beddings induced by the dissolution-corrosion effect of fracturing liquid is analyzed. The development process of HF network under different bedding angles, joint roughness coefficients (JRCs), stress differences, and confining pressures is numerically simulated by cohesive element method. Results show that the JRC of coal beddings has significant effects on the morphology of HF networks. When the JRC exceeds 15, a HF network structure with tensile main fractures and shear secondary cracks is developed. The shear fractures account for a considerable proportion (33-66%) multi-layer layered coal seams and should be taken seriously during reservoir reconstruction. As confining pressure increases, the total length of tensile HFs sharply decreases, while the change in the total length of shear HFs is not significant. When the confining pressure increases from 5 to 15MPa, the length ratio of shear HFs to tensile hydraulic fractures increases from 0.36 to about 1, confirming that increasing confining pressure can promote the transformation of HF failure types from tension to shear. The ratio of secondary crack to main crack length is between 6.31 and 9.78, indicating the secondary fractures occupy an absolute proportion in the hydraulic fracture network. This study is of significance for understanding the hydraulic fracture network development in coal reservoirs.

Characterizing the Hydraulic Fracture Propagation Behavior in Deep Fractured Formations Based on DDM and FVM

Characterizing the Hydraulic Fracture Propagation Behavior in Deep Fractured Formations Based on DDM and FVM

Numerical investigation on hydraulic fracture propagation mechanism in fault-karst carbonate reservoir

The fault-karst reservoir takes the fault-controlled fracture-cavity system as storage space, which is surrounded by a large number of high permeability zones. The distribution of reservoir seepage field has an important influence on fracture propagation behavior during the hydraulic fracturing process. Based on statistical damage mechanics theory and finite element method, this paper established a seepage-stress coupling numerical model of fracture propagation under the complex medium condition of matrix-cave-natural fracture in fault-karst carbonate reservoir. This new model innovatively considers the effects of matrix seepage, which is generally ignored by the traditional numerical models, for simulating the fluid–solid coupled fracture propagation behavior. The communication mechanism between fracture and cave is first revealed. The influence of geologic and engineering factors, e.g., permeability in high permeability zone around cave and injection rate etc., on hydraulic fracture propagation in fault-karst reservoir is studied. The results show that the high permeability zone around cave can provide sufficient infiltration capacity to communicate fracture with cave in the form of fluid pressure through fluid flow and fluid pressure conduction, even if hydraulic fracture does not directly communicate the cave. Hydraulic fracture is deflected to the direction of cave under the influence of seepage field, but the deflection angle is mostly within 10°. The high permeability of high permeability zone around cave and the short cave offset distance are conducive to the virtual communication between fracture and cave. Communicating fracture with cave in the non-principal stress direction can be accomplished by fluid flow and fluid pressure conduction, optimizing hydraulic fracturing treatment parameters should be performed by choosing lower injection rates and lower fracturing fluid viscosities. This study can provide key technical support and theoretical guidance for oil and gas development in fault-karst reservoir.

Propagation of Hydraulic Fractures and Natural Fractures: The Bypassing Behavior in 3D Space

Summary The interaction between natural fractures (NFs) and hydraulic fractures (HFs) in 3D space poses significant challenges to numerical simulation. The interaction behaviors between HFs and NFs in 3D space include crossing, offset, stopping, and bypassing. Many existing numerical simulators are 2D, which inherently limits their ability to account for the vertical growth of fractures. Consequently, they are unable to model the bypassing behavior effectively. In this paper, a mathematical model for the propagation of HFs and NFs in a naturally fractured reservoir is established. The displacement discontinuity method (DDM) is used to solve the rock deformation, while the finite difference method (FDM) is utilized to solve the fluid flow within fractures. The undirected graph structure is used to represent the complex fracture network, and a dynamic adjustment of grid connectivity method is implemented to describe the process by which HFs bypass NFs. By integrating with graphics processing unit (GPU) computing, an efficient 3D simulator for HFs and NFs propagation is developed. The accuracy is verified against analytical solutions and reference solutions. Subsequently, a series of numerical studies on the bypassing behavior are conducted. The primary findings are as follows: (1) The simulator can accurately capture the interactions between HFs and NFs in 3D space, including crossing, arresting, and bypassing behaviors. (2) The bypassing behavior is characterized by three distinct processes—intersection, height growth of HF, and bypassing. (3) During the intersection stage, both the injection pressure and maximum NF width increase. During the height growth stage, the pressure is relatively stable, while the maximum NF width continues to increase. These two stages together result in the “storage” phenomenon. Once the bypassing behavior occurs, both the pressure and the maximum NF width decrease sharply, leading to a “release” phenomenon. Additionally, the “storage” and “release” phenomena may impact proppant transport. (4) Given the presence of bypassing behavior, it is essential to consider the NFs in 3D fracture simulators. The simulator and its findings can provide valuable insights for field design.

Heart Shape to Fracture Distance: Characterizing Hydraulic Fracture Propagation before Hits

Summary Estimating the distance from the hydraulic fracture tip to the monitor well can be useful for fracture characterization, well spacing optimization, and preventing parent-child well interference. A heart-shaped signal is referred to as the extensional precursor of a fracture hit recorded by crosswell strain measurements and can serve as a vital tool for such estimation. This study incorporates the 3D displacement discontinuity method (DDM) to understand the impact of fracture geometry and monitor well offset on the heart-shaped signal’s characteristics. Results from numerical simulation and analytical solutions reveal a strong linear correlation between the spatial extent of the heart-shaped signal and the fracture tip distance. This relationship was further developed to predict tip distance using field data from the Hydraulic Fracture Test Site 2 (HFTS2). A reasonable approximation result from field data further validates the methodology. In addition, it is worth noting that the estimation accuracy depends on the ratio between fracture dimension and tip distance. The findings of this study offer a novel approach for real-time monitoring and characterizing hydraulic fracture propagation, which can be further used for well spacing optimization in unconventional and enhanced geothermal system reservoir development, as well as caprock integrity monitoring for carbon sequestration projects.

Study on the Vertical Propagation Behavior of Hydraulic Fractures in Thin Interbedded Tight Sandstone

Hydraulic fracturing technology is vital for the efficient extraction of oil and gas from low-permeability tight sandstone reservoirs.Taking the central Bohai oilfield in China as an example, these fields are typically composed of thinly interbedded tight sandstone, characterized by low permeability and significant lithological heterogeneity between layers. Fractures may either be confined, limiting vertical growth and reducing production, or overextend into water-bearing zones, causing contamination and compromising reservoir integrity. Therefore, predicting vertical fracture propagation during field fracturing operations is critical for efficient resource extraction.However, there is still a lack of comprehensive understanding of the mechanisms governing vertical fracture growth offshore.This paper applies numerical simulations based on the finite element method to elucidate the interlayer fracture propagation behavior in low-permeability tight sandstone reservoirs. A fracture propagation model for thin interlayered tight sandstone formations is constructed, and the effects of various factors on hydraulic fracture propagation are systematically analyzed, including geological factors such as interlayer stress contrast, thickness, and differences in elastic modulus, as well as operational parameters including fracturing fluid viscosity and injection rate. This study clarifies the cross-layer propagation patterns of hydraulic fractures under the influence of multiple factors and yields a comprehensive prediction chart for fracture propagation thickness under the combination of complex factors. The results of this research can provide theoretical support for the design of reservoir stimulation operations in low-permeability tight sandstone oilfields.

Numerical Modeling of Hydraulic Fracturing Interference in Multi-Layer Shale Oil Wells

Multi-layer horizontal well development and hydraulic fracturing are key techniques for enhancing production from shale oil reservoirs. During well development, the fracturing performance and well-pad production are affected by depletion-induced stress changes. Previous studies generally focused on the stress and fracturing interference within the horizontal layers, and the infilled multi-layer development was not thoroughly investigated. This study introduces a modeling workflow based on finite element and displacement discontinuity methods that accounts for dynamic porous media flow, geomechanics, and hydraulic fracturing modeling. It quantitatively characterizes the in situ stress alteration in various layers caused by the historical production of parent wells and quantifies the hydraulic fracturing interference in infill wells. In situ stress changes and reorientation and the non-planar propagation of hydraulic fractures were simulated. Thus, the workflow characterizes infill-well fracturing interferences in shale oil reservoirs developed by multi-layer horizontal wells. Non-planar fracturing in infill wells is affected by the parent-well history production, infilling layers, and cluster number. They also affect principal stress reorientations and reversal of the fracturing paths. Interwell interference can be decreased by optimizing the infilling layer, infill-well fracturing timing, and cluster numbers. This study extends the numerical investigation of interwell fracturing interference to multi-layer development.

Modeling interactions between hydraulic fracture and pre-existing microcracks in crystalline rocks using hydro-grain-texture model

The heterogeneity of the mineral grains and pre-existing microcracks significantly impacts the cracking behavior of crystalline rocks. However, these characteristics have not been adequately addressed in the existing hydraulic fracturing studies. To bridge this gap, this study introduces a fluid-solid coupling method enhanced by a microcrack simulation component, called Hydro-Grain-Texture Model (HGTM), to investigate the influence of mineral structures and pre-existing microcracks on hydraulic fracturing processes in granite. Compared with existing methods, the HGTM incorporates a “grain growth” algorithm that can more accurately represent the characteristics of mineral grains. This study investigates the base case of intact rock, and four additional cases featuring microcracks oriented in various directions, i.e., horizontal, diagonal, vertical and complex microcracks, under both hydrostatic and non-hydrostatic in-situ stress conditions. The HGTM effectively captures a range of microscopic behaviors during the hydraulic fracturing of granite, including the formation of rock fragments, fracture branches, and dry fractures, among others. Furthermore, by comparing numerical results for breakdown pressure with analytical results, the accuracy of the HGTM in predicting breakdown pressure is substantiated. The findings indicate that mineral structures (grain boundaries) and microcracks contribute to a more intricate pattern of hydraulic fractures propagation. The pre-existing microcracks significantly influence the propagation path of primary hydraulic fractures. Under fluid-driven pressures, these pre-existing microcracks experience shear failure distinct from tensile failure observed in the surrounding rock matrix.

Developmental characteristics of vertical natural fracture in low-permeability oil sandstones and its influence on hydraulic fracture propagation

Vertical natural fractures (NFs) are prevalent in low-permeability sandstone reservoirs. Presently, the impact of NFs on the extension of hydraulic fractures (HFs) remains partially unveiled, which restricts the scientific development of strategies for low-permeability, fractured oil sandstones. In this study, taking the oil sandstone of the He-3 Member, Hetaoyuan Formation, southeastern Biyang Depression as an example, we conducted a comprehensive investigation into the factors influencing vertical fracture development and the interaction between natural and hydraulic fractures. The cohesive unit simulations indicate that geostress is the principal factor influencing HF expansion, more so than NFs, with this influence intensifying as natural fracture density increases. As natural fracture density grows, the potential for two sets of conjugate natural fractures to form short HFs arises, which are limited in expansion scope, suggesting a need to reduce well spacing accordingly. Conversely, areas with a single set of NFs are more prone to developing longer HFs, warranting an increase in well spacing to avoid water channeling. High natural fracture densities may constrain the effectiveness of HFs. In fractured reservoirs with a 10 MPa horizontal stress difference, the length of HFs is 1.52 times that of HFs with 0 MPa and 5 MPa differences. However, the hydraulic fracture effectiveness index (FE) of the latter is 1.74 times higher than the former. For fractured reservoirs, the expansion capacity of HF length within a 5 MPa horizontal stress difference remains relatively stable; beyond this threshold, the expansion capacity increases with the growing horizontal stress difference, and the fracturing effect eventually deteriorates. Furthermore, as the strength of NFs escalates, the length and modified area of HFs initially decrease significantly before stabilizing. The complexity and FE value of HFs formed under strong natural fracture conditions are heightened, indicating a more effective fracturing outcome.

Geological and Engineering Integration Fracturing Design and Optimization Study of Liushagang Formation in Weixinan Sag

The Weixinan Sag in the Beibuwan Basin is rich in shale oil resources. However, the reservoirs exhibit rapid phase changes, strong compartmentalization, thin individual layers, and high-frequency vertical variations in the thin interbedded sandstone and mudstone. These factors can restrict the height of hydraulic fracture propagation. Additionally, the low-porosity and low-permeability shale oil reservoirs face challenges such as low production rates and rapid decline. To address these issues, the Plannar3D full 3D fracturing model was used to simulate hydraulic fracture propagation and to study the main controlling factors for fracture propagation in the second member of the Liushagang Formation. Based on the concept of geological–engineering integration, a sweet spot evaluation was conducted to identify reservoirs with relatively better brittleness, reservoir properties, and oil content as the fracturing targets for horizontal wells. The UFM model was then applied to optimize fracturing parameters. This study indicates that the matrix-type oil shale has a high clay mineral content, resulting in a low Young’s modulus and poor brittleness. This makes hydraulic fracture propagation difficult and leads to less effective reservoir stimulation. In contrast, hydraulic fractures propagate more easily in high-brittleness interlayer-type oil shale. Therefore, it is recommended to prioritize the extraction of shale oil from interlayer-type oil shale reservoirs. The difference in interlayer stress is identified as the primary controlling factor for cross-layer fracture propagation in the study area. Based on the concept of geological–engineering integration, a sweet spot evaluation standard was established for the second member of the Liushagang Formation, considering both reservoir quality and engineering quality. Four sweet spot zones of interlayer-type oil shale reservoirs were identified according to this evaluation standard. To achieve uniform fracture initiation, a differentiated segment and cluster design was implemented for certain high-angle sections of well WZ11-6-5d. Interlayer-type oil shale was selected as the fracturing target, and the UFM was used for hydraulic fracture propagation simulation. Fracturing parameters were optimized with a focus on hydraulic fracture characteristics and the estimated ultimate recovery (EUR). The optimization results were as follows: a single-stage length of 50 m, cluster spacing of 15 m, pump injection rate of 10 m3/min, fluid intensity of 25 m3/m, and proppant intensity of 3.5 t/m. The application of these optimized fracturing parameters in field operations resulted in successful fracturing and the achievement of industrial oil flow.

Numerical Simulation of Hydraulic Fracture Propagation in Unconsolidated Sandstone Reservoirs

In order to comprehensively understand the complex fracture mechanisms in thick and loose sandstone formations, we have carefully developed a coupled finite element numerical model that captures the complex interactions between fluid flow and solid deformation. This model is the cornerstone of our future exploration. Based on this model, the crack propagation problem of hydraulic fracturing under different engineering and geological conditions was studied. In addition, we conducted in-depth research on the key factors that shape the geometry of hydraulic fractures, revealing their subtle differences and complexities. It is worth noting that the sharp contrast between the stress profile and mechanical properties between the production layer and the boundary layer often leads to fascinating phenomena, such as the vertical merging of hydraulic fracture propagation. The convergence of cracks originating from adjacent layers is a recurring theme in these strata. Sensitivity analysis clarified our understanding, revealing that increased elastic modulus promotes longer crack propagation paths. As the elastic modulus increases from 12 GPa to 18 GPa, overall, the maximum crack width slightly decreases, with a less than 10% reduction rate. The increased fluid leakage rate will significantly shorten the length and width of hydraulic fractures (with a maximum decrease of over 70% in fracture width). The increase in viscosity of fracturing fluid causes a change in fracture morphology, with a reduction in length of about 32% and an increase in fracture width of about 25%. It is worth noting that as the leakage rate of fracturing fluid increases, the importance of the viscosity of fracturing fluid decreases relatively. Strategies such as increasing fluid viscosity or adding anti-filtration agents can alleviate these challenges and improve the efficiency of fracturing fluids. In summary, our research findings provide valuable insights that can provide information and optimization for hydraulic fracturing filling and fracturing strategies in loose sandstone formations, promoting more efficient and influential oil and gas extraction work.

Evolution mechanism of deviated well fiber-optic strain induced by single-fracture propagation during fracturing in horizontal wells

Considering the high construction cost of horizontal adjacent well monitoring and the lack of vertical adjacent well fiber optic for obtaining fracturing information, this paper proposes the use of deviated wells with fiber optics for monitoring purposes. To demonstrate the advantages of deviated well fiber optics and the feasibility of their deployment, this paper constructs a forward model based on the finite element coupled with cohesive element approach to simulate the strain induced by the propagation of a single hydraulic fracture in horizontal wells on deviated well fiber optics, and conducts a numerical simulation analysis of the strain induced by the propagation of a single hydraulic fracture on deviated well fiber optics. The results show that the strain evolution induced by single-fracture propagation in deviated well fiber optics can be divided into four stages: strain-enhancing, strain-converging, tensile strain-expanding, and linear strain-converging. The strain evolution characteristics of deviated well fiber optics are manifested as follows: a “heart-shaped” tensile strain convergence zone with a certain deviation appears in the middle, which subsequently converges into a tensile strain convergence band, with compressive strain convergence zones on both sides, and an expanding tensile strain convergence zone on the outer side of the compressive strain convergence band. The analysis finds that when the well inclination angle is greater than 45°, the strain response characteristics of deviated well fiber optics are mainly governed by the width expansion of the fracture, and when less than 45°, they are mainly governed by the height expansion of the fracture. Changes in the azimuth angle can cause a deviation of the “heart-shaped” tensile strain area and the compressive strain convergence zone in the fiber-optic strain waterfall plot, with larger deviations corresponding to smaller azimuth angles. The depth at which the deviated well fiber optics are deployed, reaching the depth of the horizontal section of the horizontal well, can reflect the upward expansion of the fracture height. The results of the analysis illustrate the advantages of deviated well fiber optics in obtaining both fracture width and height expansion information simultaneously and propose a method for selecting suitable deviated well fiber-optic construction parameters based on fracturing monitoring needs. This research can reduce the construction cost of deploying fiber optics in adjacent wells and has significant implications for guiding the layout of adjacent well fiber optics.

A novel hybrid PD-FEM-FVM approach for simulating hydraulic fracture propagation in saturated porous media

To enhance the computational efficiency of fluid–solid coupling in peridynamics (PD), a hybrid modeling approach based on the classical Biot theory is proposed for simulating hydraulic crack propagation in saturated porous media. The deformation and damage of solids are described by the coupling of the finite element method (FEM) and PD. Based on Darcy’s law, the finite volume method (FVM) is used to describe fluid seepage and calculate pore water pressure. The mutual transfer of fluid pressure and solid deformation is realized through the transition layer between the solid layer and the fluid layer. Firstly, the effectiveness of the proposed method is verified by a porous media seepage simulation example. Secondly, the ability and efficiency of this method to simulate crack propagation in saturated porous media are verified by several examples of hydraulic fracturing of rock with a single pre-existing crack. Finally, the synchronous hydraulic fracturing process of rock with double cracks is simulated. The ability of this method to simulate the simultaneous propagation of multiple fractures in the rock under fluid–solid coupling is further illustrated. The aforementioned studies demonstrate that the novel hybrid PD-FEM-FVM approach not only ensures computational accuracy and effectiveness but also significantly enhances computational efficiency.

Coupled THMC model-based prediction of hydraulic fracture geometry and size under self-propping phase-transition fracturing

The Self-Propping Phase-transition Fracturing Technology (SPFT) represents a novel and environmentally friendly approach for a cost-effective and efficient development of the world’s abundant unconventional resources, especially in the context of a carbon-constrained sustainable future. SPFT involves the coupling of Thermal, Hydraulic, Mechanical, and Chemical (THMC) fields, which makes it challenging to understand the mechanism and path of hydraulic fracture propagation. This study addresses these challenges by developing a set of THMC multifield coupling models based on SPFT parameters and the physical/chemical characteristics of the Phase-transition Fracturing Fluid System (PFFS). An algorithm, integrating the Finite Element Method, Discretized Virtual Internal Bonds, and Element Partition Method (FEM-DVIB-EPM), is proposed and validated through a case study. The results demonstrate that the FEM-DVIB-EPM coupling algorithm reduces complexity and enhances solving efficiency. The length of the hydraulic fracture increases with the quantity and displacement of PFFS, and excessive displacement may result in uncontrolled fracture height. Within the parameters considered, a minimal difference in fracture length is observed when the PFFS amount exceeds 130 m3, that means the fracture length tends to stabilize. This study contributes to understanding the hydraulic fracture propagation mechanism induced by SPFT, offering insights for optimizing hydraulic fracturing technology and treatment parameters.

Experimental study on the influence of horizontal stress difference coefficient on coal rock fracture

Hydraulic fracturing is a pressure-relief and permeability-enhancing technique widely used in the mining of low-permeability coal seams. The horizontal stress difference coefficient is an important factor that affects the fracture propagation during the fracturing. To study the mechanism of the hydraulic fracturing process, in this paper, the initiation and propagation of cracks under horizontal stress difference coefficient are studied by using the developed true triaxial hydraulic fracturing system. The fracture surface morphology was obtained by 3D scanner. The experimental results are verified by the mathematical model. The results show that the fracture pressure and the peak values of AE count rate and b value increase and the cumulative AE count decreases with the increase of the horizontal stress difference coefficient. After the first pressure drop, the “pressure built-up” in the specimen increases and the peak value of AE count rate decreases with the increased horizontal stress difference coefficient. The 3D scanning results show that when the horizontal stress difference coefficient is larger, the hydraulic fracture propagation is straighter and the fracture surface area is smaller. The experimental results are in good agreement with the theoretical values. The experimental results provide a basis for engineering practice.

Numerical Simulations of the Hydraulic Fracture Propagation in Poroelastic Media Using the Coupled Hydro-Mechanical Field-Enriched Finite Element Method

Numerical Simulations of the Hydraulic Fracture Propagation in Poroelastic Media Using the Coupled Hydro-Mechanical Field-Enriched Finite Element Method

Study on multi-cluster fracture interlaced competition propagation model of hydraulic fracturing in heterogeneous reservoir

The heterogeneity of the reservoir plays a crucial role in influencing the propagation of multi-cluster hydraulic fractures in horizontal wells. To explore this impact, a seepage-stress-damage coupled model was developed in this study for analyzing the competitive propagation of multi-cluster fractures utilizing the finite-discrete element method. Utilizing the model, a random assignment program has been developed to establish the coupling distribution of mechanical parameters between matrix elements and discrete elements for characterizing the reservoir heterogeneity. Simultaneously, a wellbore flow model describing the pressure drop of fracturing fluid flow is developed by introducing pipe flow element and fluid connection element, enabling the realization of dynamic flow distribution. Based on the developed model, an investigation is conducted into the impact of pumping rates, fracturing fluid viscosity, and perforation parameters on the fracture propagation of multi-cluster fracturing. The study findings suggest that as reservoir heterogeneity increases, the distribution of rock strength becomes more uneven, resulting in a more complex morphology of fracture propagation. Higher pumping rates lead to elevated pressure within fractures, thereby facilitating the uniform propagation of multi-cluster fractures, particularly in reservoir characterized by medium to high heterogeneity. Increasing the viscosity of fracturing fluid can diminish the tortuosity of multi-cluster fracture propagation, albeit with a somewhat limited enhancement in uniformity. As reservoir heterogeneity intensifies, the interference between fractures escalates, necessitating a reduced number of perforations to heighten perforation friction and enhance the balanced propagation of multi-cluster fractures. This research offers theoretical guidance and a scientific foundation for the design of schemes and optimization of parameters in staged multi-cluster fracturing technology for horizontal wells in heterogeneous reservoirs.

Experimental Study on Plugging Behavior of Multitype Temporary Plugging Agents in Hydraulic Fractures

Summary Various types of temporary plugging agents are used in hydraulic fracturing to promote the uniform propagation of multicluster hydraulic fractures and increase the complexity of hydraulic fractures. However, the plugging behavior of these agents in hydraulic fractures has not yet been fully clarified, making the optimization of temporary plugging formulas challenging. In this study, dozens of plugging experiments were carried out to reveal the plugging behavior of pure fiber, pure particle, and fiber-particle combination materials in hydraulic fractures. The results indicate that the high fiber concentration and long fibers are beneficial to obtaining high maximum plugging pressures. However, the low tensile strength of fibers makes it difficult to form stable plugging layers under high pressure, especially for wide fractures. For particle plugging agents, the high rigidity of the particles prevents them from compacting tightly within the plugging layer, resulting in high permeability and low temporary plugging pressure. Excessive particle diameter and concentration tend to cause rapid blockage at the fracture entrance, leading to poor plugging performance. In contrast, the fiber-particle composite plugging scheme can form a stable and tight plugging layer at lower concentrations of both fibers and particles. Moreover, replacing single-size particles in composite with multisize particles can further enhance the plugging effect, allowing for a higher plugging pressure with a lower dosage of temporary plugging agents. Comprehensively considering the effects of material concentration and size on the plugging effect, the critical plugging quantitative characterization equations for pure fiber, pure particle, and fiber-particle combination plugging schemes are established respectively, with fracture width as the independent variable and the product of material concentration and size as the dependent variable. The temporary plugging schemes for various hydraulic fracture widths can be preliminarily determined using these equations. Based on the principle of economic optimization, the optimal temporary plugging schemes with consideration of the plugging pressure requirements were selected, which have shown good field application performance.

Identifying the high potential zones for hydraulic fracture propagation / Eastern Baghdad field

For a reservoir with high storage capacity and low ability to produce, the serious problem is the sharp reduction in the recorded well productivity within a short period. One solution to this problem is to create hydraulic fractures that increase formation permeability and keep its production at high rates for a sufficient time. The field under study is the East Baghdad oil field of three formations: Saadi, Tanuma, and Khasib. Knowing the geomechanical behavior of these reservoirs has a critical effect on the success of hydraulic fracturing operations. In this study, rock stress magnitude and direction, rock elasticity, rock strength to fracturing initiation, and all these parameters in addition to petrophysical properties will be used to identify whether the hydraulic fracturing operation could be successful or not. An integrated modeling of the studied reservoir is an essential step including 1-D geomechanical evaluation of many formations in order to choose the perfect layer to create hydraulic fracture. Then, a 3-D distribution of geomechanical properties and petrophysical properties was presented to make a perfect selection of these properties. The geomechanical evaluation of the reservoirs under study is supported by experimental evaluation of core samples including Energy Dispersive X-ray spectroscopy (EDS), Scanning Electron Microscopic (SEM) image, and thin section (TS) image. The results show that a reduction in the calculated geomechanical properties in terms of Poisson ratio young modulus and compressive strength are favorable for candidate layer selection. Among the studies of rock mechanical properties, it is also noticed that unconfined compressive strength is a crucial parameter for best layer selection. The suitable depths for fracturing jobs are given in detail in this study using brief data collected from four wells.

Numerical Simulation Study on Dynamic Interaction between Two Adjacent Wells during Hydraulic Fracturing

The heterogeneity in fracture formation significantly influences the hydraulic fracture propagation among adjacent wells, underscoring the urgency to comprehend the underlying fracture mechanisms. Specifically, in shale gas or oil extraction fracturing operations, stress interactions among neighboring fracturing clusters, or mutual interference during the propagation of parallel fractures, are commonplace. At present, there is relatively little research on the sensitivity parameters of adjacent borehole fracture propagation morphology. Consequently, we employed ABAQUS software 2022 to construct a numerical model simulating the fracturing of adjacent boreholes in opposing directions. Upon validating the model’s fidelity, we systematically explored the influence of various engineering and geological factors on fracture morphology and propagation length. Our findings revealed a three-phase evolution: independent fracture propagation, subsequent mutual repulsion, and, ultimately, mutual attraction. It is worth noting that increasing the elastic modulus from 10 GPa to 80 GPa, and increasing the crack length by 16.30%, is beneficial for crack propagation, while the horizontal stress difference profoundly shapes the crack mode, but has a relatively small impact on the overall crack length. When HSD increases from 0 MPa to 15 MPa, the total crack length only changes by 1.24%. In addition, the filtration coefficient of the reservoir is a key determining factor that has a significant impact on the morphology and length of cracks generated by adjacent boreholes. Increasing the filtration coefficient from 1 × 10−14 m3/s/Pa to 5 × 10−12 m3/s/Pa reduces the total length of cracks by 60.77%. Notably, an optimal injection rate exists, optimizing fracturing outcomes. Conversely, the viscosity of the fracturing fluid exerts a limited influence on fracture morphology and length within the confines of this simulation, allowing for the selection of a suitable viscosity to ensure smooth proppant transport during actual fracturing operations. In designing fracturing parameters, it is imperative to aim for sufficient fracture propagation length while harnessing “stress interference” to foster the development of intricate fracture networks. Ultimately, our research findings serve as a solid foundation for engineering practices involving hydraulic fracture propagation in adjacent boreholes undergoing opposing fracturing operations.