Distribution Of Natural Fractures Research Articles

The propagation laws of hydraulic fractures under the influence of natural fracture zones

This paper uses the finite-discrete element method (FDEM) to establish a fluid–solid coupling model for the propagation of multi-cluster hydraulic fractures. The validity of the proposed model is verified using the analytical solution and onsite microseismic data. The results show that with the approach angle increases, the propagation of hydraulic fracture transitions from a single capture mode to the mixed modes of capture, crossing and blocking. The total length of hydraulic fractures is negatively correlated with the approach angle and cohesion of natural fracture, and positively correlated with the distribution density and bandwidth of natural fracture. The length of shear fractures initially increases and then decreases with the increase in approach angle, showing negatively, positively, and positively correlated with cohesion, length, and bandwidth, respectively, while the trend of tensile fracture length is opposite to it. The tortuosity of hydraulic fractures (which is used to characterize the complexity of fracture morphology) initially decreases and then increases with the increase in the approach angle, negatively correlated with the cohesion of natural fracture, and positively correlated with the distribution density and bandwidth of natural fractures. Comparatively, the fracture propagation morphology is the most complex at the approach angle of 45°, which is more conducive to full reservoir enhancement. Conversely, under conditions of high cohesion, narrow width, and low-density distribution of natural fractures, the fracture morphology is relatively simple, all of which are unfavorable for reservoir enhancement in the target segment.

Modeling the propagation of hydraulic fractures in reservoirs with natural fracture networks using high aspect ratio interface elements

The application of hydraulic fracturing in unconventional reservoirs is a technique widely used to overcome the problem of low permeability in porous media. However, there are complex factors involved in understanding this technique, since the propagation of hydraulic fractures can be impacted by factors such as the state of stress in situ and the distribution of natural fractures, which may have different lengths, inclination angles and aperture values. Thus, based on the continuum mechanics and using the finite element method, this paper seeks to simulate the effect of hydraulic fracturing in porous media with a complex natural fractures network under the influence of different stress states. The modeling of the problem considers a fully coupled approach for solving the hydro-mechanical problem, with the Darcy’s law governing the fluid flow in the porous media and by the classical cubic law inside the fractures. For the representation of natural and hydraulic fractures, High Aspect Ratio Interface Finite Elements (HAR-IEs) associated with a suitable tensile damage model are used and inserted into the regular mesh via the Mesh Fragmentation Technique (MFT). The results obtained are validated with the literature and show that the model is capable of reproducing the complex scenarios of propagation and interaction between multiple fractures.

A hydraulic-mechanical coupling model of dynamic waterflood-induced fractures in fractured tight reservoirs

The propagation of waterflood-induced fractures (WIFs) occurs during prolonged water injection and is influenced by the distribution and properties of natural fractures (NFs). Available numerical models rarely consider fracture activation and rupture in an integrated manner, which makes it difficult to reflect complex fracture morphology. In this paper, we propose a hydraulic-mechanical model with strain-dependent damage variables to describe the dynamic expansion characteristics of WIFs. There are discrete filled NFs in the matrix with non-equal-thickness joint elements, for which we derive the constitutive equations to calculate fracture widths during water injection and production. Damage variables for the matrix and fractures are calculated according to the maximum tensile stress criterion and the Mohr–Coulomb criterion. A comparison between the coupled model and experimental results is conducted to demonstrate its validity. Finally, we simulated and analyzed four influencing factors of the pressure response and fracture evolution. The study demonstrates that fracture behavior and damage area evolution are highly sensitive to injection rate, communication sequence, NF density, and orientation. The activation, cross, and capture interactions between NFs and WIFs complicate the fracture-damage network and enhance seepage efficiency. High injection rates promote crack tip propagation, while lower rates facilitate the evolution of secondary fractures at low pressure. For high NF density reservoirs, low-pressure injection fully activates NFs, aiding damage evolution. In low NF density reservoirs, excessive pressure induces simpler fracture morphologies, making unstable water injection more effective than continuous injection. This work guides appropriately induced fractures to improve water absorption in tight reservoirs.

Workflow Helps Predict Casing Deformation During Hydraulic Fracturing in Shale Gas

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 4043054, “Casing-Deformation-Risk Prediction With Numerical Simulation During Hydraulic Fracturing in Deep Shale Gas Reservoirs,” by Jianfa Wu, Xuewen Shi, and Qiyong Gou, PetroChina, et al. The paper has not been peer reviewed. _ In this study, a numerical simulation workflow was established based on comprehensive modeling of a time-lapse stress field, hydraulic fracturing simulation, natural fractures, and other weak interfaces to analyze casing-deformation mechanisms of shale gas horizontal wells during the multistage hydraulic fracturing process. The authors write that they aim to guide the prediction of, and provide mitigating solutions for, casing-deformation risks while improving stimulation efficiency. Introduction The burial depth of deep shale gas reservoirs in the southern Sichuan Basin is approximately 3500 to 4500 m. These have complex geological conditions with developed faults and fractures and high in-situ horizontal stresses. During multistage hydraulic fracturing operations in horizontal wells, establishing an effective prediction method for casing-deformation risks in these reservoirs is a challenge. An integrated workflow is proposed to evaluate and predict casing-deformation risks, effectively support hydraulic fracturing operations, and reduce and mitigate casing failure in these reservoirs. Modeling Methodology It is essential to consider the effects of multiscale natural fractures when constructing a 3D stress model. Natural-fracture stability can be evaluated and used to identify unstable fractures that may cause casing failures. The fundamental workflow of predicting and preventing the casing failure is as follows: 1. Build a 3D geological model characterizing the spatial distribution and geometry of faults and natural fractures 2. Construct a 3D stress model to characterize the in-situ stress state 3. Perform numerical simulations of hydraulic fracturing and 4D coupled stress simulation to obtain the stress field during and after hydraulic fracturing 4. Quantitatively analyze the shear slip risks of natural fractures by calculating slip tolerance as an indicator to determine risk levels of casing deformation 5. Optimize and adjust engineering parameters for hydraulic fracturing to reduce and mitigate casing deformation Natural-Fracture Distribution and Model Construction. In this study, natural fractures parameters such as density, strike, inclination, length of extension, and height were obtained. The natural fractures were calibrated and verified with cores and wellbore images. Natural-fracture distribution was then validated with the expected tectonic history and present-day stress regime. In Fig. 1, the left-hand plot depicts the ant-tracking results by seismic attribute, the central plot portrays natural fractures validated by microseismic events, and the right-hand plot illustrates the 3D natural-fracture model. Results showed two major fracture strikes, one in the northeast and the other in the northwest, forming a mesh network distribution that will be used in the stress model, fracturing simulation, and slip analysis.

Integrated study of hydraulic/CO2 fracturing and production coupled with a THM-D process in ultra-shallow shale reservoirs

To explore fracturing technology for vertical wells in ultra-shallow shale gas reservoirs, a coupled thermo-hydro-mechanical-damage (THM-D) fracturing and production integration model is established in this study. In addition, a new coupled hydro-mechanical damage model is established to calculate fracture evolution. These two models are validated through theoretical models and field data, respectively. Based on these models, the quality of fracturing under different geological parameters, fracturing parameters, and fracturing technology is compared and analyzed. The results show that the distribution of natural fractures significantly influences fracturing and production. In addition, due to the high leak-off in the ultra-shallow shale reservoir, the total fracture length and cumulative production after 720 days of carbon dioxide fracturing are only 70.35% and 77.26% of the values achieved by hydraulic fracturing, respectively. Therefore, it is necessary to consider reducing carbon dioxide leak-off in the design of carbon dioxide fracturing in ultra-shallow shale reservoirs. Fracturing efficiency also should be considered when designing fracturing time. When the injection rate is 5 m3/min, the efficiency drops sharply if the fracturing time exceeds 67.45 min. The production of hydraulic fracturing and carbon dioxide fractured wells has also been studied when fracturing methods without proppant are used. This study found that a satisfactory production rate can also be achieved in ultra-shallow shale gas reservoirs when fracturing without proppant.

Thermo-Hydro-mechanical coupling analysis of geothermal reservoirs: optimizing extraction capacities by revealing influential factors

Abstract Extraction of high-temperature geothermal resources from reservoirs is a challenge due to the complex interactions between temperature, permeability, and stress fields. Variations in physical fields are critical to thermal reservoir engineering. In this study, the coupling mechanism between temperature, permeability, and stress fields is systematically explored using theoretical analyses and numerical simulations, by utilizing the three-field coupling model. This study models the changes in porosity and permeability evolution during geothermal extraction, emphasizing the importance of the coupling term. The effects of pressure differences between injection and production wells, reservoir temperature variations, and fluid property changes on the temperature distribution and output thermal power within the geothermal reservoir were modeled and analyzed. The results reveal the significant effect of pressure differences between wells, and show that the geothermal extraction capacity of supercritical carbon dioxide (SC-CO2) is 1.83 times higher than that of water. Based on the statistical characteristics of the distribution pattern of natural fractures within the geothermal reservoir, the study simulated the distribution of natural fractures and developed a coupled THM model containing natural fractures. The results show that increasing the porosity of hydraulic and natural fractures can effectively increase the geothermal production capacity, especially the increase in the porosity of natural fractures is significant. These findings provide a key theoretical basis for understanding the THM coupling mechanism during geothermal extraction, and provide substantial support for optimizing the development and utilization of geothermal resources.

Relationship between Natural Fracture and Structural Style and its Implication for Tight Gas Enrichment: A Case Study of Deep Ahe Formation in the Dibei–Tuzi Area, Kuqa Depression

AbstractThe deep Lower Jurassic Ahe Formation (J1a) in the Dibei–Tuzi area of the Kuqa Depression has not been extensively explored because of the complex distribution of fractures. A study was conducted to investigate the relationship between the natural fracture distribution and structural style. The J1a fractures in this area were mainly high‐angle shear fractures. A backward thrust structure (BTS) is favorable for gas migration and accumulation, probably because natural fractures are more developed in the middle and upper parts of a thick competent layer. The opposing thrust structure (OTS) was strongly compressed, and the natural fractures in the middle and lower parts of the thick competent layer around the fault were more intense. The vertical fracture distribution in the thick competent layers of an imbricate‐thrust structure (ITS) differs from that of BTS and OTS. The intensity of the fractures in the ITS anticline is similar to that in the BTS. Fracture density in monoclinic strata in a ITS is controlled by faulting. Overall, the structural style controls the configuration of faults and anticlines, and the stress on the competent layers, which significantly affects deep gas reservoir fractures. The enrichment of deep tight sandstone gas is likely controlled by two closely spaced faults and a fault‐related anticline.

Numerical simulation of multi-fracture uniform propagation in naturally fractured reservoirs based on the continuum–discontinuum method

Multi-cluster fracturing technology with horizontal wells is significant for the production enhancement of unconventional reservoirs. However, affected by the natural fracture distribution in the reservoir, stress shadowing between multi-fractures and perforation erosion has non-negligible influence on the multi-fracture uniform propagation, which results in uneven reservoir stimulation and lower production capacity. In this study, a multi-field coupled stress-seepage-fracture model for hydraulic fracturing of fractured reservoirs based on the continuum–discontinuum method was developed, adequately simulating the full scenario of stress disturbances, perforation erosion, and fracture interactions during the fracturing process. The effect of different geological and engineering parameters on the competing propagation of multi-fractures was investigated in detail, and the results show: Different geological and engineering parameters have significant influence on the competitive propagation of multi-fractures; among the geological parameters, the elastic modulus has the highest impact on the uniform fluid intake of multi-fractures, while the horizontal stress difference has the least impact on the uniform fluid intake of multi-fractures. Among the engineering parameters, the effect of natural fracture angle on the standard deviation of the fluid injection volume is gradually reduced with the increase in perforation number, flow rate, and fluid viscosity. For a low number of perforations and high fluid viscosity, both have great influence on promoting uniform fluid entry in multiple fractures. In addition, geological parameters have a significantly greater influence on the merging of multi-fractures than engineering parameters, and the probability of merging of multi-fractures increases significantly under low stress differentials and long natural fractures.

Optimization Simulation of Hydraulic Fracture Parameters for Highly Deviated Wells in Tight Oil Reservoirs, Based on the Reservoir–Fracture Productivity Coupling Model

The production potential of highly deviated wells cannot be fully realized by conventional acid fracturing, as it can only generate a single fracture. To fully enhance the productivity of highly deviated wells, it is necessary to initiate multiple fractures along a prolonged well section to ensure the optimal number of fractures, thereby maximizing the economic returns post-stimulation. Thus, the number of fractures is a crucial parameter in the acid fracturing design of highly deviated wells. Considering factors such as the random distribution of natural fractures within the reservoir and interference between fractures during production, and, based on the oil–water two-phase flow equation, a three-dimensional reservoir–fracture production coupling model and its seepage difference model are established to simulate the production performance of highly deviated wells under varying conditions, including the number of fractures, fracture spacing, and conductivity parameters. A numerical model for the number of acid fracturing fractures in highly deviated wells is also established, in conjunction with an economic evaluation model. The simulation results indicate that the daily oil production of highly deviated wells increases with the increase in fracture number, fracture conductivity, fracture length, and reservoir permeability. However, over time, the daily oil production gradually decreases. Similarly, the cumulative production also increases with these parameters, but shows a downward trend over time. By conducting numerical simulations to evaluate the productivity and economy of highly deviated wells post-acid fracturing, it is determined that the optimal number of fractures to achieve maximum efficiency is six. The reliability of this result is confirmed by the pressure distribution cloud map of the formation after acid fracturing in highly deviated wells.

Evaluation of integrated geological engineering reservoir reconstruction in Block X of Bozi

The geological structure of the reservoir in Bozi-Dabei area is complex, and the longitudinal difference of rock mechanical properties of the reservoir is large. Most of the current evaluation techniques after reservoir reconstruction are based on the fitting of construction pressure based on the logging curve of a single well, so as to analyze the fracture morphology and the geometric dimensions of length, width and height after pressure. It is difficult to explain the fracture morphology and geometric parameters correctly because the interpretation methods used do not comprehensively consider the influence of natural fractures, 3D geological properties and 3D geomechanical properties. In order to explain the artificial fracture morphology more accurately, the target layer ant body is generated by using 3D original seismic data, and the natural fracture model of three different reservoir types in Bozi X block is generated, which provides geological basis for the integrated demonstration. By combining dynamic and static data and multidisciplinary methods, a one-dimensional rock mechanics profile model is established, and a three-dimensional geomechanical model of three different reservoir types in Block X of Bozi is established by combining geological model and deep diagenesis theory. The matching relationship between horizontal stress, fault strike and natural tensile fracture distribution is comprehensively analyzed and evaluated, providing a geomechanical basis for the evaluation of integrated reservoir reconstruction. Integrated geological model and geomechanical model are closely combined with engineering parameters to establish an integrated true three-dimensional artificial fracture model. On this basis, the optimization research and design of the parameters of displacement, liquid volume and sand ratio are completed. The optimal flow rate of Class I reservoir 6-7 (m³·min-1), Class II reservoir 5-6 (m³·min-1), Class III reservoir 4-5 (m³·min-1), Class I reservoir 600-700 m³, Class II reservoir 600-700 m³, Class III reservoir 500-600 m³, Sand ratio of 15%-20% for Class I reservoir, 15%-20% for class II reservoir and 20%-25% for class III reservoir are the optimal construction parameters, which provide guidance for field construction.

Predicting gas flow rate in fractured shale reservoirs using discrete fracture model and GA-BP neural network method

In the process of shale gas exploitation, the hydraulic fracturing technology is generally used to generate the stimulate reservoir volume (SRV). The network connectivity between natural fractures (NFs) and hydraulic fractures (HFs) significantly affects gas production rate in the hydraulic fracturing stage. To study the influence of natural fracture characteristics on gas flow behavior, a discrete fracture model considering matrix and fracture behaviors is developed. It is found that the increase of natural fracture permeability and distribution density leads to the increase of gas production rate, whereas large orientation angle may cause its decrease. To determine the nonlinear relationship between the natural fracture parameters and gas production rate, the method of back propagation (BP) neural network with genetic algorithm (GA) was applied to make intelligent prediction for the shale gas production. The gas flow rate values for different natural fracture parameters (e.g., permeability, density, orientation) were calculated by discrete fracture model, and used as input data for training and prediction in the GA-BP neural network. Results demonstrate the applicability of forecasting model, which is suitable for shale gas prediction during the operation of horizontal wells if more data profiles could be collected.

Fracturing parameter optimization technology for highly deviated wells in complex lithologic reservoirs

Highly-deviated wells are the key technology to reduce the risk of drilling accidents and improve the utilization of reservoirs. However, for reservoirs with complex lithology, highly-deviated wells are faced with the problems of geomechanical transformation and fracturing parameter optimization. The research on fracturing parameter optimization technology of high-deviated wells in complex lithologic reservoirs is helpful to the research and application of geomechanics in deep unconventional reservoirs. This paper is based on geological mechanics laboratory experiments and logging interpretation, combined with regional geological background, to clarify the geological and mechanical characteristics of the Fengcheng Formation shale oil region in the Mabei Slope. On this basis, based on the current geostress field and natural fracture distribution pattern of the Mabei Slope, an integrated model of shale oil geological engineering in local well areas was established. Based on the finite element method, optimization design was carried out for the cluster spacing, construction fluid volume, displacement, and sand volume of highly deviated well fracturing, and three-dimensional simulation of fracturing fractures was completed. The research results indicate that: (1) The current dominant direction of the maximum principal stress in the Fengcheng Formation on the Mabei Slope is from northeast to southwest, with the maximum horizontal principal stress generally ranging from 90 to 120 MPa and the minimum horizontal principal stress generally ranging from 70 to 110 MPa. (2) The difference in stress between the two horizontal directions is relatively large, generally greater than 8 MPa. Two sets of natural fractures have developed in the research area, one with a northwest southeast trend and the other with a northeast southwest trend. The natural fracture density of the Fengcheng Formation shale reservoir in the Mabei Slope is 0.32–1.12/m, with an average of 0.58/m, indicating a moderate to high degree of fracture development. (3) The geological model and three-dimensional geo-mechanical model are established according to the actual drilling geological data, and different schemes are designed to carry out single parameter optimization. The optimization results show that the optimal cluster spacing of the subdividing cutting volume pressure of the highly deviated wells in the Fengcheng Formation of the Mabei Slope is 12 m, the optimal construction fluid volume is 1400–1600 m3/section, the optimal construction displacement is 8 m3/min, and the optimal sanding strength is 2.5 m3/m. At the same time, by comparing the fracturing implementation effect with the fracturing scheme design, it is proven that the artificial parameter optimization method for highly deviated wells based on the finite element method based on the regional stress background and the natural fracture development law proposed in this paper is feasible and can provide a scientific basis for the fracturing development of highly deviated wells in complex lithologic reservoirs. This research has been well applied in Mahu area of Xinjiang oilfield.

Prediction of natural fracture distribution characteristics in tight oil and gas reservoirs based on paleotectonic stress field

Prediction of natural fracture distribution characteristics in tight oil and gas reservoirs based on paleotectonic stress field

Dynamic strength characteristics of fractured rock mass

Fractures play crucial role in the behavior of rock masses, yet the understanding of their natural distribution and impact on dynamic characteristics remain unclear. Here the effect of “natural” fractures on the dynamic impact strength of rock mass was investigated using numerical specimens with fractures prepared using the Split Hopkinson Pressure Bar (SHPB) model. These fractures were generated through biaxial compression simulation. Various axial stress levels and confining pressures replicated diverse natural rock fracture distributions. To capture the anisotropic distribution of fractures in natural rock and the randomness of impact direction, impact from 0°, 90°, 180° and 270° directions were imposed. The biaxial loading simulation showed that fracture increases with higher loading stress, and rapidly expands in the post-peak stress stage, with ∨ or ∧ shaped slip plane depending on confining pressure. The impact strength of the fractured specimen decreases as the number of prefabricated fractures increases, following a two-stage pattern, i.e., rapidly decrease with small number of fractures and gradually decrease with high number of fractures. Pre-existing fractures aligning with the impact direction provide stronger resistance compared with fractures deviated, and their location and distribution significantly affect the stress transmission. The impact from other directions has different stress transmission routes related to the fracture and macroscopic surface distribution. Importantly, a specimen’s loading history shapes its internal fracture distribution, thereby affecting its resistance to impact stress. This research provides invaluable insights into the role and mechanics of fractures in rock masses, thus enhancing our understanding of rock dynamics and potentially informing more effective geotechnical engineering practices.

A multi-scale geological–engineering sweet spot evaluation method for tight sandstone gas reservoirs

Exploration and development practices have proved that staged volumetric fracturing stimulation in horizontal wells is a key technology for tight sandstone gas development, and reservoir sweet spot is an important basis for the perforation position selection and staged fracturing in the process of well location deployment and reservoir stimulation. Tight sandstone reservoirs are usually characterized by sandstone and mudstone interlayers with different thicknesses, and complex natural fracture distribution and geostress state. It is hard to predict “geological-engineering” dual sweet spots, and these two kinds of sweet spots are usually in different zones. As a result, there lacks a basis for the optimization of fracturing parameters to stimulate tight sandstone reservoirs. This paper establishes a geological sweet spot prediction model which takes into account total hydrocarbon content, reservoir porosity and other factors, then puts forward a 3D multi-scale engineering sweet spot evaluation method which takes into account lithology, fracture morphology, fracture mechanical behavior, and dilatation and shear dilation effect, and finally a “geological-engineering” dual sweet spot evaluation model for tight sandstone reservoirs. Two wells in the tight sandstone gas field in the Linxing Block of the Ordos Basin were selected as a case, and the dual sweet spot profiles, fracturing pressure and SRV were compared and analyzed. The results show that: 1) shear dilation angle influences the distribution of engineering sweet spots at the most in the study area, followed by dissipated energy, elastic modulus and fracture energy; 2) the geological sweet spot zone with a high coefficient is not necessarily the pay zone with high shale gas production; 3) the engineering sweet spot zone with a high coefficient needs lower fracture pressure and can be stimulated relatively sufficiently; 4) high-quality geological sweet spots and high-quality engineering sweet spots are poorly consistent in spatial location. In conclusion, the stimulation of tight sandstone gas reservoirs shall take geological sweet spot as the basis and engineering sweet spot as the guarantee, and the distribution of dual sweep spots should be considered comprehensively. The multi-scale “geological-engineering” dual sweet spot evaluation method proposed in this paper provides important technical support for the prediction of sweet spots of the tight sandstone gas and the optimization of development schemes in the study area.

Hydraulic fracturing-induced microseismicity controlled by rock brittleness and natural fractures in Tongren, Guizhou, China

Hydraulic fracturing-induced microseismicity has drawn public attention in recent years. However, understanding the behavior of hydraulic fracture is limited due to the complex relationship between microseismicity and various geologic conditions. To further understand this question, we conduct a study to detect and locate hydraulic fracturing-induced microseismicity at a shale gas production site in Tongren, Guizhou, China. We investigate the relationship between their distribution and two important geologic factors: the brittleness index (BI) of rocks and the distribution of natural fractures. With the aid of a 3D active seismic survey, we first calculate the BI of rocks in the hydraulic fracturing region using Young’s modulus and Poisson’s ratio, compared with the locating result of fracturing-induced microseismicity, which indicates that most of the events are distributed in the area with higher BI. We then delineate natural fractures using the ant-tracking method of the 3D seismic attribute. The microseismic location is consistent with the region of natural fractures. Based on our findings, we suggest that the spatial distribution of induced microseismicity is highly controlled by the brittleness of rocks and the distribution of natural fractures in this region. This research provides insights into the factors controlling hydraulic fracturing-induced microseismicity and enhances our understanding of the complex interplay between geologic conditions and the behavior of hydraulic fractures.

Fracture propagation laws of staged hydraulic fracture in fractured geothermal reservoir based on phase field model

Hydraulic fracturing is widely used in geothermal resource exploitation, and many natural fractures exist in hot dry rock reservoirs due to in-situ stress and faults. However, the influence of natural fractures on hydraulic fracture propagation is not considered in the current study. In this paper, based on the phase field model, a thermo-hydro-mechanical coupled hydraulic fracture propagation model was established to reveal the influence of injection time, fracturing method, injection flow rate, and natural fracture distribution on the fracture propagation mechanism. The results show that fracture complexity increases with an increase in injection time. The stress disturbance causes the fracture initiation pressure of the second cluster significantly higher than that of the first and third clusters. The zipper-type fracturing method can reduce the degree of stress disturbance and increase fracture complexity by 7.2% compared to simultaneous hydraulic fracturing. Both low and high injection flow rate lead to a decrease in fracture propagation time, which is not conducive to an increase in fracture complexity. An increase in the natural fracture angle leads to hydraulic fracture crossing natural fracture, but has a lesser effect on fracture complexity. In this paper, we analyzed the influence of different factors on initiation pressure and fracture complexity, providing valuable guidance for the exploitation of geothermal resources.

Numerical Investigation of Influential Factors in Hydraulic Fracturing Processes Using Coupled Discrete Element‐Lattice Boltzmann Method

AbstractHydraulic fracturing is widely used to stimulate unconventional reservoirs, but a systematic and comprehensive investigation into the hydraulic fracturing process is insufficient. In this work, a discrete element‐lattice Boltzmann method is implemented to simulate the hydro‐mechanical behavior in a hydraulic fracturing process. Different influential factors, including treatment parameters (injection rates and fluid viscosity), formation parameters (in situ stress states and natural fractures) and rock properties (heterogeneity of rock strengths and rock permeability), are considered and their impacts on the initiation and propagation of hydraulic fractures are evaluated. A higher injection rate, increased viscosity, and larger in situ stress will lead to an increase in the initiation pressure. Conversely, higher formation permeability and a greater degree of heterogeneity in bond strengths will result in a decrease in the initiation pressure. The complexity of generated fractures is significantly influenced by the injection rate and degree of heterogeneity. However, fluid viscosity, in situ stress states, and formation permeability individually do not affect the geometrical complexity. Shear displacement can occur during a hydraulic fracturing process due to increased pore pressure and variations in in situ stress caused by injected fluid. Low‐viscosity fluid with a high injection rate can have a significant pressure buildup and generate complex fracture networks in low‐permeability heterogeneous formations. Natural fractures can significantly impact the complexity of generated fractures, while more in‐depth research is required regarding complex natural fracture distributions.

Frac-Hit Prevention Countermeasures in Shale Gas Reservoirs with Natural Fractures

The development of natural fractures (NFs) in shale gas reservoirs is conducive to improving the productivity of shale gas wells. However, NF development leads to high-frequency frac hits between the infill and parent wells, which critically restricts its efficiency. To elucidate the large contribution of hydraulic fractures (HFs) and NFs in frac hits during the production and the development of NF-developed shale gas reservoirs, such reservoirs in the WY area of western China are taken as an example. A total of 197 frac hits well events in this area are systematically classified via the frac-hit discrimination method, and the effects of different factors on HF- and NF- dominated frac hits are classified and studied. Combined with the correlation analysis method and the chart method, the main controlling factors affecting the two types of frac hits are determined, and the corresponding frac-hit prevention countermeasures are proposed. The research demonstrates that (1) the distribution and development of NFs are crucial to production after frac hits. NFs and HFs in the WY area cause 51% and 49%, respectively, of the frac hits. (2) The main controlling factors in NF-dominated frac hits are the approximation angle, fracture linear density, and horizontal stress difference, whereas they are net pressure in fractures, horizontal stress difference, and liquid strength in HF-dominated frac hits. Sensitivity analysis shows that the NF activation difficulty coefficient fluctuates between −35.1% and 47.6%, and the maximum hydraulic fracture length fluctuates between −43.5% and 25.29%. (3) The corresponding frac-hit prevention countermeasures are proposed for the two types of formation mechanisms from different approaches, including frac-hit risk assessment and path planning, production well pressurization and stress diversion, and infill-well fracturing parameter optimization. This paper not only provides a reference for exploring the formation mechanism of frac hits in fractured shale gas reservoirs but also a theoretical basis for the corresponding frac-hit prevention countermeasures.

Numerical Simulation on Radial Well Deflagration Fracturing Based on Phase Field Method

A radial well has a unique wellbore configuration. Fracture propagation in radial well deflagration fracturing is studied rarely. The mechanism of interaction between deflagration fractures, natural fractures, and micro-fractures is still unknown. Based on continuum mechanics, damage mechanics, and variational principles, a numerical model of fracture propagation in deflagration fracturing is established with the Hamilton principle and phase-field fracture theory. The effects of horizontal principal stress difference, natural fracture distribution, and micro-fractures around the wellbore on fracture propagation in deflagration fracturing are studied. First, when no natural fractures are developed around the radial well, fractures are initiated at both ends of the radial well. Second, when there are three natural fractures around the radial well, the created fractures have the morphology of shorter fractures in the middle and longer fractures on both sides under stress interference mechanisms. Third, a larger density of natural fractures causes obvious stress superposition, changes the initiation points of radial wells and fracture morphology, and increases fracture width and reservoir stimulation volume. Fourth, as the micro-fractures increase, their interference and induction effects on deflagration fractures are enhanced gradually, and the deflection angle of fractures increases by 38.7%. The study provides a reference for optimizing deflagration fracturing in a radial well.