Artificial Fracture Research Articles

Experimental and Modeling Investigation on Artificial Fracture Conductivity for Hybrid Fracturing in a Deep Carbonate Reservoir Using an Acid and a Proppant

Experimental and Modeling Investigation on Artificial Fracture Conductivity for Hybrid Fracturing in a Deep Carbonate Reservoir Using an Acid and a Proppant

Investigation into hydraulic fracture propagation behavior during temporary plugging and diverting fracturing in deep coal seam

In this study, we conducted indoor temporary plugging and diverting fracturing (TPDF) experiments on samples of natural deep and shallow coal seams using a small-scale true triaxial fracturing simulation system. By integrating high-precision CT scanning technology and crack reconstruction techniques, and relying on the quantitative characterization of the crack complexity coefficient, we investigated the differences in internal structures between deep and shallow coal seam samples and the variations in the expansion of TPDF cracks. Furthermore, the study primarily focused on exploring the influence of temporary plugging agent (TPA) parameters (quantity and particle size) on the expansion patterns of TPDF cracks in deep coal seam coal-rock samples. The experimental results reveal that in shallow coal samples, artificially induced fractures are notably longer and extend to various surfaces of the samples. Conversely, in deep coal samples, the expansion of artificially induced fractures is influenced by well-developed cleavage and cleats. The crack complexity coefficient of artificial fractures in deep coal samples is 1.54 higher than that in shallow coal samples, with an increased crack width of 98 μm. However, the expansion distance of the fractures is shorter and does not extend to the S3 and S6 surfaces. Increasing the dosage of the TPA is advantageous for inducing frequent redirection of fractures and communication with previously untouched areas. When the dosage of the TPA is increased from 30 g/L to 60 g/L, the expansion distance of artificial fractures significantly increases, extending to various surfaces of the samples. The crack complexity coefficient increases by 1.1, and the crack width enlarges by 84 μm. Appropriate particle sizes of the TPA can effectively form seals. However, small particle sizes (200/400 mesh) struggle to seal initial fractures, while large particle sizes (10/20 mesh) can lead to excessive wellhead blockage, causing rapid shut-in pressure, destructive fracturing in deep coal samples, and the generation of a large amount of coal fines. This study holds significant guidance for the optimal selection of process parameters in the temporary plugging hydraulic fracturing of deep coal rock.

A novel pressure transient analysis model for fracturing wells in fracture–cavity carbonate reservoirs

Large-scale karst caves are the principal storage spaces for hydrocarbon resources in fracture–cavity carbonate reservoirs. Drilling directly into these caves is considered the ideal mode of development, but many wells do not effectively penetrate karst caves. Therefore, acid fracturing is employed to generate artificial fractures that can connect with these caves. However, there are no appropriate well test methods for fracturing wells in fracture–cavity reservoirs. This study establishes a novel pressure transient analysis model for such wells. A new mathematical model is proposed that couples linear flow in acid fracturing cracks with radial flow in the oil drainage area. The Laplace transform and Stehfest numerical inversion provided analytical solutions for the bottomhole pressure. Typical log–log well testing curves were plotted to analyze oil flow, which occurs in ten stages. During the flow stage in fracturing cracks, the pressure and pressure derivative curves are parallel lines with a slope of 0.5. In the stage of karst cave storage, the pressure derivative curve is a straight line with a slope of 1. A comparison with previous models confirmed the validity of the proposed model. The influence of key parameters on the behavior of typical curves is analyzed. A field case study of the proposed model was carried out. Parameters related to fracturing cracks and karst caves, such as the crack length and cave radius, were successfully estimated. The proposed model has great potential for determining formation parameters of fracture–cavity reservoirs.

Development status and research recommendations for thermal extraction technology in deep hot dry rock reservoirs

AbstractBased on a comprehensive review of domestic and foreign literature, this article discusses the technical difficulties and development status of enhanced geothermal system (EGS) concerning the thermal energy extraction of deep hot dry rock (HDR) reservoirs and proposes suggestions for the research focus of numerical simulation of HDR reservoir stimulation. Additionally, it summarizes the existing methods and mainstream working fluids for HDR reservoir stimulation. The article emphasizes the significance of factors such as well location, production well depth, artificial fracture orientation, and complexity in optimizing the thermal production efficiency of the EGS. Furthermore, this article delves into a detailed discussion on the influence of fracture spacing, fracture permeability, fracture length, fluid injection rate, and injected fluid temperature on the performance of the EGS. In light of the thermo‐hydro‐mechanical coupling challenges associated with high‐temperature reservoirs, it is suggested that future research efforts should focus on investigating the impact of thermo‐induced stresses on the stability of the artificial fracture network within the EGS during long‐term (>30 years) circulation of hot and cold fluids.

A Viscoplasticity Model for Shale Creep Behavior and Its Application on Fracture Closure and Conductivity

Hydraulic fracturing is the main means for developing low-permeability shale reservoirs. Whether to produce artificial fractures with sufficient conductivity is an important criterion for hydraulic fracturing evaluation. The presence of clay and organic matter in the shale gives the shale creep, which makes the shale reservoir deform with time and reduces the conductivity of the fracture. In the past, the influence of shale creep was ignored in the study of artificial fracture conductivity, or the viscoelastic model was used to predict the conductivity, which represents an inaccuracy compared to the actual situation. Based on the classical Perzyna viscoplastic model, the elasto-viscoplastic constitutive model was obtained by introducing isotropic hardening, and the model parameters were obtained by fitting the triaxial compression creep experimental data under different differential stresses. Then, the constitutive model was programmed in a software platform using the return mapping algorithm, and the model was verified through the numerical simulation of the triaxial creep experiment. Then, the creep calculation results of the viscoplastic constitutive model and the power law model were compared. Finally, the viscoplastic constitutive model was applied to the simulation of the long-term conductivity of the fracture to study the influence of creep on the fracture width, and sensitivity analysis of the influencing factors of the fracture width was carried out. The results show that the numerical calculation results of the viscoplastic model were in agreement with the experimental data. The decrease in fracture width caused by pore pressure dissipation and reservoir creep after 72 h accounts for 32.07% of the total fracture width decrease.

Differences in stress sensitivity of natural-artificial fracture networks in tight sandstone gas reservoirs

Abstract The stress sensitivity of fractures has a significant impact on the production characteristics of tight sandstone gas reservoirs. However, there has been a lack of attention to and research on the differences between different types of fracture and their stress sensitivity. Based on the core samples of the Keshen gas reservoir in Xinjiang, China, this paper conducts a comprehensive comparison of the flow capacity, stress sensitivity, and the production characteristics of the structural fracture, diagenetic fracture, and artificial fracture. The findings reveal that the flow capacity of a single structural fracture is higher than that of a diagenetic fracture. Additionally, both structural and diagenetic fractures contribute to increasing the flow capacity of the porous system by 63 and 88%, respectively. The stress sensitivity of fractures varies from strong to weak, structural fractures exhibit a higher sensitivity compared to diagenetic fractures, and artificial fractures demonstrate the weakest stress sensitivity. Based on the fitting formulas of stress-sensitivity curves for different fractures, a new seepage model considering different stress sensitivities was established and numerical simulations were conducted. The numerical simulation results indicate that the gas well with a diagenetic-artificial fracture network yields a higher production, the 10-year production is 35.01% higher than that with a structural-artificial fracture network. This study is of great significance for understanding the production differences of fractured tight sandstone gas reservoirs and provides valuable insights for selecting optimal well locations.

Effect of natural fracture on the heat mining of enhanced geothermal system based on the thermo-hydro-mechanical coupling model

ABSTRACT Hydraulic fracture, natural fracture and fracture networks play a vital role for heat mining of Enhanced Geothermal System (EGS). In this work, a two-dimensional thermo-hydro-mechanical (THM) EGS model was proposed to investigate the effect of natural fracture on heat extraction performance. Based on the local thermal non-equilibrium theory and discrete natural fracture network, the spatial and temporal distribution of temperature, pore pressure, effective stress, rock matrix porosity and permeability are investigated. The results show that the natural fracture has a significant negative effect on the production temperature. After the 40-year prediction, the production temperature of the base model is 45.5°C lower than that of the without natural fracture model. In the initial operation stage, the low-temperature region is mainly distributed in the region of artificial fracture and injection well, then it expands significantly to the natural fracture due to the stress redistribution. The key parameters of quantity and orientation of natural fracture can lead to a decline in production temperature and earlier thermal breakthroughs within the thermal reservoir.

Experimental and Theoretical Study of Seepage Models under Confining Pressure for a Single Rock Fracture

The engineering water inrush events were affected by the hydraulic characteristics of the fractures. In order to quantitatively study the seepage characteristics of the fractures, the experimental analysis of artificial fracture of shale was carried out under different confining pressure (22 MPa – 38 MPa) to explore the influence of confining pressure on seepage characteristics. Three theoretical constitutive formulas to describe the characteristics of seepage were proposed based on cubic law and fracture constitutive equation (Bandis model, Rong model, Sun model), and these theoretical constitutive formulas all had good fitting results to experiment results which indicated that the derived formulas are feasible. The parameters for the three models were compared, among which the Rong model was more suitable to describe the connection between (Q) and (Pc). Rong model and Sun model were highly descriptive to the relationship between (Pc) and (Ps). The formulas that based on three theoretical models can provide quantitative calculation for the influence of in-situ stress change on the seepage of fractures in engineering practice.

A technique for enhancing tight oil recovery by multi-field reconstruction and combined displacement and imbibition

A seepage-geomechanical coupled embedded fracture flow model has been established for multi-field coupled simulation in tight oil reservoirs, revealing the patterns of change in pressure field, seepage field, and stress field after long-term water injection in tight oil reservoirs. Based on this, a technique for enhanced oil recovery (EOR) combining multi-field reconstruction and combination of displacement and imbibition in tight oil reservoirs has been proposed. The study shows that after long-term water flooding for tight oil development, the pressure diffusion range is limited, making it difficult to establish an effective displacement system. The variation in geostress exhibits diversity, with the change in horizontal minimum principal stress being greater than that in horizontal maximum principal stress, and the variation around the injection wells being more significant than that around the production wells. The deflection of geostress direction around injection wells is also large. The technology for EOR through multi-field reconstruction and combination of displacement and imbibition employs water injection wells converted to production and large-scale fracturing techniques to restructure the artificial fracture network system. Through a full lifecycle energy replenishment method of pre-fracturing energy supplementation, energy increase during fracturing, well soaking for energy storage, and combination of displacement and imbibition, it effectively addresses the issue of easy channeling of the injection medium and difficult energy replenishment after large-scale fracturing. By intensifying the imbibition effect through the coordination of multiple wells, it reconstructs the combined system of displacement and imbibition under a complex fracture network, transitioning from avoiding fractures to utilizing them, thereby improving microscopic sweep and oil displacement efficiencies. Field application in Block Yuan 284 of the Huaqing Oilfield in the Ordos Basin has demonstrated that this technology increases the recovery factor by 12 percentage points, enabling large scale and efficient development of tight oil.

Optimization method of refracturing timing for old shale gas wells

Based on the elastic theory of porous media, embedded discrete fracture model and finite volume method, and considering the micro-seepage mechanism of shale gas, a fully coupled seepage-geomechanical model suitable for fractured shale gas reservoirs is established, the optimization method of refracturing timing is proposed, and the influencing factors of refracturing timing are analyzed based on the data from shale gas well in Fuling of Sichuan Basin. The results show that due to the depletion of formation pressure, the percentage of the maximum horizontal principal stress reversal area in the total area increases and then decreases with time. The closer the area is to the hydraulic fracture, the shorter the time for the peak of the stress reversal area percentage curve to appear, and the shorter the time for the final zero return (to the initial state). The optimum time of refracturing is affected by matrix permeability, initial stress difference and natural fracture approach angle. The larger the matrix permeability and initial stress difference is, the shorter the time for stress reversal area percentage curve to reach peak and return to the initial state, and the earlier the time to take refracturing measures. The larger the natural fracture approach angle is, the more difficult it is for stress reversal to occur near the fracture, and the earlier the optimum refracturing time is. The more likely the stress reversal occurs at the far end of the artificial fracture, the later the optimal time of refracturing is. Reservoirs with low matrix permeability have a rapid decrease in single well productivity. To ensure economic efficiency, measures such as shut-in or gas injection can be taken to restore the stress, and refracturing can be implemented in advance.

Dynamic Pressure Analysis of Shale Gas Wells Considering Three-Dimensional Distribution and Properties of the Hydraulic Fracture Network

A major challenge in transient pressure analysis for shale gas wells is their complex transient flow behavior and fracturing parameters. While numerical simulations offer high accuracy, analytical models are attractive for transient pressure analysis due to their high computational efficiency and broad applicability. However, traditional analytical models are often oversimplified, making it difficult to capture the complex seepage system, and three-dimensional fracture characteristics are seldom considered. To address these limitations, this study presents a comprehensive hybrid model that characterizes the transient flow behavior and analyzes the pressure response of a fractured shale gas well with a three-dimensional discrete fracture. To achieve this, the hydraulic fracture is discretized into several panels, and the transient flow equation is numerically solved using the finite difference method. Based on the Langmuir adsorption isotherm and the pseudo-steady diffusion in matrix and Darcy flow in the network of micro-fractures, a reservoir model is established, and the Laplace transformation is adopted to solve the model analytically. The transient responses are obtained by dynamically coupling the flow in the reservoir and the discrete fracture. The precision of the proposed model is validated using the commercial numerical simulator, Eclipse. A series of transient pressure dynamic curves are drawn to make a precise observation of different flow regimes, and the effects of several parameters on transient pressure response are also examined. The results show that the shale gas well testing interpretation curves comprise nine flow stages. The pressure drop of shale gas reservoirs is lower than that of conventional gas reservoirs due to the replenishment of desorbed gas. The artificial fracture flow capacity, fracture length, and height are the main engineering factors affecting the pressure responses of shale gas wells. Maximizing the degree and scope of reconstruction can enhance the gas well production capacity during fracturing construction. The research results also indicate that our model is a reliable semi-analytical model for well test interpretations in real case studies.

Experimental study on the effect of foam in preventing gas channeling in shale reservoir

Shale oil resources have enormous potential and broad development prospects in China. Especially with the rapid development of horizontal well volume fracturing technology, the production of shale oil has been greatly increased, and it has become an important position to increase oil and gas storage and production. However, due to the existence of artificial and natural fractures produced by fracturing, gas channeling will occur in the process of huff-n-puff gas injection, which will affect the production and lead to poor development effect. In this paper, foam is used as an anti-channeling agent in the process of huff-n-puff gas injection. The results of microfluidic experiments show that the production mode of foam in porous media is liquid membrane hysteresis and liquid membrane separation. In porous media, foam first blocks large channels such as fractures, and then enters the matrix. The oil recovery mechanism of foam assisted gas injection in porous media is to improve the sweep efficiency and oil displacement efficiency of gas. Compared with N2 huff-n-puff, the oil recovery of the first cycle of foam assisted N2 huff-n-puff increased by 4.50%, and the third cycle increased by 9.58%. It is proved that foam has good anti channeling effect in gas huff-n-puff injection process. The research results provide an effective method for efficient gas injection development of shale oil.

Study on multi-cluster fracturing simulation of deep reservoir based on cohesive element modeling

With the depletion of conventional reservoir development, reservoir fracturing under deep high geo-stress and high geo-stress difference conditions is receiving increasing attention. Deep reservoirs typically require multi-cluster fracturing to achieve efficient reservoir transformation and development. In this paper, considering the relevant geological parameters of a certain reservoir in the southwest, three-dimensional multi-cluster reservoir fracturing models were established based on cohesive element modeling. Then, the propagation law of artificial fractures in reservoirs under the influence of the different number of fracturing clusters, injection displacement, and Young’s modulus in different regions of the 60 m fracturing well section is analyzed, and the quantitative law of parameters such as fracture length, maximum fracture width, injection point fracture width, fracture area, and tensile failure ratio during multi-cluster fracturing construction, as well as the propagation law of fracture morphology are revealed. The simulation results show that using multi-cluster fracturing can significantly improve the effectiveness of reservoir reconstruction, but as the number of fracturing clusters increases, it is also easy to form some small opening artificial fractures. These small opening artificial fractures may not be conducive to the transportation of proppants and fluids. During single cluster fracturing, the interface stiffness and rock Young’s modulus have a significant impact on the propagation of artificial fractures in the reservoir. As the number of fracturing clusters increases, the competition between artificial main fractures expands significantly, which may reduce the impact of interface stiffness and rock Young’s modulus. The fluid injection rate has a significant impact on reservoir fracturing, and in the same area, using high displacement injection can significantly increase the volume of reservoir reconstruction. This study can provide some reference for multi-cluster fracturing construction in deep reservoirs.

Experimental investigation of CO2 foam flooding-enhanced oil recovery in fractured low-permeability reservoirs: Core-scale to pore-scale

Fractured low-permeability reservoirs are characterized by poor reservoir physical properties, strong interlayer heterogeneity and the existence of natural and artificial fractures, resulting in significant water or gas channeling during flooding development. CO2 foam can effectively control the mobility of CO2 and ensure a more stable flooding front. In this study, taking into account the imbibition effect of the flooding process, the flooding performance under different injection methods and the influencing factors of foam pre-injection volume, back pressure and fracture complexity on CO2 foam flooding were systematically analyzed using fractured low-permeability core flooding experiments. In addition, the mechanism of CO2 foam flooding enhanced oil recovery (EOR) in low-permeability fractured reservoirs was obtained in combination with microscopic flooding experiments. The results show that the maximum recovery of 59.36 % can be obtained by soaking the core samples for 12 h with pre-injection of 0.4 PV CO2 foam followed by CO2 foam flooding, which adequately considers the imbibition effect during the flooding process. The pressure difference and oil recovery increases with increasing foam pre-injection amount, and the oil recovery with back pressure (2 MPa and 4 MPa) is significantly higher than that without back pressure; however, a further increase in back pressure has less impact on the recovery. The oil recovery rate of the fracture-free core is lower than that of the multiple fracture core during CO2 foam flooding but higher than that of the single fracture core, and the fracture complexity of the fractured cores has less impact on the final oil recovery. Microscopic experiments show that CO2 foam can effectively prevent channeling and improve the sweep efficiency. Soaking during the CO2 foam flooding process makes foam enter the matrix through the fracture, and CO2 dissolves after the foam breaks to increase the mobility of the crude oil, while the surfactant solution emulsifies the crude oil and changes the rock wettability. The unbroken foam can increase the sweep range, and the crude oil that flows into the fracture is carried by the subsequent injected foam to be recovered as foamy oil.

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.

Acid Fracturing Technology and Effect Evaluation of Carbonate Horizontal Well in Fuman Oilfield

Since the deep and ultra-deep carbonate rocks in the Fuman oilfield have made continuous breakthroughs, the acidification and fracturing of the reservoir on the south bank of Tarim River have been faced with problems such as faster acidification and shorter effective acidification fracture length with the increased burial depth and formation temperature, which seriously restrict the effect of acidification and fracturing. At present, the Fuman oilfield has achieved remarkable results after acid fracturing construction. In this paper, the acid fracturing construction effects of multiple reservoir reconstruction Wells in Tahe Yueman, Fuyuan, Guole, and Manshen blocks are evaluated and classified by analyzing acid fracturing construction curves, using fracture static pressure fitting and fracture conductivity curve analysis. The characteristics and distribution law of carbonate reservoirs corresponding to different construction curves are studied, and various situations of artificial fractures communicating with natural fracture-cavity systems are analyzed. The research results can accurately guide the design optimization and development of acid pressure.

Parameter optimization study of three-dimensional well network-fracture network coupled fracturing in jimsar shale oil

The exploration of sweet spots in the Jimsar shale oil reservoir in Xinjiang involves creating a complex fracture network through three-dimensional well networks and advanced fracturing technology, crucial for successful shale oil reservoir development. However, the extremely low permeability of shale oil and limited natural flow capacity of crude oil pose significant challenges. The interconnection between three-dimensional well networks and artificial fracture networks, and the relationship between fracturing parameters and fracture morphology, remain unclear. This study focuses on the P2l12−2 and P2l12−3 layers of the Lucaogou Formation. Utilizing the Petrel geological engineering integrated platform and the Kinetix fracturing module, we conducted numerical simulations to explore coupled fracturing in different sweet spots, with a specific emphasis on well network and fracture network coupling. This study identified relevant optimized engineering parameters. Research findings indicate that, during single-well single-factor optimization, the viscosity optimization range for Class II reservoirs is smaller compared to Class I reservoirs. However, for other factors such as injection rate, liquid volume, proppant concentration, cluster count, etc., the optimization ranges are greater for Class II reservoirs than for Class I reservoirs. In the case of single-factor optimization for well networks, increasing well spacing leads to larger optimization ranges for proppant concentration and perforation numbers. Under the same well spacing, an alternating wellbore arrangement results in a smaller optimization range for proppant concentration but a larger range for perforation numbers compared to a directly opposite wellbore arrangement. Additionally, this paper summarizes the optimization ranges and provides relevant tables and figures, aiming to offer guidance for on-site construction.

Artificial fractures conductivity impairment in gas shale when fracturing with surface water

The shale gas fields are mainly in mountainous areas in China. Surface water is the major source of hydraulic fracturing fluid to develop shale gas. The clay mineral is generally rich in the shale gas reservoir. When encountered with low salinity surface water, the clay minerals are easy to hydrate in the process of fracturing and well shut-in. The hydration of clay minerals would result in the expansion, dispersion, and migration of mineral particles from the fracture surface, changing the structure and space of fractures, thereby affecting fracture conductivity. In this paper, shale artificial fracture core models were developed with rough fracture surfaces. With proppant-supported and self-supported fracture core models, the impact of hydration time, net pressure, and dislocation distance of fracture surfaces on the artificial conductivity were evaluated systematically. The results show that the conductivity of proppant-supported and self-supported fractures decreases by 85.3–95.1% under hydration. The turning point of conductivity is 8.0 hrs. and 4.3 hrs., respectively. At the initial stage of production, the artificial fracture could be protected better if the net pressure on the fracture is maintained from small to large. At the same time, the initial net pressure on fracture should be less than the proppant crushing pressure. Certain dislocation distances of self-supported fractures would augment the conductivity by 6.4–12.8 times. After hydration, illite and montmorillonite in the rock surface expanded and dispersed when encountered with water. The fracture surface strength decreases by 29.8%, while the surface roughness decreases by 46.1–51.6%, and some proppants were crushed. Then the fracture conductivity space was reduced. By adding KCl into the fracturing fluid, hydration can be effectively inhibited, which can increase the proppant-supported and self-supported fracture conductivity by 2.5–3.4 times, compared with fracturing fluid prepared with surface water. This study provides a theoretical basis for the optimization of shale gas reservoir fracturing technology and production strategy.

Determination of fracturing pressure during drilling analytical method

When drilling, the depth of wells is constantly increasing, and as a result, the likelihood of various complications increases. Complications include: loss of drilling fluid; gas-oil-water manifestations, violation of the stability of the well walls, sticking. Almost all complications, if special measures are not taken to prevent and eliminate them, turn into accidents. One of the complications arising from well drilling is hydraulic fracturing. Fracturing pressure is the pressure at which the integrity of the rock in the walls of the well is broken, and artificial fractures are formed. During the drilling process during hydraulic fracturing, the drilling fluid goes into the surrounding rocks. n the proposed scientific work, using the energy condition of destruction, the hydraulic fracturing pressure is determined depending on the mechanical characteristics of the rock and reservoir pressure.

Effects of cyclic fatigue loads on surface topography evolution and hydro-mechanical properties in natural and artificial fracture

This work investigated permeability evolution for fluid flow through natural fractures and artificial fractures in granite and the evolution of failure surface under cyclic fatigue loads condition. We revealed and compared a clear distinction between two types of fracture surfaces before and after the test, and analyzed the evolution of fracture surface roughness and other parameters which can characterize their topography feature, as well as the relationship between fracture surface topography and permeability. The studies indicated that artificial fractures show the higher roughness and subtler variations of surface topography than those of natural fractures, however, the surface topography of natural fractures was more susceptible to cyclic fatigue loads. The initial permeability and average permeability of nature fractures were both higher than those of artificial fractures during the stress-seepage coupling test and the permeability of artificially fracture was more sensitive to normal stress changes. Moreover, the experimental results were in line with theoretical predictions and the research results can provide reference for preventing the failure of rock engineering.