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The mid-deep geothermal energy is extracted from the fracture network created by hydraulic fracturing. Generally, the hydraulic fracture created in the deep thermal reservoir shows the planar shape but not the network shape, and this significantly impacts the geothermal extraction efficiency. In this study, a geothermal extraction technology by radial well assisted hydraulic fracturing, which connects hydraulic fractures to each other, was proposed. An operation technique of radial well-assisted hydraulic fracturing in geothermal reservoirs without well-developed NFs was established. The model considering evolution of fracture permeability was resolved by thermo-hydromechanical (THM) coupling numerical simulation. The results show that the radial wells should be placed vertically within a large range. The thermal production increases by 20%, about 0.25 MW as the radial well length increases from 50 m to 200 m. As many fractures as possible are needed in thermal exploitation, and the fracture number should be at least 7. The simulation demonstrates that the radial well-assisted hydraulic fracturing heat recovery method is feasible in simulation. In this thesis, a more accurate numerical simulation method of geothermal production capacity is proposed, which has engineering guiding significance for the actual development and prediction of geothermal energy. [ABSTRACT FROM AUTHOR]

Fracturing fluid flowback is a key step in the process of hydraulic fracturing, and the imbibition of fracturing fluid in unconventional tight reservoirs cannot be ignored. Based on the oil-water two-phase seepage theory, Bernoulli equation and the continuity equation, we establish a numerical simulation model of post-fracturing flowback by considering the effect of fracturing fluid imbibition and obtain the pressure and flowback rate during the flowback process through programmed numerical calculation. The critical flow rate of fracturing fluid when the proppant starts to reflux is calculated according to the proppant backflow model. Then an optimization design method of flowback working system is formed based on the principle of controlling proppant backflow and rapid fluid flowback. The numerical simulation results are compared with the actual flowback data of LX3 well, and the flowback working strategy of M87 well is designed, and the effects of formation fluid viscosity and initial formation pressure on fracturing fluid flowback are analyzed. The results show that a phenomenon of formation fluid seepage to fractures is observed during the flowback, and the change of original formation pressure has a significant impact on fracturing fluid flowback, but the formation produced fluid has minor effects. The numerical results of flowrate and wellhead pressure of LX3 well are consistent with the field monitor data, with average errors of 13. 8% and 15. 5% respectively. It is verified that the flowback numerical model has high accuracy and can be used to guide the on-site fracturing flowback construction design in oilfield. [ABSTRACT FROM AUTHOR]

• Numerical model for in-fracture temporary plugging fracturing established. • Horizontal stress gradient markedly affects maximum deflection of steering fractures. • Raising in-fracture pressure enhances temporary plugging fracture efficiency. Internal temporary plugging fracturing technology improves the stimulated volume by forming a more complex fracture network, significantly enhancing the reservoir stimulation effect and effectively developing unconventional oil and gas resources. However, the current understanding of the fracture propagation mechanism on internal temporary plugging fracturing is still unclear, making it difficult to determine the main controlling factors that affect the shape of the fractures. In addition, the lack of practical numerical simulation methods for temporary plugging fracturing makes it challenging to provide guidance for field scheme design. Utilizing the finite element cohesive zone method, which incorporates globally embedded cohesive elements, this study constructs a comprehensive numerical model to investigate the propagation behavior of temporarily plugging fracturing fractures. The model delves into the impact of various geological and construction parameters on the opening conditions of branch fractures during the temporary plugging fracturing process, as well as the propagation patterns of fractures within naturally fractured reservoirs. The research findings indicate that the construction factors have the following impacts: When the pumping rate and viscosity of the fracturing fluid are comparatively high, the resulting fluid pressure within the fracture escalates, resulting in the creation of numerous branch fractures within the naturally fractured reservoir. This, in turn, augments the fracture's complexity. However, these two factors have little influence on the maximum deflection distance of the deflected fracture. As for the geological factors, an increase in the horizontal stress difference will decrease the maximum deflection distance of the deflected fracture, reducing the number of natural fractures intersected and shortening the length of the deflected fracture. Conversely, an increase in the approach angle will increase the maximum deflection distance of the deflected fracture, thereby expanding the affected area. Additionally, the influence of Young's modulus and Poisson's ratio on fracture propagation is very slight. A decrease in the tensile strength of natural fractures leads to more natural fractures being intersected during the process, resulting in increasing the length of the fracture and an improvement in the complexity of the fracture grid. [ABSTRACT FROM AUTHOR]

As a green, low-carbon and renewable energy, the geothermal energy has attracted great attentions. Abundant geothermal resources are hosted in several depleted oilfields. Geothermal development in abandoned oilfields has its advantages that operators are familiar with the geographic environment, geological conditions, and drilling and development techniques in the oilfield. In this study, a thermo-hydro- mechanical multi-field coupling mathematical model was established with data from Liubei Buried Hill reservoir in North China Oilfield. Then, the geothermal development in abandoned high-temperature oilfields was simulated, and the sensitivity of the geothermal development effect to well patterns, fracturing conditions, and working media was analyzed. The results show that the well pattern of one-injector and four-producer leads to the largest heat-exchange area. The hydraulic fracture model causes earlier thermal breakthrough but produces more heat than the non-fractured model. CO 2 has the better working fluid performance and leads to the better geothermal development effect than water. This study provides a theoretical basis for the high-efficiency development of geothermal energy in abandoned oilfields, and a guidance for research on geothermal development model and fracturing design. [Display omitted] [ABSTRACT FROM AUTHOR]

Hydraulic fracturing, a production enhancement technique, is widely used in the development of unconventional oil and gas reservoirs. The formation of a complex network of hydraulic fractures that connect with natural fractures is crucial for hydraulic fracturing in unconventional reservoirs. However, the current understanding of vertical fracture propagation behavior under the influence of variations in the mechanical properties of interbedded rock is insufficient to meet the requirements for simulations of unconventional reservoirs under complex geological conditions. In this study, a three-dimensional discrete grid method was employed to establish a model of three-dimensional fracture propagation. Numerical simulations were conducted to investigate the vertical growth of fractures while considering the influence of bedding planes. The effects of formation factors (stress, Young's modulus) and bedding planes (cohesion, density) on the height growth of hydraulic fractures were explored. The results indicated that the interbedded stress contrast, Young's modulus contrast, and bedding planes collectively controlled the height growth of hydraulic fractures. The height of hydraulic fractures decreased with increasing minimum horizontal principal stress of adjacent layers. When the minimum horizontal principal stress of adjacent layers exceeded the vertical stress, hydraulic fractures gradually deflected into the horizontal plane. Adjacent layers with large values of Young's modulus promoted the height growth of hydraulic fractures, while adjacent layers with small values of Young's modulus inhibited the height growth of hydraulic fractures. The presence of bedding planes further suppressed height growth, and the degree of suppression was related to the cohesion and density of the bedding planes. Weaker cohesion and higher density resulted in greater suppression. The results of this study provide a reference for the design and optimization of hydraulic fracturing treatments in unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

The clear mechanism of hydraulic fracture propagation in glutenite reservoirs with high heterogeneity is still not obtained, thus it is difficult to carry out the design of fracturing plan effectively. Based on the characteristics of the glutenite reservoirs, a coupled flow-stress-damage (FSD) model of hydraulic fracture propagation with gravels is established. This model is experimentally verified and the research on the influence of rock physical parameters and gravel property on the hydraulic fracture propagation is conducted. It is shown that as the gravel tensile strength increases, the hydraulic fracture is prone to propagate around the gravel, where the fracture deflection always occurs; as the gravel Young's modulus increases, there is high probability that hydraulic fracture propagates around the gravel, with more obvious fracture deflection; the matrix permeability influences fracture propagating morphology when encountering gravel and total fracture length; the horizontal geostress difference seriously impacts the fracture deflection; as the fracturing fluids injection displacement increases, the fracture is prone to deflect when encountering gravel; the low viscosity fracturing fluids result in the shorter fracture; the larger gravel increases the possibility of fracture deflection; in case of smaller gravel sizes, the increasing gravel content has a big influence on fracture deflection, and the increasing content of large gravel complicates the fracture morphology, resulting in the fine branched fractures; for the well rounded gravel, the fracture propagation around the gravel is prone to occur, and the fracture is not prone to deflect. Compared with the conventional sandstone reservoir, the glutenite reservoirs have higher breakdown and extension pressures, which fluctuate due to the gravel; the larger gravel size results in higher extension pressure. In this paper, a simulation method of hydraulic fracture propagation in the glutenite reservoirs is introduced, and the result provides the theoretical support for prediction of fracture propagation morphology and plan design of hydraulic fracturing in the glutenite reservoirs. [ABSTRACT FROM AUTHOR]

The conventional hydraulic fracturing is not effective in the target oil development zone (remaining oil or gas, trap reservoir, etc.) with available wellbores located in the azimuth of non-maximum horizontal in-situ stress. The technology of directional propagation of hydraulic fracture guided by vertical multi-radial boreholes was innovatively developed. In order to verify the technology, a 3D extended finite element numerical model of hydraulic fracturing promoted by vertical multi-radial boreholes was established using Abaqus Software, and the influence of horizontal in-situ stress differences, azimuth, diameters, spacing, and lengths of radial boreholes, rates and viscosities of fracturing fluids, Young modulus and Poisson's ratio of rock, and reservoir permeability on propagation of hydraulic fracture guided by radial borehole row were comprehensively analyzed. Moreover, the term ‘Guidance factor (G)’ was introduced for the first time to effectively quantify guidance of radial borehole row. Finally, the guidance of the above ten factors is comprehensively evaluated through gray correlation analysis. The results showed that the directional propagation of hydraulic fracture is realized through scientifically arranged vertical radial borehole row, and ‘G’ reflects the real guidance strength of radial borehole row to hydraulic fracture. The azimuth of radial borehole row increases by 75°, G increases by 18 times. Horizontal in-situ stress difference increases by 9 MPa, G increases by 95%. The borehole diameter increases by 4 cm, G decreases by 54%. The borehole spacing increases by 0.5 m, G increases by 18%. The borehole length increases by 10 m, G decreases by 40%. Young's modulus of reservoir rock increases by 20 GPa, G decreases by 23%. Poisson's ratio increases by 0.1, G increases by 57%. Permeability of reservoir increases by 100 times, G increases by 3.3 times. Injection rate increases by 9 m 3 /min, G decreases by 63%. Both excessively high and low viscosities are adverse to guidance of radial borehole to hydraulic fracture, and 50 mPa s fracturing fluid creates best guidance to propagation of hydraulic fracture. The gray correlation analysis showed that the influences (from strong to weak) of the above factors on guidance of radial borehole were listed as follows: azimuth of radial borehole > injection rate of fracturing fluid > horizontal in-situ stress differences > Young's modulus of rock > viscosity of fracturing fluid > borehole diameter of radial borehole > radial borehole spacing > reservoir permeability > length of radial borehole > Poisson's ratio. This study provided theoretical evidence for directional propagation of hydraulic fracture promoted by radial borehole, and it predicted the guidance of radial borehole to hydraulic fracture in a certain extent, which is helpful for planning well-completion and fracturing operation in technology of hydraulic fracturing promoted by radial borehole. [ABSTRACT FROM AUTHOR]

In order to study the effects of different parameters in hydraulic fracturing on formation temperature after low-temperature fracturing fluid is injected into high-temperature reservoir, in this paper, considering (1) osmotic pressure and capillary pressure (2) microthermal effect (heat conduction, heat convection, heat expansion, viscous dissipation) (3) the coupling processes of temperature (T), hydraulic, (H) mechanical (M) and chemical (C) in hydraulic fracturing process, and the coupled temperature prediction model of oil-water two-phase THMC based on discrete fractures is established. The effects of fracturing fluid temperature, reservoir temperature, dimensionless conductivity, Young's modulus, injection rate, cluster spacing, and proportion of branch fracture area on reservoir and fracture temperature during the pumping and shut-in stages of shale oil reservoir were studied. The results show (1) For formations with different reservoir temperatures, the temperature drop at the fracture was approximately 97% from the start of the operation to the end of the 30-day shut-in. The saturation change caused by fracturing fluid filtration is much larger than the temperature change caused by heat transfer, and it is found that the temperature and saturation change mainly occur in the early shut-in period (2) Imbibition accelerates the filtration loss of fracturing fluid. During pumping, the bottom hole temperature with imbibition considered is lower than that without imbibition considered. The temperature curve with imbibition considered begins to deviate about 10 min after pumping, but the final temperature tends to be the same, (3) When the fracturing fluid is pumped at high pressure, the fracture and matrix will be deformed, which will improve the porosity and permeability of the near well zone, thus speeding up the heat transfer rate. The high Young's modulus inhibits the increase of permeability. Compared with the young's modulus of 40 GPa and 20 GPa, the increase of permeability decreases by 9% (4) When the well was shut in for 30 days, the cluster spacing was greater than 20 m, and the temperature change around the fracture did not affect the clusters on both sides. The spacing between the clusters was 5 m, and the perforation clusters on both sides had a significant effect on the temperature. The temperature of the reservoir between the two adjacent clusters dropped from 393 K to 385 K. When there is a branch fracture, the small cluster spacing is equivalent to increasing the complexity of the fracture and accelerating the initial heat transfer rate. (5) High injection temperature, high dimensionless conductivity, low Young's modulus and low pumping rate are conducive to the heat transfer of fracturing fluid in the formation. • Based on the discrete fracture model, the temperature prediction model of oil-water two-phase flow was established. Considering the capillary force and osmotic pressure, the temperature (T) -hydraulic (H) -mechanical (M) -chemical (C) was realized. The finite element method is used to solve the model. • The effects of multiple factors on reservoir and fracture temperature during fracturing pumping and shut-in stages are analyzed. [ABSTRACT FROM AUTHOR]

On the basis of damage mechanics, a 2D fracture propagation model for seepage-stress-damage coupling in multi-fracture shales was established. Numerical simulations of hydraulic fracture propagation in the presence of natural fractures were carried out, with the use of mechanical parameters of shale reservoirs. The results showed that when hydraulic fractures encountered natural fractures in a shale reservoir, the morphology of fracture propagation was jointly affected by the properties of natural fractures (permeability and mechanical properties of rocks), approaching angle, horizontal stress difference, and flow rate of fracturing fluids. At a small horizontal stress difference, or low approaching angle, or small friction coefficient, natural fractures had increased potential to be damaged due to shear and tension. In such cases, the hydraulic fractures tended to propagate along the natural fractures. As the flow rate of fracturing fluid increased and the width of hydraulic fractures expanded, branch fractures formed easily when the net pressure exceeded the sum of horizontal stress difference and tensile strength of the rocks in which natural fractures with approaching angle smaller than 60° existed. It is seen, a high flow rate will increase the complexity of fracture network. However, when a large number of natural fractures with approaching angles greater than 60° existed, a large flow rate generally led to propagation of hydraulic fractures beyond natural fractures, which was not favored. Hence, an appropriate flow rate should be selected based on the orientations of natural fractures and hydraulic fractures. At the early stage of hydraulic fracturing, a low flow rate was favorable for the initiation of natural fractures and the growth of complexity of regional fractures near the well. Later, a higher flow rate facilitated a further propagation of hydraulic fractures into the depth of reservoir, thus forming a network of fractures. The underlying control mechanism of flow rate and net pressure on the formation of fracture network still requires clarification. The bending degree of the fracture propagation path depended on the ratio of net pressure to stress difference at a distant point as well as on the spacing between fractures. When the horizontal stress difference (<9 MPa) or coefficient of horizontal stress difference (<0.25) was low, the ratio of net pressure to stress difference was high. In this case, the fracture-induced stress obtained an enhanced significance, while the interactions of hydraulic fractures intensified, leading to a non-planar propagation of fractures. In addition, a smaller spacing between fractures caused intensified interactions of hydraulic fractures, so the propagation path altered more easily. This work contributes to the prediction of morphology of fracture propagation in unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

Compared with conventional hydrofracturing fluid, SC-CO 2 has the merits of no water sensitivity and effective carbon dioxide storage. At present, the research on the fracture initiation mechanism of SC-CO 2 fracturing is still at the exploring phase. This paper conducts a detailed study on the fracture initiation mechanism of SC-CO 2 fracturing, and establishes a fracture initiation and propagation model of flow-stress-damage coupling according to damage mechanics. A series of numerical simulation studies have been carried out on the rock physical parameters, fracturing construction parameters, natural fracture distribution and other factors that affect the fracture propagation of the reservoir to provide a reference for the SC-CO 2 fracturing construction design. The findings suggest: the lower formation permeability, the less SC-CO 2 filtration loss, and the larger total fracture length and width; SC-CO 2 is easier to improve the reservoir continuity and result in a complex fracture network; The lower the viscosity of SC-CO 2 , the larger total length of fractures, and the more complex the fracture network; As the delivery of pump increases, the width of fracture continues to increase, and the total fracture length decreases; SC-CO 2 has a better effect on communicating natural fractures and porous media, and the fracture network is more complex. • Fracture propagation model with flow-stress-damage (FSD) coupling is developed. • A simulation method of hydraulic fracture propagation in the glutenite reservoirs is introduced. • The model accuracy is validated through comparison between results of physical experiment and numerical simulation. • The effects of multiple factors on fracture propagating in the glutenite reservoirs are analyzed. [ABSTRACT FROM AUTHOR]

• A coupled THMD model for thermal reservoir fracturing propagating simulation was built. • The model accuracy was validated through case study, theoretical model and experiment. • The effect of different parameters on HDR hydraulic fracturing under thermal stress was explored. The hot dry rock (HDR) hydraulic fracturing is a complex physical process coupling the effects of seepage, stress, temperature, and damage. The high temperature and brittleness of the HDR leads to the great thermal stress, and the rock is possibly thermally damaged, thus promoting hydraulic fracture (HF) extension and significantly improving the permeability around the HF. In this paper, a thermo-hydro-mechanical-damage (THMD) coupling model is established based on elastic thermodynamics, Biot's classic seepage mechanics and mesoscopic damage mechanics, and its accuracy is evaluated through case study and verification with theoretical models and experiments. The evolution of multi-physics during hydraulic fracturing of HDR is studied, and the effects of rock thermophysical parameters, temperature difference, rock heterogeneity, Young's modulus, permeability, and injection rate on HF extension in the HDR are investigated. The results show that initially, due to the severe temperature variation near the borehole, the higher thermal expansion coefficient leads to the greater thermal tensile stress and facilitates rock damage, thus reducing the fracture pressure. The research results provide theoretical basis and technical support for fracturing design of geothermal system. [ABSTRACT FROM AUTHOR]

• A new model is proposed to study the multi-cluster fracturing. • The influence of different factors on the fracture propagation is studied. • The accuracy of model is verified by experiment. Multi-cluster fracturing in horizontal wells is a key technology for successful development of ultra-low permeability reservoir. The propagation of hydraulic fracture during multi-cluster fracturing is complicated, especially in shale reservoir with multiple natural fractures. The design and operation of multi-cluster fracturing requires adequate understanding of influence of different factors on hydraulic fracture propagation. Up to now, many scholars have studied the hydraulic fracture morphology in multi-cluster fracturing, but few have analyzed the effect of natural fractures on hydraulic fracture propagation during multi-cluster fracturing. In this paper, a new computationally version of the particle-based model is established by Xsite to study the fracture propagation in multi-cluster fracturing with natural fractures. The tensile strength and rock toughness are calculated, and tri-axial experiments are performed to verify the accuracy of model. Simulation results show that cluster spacing and in-situ stress difference have a significant influence on the length of the hydraulic fracture and the morphology of fracture. The length of middle fracture increases with the increase of the cluster spacing, but decreases with the increase of the in-situ stress difference during multi-cluster fracturing with three natural fractures. The enhancing of cluster spacing can reduce the deflection of left and right fractures, and the increase of the in-situ stress difference can improve the ability of middle fracturing penetrating the natural fracture. Three fracturing sequence of synchronous fracturing, two-step fracturing and sequential fracturing is simulated. The left and right fractures can always penetrate the natural fracture with different fracturing sequence. But the middle fracture shows different morphology of arresting by natural fracture (during synchronous fracturing), partially penetrating the natural fracture (during two-step fracturing) and directly penetrating the natural fracture (during sequential fracturing). Different cement strengths of natural fracture are analyzed. The increase of strength of natural fracture can enhance the ability of hydraulic fracture penetrating the natural fracture. Hydraulic fracture is arrested by weak natural fracture (shear strength of 0.5 MPa), resulting in natural fracture opening. As hydraulic fracture intersecting with strong natural fracture (shear strength of 20 MPa), the hydraulic fracture can penetrate the natural fracture directly without natural fracture opening. [ABSTRACT FROM AUTHOR]

The existence of solid hydrate in porous media always greatly reduces the relative permeability, which limits the development of hydrate reservoirs. Therefore, to recover the gas, it is necessary to carry out reservoir reconstruction measures that induce fractures around the production wells to increase the gas production of hydrate reservoirs. At present, there is limited quantitative research on the promotion of gas production by induced fractures in hydrate reservoirs. In this paper, numerical models of Class Ⅲ hydrate reservoirs with induced fractures are established. By comparing the gas production with and without induced fractures, the effectiveness of induced fractures in promoting the depressurization production of natural gas hydrates is verified. An index of improved efficiency is established and calculated to measure the promotion effect of induced fractures during the fracture promotion stage. The multiple regression calculation formulas of improved efficiency with reservoir geological parameters are obtained by integrating nonlinear regression and linear regression. The calculation model is helpful to quickly and directly measure the rationality and economy of the induced fracture depressurization method to promote hydrate development. • Numerical models of Class Ⅲ hydrate reservoirs with induced fractures are established. • An index of Improved Efficiency is established to measure the promotion effect of induced fractures. • The improved efficiency of induced fractures under different geological parameters is calculated and compared. • The multiple calculation formulas of improved efficiency with geological parameters are obtained by stepwise regression. [ABSTRACT FROM AUTHOR]