Reasonable volumetric fracturing effect evaluation is the key to effective stimulation of fractured reservoir. Traditional fracturing effect evaluation is mainly conducted by the SRV (stimulated reservoir volume), fracture length, fracture width and other indicators, ignoring the influence of failure mode on fracturing performance. In this paper, the different fracture modes including main fractures, branch fractures and self-supporting fractures contained in the fracture network and their contributions to fracturing effect were studied in depth by numerical simulation. The results show that the main fracture formed by tensile failure has the largest width but simple shape and relatively small distribution range, while the branch fracture has a slightly smaller width but effectively expands the main fracture. Although the self-supporting fracture by shear failure is not connected, it can still improve the overall flow conductivity. The angle and number of natural fractures in fractured reservoir have a significant effect on fracture network scale and fracturing effect. When the number of natural fractures is larger, both of the number and proportion of branching fractures and self-supported fractures are larger, although the isolated self-supported fractures account for a larger proportion, the overall flow conductivity of the final fracture network is stronger. When the angle of natural fractures is larger, the natural fractures in uniform stress field are easier to be connected by hydraulic fractures and the final fracturing effect is better. The research methods and results have a certain guiding significance for the evaluation of volumetric fracturing effect in fractured reservoirs and are conducive to the reasonable selection of favorable fracturing areas and engineering parameters.

The bottom hole fluctuating pressure has a large influence on the wellbore instability. To address this problem, firstly, according to the principle of seepage mechanics, we established a calculation model of the change in pore pressure around the wellbore radius under fluctuating pressure; then, through laboratory rock mechanics test and rock damage mechanics theory analysis, the change law of formation strength under the action of static hydration and dynamic damage are determined; finally, based on the theory of rock mechanics in porous media, a quantitative evaluation method for the risk of wellbore instability under fluctuating pressure is established and the changing pattern of wellbore instability risk is analyzed. The results show that the pore pressure around the well shows a trend of fluctuation increase under fluctuating pressure, and there is a certain lag in the fluctuation of pore pressure inside the formation; the longer the muddy shale is immersed in drilling fluid, the greater the reduction in strength; the reduction is greater in the early stage of immersion, and the reduction in strength in water-based drilling fluid is greater than that in oil-based drilling fluid. At the beginning of the pressure cycle, the formation damage variable and compressive strength gradually increase and decrease with the increase of the pressure cycle number; after several cycles, the magnitude of change gradually decreases with the increase of the cycle number. When the bottom hole pressure fluctuates at a certain period, the greater the fluctuation, the shorter the period of wellbore stability; when the bottom hole pressure fluctuates at a certain range, the smaller the fluctuation period, the faster the borehole enters the high-risk period, while the shortest period of wellbore stability occurs when the fluctuation period is smallest; and when the wave cycle is in the middle, the wellbore stability period is the longest.

The enhanced geothermal system (EGS) is the key to improving the heat production efficiency of hot dry rock (HDR). Due to the existence of EGS, the reservoir produces significant heterogeneity, so the optimal design of well location and injection rate has an important influence on the heat recovery effect of an EGS. To solve this problem, a calculation model for the heat output of an EGS under multifield coupling is established in this paper, and the influence of well location and injection rate on the heat recovery effect under different scales of EGS is deeply analyzed. The results show that the production well location and injection well displacement have a great influence on the heat recovery effect under different fracture‐network scales. The larger the size of the fracture network, the larger the effective utilization area of reservoir heat recovery and the better the effect of heat recovery. The closer the production well is to the fracture network and in the direction of the fracture network, the larger the effective utilization area of reservoir heat recovery is, and the better the effect of heat recovery is. The higher the injection well displacement is, the larger the effective utilization area of reservoir heat recovery is, and the better the heat recovery effect is. The research results have important guiding significance for the optimization of the scale, well placement, and water injection displacement of the EGS in the HDR reservoir.

Due to the nature of hot dry rock resources and the particularity of the development methods, the fault activation induced by injection and production of hot dry rocks involves a complex multifield coupling mechanism. Traditional methods cannot effectively evaluate the fault activation behavior in hot dry rock injection and production. Aiming at the above-mentioned problems, a thermal–hydraulic–mechanical coupling mathematical model of injection and production of hot dry rocks is established and solved by a finite element method. At the same time, the fault slip potential (FSP) is introduced to quantitatively evaluate the risk of fault activation induced by injection and production of hot dry rocks under different injection and production conditions and geological conditions. The results show that under the same geological conditions, the greater the well spacing of injection and production wells, the greater the risk of fault activation induced by injection and production and the greater the injection flow, the greater the risk of fault activation. Under the same geological conditions, the lower the reservoir permeability, the greater the fault activation risk and the higher the initial reservoir temperature, the greater the fault activation risk. Different fault occurrences result in different risks of fault activation. These results provide a certain theoretical reference for the safe and efficient development of hot dry rock reservoirs.

How to improve the heat extraction performance of HDR (hot dry rock) is one of the most concerned problems in HDR extraction. The key is to take a reasonable method to evaluate the heat extraction performance of hot dry rock and find out the main factors influencing the heat extraction performance of hot dry rock. The permeability of HDR reservoir, well type, well spacing, well pattern and injection flow rate of cold water have important influence on heat extraction performance of HDR reservoir. Based on this, a multi-field coupling mathematical model for injection and production of HDR is established and solved by finite element method to analyze the evolutions of seepage field, temperature field and stress field in HDR reservoir. Then, high temperature production time and heat extraction rate were introduced to quantitatively evaluate the heat extraction performance of HDR reservoir under different reservoir permeability, different well type, different well spacing, different well pattern and different injection flow rate. The research results show that different reservoir permeability has little influence on the heat extraction performance of HDR reservoir. Comparing the vertical well production system with the horizontal well production system, horizontal well production system has longer high temperature production time, and vertical well production system has higher heat extraction rate. The greater the well spacing and injection flow rate, the better the heat extraction performance of HDR reservoir. The heat extraction performance of the well pattern is not necessarily better than that of the one-injection and one-production well pattern, the heat extraction performance of the one-injection two-production well pattern and the two-injection one-production well pattern is worse than that of the one-injection one-production well pattern, and the heat extraction performance of the four-injection one-production well pattern and the one-injection four-production well pattern is better than that of the one-injection one-production well pattern. The research results can provide a theoretical basis for the formulation of economic and reasonable HDR development program and working system, and realize efficient utilization of HDR reservoir.