Energized pre-fracturing has emerged as an effective approach for enhancing reservoir energy, fracture complexity and oil recovery in tight reservoirs. However, the mechanisms by which fracture propagation induced by different energized pre-pad fluids governs subsequent imbibition-driven oil recovery remain insufficiently understood. To address this issue, an integrated experimental framework was established to investigate the coupled evolution of fracture networks and pore-scale oil displacement during energized pre-fracturing. By combining X-ray computed tomography for quantitative fracture characterization and dynamic nuclear magnetic resonance for monitoring imbibition-driven oil recovery, the interactions between fracture-scale architecture and pore-scale fluid redistribution were systematically elucidated. The results demonstrate that, compared to conventional fracturing, energized pre-fracturing not only lowers breakdown pressure but also promotes the formation of more complex, highly connected fracture networks, which in turn substantially enhance ultimate oil recovery. Notably, gaseous pre-pad fluids exhibit clear advantages over aqueous systems, with supercritical CO₂ generating the lowest breakdown pressure and the most intricate multi-branch fracture networks, as indicated by higher fracture fractal dimension and area ratio. These fracture characteristics significantly facilitate imbibition efficiency, resulting in higher oil recovery. Pore-scale analysis further reveals that oil mobilization is dominated by contributions from micropores and mesopores, underscoring the critical role of energized pre-fracturing in activating oil stored in small-scale pore systems. The proposed multi-scale methodology, integrating fluid properties, fracture network evolution, and imbibition dynamics, provides a mechanistic basis and practical guidance for optimizing energized fracturing and improving the efficient development of tight conglomerate reservoirs.

Temporary plugging and diverting fracturing (TPDF) is one of the important stimulation means to increase production when developing unconventional oil and gas resources. By compiling the literature on TPDF technique at home and abroad, the development of TPDF technique was summarized from three aspects: mechanism, material and process. Firstly, TPDF included three key steps: transport of the temporary plugging agent, plugging process, and fracture diverting. The divergent behavior in transport of different temporary plugging agent particles affected the subsequent plugging process, which in turn affected the opening of new fractures, and all three are closely related. Secondly, various types of temporary plugging agents are applied in the field, including solid particles, fibers, gels, foams, etc. Suitable temporary plugging agents need to be selected according to the reservoir characteristics, especially considering their temperature resistance, degradability and intensity. Presently, degradable particles and fiber temporary plugging agents were the mainstream development trend. Finally, the TPDF technique had a wide range of application scenarios, and its effectiveness had been confirmed by various monitoring methods. During the operation, different filling methods need to be adopted according to the difference in temporary plugging agent types, and the amount and timing of temporary plugging agent can be optimized and designed through various advanced technical means such as fiber optics outside the pipe and high frequency pressure monitoring. With the application and promotion of these advanced technologies, the TPDF operation will finally realize real-time regulation and optimization.

Horizontal well with multistage hydraulic fracturing (HWMHF) optimization is crucial for the economic and efficient development of unconventional oil and gas resources. In this paper, fracture propagation modeling, production simulation, and automatic search algorithms are coupled to establish an integrated workflow for the optimization of HWMHF. Intelligent optimization of high-dimensional parameters of HF is conducted to obtain the best matching set of HWMHF parameters, which maximizes the value of the economic index in the global range. The fracture propagation simulation employed a self-pro-grammed boundary element fracture propagation simulator. The production simulation employed a CMG component simulator. The automatic search algorithm employed the Genetic algorithm (GA) and the Bayesian optimization algorithm. The whole optimization process is automated, i.e., the overall fracture morphology is automatically imported into CMG, the fracture model is automatically established, the oil and gas water production is predicted by the CMG HWMHF model, and the objective function value is calculated automatically. Further, the automatic search algorithm updates the next generation of input by measuring the relationship between the objective function values and the HWMHF parameter values, and re-performs fracturing simulation until the ideal fracturing parameters are obtained. The fracturing optimization process and results show that: (1) the combination of boundary element fracture propagation simulator and CMG component simulator can achieve fast fracturing simulation and satisfy the high simulation times for intelligent search; (2) the economic index has been improved 55% though the intelligent optimization; (3) the GA searches for better HWMHF parameters, while the Bayesian optimization algorithm performs a less number of iterations, while it can better embrace the domain knowledge; (4) both methods are suitable for solving the “black box” question of HWMHF optimization, and each has its advantages and obvious potential for field application promotion.

Horizontal well multi-stage fracturing is one of the necessary technologies for unconventional oil and gas development. Clarifying multi-cluster fracture propagation and the main control factors of the fluid shunt are crucial to optimizing the stages and cluster design. In this paper, firstly, the original logging data and logging interpretation data at each perforation cluster are obtained. Then, based on distributed optical fiber monitoring technology, the data of the fracturing sequence, liquid inlet ratio, and liquid production ratio of each fracture in the stage are calculated. The well logs and optical fiber monitoring data are compared and analyzed to determine the main controlling factors affecting the multi-cluster fracturing effect in the stage. The results show that the perforated clusters with low minimum principal stress and high brittleness index are opened first. The four most critical factors affecting the proportion of pre-liquid and the sand liquid are: QL > Neutron > Gamma Ray > Acoustic; The key factors affecting the proportion of liquid produced are the total liquid dispensing ratio and the φ×S_o. The research results of this paper have significance for guiding formulation of a fracturing scheme for horizontal wells.

Unconventional oil and gas resources serve as vital replacement energy in China’s hydrocarbon portfolio, and their efficient development is of great significance for safeguarding national energy security. The implementation of staged multi-cluster hydraulic fracturing in horizontal wells, along with the optimization of intra-stage cluster design parameters, is critical to maximizing the production potential of unconventional reservoirs. Clarifying fracture propagation mechanisms and quantifying the relationship between fracture geometry and well productivity is key to optimize intra-stage multi-cluster fracturing strategies. In this study, a phase-field method is employed to simulate the competitive propagation morphology of multiple fractures within a fracturing stage. A fracture morphology identification technique is integrated to construct a two-dimensional equivalent fracture model, which can characterize the stimulated flow pathways. Equivalent physical parameters after stimulation are extracted and transferred-together with geometric descriptors-as input for a discrete fracture flow model. This enables automatic coupling and data transfer between the geometric and flow models, thereby facilitating quantitative evaluation of production performance under different fracturing scenarios and ultimately achieving fully coupled fracture propagation-fluid flow simulation. The accuracy and feasibility of the dual-model coupling method are verified through comparison with laboratory-scale physical simulation experiments and field fracturing data. On this basis, the effects of intra-stage cluster number and cluster spacing on fracture morphology and production response are further investigated. The results show that, as the cluster spacing increases from 15 m to 25 m, the fracture deflection point shifts farther from the wellbore, and the tip deflection angle decreases from 30° to 24°. Meanwhile, the pressure gradient around the fracture tip is reduced, weakening the fluid driving force and significantly diminishing inter-fracture fluid interference. This change leads to a decline in peak daily oil production and stabilized production rate, with daily and cumulative oil output decreasing by 35.88% and 35.89%, respectively. In contrast, when the number of clusters per stage increases from 3 to 5, the deflection angle at the tip of the outer fractures increases from 30° to 34°, while the coverage of the induced stress field expands from 36.74% to 42.46%. This results in a higher pressure gradient surrounding the fractures, enhancing the fluid driving force and significantly improving oil mobilization. Consequently, peak daily and cumulative oil production increased by 40.49% and 45.467%, respectively. Therefore, optimizing the intra-stage cluster spacing and cluster number can effectively balance the degree of fracture interference and enhance single-well productivity, thereby improving the overall effectiveness of staged multi-cluster hydraulic fracturing in horizontal wells.

Aiming at the problems of deep burial, high formation pressure and difficult fracturing stimulation of high-temperature deep oil and gas reservoirs, research on high-temperature resistant weighted fracturing fluid was carried out. A polymer thickener TS-700, which is resistant to high temperature and salt, and organozirconium crosslinker OZ-60, which is suitable for acid crosslinking, were independently synthesized in the laboratory, and the additive dosage was optimized to form an acidic-crosslinking fluid system with a temperature resistance of 180 ℃. The viscosity, drag reduction and delayed crosslinking of the weighted fracturing fluid were studied, and the temperature and shear resistance, sand carrying, gel-breaking, core damage and string corrosion ability were systematically evaluated. The experimental results show that the novel fluid system can be crosslinked under acidic conditions, and the crosslinking time can be controlled within 3~12 min by adjusting the dosage of crosslinker and the pH value. High temperature is conducive to the improvement of viscosity, while the addition of salt will reduce the viscosity of the base fluid. The retention viscosity of the weighted fracturing fluid formula with a density of 1.20 g/cm³ is still greater than 70 mPa·s after shearing for 120 min at 180 ℃. Weighting agent can reduce the drag reduction performance of fracturing fluid to a certain extent, but under different thickener dosages, the drag reduction rate of the weighted fracturing fluid can still reach more than 68%, which meets the requirement of effectively reducing the friction loss in long wellbores. The crosslinked fracturing fluid showed excellent sand suspension at room temperature and 100 ℃, with low proppant settling rate. The results of gel-breaking and core damage show that the crosslinked system can achieve complete gel breaking at 0.03% of the dosage of breaker, and the damage rate of gel-breaking liquid to the tight core is only 19.4%. The high-temperature and high-pressure dynamic corrosion test results show that the fully formulated fracturing fluid has a low corrosion rate on N80 and 13Cr steel, which can ensure the safety of the fracturing string in the field.

Wax precipitation damage caused by cold water injection or temperature reduction is very commonly seen in the development of waxy crude oil reservoirs. Various methods for eliminating wax precipitation damage have been studied by many scholars, such as injecting hot water, artificial fracture, and using chemical dewaxing agents. However, the effects of nanoemulsion on wax crystals and enhanced oil recovery (EOR) have not yet been systematically studied. This study used core displacement system based on nuclear magnetic resonance (NMR) to investigate the effect of nanoemulsion on the EOR in low-permeability, waxy oil reservoirs. Some influencing factors such as injection water temperatures, core permeability, fractured/unfractured core, and nanoemulsion concentration conditions have been investigated. Meanwhile, the wax crystal morphology and quantity have been studied before and after using nanoemulsion using a polarizing microscope. The main conclusions are as follows: (1) After injecting 60 ℃ hot water, the recovery can be increased from 19.36% to 32.82%, which can alleviate wax deposition damage to a certain extent. (2) Enhancing core permeability or using fractured cores can increase the flow capacity of displacement fluid within the core and enhance waxy crude oil recovery. The EOR after improving core permeability is 10.22%, while the EOR of the fractured core is 26.24%. (3) Nanoemulsions can dissolve wax crystals in waxy crude oil and inhibit their formation to achieve EOR. The crude oil recovery at nanoemulsion concentrations of 0.1, 0.5, and 1.0 wt% were 34.84%, 38.24%, and 42.85%, respectively. (4) The use of nanoemulsion can reduce the number, area ratio, and fractal dimension of wax crystals, thereby mitigating wax deposition damage. Using a 1 wt% of nanoemulsion, the area ratio of wax crystals decreased from 47.25% to 16.67%, and the number of wax crystals decreased from 1309 to 496.

Carbon dioxide pre-fracturing has shown high application potential in improving oil recovery in conglomerate reservoirs. However, the influence of CO₂ on the physical properties of reservoir rock and its diffusion behavior within the reservoir matrix have not been systematically studied. This paper integrates CO₂-saturated water soaking experiments, true triaxial fracturing experiments and field-scale tests to demonstrate that CO₂ soaking induces quartz reduction and clay mineral increase, leading to a decrease in porosity and mechanical strength. Clay-cemented conglomerates experience a greater loss in compressive strength and a higher reduction in permeability compared to calcareous-cemented counterparts under identical CO₂ soaking. In the horizontal principal stress direction, CO₂ fracturing achieves a greater fracture penetration depth than slickwater fracturing or CO₂ pre-injection followed by slickwater fracturing. CO₂ pre-fracturing reduces breakdown pressure by 15%-5% and increases fracture complexity. Field tests confirm a reduction in injection pressure and improved effective stimulation. However, dnarrower fracture width and higher tortuosity may limit proppant transportation.

High-frequency pressure monitoring (HFPM) is a real-time, easy to operate and cost-effective method for hydraulic fracturing diagnostics. It enables the rapid assessment of injection point depth, fracture initiation position, temporary plugging and diversion effects and mechanical plug sealing. By analyzing water hammer pressure waves stimulated during the fracturing process, it facilitates the evaluation of fracturing stimulation effectiveness, guiding on-site construction decisions, resource allocation rationalization, and the comprehensive development of shale gas reservoirs. In this study, HFPM is employed to evaluate the temporary plugging effect and mechanical plug sealing efficiency in the fracturing of a horizontal shale gas well in Changning. Additionally, the complexity of the fractures is assessed based on the attenuation characteristics of the water hammer pressure wave. A comparative analysis is conducted between the diagnostic effects of HFPM and the pressure increase method before and after temporary plugging. HFPM demonstrates a higher ability to identify temporary plugging turning effects, with a recognition rate increasing from 45% to 75%, and exhibits superior diagnostic performance. The application of HFPM can contribute to the optimization of fracturing process parameters for shale gas horizontal wells and facilitate the efficient development of shale gas reservoirs in China.

Natural fractures (NFs) are common in shale and tight reservoirs, where staged multi-cluster fracturing of horizontal wells is a prevalent technique for reservoir stimulation. While NFs and stress interference are recognized as significant factors affecting hydraulic fracture (HF) propagation, the combined influence of these factors remains poorly understood. To address this knowledge gap, a novel coupled hydro-mechanical-damage (HMD) model based on the phase field method is developed to investigate the propagation of multi-cluster HFs in fractured reservoirs. The comprehensive energy functional and control functions are established, while incorporating dynamic fluid distribution between multiple perforation clusters and refined changes in rock mechanical parameters during hydraulic fracturing. The HMD coupled multi-cluster HF propagation model investigates various scenarios, including single HF and single NF, reservoir heterogeneity, single HF and NF clusters, and multi-cluster HFs with NF clusters. The results show that the HMD coupling model can accurately capture the impact of approach angle (θ), stress difference and cementation strength on the interaction of HF and NF. The criterion of the open and cross zones is not fixed. The NF angle (α) is not a decisive parameter to discriminate the interaction. According to the relationship between approach angle (θ) and NF angle (α), the contact relationship of HF can be divided into three categories (θ = α, θ < α, and θ > α). The connected NF can increase the complexity of HF by inducing it to form branch fracture, resulting in a fractal dimension of HF as high as 2.1280 at angles of ±45°. Inter-fracture interference from the heel to the toe of HF shows the phenomenon of no, strong and weak interference. Interestingly, under the influence of NFs, distant HFs from the injection can become dominant fractures. However, as α gradually increases, inter-fracture stress interference becomes the primary factor influencing HF propagation, gradually superseding the dominance of NF induced fractures.