Multi-component thermal fluid (MTF) injection is an effective enhanced oil recovery (EOR) technique for heavy oil reservoirs. However, the complex multiphysics coupling mechanisms governing gas chamber expansion remain incompletely understood. In this study, a 3D fully coupled thermo-hydro-mechanical-diffusion (MTF-THMD) finite element model is developed, which comprehensively integrates non-isothermal multiphase flow, poro-thermoelastic deformation, convective diffusion, and phase behavior evolution. Numerical investigations under high-temperature and pressure conditions reveal that gas chamber expansion is highly non-uniform, ultimately forming an asymmetrical “umbrella-shaped” morphology driven by gravity override and positive thermo-hydro feedback. In addition, a spatial decoupling between heat and mass transfer is identified: the CO2 diffusion front outpaces the thermal front, creating an enhanced dissolution-driven viscosity reduction zone that dynamically compensates for the lack of thermal viscosity reduction in the far-field. Geomechanically, matrix thermal expansion induces near-wellbore compression, resulting in up to an 8% reduction in permeability. However, increasing the injection rate effectively mitigates this thermally-induced geomechanical damage and improves top-layer sweep efficiency. This work investigates the non-synergistic multiphysics mechanisms of MTF injection, providing mechanistic insights that may support future optimization of MTF injection strategies.

Formation pressure-lithofacies type are the most critical factors influencing micro pore structure and porosity in shale reservoir. However, how these two factors jointly affect shale gas accumulation remains unclear. Scanning electron microscopy (SEM), X-ray diffraction (XRD), nuclear magnetic resonance (NMR), on-site desorption and low-temperature N2 adsorption (LTNA) are integrated to analyze coupling effects of pressure variation and lithofacies on reservoir quality and gas-bearing characteristics of deep-buried shale. Three lithofacies are identified in Longmaxi deep-buried shale: siliceous lithofacies (S), argillaceous lithofacies (CM) and mixed lithofacies (M). Pores with pore size < 4 nm are the main contributors to the specific surface area (SSA), and pores between 4 nm and 30 nm are the main contributors to the pore volume (PV). Pressure variations directly affect the size and number of organic matter pores but have no impact on intraparticle pores. The variability in interparticle pores indicates that the S lithofacies has a stronger resistance to compaction compared to the M lithofacies. Porosity and micro structure of deep-buried shale reservoir are influenced by lithofacies type, burial depth and pressure variation. Organic-rich S shale and organic-poor S shale demonstrate good reservoir properties under over-pressure and well-preserved conditions, with organic-rich S shale having the strongest resistance to compaction. Organic and inorganic pores are largely lost during compaction of organic-rich M shale. CM lithofacies also has a poor material foundation and the weakest resistance to compaction, making it difficult to preserve original porosity and pore structure during compaction. The decrease in formation pressure results in macropores making almost no contribution to pore volume, while the contribution of mesopores is further enhanced. As the formation pressure decreases, the contribution of micropores to pore volume is gradually increased. As shale porosity decreases, porosity associated with macro pores declines first, followed by that associated with mesopores. Free-gas content in the CM and M lithofacies declines rapidly as porosity decreases. Both adsorbed and free gas decrease sharply as porosity is lost.

The shale gas resources in the Sichuan Basin have great potential, large distribution area and good preservation conditions, which is of great significance for the production of shale gas in China. The exploitation practice of shale gas in China shows that pressure condition has a significant influence on the nanopore occurrence and structure. In this study, X-ray diffraction (XRD), scanning electron microscopy (SEM), mercury intrusion porosimetry (MIP) and low-temperature N-2 adsorption (LTNA) are integrated to reveal the evolution of physical property and nanoscale pore of shale reservoir in the Sichuan Basin. Three shale lithofacies are determined in Longmaxi Formation 1st Member: siliceous shale (S), argillaceous shale (CM) and mixed shale (M) lithofacies. Nanopores in S lithofacies are composed of organic nanopores in solid bitumen and interparticle nanopores between rigid grains. Nanopores in M lithofacies are composed of organic nanopores and intraparticle nanopores within carbonate grains. Organic nanopores are the primary type of pore identified in the CM lithofacies. Under overpressure conditions, the organic nanopores in all three types retain their morphological characteristics, with the S lithofacies exhibiting the most well-preserved pore system. With decreasing pressure coefficient, the rigid quartz-supported grain framework in the S lithofacies effectively mitigates compaction, allowing nanopore structures and porosity to be largely preserved under deep burial. In contrast, in the M lithofacies, the replacement of carbonate minerals by illite weakens the grain framework, reducing its resistance to compaction and resulting in significant pore and porosity loss. The CM lithofacies lacks rigid framework-forming minerals; thus, clay minerals and organic matter are directly subjected to compaction during pressure reduction, leading to a sharp decrease in both nanopore abundance and pore size. The evolution of nanopore structure and quantity is directly reflected in porosity variations and indirectly controls shale gas adsorption and storage capacity. These results demonstrate that lithofacies-dependent pressure responses fundamentally govern nanopore preservation and reservoir quality in deeply buried shales, providing new insights into shale gas evaluation under variable pressure conditions.

Depleted gas reservoirs serve as critical carriers for large‐scale, long-term underground hydrogen storage, and their hydrogen‐blended gas storage performance is generally governed by the coupled effects of multiple parameters. Taking the low‐permeability depleted gas reservoir of the Yanchang Formation in the Ordos Basin as the prototype, this study employs the CMG‐GEM compositional simulator to establish a numerical model, aiming to investigate the effects of porosity, permeability, microfractures, and water saturation on hydrogen occurrence and migration. By adopting orthogonal experimental design and range analysis, and using hydrogen recovery factor and gas‐mixture sweep efficiency as evaluation indices, we quantitatively rank the sensitivities under multi‐parameter coupling. The results demonstrate that the sensitivity order of the parameters is strictly: porosity > initial water saturation > microfracture permeability > horizontal permeability. Based on the single‐factor threshold analysis and range analysis, the optimal combination intervals of reservoir petrophysical properties are determined as: porosity 0.10–0.15, horizontal permeability 1–10 mD (with Kv/Kh of 0.05–0.10), microfracture permeability 10–50 mD (with shape factor of 0.1–1.0 m⁻²), and initial water saturation 0.20–0.30. This study achieves a transition from qualitative single‐factor analysis to quantitative ranking of multiple parameters. The established quantitative assessment framework of dominant controlling factors can provide a theoretical basis and decision‐making reference for the optimization of geological sweet spots and parameter design of underground gas storage.

The development of low-cost, high-performance oil soluble temporary plugging agents capable of minimizing drilling fluid damage to reservoirs is a critical issue in drilling and completion operations. Owing to their selective plugging ability, limited penetration depth, and self-dissolving behavior upon contact with oil and gas, oil soluble temporary plugging agents hold significant potential for reservoir protection. In this study, three oil soluble temporary plugging agents N-alkane-I, N-alkane-II and N-alkane-III, were prepared via a suspension-dispersion blending method using n-alkane, C5 petroleum resin, C9 petroleum resin, and coumarone resin as raw materials, with cost and performance considerations guiding their selection. The preparation process was optimized through single factor experiments, and the products were systematically evaluated for structure, microstructure, and performance. Morphological analysis revealed relatively uniform solid particle distributions approximating a normal distribution. Measured particle size ranges were 7.78-995.6 mu m, 2.75-1000.46 mu m, and 31.11-1000.97 mu m, respectively, with all exhibiting excellent thermal stability; oil solubility exceeded 95% at 90 degrees C. Additional physicochemical properties and reservoir adaptability, including softening point, dispersibility, and resistance to acid, salt, and temperature, were characterized. Compatibility with drilling fluids was also assessed through pH, density, filtrate loss, plugging efficiency, and rheological behavior. Based on these synthesized agents, a reservoir-protective water-based drilling fluid system was developed. Core displacement experiments and modeling simulations confirmed that particle sizes fell within the ranges recommended by theoretical calculations, providing effective reservoir protection. Efficient temporary plugging is primarily governed by the appropriate matching of particle size to the throat structure of reservoir pores.

Shale gas is a critical unconventional energy source in China (31.6 trillion m3 recoverable reserves), with commercial extraction relying heavily on hydraulic fracturing. Low-viscosity fluids (e.g., slickwater) have limited proppant-carrying capacity, easily causing premature settlement—addressed by bubble-suspended proppants (40/70 mesh quartz sands sprayed with a surfactant for bubble adsorption). However, insufficient understanding of bubble-suspended proppants’ migration (especially in complex fractures) limits their deployment and fracturing optimization. This study focused on bubble-suspended proppants’ migration via an integrated method: large-scale visualized experiments compared them with conventional proppants (digimizer extracted sand dune parameters); an Eulerian three-phase flow model simulated bubble-suspended proppants’ migration (validated by experiments); a complex fracture network model (main/crossed/secondary fractures) further explored their transport. Results showed bubble-suspended proppants’ superior transport: longer stable migration in main fractures (overcoming gravity), less junction accumulation in crossed fractures (preventing blockage), and uniform filling in secondary fractures (via bubble suspension). A higher gas-solid ratio, appropriate pumping rate, and lower density enhanced their performance. This study clarifies the migration mechanism of bubble-suspended proppants in a gas-liquid-solid three-phase system within complex fractures and establishes targeted simulation and prediction methods. It provides accurate theoretical support and engineering guidance for the parameter optimization of bubble-suspended proppant fracturing and sand placement processes. This achievement effectively promotes the implementation of the high-efficiency sand placement technology featuring “low fluid volume and high proppant concentration,” significantly enhances fracture conductivity, helps improve shale gas recovery, and provides important support for the economy and sustainability of shale gas development.

The genetic mechanism of low-resistivity oil reservoirs in the Guantao Formation of the Bohai Sea is complex, and understanding the role of clay minerals and pore structures in forming low resistivity remains unclear. This study employed multiscale digital core technology to integrate multisource digital core data. Combined with flow characteristic-based upscaling technology, microscale and nanoscale digital cores were reconstructed to calculate parameters such as porosity, permeability, and formation factor. At the same time, mercury intrusion and seepage experiments were simulated. The research reveals two key mechanisms underlying the influence of clay minerals and pore structures on low-resistivity oil reservoirs: first, the additional conductive effect of clay. Among clay minerals, illite-smectite mixed-layer minerals exhibit the strongest conductivity, which is the key factor contributing to reduced resistivity, followed by illite, kaolinite, and chlorite in decreasing order of additional conductive capacity. The second is the regulatory role of pore structures. Kaolinite fills intergranular pores to form a complex micropore system, resulting in high irreducible water saturation in the reservoir, which is the primary cause of low-resistivity oil reservoirs. This study clarifies the influence mechanisms of clay minerals and pore structures on resistivity, provides key technical support for fine geological modeling and optimization of oil and gas reservoir development schemes, and holds significant practical value for reducing exploration risks and improving oil recovery efficiency.

Ultra-deep carbonate hydrocarbon reservoirs represent a key target for hydrocarbon exploration in the Tarim Basin. Characterized by great burial depth and strong reservoir heterogeneity, they pose significant challenges to reservoir prediction and the understanding of hydrocarbon accumulation mechanisms. Taking the Ordovician Yingshan Formation in the Catake depression of the Tarim Basin as a case study, this paper systematically analyzes the main controlling factors and hydrocarbon accumulation models of such reservoirs based on seismic, logging, and core data. The results indicate that the Yingshan Formation reservoirs generally exhibit low porosity and low permeability, and their reservoir effectiveness is mainly controlled by multi-stage tectonic-karstification processes. The reservoir types are dominated by dissolution pores, vugs, and structural fractures. The NE-trending strike-slip faults in the study area serve as critical migration pathways, connecting deep Cambrian source rocks and governing the hydrocarbon accumulation process featuring “multi-stage charging and late-stage accumulation”. Through a systematic comparative analysis of existing drilling data, it is concluded that three core conditions are essential for encountering high-quality hydrocarbon reservoirs: an effective oil-source fault migration system, well-developed high-quality fracture-vug reservoir bodies, and favorable structural conditions, all of which are considered essential. Subsequent drilling results support this interpretation. This study provides useful insights and practical value for the precise exploration of similar ultradeep and complex carbonate hydrocarbon reservoirs.

Enhanced Geothermal Systems (EGS) offer a scalable route to exploit Hot Dry Rock (HDR) resources, yet the geomechanical controls on stimulation efficiency and induced seismicity remain debated. Here we integrate two years of microseismicity, 3-D seismic attributes, borehole images and moment-tensor data from China’s first EGS project in the Gonghe Basin, NE Tibetan Plateau, to quantify how pre-existing fractures dictate reservoir response under low-rate, low-pressure “slow” injection. A network of 20 surface seismic stations was deployed for in-field continuous observation. During hydraulic stimulation, the maximum injection flow rate and wellhead pressure reached 140 L/s and 65.3 MPa, respectively. Using the Short-Term to Long-Term Average (STA/LTA) detection method, a total of 5,797 microseismic events were identified, with local magnitudes (ML) ranging from −2.0 to 3.2 and focal depths between 3.4 and 4.2 km. The spatial and temporal distribution of events exhibits a predominant NW–SE orientation, consistent with the main strike orientations of natural fracture networks revealed by 3D seismic exploration. Regional stress analysis combined with borehole breakout data indicates that the maximum horizontal principal stress (SHmax) is oriented NE 42.68° ± 15°. Focal mechanism solutions suggest that strike-slip and reverse-faulting events are dominant, while normal-faulting events are relatively rare. The integrated results indicate that under the high-stress regime of the Gonghe region, hydraulic stimulation performed at low injection rates and wellhead pressures (“slow injection”) induces seismicity that is governed primarily by pre-existing fractures and discontinuities, rather than by the SHmax orientation. This mechanism constrains the effectiveness of reservoir stimulation and may reduce the overall heat-exchange efficiency of the geothermal system.

The deep sandstone reservoirs of the Badaowan formation in the Junggar basin exhibit complex pore structures and strong microscopic heterogeneity. Understanding the microscopic pore characteristics is crucial for accurate reservoir evaluation. In this study, the deep sandstone reservoir of the Badaowan formation in the Mosuowan uplift of the Junggar basin is selected as the research object. A full-scale characterization of the microscopic pore structure is conducted by the joint application of CO2 adsorption, N2 adsorption, and high-pressure mercury intrusion experiments. Experimental results indicate that reservoir pores are mainly slit-like and open channel-like, with a multi-peaked pore size distribution. Overall, the reservoir is characterized by low pore volume and strong heterogeneity. Macropores dominate the total pore volume, typically contributing more than 85%, while the specific surface area is mainly controlled by micropores and mesopores. Based on the N2 adsorption hysteresis loops, two pore structure types are identified: Type I, characterized by an H4 hysteresis loop, representing a micropore-dominated structure with slit-like pores; and Type II, featuring an H3 hysteresis loop, indicative of a mesopore-dominated structure with open groove-like pores. Mineral composition exerts a significant control on pore structure. The sand content (quartz together with feldspar) is closely related to the degree of pore development: as sand content increases, the average pore size of micropores decreases, while the macropore volume increases. Conversely, a higher clay mineral content tends to fill macropores, reducing overall pore connectivity. In summary, reservoirs with high sand and low clay content exhibit better pore development, with macropore volume contributions exceeding 85%, making this parameter a key indicator for identifying high-quality reservoirs. These findings provide important insights for predicting favorable reservoir sweet spots in the deep sandstone of the Badaowan formation in the Junggar basin.

The efficient extraction of natural gas from marine natural gas hydrate (NGH) reservoirs is challenging, due to their low permeability, high hydrate saturation, and fine-grained sediments. Hydraulic fracturing has been proven to be a promising technique for improving the permeability of these unconventional reservoirs. This study presents a comprehensive triaxial experimental investigation of the fracturing behavior and fracture initiation mechanisms of NGH-bearing sediments, using large-scale ice-saturated synthetic cubic models. The experiments systematically explore the effects of key parameters, including the injection rate, fluid viscosity, ice saturation, perforation patterns, and in situ stress, on fracture propagation and morphology. The results demonstrate that at low fluid viscosities and saturation levels, transverse and torsional fractures dominate, while longitudinal fractures are more prominent at higher viscosities. Increased injection rates enhance fracture propagation, generating more complex fracture patterns, including transverse, torsional, and secondary fractures. A detailed analysis reveals that the perforation design significantly influences the fracture direction, with 90° helical perforations inducing vertical fractures and fixed-plane perforations resulting in transverse fractures. Additionally, a plastic fracture model more accurately predicts fracture initiation pressures compared to traditional elastic models, highlighting a shift from shear to tensile failure modes as hydrate saturation increases. This research provides new insights into the fracture mechanisms of NGH-bearing sediments and offers valuable guidance for optimizing hydraulic fracturing strategies to enhance resource extraction in hydrate reservoirs.

The improvement of production profiles in stratified heavy oil reservoirs holds paramount significance within the domain of improved oil recovery. The separate-layer steam injection technique is an effective approach to minimize the recovery difference among layers. However, the accuracy of steam allocation is hampered by the dynamic heterogeneity after long-time steam flooding. This paper proposes an improved injection rate allocation model for stratified heavy oil reservoirs with a separate-layer steam injection process. Considering the time variable phenomena of temperature and water saturation in reservoirs during a steam flooding process, the classical Buckley-Leverett (BL) displacement theory is extended to establish an injection rate allocation optimization strategy for stratified heterogeneous heavy oil reservoirs. First, the water saturation at an oil-water front and the average water saturation (AWS) in a two-phase region are determined. Then, the layers occurring (hot) water breakthrough are identified. Furthermore, the water saturation at the outlets of the layers occurring water breakthrough is calculated, and the location of an oil-water front in pre-breakthrough layers is obtained. Finally, the injection rates of these two-type layers are programmed by assuming an equivalent water saturation at each outlet. The reservoir properties and injection parameters in an actual heavy oilfield are input into the optimization program. Field data shows that a permeability heterogeneity can highly affect the temperature and water saturation in layers. The results demonstrate that a high-permeability layer (HPL) occurs water breakthrough, in which the current water saturation exceeds the AWS in a two-phase region. Moreover, affected by a variation of temperature, a fractional flow curve in a layer with a low water-oil viscosity ratio (WOVR) is more convex, while a fractional flow curve in a layer with a high WOVR is more concave. As the water saturation in a layer before adopting the separate-layer steam injection technique increases, the optimized injection rate per unit reservoir thickness decreases. The injection rate allocation is found to be a strong function of separate-layer injection time. Furthermore, a decrease in the injection time results in a greater contrast of injection rate allocation. Based on the programmed optimization code, the contrasts of injection rate allocation among layers for 5 years and 10 years are 9.2 m3/(d·m) and 8.3 m3/(d·m), respectively. This research extends the application scope of the Buckley-Leverett displacement theory into a non-isothermal displacement process. It provides valuable insights for designing suitable injection rate allocation in stratified heterogeneous heavy oil reservoirs.

An advanced enhanced oil recovery (EOR) method was investigated, employing a surfactant–polymer (SP) system in combination with a viscosity reducer for application in a heavy oil reservoir within the Haiwaihe Block, Liaohe Oilfield, in China. Significant advantages were observed through the combination of LPS-3 (an anionic surfactant) and OAB (a betaine surfactant) in reducing interfacial tension and enhancing emulsion stability, with the optimal results achieved at the ratio of 9:1. The BRH-325 polymer was found to exhibit superior viscosity enhancement, temperature resistance, and long-term stability. Graphene nanowedges were utilized as a viscosity reducer, leading to a viscosity reduction in heavy oil of 97.43%, while stability was maintained over a two-hour period. The efficacy of the combined system was validated through core flooding experiments, resulting in a recovery efficiency improvement of up to 32.7%. It is suggested that the integration of viscosity reduction and SP flooding could serve as a promising approach for improving recovery in mature heavy oil reservoirs, supporting a transition toward environmentally sustainable, non-thermal recovery methods.

Sorel cement has emerged as an effective solution for controlling severe leakage during drilling in fractured formations. However, it can thicken prematurely under high- temperature and high- pressure (HTHP) conditions in the wellbore, leading to operational risks, such as pipe sticking and pressure trapping. Sodium salicylate (SS) has been identified as a potential retarder for Sorel cement, but its effectiveness and retardation mechanism remain unclear. In this study, we investigate the effects of SS on the physicochemical properties, hydration process, and microstructure evolution of Sorel cement, with particular emphasis on its retardation mechanism. The results show that SS effectively prolonged the setting time and shortened the interval between initial and final setting. At an optimal dosage of 17%, the atmospheric and HTHP thickening times were extended to 200 minutes and 237 minutes, respectively. The consolidated cement exhibited a plugging pressure resistance of more than 18 MPa (fracture widths of 4-10 mm) and an acid dissolution rate above 95%. SS also reduced the temperature peak and heat release rate, altered the hydration kinetic model from the nucleation and crystal growth (NG), phase boundary reaction (I), and diffusion (D) stages to the NG- D model, and modified the morphology and composition of hydration products. The retardation mechanism was attributed to the adsorption and complexation of SS, forming platy magnesium salicylate crystals that temporarily hinder hydration. These findings provide mechanistic insight into the retardation behavior of SS, which helps improve the formulation of Sorel cement for extended safe drilling operations.

The efficient development of coalbed methane has become the preferred and strategic development goal of clean energy and gas disaster prevention and control, and it is urgent to innovate the theory and technology of coal reservoir transformation. In order to solve a series of problems such as strong reservoir adsorption, low permeability, easy blockage of migration channels, water lock effect, and lack of water resources in the development process of surface coalbed methane. In this research, the theory of high-energy electric detonation (HEED) volume fracturing and permeability enhancement in surface coalbed methane wells were deeply analyzed. Based on the energy release characteristics of shock wave-stress wave-vibration wave propagation in electric detonation liquid phase discharge, A multi-point electric detonation-induced volumetric fracturing model of high-precision energy allocation roof, floor, and coal reservoir was established. The method of strengthening coalbed methane extraction by HEED volume fracturing in coal reservoirs is put forward, and the technology and process of HEED volume fracturing of surface coalbed methane are formed. Using the self-developed HEED volume fracturing and permeability increasing equipment with storage energy up to 604.92 kJ and adjustable, an engineering experimental study of roof, floor, and coal seam fracturing caused by different HEED energy cycles was carried out. During this period, the surface microseismic monitoring system was used to characterize the influence radius of the reservoir fracture network in real-time, and the reliability of HEED volume fracturing technology and equipment was investigated according to the volume fracturing effect and long-term coalbed methane production. The results show that the HEED cycle induces the development and expansion of cracks or micropores, and forms a volume fracturing effect with high crack density. The amplitude of the microseismic signal near the well was large and gradually decreased with the increase in distance. The plane distribution of microseismic events was ring-shaped and spread around. The increase of HEED energy and induction times leads to the increase and then decrease of the influence radius of the coal reservoir fracture network. The influence radius of the fracture network induced was as high as 200 m by HEED underwater excitation energy of 361.97 kJ. The average coalbed methane production during the re-extraction period was 0.80～1.53 times higher than that during the depletion period. It was verified that the proposed HEED volume fracturing technology could effectively improve the coal reservoir and promote the desorption, diffusion, and migration of coalbed methane. The research results have theoretical and engineering guiding significance for the fracture network transformation of low permeability soft coal reservoir to realize the efficient development of coalbed methane.

Heating development has become the main development mode of medium- to low-maturity shale oil. In this study, the thermodynamic mathematical models of flow and heating development of organic matter, inorganic matter, hydraulic fracture, and natural fracture are established based on the embedded discrete fracture model (EDFM). A model for calculating the apparent permeability is established based on the fractal theory considering the effect of adsorption and slippage of fluid in shale pores. The mathematical model is solved by the finite volume method. The results show that improving formation temperature can increase the shale oil production. When the temperature increases from 338 K to 500 K, the cumulative production of shale oil can increase by 40.34%. The more natural fractures are, the greater the cumulative production of shale oil is. As the half-length of hydraulic fracture increases, the cumulative production of shale oil increases. When there is greater thermal conductivity and a decrease in the heat capacity of the matrix, the formation area affected by the thermal effect is enlarged and the cumulative oil production increases. There is a negative correlation between the shale oil production and the proportion of pore volume of organic matter. Through the study of the influencing factors of shale oil heating development, characteristics of shale oil production under different fracture and matrix parameters are clarified, and the optimal parameters under different influencing factors are obtained and a significant theoretical basis for shale oil heating development is achieved.

Acid fracturing is a crucial method for reservoir reconstruction in carbonate reservoirs, and the propagation pattern of acid-etched fractures plays a key role in determining the scope of reservoir enhancement and post-fracturing productivity. However, large-scale physical simulations directly using acid solutions in fracturing experiments are limited, and the fracture propagation patterns under acid fracturing remain unclear. To address this gap, in this study, we collected carbonate rock samples from the Majiagou Formation in the Daniudi area, preparing large-scale fracturing specimens with side lengths of 30 cm. The propagation of acid fracturing fractures was investigated using self-developed true-triaxial acid fracturing equipment. Based on post-fracturing fracture morphology and pressure curves, the effects of fracturing fluid type, injection rate, injection mode, and natural fractures (NFs) on acid fracturing fracture propagation were analyzed. The experimental results showed that the acid solution effectively weakens the mechanical properties of the open-hole section, creating multiple mechanical weak points and promoting the initiation of fractures. Pre-fracturing treatment with low-viscosity acid can significantly enhance fracture complexity near the wellbore and expand the near-well stimulation zone. Lowering the injection rate increases the acid solution’s filtration loss into natural fractures, weakening the cementation strength of these fractures and encouraging the formation of complex fracture networks. Furthermore, employing a multi-stage alternating injection of high-viscosity and low-viscosity acids can reduce fracture temperature and acid filtration loss while also enhancing differential etching through viscous fingering. This approach improves the conductivity and conductivity retention of the acid-etched fractures. The results of this study can provide a reference for the acid fracturing stimulation of fractured carbonate reservoirs.

Constructing high-strength network structures is crucial for polyacrylamide-based thickener applications, particularly for hydraulic fracturing fluids. While conventional approaches rely on either molecular weight increase or hydrophobic modification to strengthen polymer networks, insufficient attention has been given to balancing rapid dissolution. Herein, a dual-regulation method combining molecular weight adjustment and hydrophobic monomer refinement was proposed to obtain polymers optimization. A series of polymers with varying molecular weights and different hydrophobic monomer contents were synthesized for systematic comparison. The performance evaluation was primarily focused on the solubility and rheological properties of the polymers. Polymers with octadecyl (C18) chain hydrophobic monomers resulted in larger hydrophobic micro-regions compared to those with hexadecyl (C16) chains, thereby increasing the intermolecular crosslinking density. The optimized polymer AAC18-6 (1.55 x106 g/mol) with 2.0 mol% hydrophobic monomer showed a same dissolution rate comparable to that of HPAM-1 (7.88 x106 g/mol). Due to its low molecular weight and enhanced hydrophobic interactions, the optimized polymer AAC18-6 exhibited significantly improved zero-shear viscosity, thixotropy, and elastic dominance. These features demonstrate the formation of a dense and stable polymer network. Overall, we present a novel strategy of reducing molecular weight while enhancing hydrophobic association to construct fast-dissolving, dense polymer networks. The approach effectively overcomes the conventional trade-off between molecular networks strength and rapid dissolution in hydrophobic association polyacrylamide systems.

Direct injection of low- solid curable materials with drilling fluid has the potential to streamline the construction process and reduce costs associated with lost circulation. In this paper, the basic properties, curing behavior, plugging performance, and acid- dissolution characteristics of the mixed slurry using self- made Magnesium oxide (MgO)- based curing material (MCM) combined with polysulfonate drilling fluid were investigated. The basic properties of the mixed slurry exhibited excellent pollution resistance of MCM. The mixed slurry containing 30-50% MCM showed the volume shrinkage ranging from -1.55% to 3.02% and the curing time spanning from 1.67 hours to 2.17 hours, showing exceptional curing behavior. The drilling fluid had no effect on the final strength, but the different components had either negative [sulfonated phenolic resin (SMP- 1)] or positive [sodium hydroxide (NaOH)] effects on the hydration process through scanning electron microscope (SEM), X- ray diffraction (XRD), and energy- dispersive spectrometer (EDS). Besides, retarder effectively extended the curing time to 270-470 minutes without compromising the strength of the final cured product or affecting formation processes, which can be used to control the curing time of MCM. Pressure- resistance testing revealed that sealing zones and induced cracks with rough surfaces exhibited higher interfacial bonding capacity, while induced cracks as small as 2 mm showed minimal leakage at pressures up to 16 MPa and eventually stabilized at 14 MPa. Furthermore, acid dissolution tests demonstrated complete release of cured products in a short time, offering potential benefits for reservoir protection. Field application examples further confirmed the compatibility of MCM with drilling fluid and its effectiveness in sealing cracks.