Carbonate reservoirs are rich in geothermal and petroleum resources, and matrix acidizing is one of the main methods for such reservoir’s stimulation. This study systematically reviewed the research progress of matrix acidizing technology for carbonate reservoirs. It introduced the development history of acidizing technology, judgment method of whether to use matrix acidizing, acid-rock reaction mechanism and steps, acid system and its optimization methods, the influencing factors and simulation methods of wormhole, acid distribution processes, optimization methods of construction parameters, real-time diagnosis and effectiveness evaluation methods of acid treatment. Then, the future development trend of matrix acidizing for carbonate reservoirs was prospected. Some interesting insights were as follows. Firstly, due to the influence of factors such as closure stress and rock mechanical properties, there were significant differences in the critical permeability values suitable for matrix acidizing in different reservoirs. Secondly, compared to strong acids, the reaction between weak acids and rocks involved an additional step. Starting from the idea of controlling the steps of acid-rock reaction, a new approach was provided for the development of slow reactive acid fluids for high temperature reservoirs. Thirdly, the dual scale wormhole model had good prospects at the engineering scale, and in the future, it should focus on breaking through the three-dimensional radial flow wormhole extension simulation considering pores, cracks, and caves. Fourthly, uniform acid distribution methods included two categories, i.e., mechanical and chemical methods, with four and six subcategories respectively. Its action areas were in the wellbore and the formation respectively, and the mechanical methods were generally more expensive. Fifthly, the acidizing efficiency was highest when forming the dominant wormhole, and the displacement should be appropriately increased with the increase of injection time during acid treatment. Lastly, it was necessary to focus on establishing evaluation criteria for diversion methods and evaluation method for acidizing effects considering complex reservoir and diversion acidizing.

Summary In deep and ultradeep geothermal or natural gas reservoirs, the fracture conductivity generated by acid fracturing stimulation plays a critical role in determining geothermal energy extraction efficiency and gas production rates. However, extremely high closure stress and the rock weakening effect caused by acid-rock reactions often result in the fracture conductivity declining rapidly. Mineral alteration technology aims to enhance rock strength by in-situ transforming existing minerals into new, harder ones. However, the current mineral alteration process is excessively slow (72 hours). In this study, we investigate the effects of 15 wt% hydrochloric acid (HCl), varying concentrations of phosphoric acid (H3PO4), and sodium phosphate (Na2HPO4) on rock strength at 200°C, and propose an innovative pH-regulation strategy to accelerate mineral alteration. First, experimental results show that 15 wt% HCl and H3PO4 significantly reduce rock strength, with reductions of up to 33.1% and 32.1%, respectively, while Na2HPO4 enhances rock strength, with a maximum increase of 63.7%. Second, the mechanisms of both rock weakening and strengthening, as well as the positive influence of high pressure, are elucidated. The 15 wt% HCl solution induces abundant irregular dissolution pores and microcracks, severely damaging the rock structure and significantly reducing strength. H3PO4 accelerates calcium ion (Ca2+) release. As H3PO4 concentration increases, although a higher hydrogen ion (H+) concentration aggravates acid damage, the products formed by phosphate ions and Ca2+ evolve from disordered, amorphous forms to well-ordered, highly crystalline forms, leading to a reduced loss in rock strength. Na2HPO4 enhances strength through dual mechanisms: transforming carbonate minerals into harder phases and repairing acid-damaged rock structures. Its strengthening effect improves with increasing concentration. High pressure promotes crystal formation, further increasing rock hardness. Finally, the mixed solution of H3PO4 and Na2HPO4 with a pH of 5.6 and a concentration of 0.8 M, referred to as PPN for short, combines the advantages of both components, enabling the hardening treatment to be completed in just 1 hour, representing a 98.6% reduction in time. This study presents a new pathway for rapid in-situ modification of reservoir fractures to enhance rock strength.

The harsh environment of the Qinghai-Tibet Plateau, characterized by frequent low-temperature freeze-thaw cycles and extensive saline soil erosion leads to concrete damage and accelerates steel corrosion, severely degrading the seismic performance and durability of steel‐reinforced columns. Hybrid reinforcement with BFRP bars offers a promising solution. However, the influence of the BFRP reinforcement ratio on the seismic behavior of hybrid-RC columns in such environments remains unclear. In this study, five round-ended column specimens with BFRP reinforcement ratios (defined by equivalent strength replacement) of 0, 0.25, 0.50, 0.75, and 1.00 were first subjected to 100 freeze-thaw cycles (-40℃ to 20℃) in a composite salt solution (3.5% Na2SO4 + 1.5% NaCl), followed by accelerated electrochemical corrosion (with measured corrosion ratio of 4.72% to 5.45%) and then tested under quasi-static cyclic loading. The results show that, compared with the steel-reinforced specimen, the peak load declines monotonically with increasing of BFRP reinforcement ratio, decreasing by 16.1%, 17.9%, 14.9% and 38% at BFRP ratios of 0.25, 0.50, 0.75 and 1.00. The ductility coefficient and energy dissipation capacity follow a non‐monotonic trend, both reaching maximum values at a BFRP ratio of 0.50, increasing by 26.4% and 56.2%, respectively. These results demonstrate that a BFRP reinforcement ratio of 0.50 provides the best balance of strength, ductility, and energy dissipation. Finally, a theoretical method incorporating salt-freeze-thaw-induced degradation of materials, cover spalling, and stirrup confinement is developed to predict the lateral bearing capacity of hybrid-RC columns.

Ultra-high-temperature carbonate reservoirs (similar to 200 degrees C) exhibit extremely rapid acid-rock reactions, leading to shallow penetration and limited effectiveness of conventional acidizing treatments. In this study, a high-temperature rotating disk reactor and rock-plate etching device were used to systematically evaluate the reaction kinetics, etching morphology, and fracture conductivity of five acid systems-HCl, gelled acid, acetic acid, DTPA, and self-generating acid-at 200 degrees C. Results show that the reaction rate follows the order HCl > gelled acid > HAc > DTPA > self-generating acid, while the degree of non-uniform etching exhibits the opposite trend. HCl dissolves rock rapidly but generates nearly uniform surfaces with poor conductivity. Gelled acid produces the strongest non-uniform etching and the highest initial fracture conductivity, though its retardation weakens at higher concentrations due to polymer degradation. Weak acids (HAc, DTPA, and self-generating acid) remain reaction-controlled and exhibit stable retardation at 200 degrees C, maintaining deeper penetration than strong acids. Quantitative morphology analysis and conductivity testing confirm that fracture conductivity is governed jointly by etching depth and heterogeneity, rather than dissolution volume alone. Engineering results suggest that, for reservoirs exceeding 180 degrees C, combining gelled acid with a weak-acid system can effectively control reaction rate, enhance non-uniform etching, and create high-conductivity acid-etched fractures. This study provides the first systematic kinetic and etching-conductivity framework at 200 degrees C, offering practical guidance for acid selection and treatment design in ultra-deep carbonate formations.

Multi-stage, multi-cluster hydraulic fracturing plays a critical role in increasing the heat-exchange volume and improving heat-extraction efficiency in geothermal reservoirs. However, stress shadowing induces competitive fracture propagation and limits reservoir stimulation. To address this issue, a fully coupled model of wellbore flow, fracture flow, and rock mechanics is developed. The model accounts for induced stress, fracture shear displacement, fluid leakoff, and temporary plugging. After validation, the model is used to investigate the effects of cluster spacing, perforation number, fracturing sequence, fluid viscosity, and temporary plugging on fracture morphology and propagation uniformity. The results show that competitive fracture propagation is jointly controlled by stress interference and flow allocation. Increasing cluster spacing, reducing the perforation number, and using higher-viscosity fluids improve fracture propagation uniformity. Sequential fracturing and temporary plugging further optimize flow allocation and promote balanced propagation. These findings provide guidance for treatment-parameter optimization, fracture-network control, and enhanced heat extraction in porous geothermal reservoirs.

With the widespread implementation of hydraulic fracturing, the oil and gas industry increasingly relies on recycling formation flowback water to conserve freshwater. However, this practice introduces severe challenges, specifically pipe network scaling and formation damage induced by the high salinity and complex ionic composition of the flowback fluids. While conventional phosphonate and carboxylate inhibitors effectively mitigate scaling, they are plagued by poor biodegradability and eutrophication risks. Although emerging "green" scale inhibitors (e.g., PASP, PESA, and modified polysaccharides) offer eco-friendly alternatives, they often suffer from performance degradation under the extreme conditions of deep reservoirs-specifically high temperatures (>120( degrees)C) and ultra-high mineralization. This review provides a critical analysis of the transition from traditional to green scale inhibitors, with a specific focus on their applicability in high-temperature and high-salinity (HTHS) oilfield environments. Beyond a comprehensive classification, we deeply elucidate the structure-activity relationships (SAR), highlighting how specific molecular designs-such as the introduction of sulfonic acid groups, graft copolymerization, and nano-functionalization-can overcome the thermal and salt tolerance limitations of biodegradable polymers. The mechanisms of chelation, lattice distortion, and dispersion are re-examined through the lens of recent molecular dynamics (MD) simulations and experimental morphology studies. Finally, the review identifies unresolved challenges in compatibility and cost-effectiveness and proposes future research directions, including multifunctional integrated agents (scale/corrosion/bacteria control) and research progress of nano-scale inhibitors. This work serves as a theoretical foundation and practical guide for designing the next generation of robust, eco-friendly inhibitors for harsh oilfield conditions.

Conventional fracturing fluids often suffer from severe viscosity degradation under ultra-high temperature (>240 degrees C) reservoir stimulation conditions. This is primarily caused by thermal-oxidative degradation and high-shear forces. To address this challenge, a water-soluble reticulated nanocomposite polymer (HT-PVSDA) was developed by integrating nanofluidic topological modulation and free-radical-trapping. This material utilizes trifunctionalized nano-SiO2 as chemical crosslinking nodes and a hydrophobic monomer containing a quaternary ammonium imidazole group as a multifunctional radical trapping agent. The topological network architecture, synergistically reinforced by covalent bonding and self-assembly, confers significantly superior thermal stability upon it. Experimental results demonstrate that the viscosity remained at 112 mPas after 120 min of shearing at 240 degrees C and 170 s(-1). Scanning Electron Microscopy images distinctly reveal a robust spatial framework supported by SiO2 nodes. Density Functional Theory calculations indicate that the radical trap preferentially captures center dot OH radicals (reaction activation energy as low as 5.20 Kcal mol(-1)), subsequently forming a stable product requires only 5.48 kcal mol(-1) of activation energy, lower than the 67.11 Kcal mol(-1) and 51.29 Kcal mol(-1) required for center dot OH to propagate in the polymer backbone. This effectively interrupts the radical chain reaction propagation along the polymer backbone, thereby inhibiting thermal-oxidative decomposition. Furthermore, the polymer exhibits an intelligent temperature-responsive reinforcement mechanism: supramolecular interactions dominate at low-to-medium temperatures, while metal crosslinking and antioxidative functional groups activate within the ultra-high temperature regime. Notably, this system achieves high-strength crosslinking within 5 min at 180 degrees C, further improving heat resistance. This research offers a novel solution for surpassing the performance limits of ultra-high-temperature fracturing fluid materials, demonstrating significant engineering application potential for the development of ultra-deep hydrocarbon resources beyond 10,000 m.

Near-wellbore formation damage in carbonate reservoirs is commonly characterized by the coexistence of complex organic and inorganic deposits, which severely deteriorate reservoir permeability and oil well productivity. Conventional acidizing schemes are largely based on experimental data obtained from pure mineral cores, which fail to realistically represent the compositional characteristics of in-situ plugging materials and their influence on acid-rock reaction behavior, thereby limiting their engineering applicability. To address this issue, the organic-inorganic composite composition of near-wellbore plugging materials was first systematically characterized, and artificially damaged cores that reflect the actual damage features were subsequently constructed. On this basis, a targeted hybrid acid system was developed. Core-flooding tests demonstrated that this system achieved a permeability ratio of 18 times (i.e., a 1700% increase), significantly outperforming conventional hydrochloric acid. Key reaction kinetics parameters obtained from static dissolution and rotating disk experiments were utilized to construct and calibrate a dual-scale model. Numerical simulations confirmed that the hybrid acid system generates smoother, more elongated wormholes at lower injection rates compared to the HCl system, explaining its superior deep-penetration capability. This study demonstrates that the hybrid acid system developed herein, benefiting from the synergistic complementarity between organic and inorganic acids, effectively targets the organic-inorganic composite plugging characteristics of ZH Well. The system simultaneously achieves efficient dissolution and enhanced deep penetration, thereby significantly improving stimulation performance in complex and severely damaged carbonate reservoirs.

Permeability reduction due to mineral scaling, particle migration, and geochemical interactions is a critical challenge in carbonate geothermal reservoirs, significantly affecting the efficiency of Enhanced Geothermal Systems. Acid treatment is widely used to restore permeability by dissolving blockages and creating wormholes, thereby improving reservoir flow and heat transfer. However, existing acidizing models often neglect the effects of fracture blockage and reaction heat. To address these gaps, this study develops a thermo-hydro-chemical coupled model that integrates fluid dynamics, acid transport, thermal effects, and acid-rock reactions in a two-dimensional representation of a fractured carbonate geothermal reservoir. The model is formulated using the Stokes-Brinkman equation, the first and second laws of thermodynamics, Fick's law, the Arrhenius equation, and the Kozeny-Carman relationship to accurately capture wormhole propagation. A grid independence study ensures numerical stability, and the model is validated against published experimental results, confirming its reliability in predicting acid-rock interactions. Simulation results reveal that fracture blockage significantly alters acid flow paths, and if permeability within blocked fractures falls below that of the surrounding matrix, acid bypasses the fractures, increasing acid treatment costs. Furthermore, reaction heat plays a crucial role in wormhole propagation, with elevated temperatures accelerating acid consumption and altering dissolution patterns. The study also emphasizes the necessity of real-time monitoring of fracture conditions, as sudden changes in injection pressure or production flow rate may indicate blockage formation requiring intervention. This study provides theoretical guidance for efficient acid treatment in carbonate geothermal reservoirs.

At 200 °C, conventional acids for carbonate stimulation exhibit excessively fast acid–rock reactions and severe corrosivity, limiting their use in ultra-high temperature acid fracturing. This study aims to develop a buffering acid system with high thermal stability, controllable reactivity, and reduced corrosion. Dissolution and corrosion experiments were conducted to compare hydrochloric–formic and hydrochloric–acetic acid systems at various concentrations under 200 °C conditions. A suitable buffering formulation was then identified and further evaluated through reaction kinetics tests, long-duration dissolution, and extended fracture-etching experiments. Molecular simulations were also performed to clarify the buffering mechanism.Results show that a system containing 15 % HCl and 6 % formic acid is most suitable for acid fracturing at 200 °C. Its dissolution capacity reached 96.32 % of that of 20 % HCl, while the corrosion rate on 110SS steel was 68.1339 g/(m²·h), meeting industry standards. The reaction rate was only 76.90 % of that of hydrochloric acid at the same concentration, demonstrating effective retardation. The apparent activation energy was 36.19 kJ/mol, significantly higher than that of HCl, indicating slower H⁺ release and enhanced buffering behavior.Etching morphology analysis revealed that this buffering acid achieved stronger etching than weak acids (e.g., formic acid) and a longer effective penetration distance than strong acids (e.g., HCl). Unlike pure hydrochloric acid, the HCl–formic acid system exhibits a stable pH buffering range of 2.82–4.74. The interaction between formate ions and hydrogen ions reduces H⁺ diffusion and consumption, thereby extending the acid’s reactive distance within the fracture network.

Abstract Deep and ultra-deep carbonate reservoirs contain abundant geothermal and natural gas resources, and the acid-fractured conductivity is a critical factor determining the development efficiency of these resources. However, high closure stress and acid-induced damage can lead to fracture closure and conductivity degradation. A new approach to enhancing fracture conductivity has been proposed based on mineral alteration, i.e., the in-situ transformation of original minerals into new phases; however, this process remains time-consuming (up to 72h). PMAA has been preliminarily shown to rapidly improve rock mechanical strength. In this work, the influences of different acid systems (such as gelled and organic acids) and PMAA treatment at 200°C on the etching morphology, mechanical strength (HV), and fracture conductivity of tight carbonate rocks were systematically examined. The crystalline phases and hardness of the rock samples were analyzed using micro-Vickers hardness testers. A 3D laser scanner was utilized to capture the surface characteristics of the fractures, and based on this, the surface roughness was calculated. Fracture conductivity was measured using a high temperature and pressure fracture conductivity testing apparatus. The results demonstrate that rapid PMAA treatment at ultra-high temperature markedly improves fracture conductivity under high closure stress while clarifying the underlying mechanism. At 200°C, a 4h PMAA treatment led to an approximately 18.8-fold increase in fracture conductivity relative to untreated groups. Acid-induced dissolution altered the rock microstructure from a dense and compact state to a more porous and loosened framework, generating abundant dissolution pores and microfractures. By contrast, PMAA treatment promoted the in-situ transformation of carbonate minerals on fracture walls into harder hydroxyapatite and simultaneously completely repaired structural damage caused by acid exposure. This process enhanced rock strength and resistance to deformation, thereby reducing fracture closure displacement under applied stress. Acid treatment alone decreased rock hardness by as much as 36.7%. In comparison, PMAA application proved effective for carbonate rocks with varying calcium carbonate contents, with maximum hardness improvements reaching 39.1%. Moreover, etching induced by organic acid in argillaceous limestone exhibited greater heterogeneity than that produced by gelled acid in tight limestone. Overall, these findings indicate that PMAA can rapidly reinforce fracture wall strength and maintain high conductivity under elevated temperature and pressure conditions, providing a promising approach for the rapid creation of highly conductive fractures during acid fracturing of carbonate reservoirs.

Deep and ultra-deep carbonate reservoirs contain abundant geothermal and natural gas resources, and the conductivity of acid-fractured fractures is a critical factor determining the development efficiency of these resources. However, high closure stress and acid-induced damage can lead to fracture closure and conductivity degradation. Mineral alteration refers to the in-situ conversion of existing minerals into new compounds, but the mineral alteration process is currently too slow (72 h). The Na2HPO4 + H3PO4 buffer solution (PPN) has been preliminarily proven effective in rapidly enhancing rock strength. This study investigated the effects of different acid systems (gelling acid and organic acid) and PPN treatment at 200 degrees C on the etching morphology, hardness, and fracture conductivity of dense carbonate rocks from two formations: the Mao-kou limestone and the Jialingjiang argillaceous limestone. The experimental results confirm that PPN rapid treatment under ultra-high temperature is effective in enhancing the fracture conductivity under high closure stress, and also reveal its mechanism of action. After 4 h of PPN treatment at 200 degrees C, the fracture conductivity of the Mao-kou formation and Jialingjiang formation samples increased by factors of 29.4 and 19.0, respectively, compared with untreated samples. Acid dissolution caused the rock's microstructure to transform from being dense and compact to becoming loose, with numerous dissolution pores and micro-fractures. In contrast, PPN treatment converted carbonate minerals on the fracture surfaces in situ into harder hydroxyapatite and repaired acid-induced structural damage, thereby enhancing rock strength and deformation resistance, resulting in smaller fracture-closure displacement under stress. Acid-induced damage reduced the hardness of Mao-kou formation and Jialingjiang formation samples by up to 25.6 % and 36.9 %, respectively. PPN treatment was effective for both limestone and argillaceous limestone, with the maximum increases in rock hardness reaching 39.4 % and 29.8 %, respectively. The organic acid produced a more heterogeneous etching morphology in the argillaceous limestone than the gelling acid did in the limestone. This study provides a new pathway for the rapid construction of high-conductivity fractures in deep and ultra-deep reservoir and efficient energy development.

As oil and gas exploration moves into deeper and ultra-deep carbonate reservoirs, ultra-high temperature and high pressure (UHTHP) conditions pose serious challenges for acid fracturing. However, a comprehensive review framework covering the full acid fracturing process under UHTHP conditions is still lacking. This review summarizes recent progress in acid fracturing under UHTHP environments. First, it examines acid-rock reaction kinetics, focusing on acid rheology under UHTHP and its impact on reaction rates, while comparing retardation mechanisms across different acid systems. Second, it reviews the effects of acid etching on the mechanical weakening of carbonate rocks and discusses constitutive models based on damage mechanics. Fracture conductivity prediction methods are also evaluated, with emphasis on their current limitations. Third, the review highlights the role of multi-stage alternating acid fracturing in enhancing non-uniform etching and improving fracture conductivity, especially under high closure stress. Finally, it outlines key research gaps in reaction modeling, mechanical degradation, and acid fracturing optimization under UHTHP conditions. The findings indicate that current kinetic models and conductivity prediction methods are poorly applicable to UHTHP environments, and that acid-induced weakening mechanisms require further investigation. This work provides theoretical insight and practical guidance for the design and optimization of acid fracturing in ultra-deep carbonate reservoirs.

Tight gas reservoirs represent a significant domain for natural gas development in China. Sliding sleeve fracturing technology, which eliminates the need for pumping bridge plugs, serves as a crucial measure for enhancing production, reducing costs, and improving operational efficiency. This study establishes a fracture initiation model at the dual interfaces, based on the cement sheath tensile-compressive initiation criterion and the formation tensile failure criterion. By incorporating induced stresses from hydraulic fractures into the cement sheath-formation interaction evolution model, the characteristics of hydraulic fracture propagation are investigated. Numerical simulations reveal that single-cluster sliding sleeve fracturing experiences an increased fracture initiation pressure due to interface breakthrough, while the subsequent lower extension pressure promotes greater fracture width and length. During simultaneous fracturing of multiple sliding sleeve clusters, fractures near the root form preferential flow channels, whereas the propagation of central fractures is constrained by stress interference and flow distribution. Optimization results indicate that a fracture spacing of 20-25 m and a pumping rate exceeding 12 m & sup3;/min achieve the optimal fracture-controlled volume. A comparison of multi-process stimulation volumes demonstrates that multi-cluster sliding sleeve sequential fracturing outperforms both multi-cluster sliding sleeve simultaneous fracturing and multi-cluster perforation fracturing. This study provides a theoretical foundation for large-scale volume fracturing in tight gas reservoirs using sliding sleeve segmentation technology, and offers robust support for optimizing fracturing design parameters.

The extraction of deep coalbed methane (CBM) relies on high-rate, large-volume network fracturing. In water-scarce regions, recycling formation flowback fluids for fracturing fluid preparation is essential to reduce freshwater consumption. To address the performance degradation of fracturing fluids in high-salinity flowback water, a biomimetic salt-tolerant polymer friction reducer (ASD) was developed, inspired by the zwitterionic salt-resistance mechanism in mussels. By integrating hydrophobic association with the antipolyelectrolyte effect, the ASD-based slickwater maintains an apparent viscosity of ∼75 mPa·s in flowback water with total dissolved solids exceeding 120,000 mg/L. Experimental results demonstrate a maximum drag reduction rate of 79.58% and superior dynamic proppant transport. At 60 °C, the fluid completely breaks within 3 h, leaving a low residue of 310 mg/L. Mechanistically, particle size and zeta-potential analyses confirm that ASD exhibits a significant increase in hydrated radius (500-2000 nm) in saline solutions, far exceeding the 10-35 nm observed for conventional hydrolyzed polyacrylamide, validating its strong antipolyelectrolyte response. Molecular dynamics simulations further elucidate this structural adaptability in high salt solutions. This biomimetic strategy offers a high-performance, sustainable solution for deep CBM stimulation using hypersaline flowback water.

Mixed sedimentary rocks present considerable challenges for petroleum and geothermal resource development due to their strong heterogeneity. Acidizing is an effective stimulation technique to enhance the productivity of such reservoirs. To investigate the impact of rock heterogeneity on matrix acidizing performance, this study assumes the coexistence of carbonate and non-reactive minerals within each mesh and constructs three mineral distribution models: uniform, banded, and blocky. Based on a coupled thermo-hydro-chemical two-scale model, the effects of mineral composition, mineral distribution, temperature, and reaction heat on wormhole development in mixed sedimentary rocks are systematically analyzed. The results show that the content of non-reactive minerals significantly affects acidizing efficiency. A high content reduces efficiency, whereas a low content suppresses branching and lowers acid consumption. Mineral distribution patterns strongly influence wormhole morphology and acidizing efficiency. Uniform distributions promote branching and higher acid consumption, while banded patterns favor dominant channels, with the breakthrough pore volume (PVbt) reduced by 46 % compared with the uniform distribution. In blocky distributions, acidizing efficiency is more sensitive to the injection rate. Initial wormhole formation near the wellbore is mainly controlled by the original permeability, while mineral distribution governs the selection and branching of dominant wormholes. Temperature exerts a limited effect on dissolution patterns. However, increasing temperature accelerates wormhole growth and branching, thereby reducing acidizing efficiency, while higher injection rates can mitigate this effect. The influence of reaction heat on PVbtdecreases with increasing temperature. In low-temperature reservoirs, reaction heat enhances local temperature and reaction rate, resulting in a 9.3 % reduction in PVbt. Moreover, reaction heat significantly alters the reservoir thermal field, raising the overall temperature by approximately 10 degrees C and forming high-temperature zones around wormhole walls and tips. This study provides useful insights for optimizing acidizing treatments in mixed sedimentary reservoirs.

This study presents a systematic investigation into the design, optimization and mechanism of high-performance solid inhibitors for low-carbon steel in a high-temperature maleic-acid (ML)-ammonium hydrogen fluoride (FRC) solid mud-acid system. Multiple approaches were used, including weight-loss tests, controlled-variable method, orthogonal response surface methodology, electrochemical analysis, SEM-EDS characterization, and molecular-dynamics (MD) simulations. The results show that, at 120 degrees C in a 17% ML + 1.5% FRC solution, a composite inhibitor with the composition hexamethylenetetramine (HMTA):potassium iodide (KI):sulfonate (HS):tetradecyltrimethylammonium chloride (JA) = 0.5%:0.3%:0.25%:0.3% reduces the corrosion rate of N80 steel to 1.98 g/m2 & centerdot;h and achieves an inhibition efficiency of 99.44%, meeting relevant industry requirements. Electrochemical data, SEM-EDS analyses and MD simulations jointly indicate that promoters addition lowered steric hindrance among HMTA molecules and increased the density of the adsorption film at the interface; a complex, compact adsorption layer composed of HMTA, promoter molecules and ML-species forms on the steel surface and suppresses corrosion processes. The combined experimental and theoretical evidence demonstrates effective metal protection and provides a novel solid corrosion inhibition system with sufficient potential for ML-FRC acidification.

Acid fracturing is the most effective production enhancement measure for carbonate reservoir stimulation. The retardation performance of acid systems is one of the key parameters influencing the effectiveness of acid fracturing. However, current methods for evaluating acid retardation, based on static dissolution experiments and acid-rock reaction kinetics, have certain limitations. This study introduces a new method for evaluating acid retardation by simulating acid flow in formation fractures. The morphology of acid-etched fractures was obtained, and the depth and width distribution of the etched fractures were quantitatively analyzed to assess the acid retardation performance. In addition, high-temperature dissolution experiments were used to evaluate the acid's dissolution capacity, and acid-rock reaction kinetics experiments were conducted to determine the acidrock reaction rate and activation energy of the acid systems. The results show that at 130 degrees C, the reaction rate between hydrochloric (HCl) acid and rock (2.12 x 10-5 mol/(s & sdot;cm2)) was the fastest, followed by Diverting acid, while G acid had the slowest reaction rate (1.51 x 10-6 mol/(s & sdot;cm2)). The activation energy of weak acid systems was much higher than that of strong acid systems. The new evaluation method revealed that the average fracture width and depth etched by HCl acid were the largest (7.57 mm and 6.39 mm, respectively), while the fracture depth etched by G acid was the smallest (0.87 mm), and the average fracture width etched by Acetic acid was the smallest (2.30 mm). This indicates that acetic acid has a stronger etching ability along the fracture length compared to G acid. Additionally, the fracture width and depth curves of strong acids (e.g., HCl acid and Diverting acid) showed a downward trend, whereas those of weak acids (Acetic acid and G acid) showed an upward trend. This suggests that Diverting acid has poor retardation performance, while G acid has the best retardation performance. Furthermore, the roughness of fractures etched by strong acids was much greater than that of fractures etched by weak acids, indicating that strong acids have a stronger non-uniform etching ability. To balance the non-uniform fracture etching morphology and the effective reach of the acid, a combination of strong and weak acids can be used.