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.

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.

Hydrothermal activity exerts dominant control on the spatial heterogeneity and quality of volcanic reservoirs. Permian volcaniclastic reservoirs distributed in the western Sichuan Basin, Southwestern China, which are closely associated with the Emeishan Large Igneous Province (ELIP), have undergone intensive superimposed alteration jointly induced by hydrothermal events and hydrocarbon emplacement. However, the timing, duration and formation mechanisms of this hydrothermal modification remain unclear. This study integrates petrology, geochemistry, geochronology and trace element analysis of hydrothermal zircon grains in eruptive-facies tuff breccia of the western Sichuan Basin, Southwestern China, aiming to constrain zircon formation ages and clarify their genetic mechanisms. Geochemical data indicate that the tuff breccia was derived from high-Ti alkaline basalt magmas with trace element signatures analogous to ocean island basalts (OIB), and was emplaced during the main eruptive phase of the ELIP (263–259 Ma). Zircon geochronological results reveal two discrete episodes of hydrothermal fluid activity within the reservoir. The first episode (242.4 ± 3.6 Ma and 238.1 ± 1.1 Ma) is genetically linked to Indosinian orogeny-related magmatic-hydrothermal activity. During this stage, volatile-rich hydrothermal fluids triggered coupled dissolution-precipitation of primary zircon grains, resulting in radiogenic Pb loss and the formation of altered zircon domains. The second episode (159.0 ± 3.5 Ma) corresponds to Yanshanian tectonically driven hydrothermal circulation, coinciding with the regional hydrocarbon charging peak. Early hydrothermal activity promoted the formation of devitrification-related pores in the tuff breccia. In contrast, late hydrothermal fluids facilitated mineral alteration and dissolution pore development, significantly enhancing secondary porosity. Hydrothermal zircon thus serves as reliable geochronological and geochemical tracers for recording multi-stage tectonic-magmatic-fluid interactions, which jointly dominate the diagenetic evolution and quality of Permian volcaniclastic reservoirs in the study area.

High-quality vuggy reservoirs have been developed in the Upper Carboniferous–Lower Permian Tahaqi Formation in the southwestern Tarim Basin piedmont area, following significant exploration breakthroughs. However, the unclear reservoir genesis has severely constrained exploration efficiency. Integrating petromineralogical data (drilling cores, thin sections, well logs), field outcrops, and geochemical analyses, this study reveals that Tahaqi Formation reservoirs are controlled by early diagenetic karst within a high-frequency sequence framework (instead of traditional weathering crust karst). The formation comprises two third-order sequences (SQ1–SQ2), with fourth-order sequences characterized by platform margin facies progradation. Typical early diagenetic karst markers (e.g., exposure surfaces, mottled brecciated limestones) in the highstand systems tracts of fourth-order sequences are confirmed by geochemical data. Three vertical karst sequence types are classified based on exposure duration and karst intensity. Moderate early diagenetic karstification is critical for high-quality reservoirs—thick oolitic shoals in the SQ2 highstand systems tract (Well Qiqian 2–Artux section) form favorable reservoirs via karst modification. Combined with the Carboniferous–Permian source-reservoir-caprock assemblage, favorable reservoir belts are predicted from the central study area to the Kashgar-Yecheng Sag, providing a key geological basis for reservoir prediction and risk exploration.

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.

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.

A diverting fracturing technique has been widely utilized for old and new wells stimulation in various geothermal and petroleum fields, and has been paid much attention by governments and companies. Diverting agent is one of the key materials for this technology, and it is also one of the characteristics with which this technology is different from a conventional fracturing technology. Although some diverting agents have been developed, they have some shortcomings or are limited by application scenarios. Therefore, this paper introduced a novel thermo-responsive diverting agent and put forward a corresponding diverting fracturing process based on its characteristics. Through indoor and outdoor studies, positive findings were obtained. First, with the increasing temperature, the thermo-responsive diverting agent could realize a solution-gel-solution multiphase transition process. A change in the reservoir temperature during and after fracturing treatment could be utilized to realize the multiphase transition of this diverting agent. Second, the multiphase transition speed could be controlled by adjusting the gel factor (GF) dosage and heating temperature. Third, it had a good injection property (initial viscosity 3.7 mPa s) and could be quickly transformed into a semi-solid gel to achieve temporary blocking. Fourth, the breakthrough pressure of the semi-solid gel had a positive correlation with a plugging length, and the gradient was about 9.4 MPa/m. Fifth, it had good compatibility and low formation damage (only 2%), and could effectively protect the formation permeability. Finally, the results of fracturing construction curves, micro-seismic monitoring, and gas production data proved that this diverting agent had a promising outcome. The direction of formation break changed from the southwest to the northeast of the wellbore after temporary blocking confirmed by micro-seismic results. The production of diverting fracturing wells was 1.3 times that of the initial production and 1.5 times that of the later-stage production of conventional fracturing wells. This study provided a reference for the diverting fracturing stimulation in low permeability reservoirs.

Unconsolidated sandstones are characterized by low degrees of cementation, and the pore structure changes significantly during water injection development, which leads to a rapid increase in water content and an uneven distribution of the remaining oil. It is crucial to quantify the pore structure changes for water control and oil stabilization in unconsolidated reservoirs. Taking the PL A Oilfield as an example, this study clarifies the change patterns and mechanisms of pore structure in different types of reservoirs as affected by water flooding. The analysis combines core test data before and after flooding, quantitative analysis of full-scale casting thin sections, and nuclear magnetic resonance water-flooding experiments on sand-filled samples. The results indicate that significant changes occur in the pore structures of various reservoirs after long-term waterflooding. Specifically, the intergranular particle content and pore structure heterogeneity decrease, while the maximum and average pore throat radius increase. The proportion of large pores increases, while that of small pores decreases. Overall, these changes lead to an improved reservoir pore structure. The range of change decreases progressively from Class I to Class III, indicating that water flooding affects different types of reservoirs with varying intensity. Particle dispersion and migration during water flooding are the primary causes of changes in the pore structure. The main components of the particles are quartz and clay minerals. The original sedimentary conditions of the reservoir cause different degrees of particle migration, which lead to different changes in the pore structure. Changes in wettability facilitate particle migration. Carbonate minerals generated by reservoir scaling can block pore throats and reduce permeability, thereby also contributing to changes in the pore structure. This study offers a scientific basis for devising residual oil recovery strategies in the oilfield and serves as a valuable reference for analogous reservoirs.

High-pressure mercury injection capillary pressure is an important method for quantitative characterization of reservoir pore structure. However, the high-pressure mercury injection curves of low porosity and low permeability sandstone are difficult to distinguish because of their small morphological differences, resulting in different classification standards of pore structure of low porosity and low permeability sandstone. In addition, it is necessary to establish an accurate reservoir pore structure prediction model based on logging data. This paper presents a set of quantitative classification and prediction methods for low porosity and low permeability sandstone pore structures based on machine learning. The methods were developed using the casting thin section, scanning electron microscope, and logging data of the low porosity and low permeability sandstone reservoir in the Kaiping Sag, located in the Pearl River Mouth Basin. Firstly, based on the ordered points to identify the clustering structure algorithm, the sample mercury injection data is clustered. A reasonable number of clusters is obtained using the ordered list decision diagram, and the labels are assigned to each sample. Secondly, random forest, XGBoost, and LightGBM algorithms are trained with logging and class label data to learn the mapping relationship between them. Finally, the trained random forest, XGBoost, and LightGBM model are used to predict the pore structure of the test well. Through the verification of casting thin sections and scanning electron microscope photos, the sample class label given by the ordering points to identify the clustering structure algorithm is reasonable. The LightGBM algorithm attains the highest F1 - score value of 0.91 and 0.72 in the prediction of pore types of two well test horizons, showing its superior performance. The unsupervised - supervised machine learning approach proposed in this paper provides an objective and precise prediction of the pore structures within low porosity and low permeability sandstone reservoirs. This outcome holds referential implications for the prediction of pore structures in other reservoirs.

Geological Carbon Sequestration (GCS) plays a crucial role in addressing climate change, particularly in oil and gas development. Understanding the reaction of supercritical CO2 under in situ conditions and its effects on minerals is essential for advancing GCS technology. This study investigates the reaction mechanisms of feldspar (potassium and sodium feldspar) and clay minerals (chlorite, illite, montmorillonite, kaolinite) in CO2 environments. The impacts on mineral crystal structures, morphologies, and elemental compositions were analyzed using X-ray diffraction (XRD), scanning electron microscopy (SEM), energy-dispersive spectroscopy (EDS), and ion concentration measurements (ICP-OES and ICP-MS). The results show that feldspar minerals exhibit lower reaction rates, with sodium feldspar dissolving faster than potassium feldspar, due to the higher solubility of sodium ions in acidic conditions. Chlorite showed significant crystal structure damage after 30 days, while montmorillonite underwent both dissolution and precipitation, influenced by interlayer cation dissociation. Kaolinite exhibited minimal reaction, primarily showing localized dissolution. Additionally, the formation of siderite (FeCO3) was observed as Fe2+ substituted for Ca2+ in CaCO3, highlighting the role of iron-bearing carbonates in CO2 interactions. The study provides insights into the factors influencing mineral reactivity, including mineral structure, ion exchange capacity, and solubility, and suggests that chlorite, montmorillonite, and illite are more reactive under reservoir conditions, while kaolinite shows higher resistance to CO2-induced reactions. These findings offer valuable data for optimizing GCS technologies and predicting long-term sequestration outcomes.

Significant variations in depositional environments, reservoir conditions, and burial depths across the Yuxi, Luzhou, Changning, and Zhaotong areas, this study investigates the reservoir heterogeneity and pore structure controls in Sichuan Basin's Wufeng-Longmaxi shales. This paper studys the reservoir characteristics of four typical shale exploration areas, by using XRD, FE-SEM and low-temperature N2 adsorption experiments. The main controls on pore structure were then selected using the grey correlation algorithm. High-quality shale reservoirs consistently develop at the base of the Longmaxi Formation. However, excessive thermal maturity causes degradation of hydrocarbon generation potential and storage capacity in localized areas. There is a strong correlation between pore structure and TOC content (correlation coefficient: 0.72-0.76), Ro (0.73-0.74), tectonics (0.65-0.71), and burial depth (0.23-0.63). Pore structure parameters exhibit a strong positive correlation with TOC content. Pore systems undergo a six-stage evolutionary progression with advancing thermal maturity. In structurally compromised anticlines, pore networks develop directional slit-shaped configurations with reduced pore volumes and surface areas, while excessive burial depth similarly causes reduction in these two parameters. This paper is crucial for improving an understanding of the shale pore system and facilitating the efficient development of shale gas resources.

In geothermal, oil, and gas reservoirs, the conductivity of hydraulic or acid-etched fracture determines efficient and economical resource exploitation. Proppant embedding or acid-rock reaction weakening rock leads to a sharp decline in fracture conductivity. Mineral alteration is a technique of in-situ transformation of existing minerals into harder minerals to improve rock strength, and diammonium hydrogen phosphate (DAP) has been shown to be an effective mineral alteration agent for high-porosity and high-permeability carbonate rocks at low temperatures. This work studied the effect of 10 wt% HCl and 0.8 M DAP solution on the hardness of rock samples (0.36%-1.31 % porosity and 2.72-17 x 10-6 mu m2 permeability) at 25, 80, 140 and 200 degrees C. The experimental results proved the weakening effect of acid and the strengthening effect of DAP on rock. The mechanism of hardening caused by DAP treatment and the positive effects of high temperature were revealed. As the temperature increased, the chemical reaction between DAP and rock accelerated, resulting in an increase in the amount of reaction products (calcium phosphate) and higher crystallinity, which made the rock harder. Even at ultra-high temperatures (200 degrees C), DAP treatment remained remarkably effective for very dense rock samples. In addition, the relationship between rock hardness and rock embedding strength was established. The fracture conductivities under different rock hardness were calculated by Nierode-Kruk correlation and numerical method. The results indicated that it was feasible to improve the fracture conductivity through DAP treatment at high temperatures. This study provides a theoretical basis for creating high-conductivity fractures through mineral alteration in deep carbonate reservoirs.

The simultaneous occurrence of H2S and CO2 exists during many processes, and they react with each other to form COS and H2O. Here, we develop a novel non-fitting functional representation regarding the chemical equilibrium constant subject to the reaction of H2S and CO2. It depends only on standard experimental data for the concerned five molecular constants of CO2 and COS and six molecular constants for H2S and H2O, and possesses the advantages of direct algebraic operation and convenient application, whereas the conventional empirical correlations involve multiple adjustable coefficients for fitting experimental data. The average absolute deviations between three experimental data sets of the equilibrium constants and the theoretical values predicted with the developed functional representation are 4.33 %, 5.73 %, and 5.93 %, respectively, while the corresponding deviations of three same experimental measurements from the theoretically calculated results with the previous empirical correlation provided in the well-known Aspen databank are 19.1 %, 73.6 %, and 10.0 %, respectively. Through a comparison of the theoretically predicted results of the equilibrium constants with the experimental data, we find that the presently proposed prediction formulation based on considering the structural characteristics of molecules is reliable, while the corresponding empirical correlation given in the well-known Aspen databank is not applicable. This study provides a novel approach to predict the chemical reaction characteristics involving highly toxic sulfur-containing compounds.

The primary factor constraining the performance of unconsolidated sandstone reservoirs is blockage from particle migration, which reduces the capacity of liquid production. By utilizing logging, seismic, core–testing, and oil–well production data, the reservoir damage induced by particle migration in the Bohai A oilfield was characterized and predicted through combined well–seismic methods. This research highlights the porosity, permeability, median grain diameter, and pore structure as the primary parameters influencing reservoir characteristics. Based on their permeability differences, reservoirs can be categorized into Type I (permeability ≥ 800 mD), Type II (400 mD < permeability < 800 mD), and Type III (permeability ≤ 400 mD). The results of the core displacement experiments revealed that, compared to their initial states, the permeability change rates for Type I and Type II reservoirs exceeded 50%, whereas the permeability change rate for Type III reservoirs surpassed 200%. Furthermore, by combining this quantitative relationship model with machine learning techniques and well–seismic methods, the distribution of permeability change rates caused by particle migration across the entire region was successfully predicted and validated against production data from three oil wells. In addition, to build a reliable deep learning model, a sensitivity analysis of the hyperparameters was conducted to determine the activation function, optimizer, learning rate, and neurons. This method enhances the prediction efficiency of reservoir permeability changes in offshore oilfields with limited coring data, providing important decision support for reservoir protection and field development.

Water (gas) saturation of shale gas is a crucial parameter for free gas evaluation. Due to the influence of various conductive factors, such as graphitization of highly mature organic matter, pyrite, clay minerals and formation water, the phenomenon of ultra-low logging resistivity (logging resistivity R-i< 5 Omega m) appears successively in shale gas exploration and development in Changning, Luzhou, western Chongqing and other blocks in southern Sichuan. As a result, the traditional saturation calculation methods based on electrical methods (Archie formula, Simandoux equation, etc.) are not applicable. Therefore, in order to clarify the influence law of different conductive factors on low resistivity shale gas reservoirs, and then establish a reasonable saturation evaluation model to improve the calculation accuracy of low resistivity shale gas reservoir saturation, taking Wufeng Longmaxi Formation low resistivity shale gas reservoirs in Changning area of southern Sichuan as an example, first, Based on the data of X-ray diffraction, geochemistry, Laser Raman, microscopic thin section, saturation test and logging, and on the basis of the rock volume physical model of low resistivity shale gas reservoir, the improved saturation electrical response equation considering graphitized organic matter, pyrite and other factors is derived based on the parallel conduction model. Secondly, through the numerical simulation of resistivity response, combined with the actual well clay mineral content, pyrite content, graphitization degree of organic matter, formation water saturation and salinity data, it is clear that the highly evolved organic matter graphitization and high water saturation are the core factors for forming ultra-low resistivity shale gas reservoirs in the Wufeng Longmaxi Formation of Changning block. Finally, based on the established saturation response equation, the optimal iterative method is used to calculate the water saturation of low resistivity shale gas reservoir. The correlation coefficient between the calculated results and the test data of pressure retaining core saturation is more than 0. 90, which effectively solves the difficult problem of accurate calculation of low resistivity shale gas reservoir saturation. It provides a basis for reducing the risk of shale gas exploration and development with low resistivity.

Unconsolidated sand reservoirs containing heavy oil play a significant role in hydrocarbon resources, characterized by high porosity and permeability alongside abundant movable fines. During production, these fines can detach and migrate with the reservoir fluids, causing pore plugging and reduced productivity. Visualizing and quantitatively evaluating the evolution of pore structure caused by fines migration under various influencing factors at the microscale is fundamental for devising effective prevention and mitigation measures. This study employs on-line NMR experiments and CFD-DEM simulations to investigate fines migration processes and their effects on physical properties and pore structure at the pore scale. Results indicate that fines migration initiates the formation of a preferential network of migration pathways. The evolution of pore structure demonstrates zonal characteristics along the flow direction, with fines plugging and residual accumulation primarily occurring in the middle/rear section of the core. As the core’s skeleton porosity decreases, fines plugging intensifies; however, at high injection velocity, new dominant flow channels may emerge, leading to a transition from a single-peak to a double-peak T2 spectrum. Below the critical velocity (0.5–1 mL/min), an increase in flow velocity exacerbates severe fines plugging. Conversely, above the critical velocity, an increase in flow velocity results in a more pronounced enhancement of permeability.

Deep Wufeng-Longmaxi marine shale has abundant natural gas resources, but its complex tectonic characteristics lead to strong reservoir heterogeneity, limiting large-scale shale gas development. Herein, to clarify the effects of tectonism on shale pore structure characteristics and reservoir quality in different tectonic regions, typical shale samples from high-steep anticline (HSA) and broad-gentle syncline (BGS) were collected and analyzed through field emission scanning electron microscopy (FE-SEM), gas adsorption, high-pressure mercury injection, and field gas desorption. The results show that under stable tectonic conditions, BGS-shale develops lots of organic matter (OM) pores, and mesopores provide the main pore volume, accounting for over 75%. Deformed and damaged by tectonic extrusion, the HSA-shale is mainly composed of interparticle (InterP) pores and intraparticle (IntraP) pores, with mesopores and micropores accounting for 38.97-47.69% and 37.79-51.28% of total pore volume. Benefiting from increased microfractures and dissolution pores, the macropore volume of HSA-shale is similar to that of BGS-shale. Under good preservation and high pressure coefficient, BGS-shale has a larger pore volume, pore surface area, and porosity to store abundant shale gas, which is conducive to a high shale gas yield. However, the HSA-shale has lower shale gas storage capacity and yield because its porosity, pore volume, and pore surface area are reduced with worse preservation condition. Therefore, in complex tectonic zones, the deep BGS-shale is more favorable for shale gas development than HSA-shale.