Tight Sandstone Gas Reservoir Types and Formation Mechanisms in the Second Member of the Xujiahe Formation in the Anyue Area, Sichuan Basin

Abstract

With the advancement of oil and gas exploration and development, tight sandstone gas has become a major current exploration field. However, the effective development of tight sandstone gas faces significant challenges due to the strong heterogeneity of tight sandstone reservoirs, diverse reservoir types, complex pore structures, and unclear understanding of reservoir formation mechanisms, which brings great difficulties. Clarifying the types and formation mechanisms of tight sandstone reservoirs is vital for guiding oil and gas exploration and development. This study investigates the characteristics, types, and formation mechanisms of tight sandstone gas reservoirs in the Xujiahe Formation (T₃X₂) of the Anyue area using core observation, cast thin-section identification, scanning electron microscopy, high pressure mercury intrusion, nuclear magnetic resonance, and other experimental methods. It defines the physical property lower limit of T₃X₂ reservoirs in Anyue, classifies reservoir types, elaborates on the basic characteristics of each type, and analyzes their genetic mechanisms. The results show that T₃X₂ reservoirs in the Anyue area can be divided into four types. Sedimentary, diagenetic, and tectonic processes are identified as the primary factors controlling reservoir quality, governing the formation mechanisms of different reservoir types. Based on these findings, a reservoir formation mechanism model for T₃X₂ reservoirs in the Anyue area is established, providing an important basis for subsequent oil and gas exploration and development in the region.

1. Introduction

The study of tight sandstone gas began in the 1950s, and the exploration and development of tight sandstone gas reservoirs in the United States and Canada was the highest [1]. In recent years, the exploration and development of tight oil and gas in China has also achieved rapid development, and the reserves and production of low-permeability sandstone gas reservoirs have increased rapidly, which are expected to become the main body of oil and gas storage and production in China in the next 10–20 years [2,3]. Tight sandstone gas has the characteristics of multiple distribution layers, a wide range, and a large resource scale. Low-permeability sandstone gas reservoirs in China are mainly distributed in the Sichuan, Ordos and Tarim basins, and are also found in the Songliao and Bohai Bay basins [4]. Natural gas exploration of the Xujiahe Formation (T_3X) in Sichuan Basin began in the 1950s, and successively discovered the Hechuan, Xinchang, Guangan, Anyue, Bajiaochang, Luodai, and Qiongxi tight sandstone gas fields, showing huge exploration potential with accumulated proven reserves of nearly one trillion cubic meters up to now [5,6,7,8,9]. Up to now, the proven reserves of natural gas in T₃X₂ of the Anyue area have reached 2089.91 × 10⁸ m³. Although the reserves of tight sandstone gas are large, the overall utilization rate is low, the recovery degree is only 51.59%, and the exploration potential is still large. The reservoir of T₃X₂ in the Anyue area is characterized by low porosity and low permeability as a whole, and the reservoir is highly heterogeneous, with diverse reservoir configurations and complex pore structures, and with the unclear understanding of the reservoir formation mechanism bringing great difficulties to the effective development of the tight sandstone gas reservoirs.

At present, the classification and evaluation methods of tight sandstone reservoirs are mainly studied by core physical property analysis, mercury injection, nuclear magnetic resonance, cast thin slice, scanning electron microscope, and other petrophysical experiments, combined with logging data and neural network technology. In terms of reservoir classification and evaluation techniques, Chen et al. [10] systematically sorted out the basic principles, applicability, advantages, and disadvantages of 11 reservoir evaluation methods, such as the geological empirical method, weight analysis method, analytic hierarchy process, fuzzy logic method, and artificial neural network method. Han et al. [11] summarized the classification methods of reservoir logging into four categories: a semi-quantitative classification method based on the crossplot method, a reservoir classification method based on flow units, a reservoir classification method based on multivariate statistics and a machine learning algorithm, and a reservoir classification method based on a new logging technology and method. Cheng et al. [12] carried out a review of research on reservoir logging evaluation based on machine learning, and believed that machine learning technology could effectively solve complex nonlinear problems such as well logging evaluation, and proposed the development direction of well logging fine reservoir evaluation. In terms of the establishment of evaluation criteria for tight sandstone reservoirs, Wei et al. [13] discussed the physical properties, pore structure, and other parameters for the tight sandstone reservoirs of the Middle Jurassic Shaximiao Formation in Sichuan Basin, and they divided them into classes I, II, and III. On the other hand, Liu et al. [14] established a classification scheme for conglomerate reservoirs by using the cluster analysis method. Zhou et al. [15] constructed a comprehensive evaluation index of pore structure and combined reservoir quality factors to classify tight sandstone reservoirs. Meng et al. [16] used the relationship between parameters, such as the effective pore throat radius, effective porosity and effective mobile porosity, and macro-physical properties, to classify and evaluate tight sandstone reservoirs. Wang et al. [17] analyzed the petrological composition and pore structure characteristics of the tight reservoir in Jiyang Depression, and used cluster analysis to classify the paleogene tight reservoir. Liu et al. [18] conducted a fractal analysis on the transverse relaxation time distribution of tight sandstone by nuclear magnetic resonance (NMR), evaluated the pore structure and rock types of tight sandstone by using multi-fractal parameters, and further divided the reservoir types. Based on mercury injection and nitrogen adsorption experiments, Wu et al. [19] studied the pore structure and fractal characteristics of tight sandstone reservoirs to classify reservoir types. Ma et al. [20] studied the pore structure characteristics of tight sandstone reservoirs in Ordos Basin by using mercury injection, cast wafer, and NMR experiments, and divided the reservoirs into four categories according to the pore structure parameters, providing a basis for the exploration and development of tight sandstone reservoirs.

In addition, many scholars have analyzed reservoir characteristics and formation mechanisms from the aspects of sedimentary facies, provenance, lithology association, and diagenesis. Jiang et al. [21] studied the sandstone reservoirs in the Bozi area and determined that the physical properties of the reservoirs are controlled by sedimentation, diagenesis, and tectonic processes (fractures), among which carbonate cementation is the main factor of the late physical properties of the reservoirs. Overpressure, hydrocarbon fluid charging, and fracture development affect carbonate cementation, resulting in differences in reservoir physical properties. Li et al. [22] studied differential reservoir control in the Xinchang area of western Sichuan. They believed that the formation of tight sandstone reservoirs is closely related to the sedimentary environment, grain size, diagenesis, and tectonic rupture, and the differential reservoir control effect between different types of reservoirs is obvious. In general, sedimentation is the foundation and differential diagenesis and tectonic rupture are the key factors. Yu et al. [23] comprehensively analyzed the genetic mechanism of the Liangshan Formation tight sandstone reservoir in the eastern Sichuan area, and concluded that the subaqueous branch channel sandstone in the upper system domain is the material basis for the development of high-quality reservoirs in the study area. Mechanical compaction is the main reason for reservoir densification, chlorite coating and early pore calcite protect the primary pores, and the secondary pores are formed by dissolution. The evolution of source rocks provides important organic acids and hydrocarbon sources. Song et al. [24], by studying the genetic mechanism of relatively high quality tight sandstone reservoirs of the Middle Jurassic Shaximiao Formation in the transitional zone of central and western Sichuan, concluded that a high-energy sedimentary environment, early retention diagenesis (pore liner chlorite), multi-stage and multi-type dissolution, and local micro-fracture development and transformation, are the main mechanisms for the development of the relatively high quality reservoir in Shaximiao Formation in the study area. Wang et al. [25] studied the genetic mechanism of deep and ultra-deep reservoirs in the lower Cretaceous in the Bozi-Dabei area, and confirmed that sedimentary facies dominated reservoir physical properties, and compaction (including vertical compaction and lateral compaction) and cementation were the main pore-reducing effects, among which lateral compaction resulted in the formation of a large number of structural fractures. The permeability of the reservoir is improved effectively. Corrosion is the main pore-increasing effect. The abnormal fluid high pressure reduces the effective stress of the reservoir and causes obvious undercompaction, which effectively maintains the physical properties of the reservoir.

In the early research process, related scholars preliminarily discussed the geological conditions of reservoir formation, diagenetic evolution, reservoir characteristics, reservoir type division, main control factors of reservoir development, and pore evolution process of T₃X₂ in the Anyue area. Regarding well logging identification of the pore structure and diagenetic equality, on the basis of clear reservoir characteristics, seismic technology is used to predict the reservoir. The crack is quantitatively evaluated based on new image recognition technology. The sedimentological characteristics of the reservoir were studied by using the analysis techniques of cast thin sections, X-Ray Diffraction (XRD), physical property testing, etc., the stratigraphic framework was improved, the characteristics and distribution of sedimentary microfacies were defined, the micro-characteristics of the reservoir were deeply explored, and the distribution of the “sweet spot” was finely characterized. This study shows that the reservoir rock types in the study area are mainly lithic feldspar sandstone and feldspar lithic sandstone. The reservoir type is a fracture–pore type, with low porosity and low permeability, and the reservoir is highly heterogeneous. The reservoir physical properties are mainly controlled by sedimentation and diagenesis; the physical properties of the sand body of the subaqueous distributary channel and mouth bar are better, but the physical properties of the interdistributary bay are worse. In the study area, the constructive diagenesis mainly includes early rim chlorite cementation and dissolution, and the destructive diagenesis includes compaction, pressure dissolution, and cementation. According to the pore structure parameters of the river capillary pressure curve, the reservoir types are divided into four categories, including Type I for a good reservoir, Type II for a good reservoir, Type III for a poor reservoir, and Type IV for a non-reservoir [26,27,28,29,30,31,32]. Although previous studies have been carried out on the tight sandstone reservoirs of the Xujiahe Formation in the Anyue area, focusing on structure, sedimentation, petrology, diagenesis, and reservoir densification, these primarily address the basic characteristics of the reservoirs. Comprehensive research on the fine classification of reservoir types in T₃X₂ and the formation mechanisms of different reservoir types remains limited. There is a lack of clear standards for reservoir type classification, particularly for mixed reservoir types such as pore type and fracture–pore type reservoirs with unclear demarcation. Additionally, the formation mechanisms of tight sandstone reservoirs have not been fully clarified, leading to ineffective exploitation of tight sandstone gas in T₃X₂ in the Anyue area. To solve this problem, on the basis of previous studies, this paper systematically studies the petrology, reservoir performance, diagenesis, and tectonic characteristics of the tight sandstone reservoir in T₃X₂ in the Anyue area by using a variety of experimental methods and analysis methods such as core observation, casting thin section identification, scanning electron microscopy (SEM), high pressure mercury injection (HPMI), nuclear magnetic resonance (NMR), etc., and further identifies the reservoir types and genetic mechanisms of various reservoirs in order to provide a basis for further oil and gas exploration and development of T₃X₂ in the Anyue area. In terms of research content, compared with previous studies, this paper further refines the classification of reservoir types on the basis of previous research on sedimentary facies, basic characteristics of reservoirs, diagenesis, and preliminary classification of reservoirs in T₃X₂ in the Anyue area. It clarifies the classification criteria for reservoir types, divides diagenetic facies types based on diagenesis research, and defines the corresponding relationship between diagenetic facies and reservoirs, thereby clarifying the genetic mechanisms of various reservoir types. In terms of research methods, this paper mainly adopts a combination of multiple methods. For example, methods such as the bound water saturation method, productivity simulation method, and porosity–permeability relationship method are used to determine the physical property lower limits of reservoirs. Multiple experimental methods, including cast thin section identification, SEM, HPMI, and NMR, are employed to determine the basic characteristics of reservoirs and the intensity of diagenesis. The purpose of this study is to clarify the formation mechanism of tight sandstone reservoirs in T₃X₂ in the Anyue area and establish a formation mechanism model for various reservoir types, so as to provide a basis for the next step of oil and gas exploration and development in T₃X₂ in Anyue area.

2. Regional Geological Profile

The Sichuan Basin belongs to the second-order tectonic unit in the northwest of the Yangtze quasi-platform, and is a diamond-shaped tectonic–geomorphic basin enclosed by faults and folds around the basin [33]. According to regional tectonic types, the basin can be divided into six second-order tectonic units, namely, the central Sichuan middle-inclined gentle belt, west Sichuan depression low-steep belt, east Sichuan high-steep fold belt, southwest Sichuan slope low-fold belt, north Sichuan depression gentle belt, and south Sichuan low-steep curved belt [34,35]. The Anyue gas field, located in Anyue County, Ziyang City, in the central and eastern Sichuan Basin, tectonically belongs to the central part of the central Sichuan middle-inclined gentle belt (Figure 1a). As a part of the Sichuan Basin, the Anyue gas field has experienced the sedimentary–tectonic evolution history of the Sichuan Basin, successively depositing marine strata dominated by carbonate rocks below the Middle Triassic and continental strata dominated by sandstone and mudstone in the Upper Triassic–Jurassic. It has undergone multiple phases of tectonic movements, among which the Indosinian, Yanshan, and Himalayan movements have had significant impacts on the formation of the T₃X₂ gas reservoir in the Anyue gas field [36,37,38].

The Upper Triassic Xujiahe Formation (T_3X) is a set of braid river delta sand–mudstone deposits with a stable thickness ranging from 500 to 650 m. The top is in disconformity contact with the Jurassic Ziliujing Formation (J_1Z), and the bottom is in disconformity contact with the lower Triassic leikoupo Formation (T_2L). From bottom to top, the Xujiahe Formation (T_3X) can be divided into six sections: Member 1 (T₃X₁), Member 2 (T₃X₂), Member 3 (T₃X₃), Member 4 (T₃X₄), Member 5 (T₃X₅), and Member 6 (T₃X₆). T₃X₁, T₃X₃, and T₃X₅ mainly develop black mud, shale, and thin siltstone or coal seam, which are shallow lake facies, and are the main hydrocarbon source layers and cover layers of the Xujiahe Formation, while T₃X₂, T₃X₄, and T₃X₆ are composed of gray and grayish-white fine-medium-grained sandstone with thin layers of mud and shale, which are the main reservoirs of the Xujiahe Formation [39] (Figure 1b). T₃X₂ in the Anyue area is composed of delta front subfacies deposits; the subaqueous distributary channel and mouth bar microfacies mainly developed in the delta front, interdistributary bay microfacies developed in some areas, and the subaqueous distributary channel and mouth bar are favorable reservoir microfacies (Figure 2).

T₃X₂ is the main gas-bearing reservoir segment of the Xujiahe Formation in the Anyue area, with an average thickness of about 150 m. It can be divided into two sub-members and five sand groups. The first sand group (T₃X₂¹) in the lower part of T₃X₂ can be divided into two layers (T₃X₂^1-1 and T₃X₂^1-2, respectively). The second sand group (T₃X₂²) in the upper part of T₃X₂ can be divided into three layers (T₃X₂^2-1, T₃X₂^2-2, and T₃X₂^2-3, respectively). Influenced by sedimentary facies, the channel sand bodies are interspersed and overlapped vertically, and are widely developed laterally, showing the good horizontal continuity of the sand bodies as a whole. The total thickness of the T₃X₂^1-1 sand body can reach 110 m, with individual layers ranging from 15 to 30 m, and in the T₃X₂^1-2 layer, a set of black shale or carbonaceous mudstone belts with stable thickness and wide distribution developed, while the sand body thickness is relatively thin, about 10 to 15 m. The T₃X₂^2-1 layer contains thin mudstone interlayers, with the sand body thickness ranging from 10 to 20 m. The T₃X₂^2-2 layer features a thick sand body that developed, with a thickness of 15~30 m. The T₃X₂^2-3 layer is similar to the T₃X₂^2-1 layer, also containing a thin mudstone interlayer, but the overall sand body thickness is larger, about 15~30 m (Figure 3).

3. Sample and Method

3.1. Sample

The samples in the study area were collected from the tight sandstone of T₃X₂ in the Anyue area, Sichuan Basin. During this study, 60 core samples were collected from 9 wells, Y5, Y2, Y3, AY2, and Y114. The cast thin section identification, scanning electron microscopy, high pressure mercury injection, and nuclear magnetic resonance experiments were performed on these samples to study the characteristics of tight reservoirs. In addition, routine core test data from the Shunan gas mine of the Southwest Oil and Gas Field Company of Petrochina was collected, including 3637 measurements of porosity, permeability, water saturation, and other parameters.

3.2. Experimental Method

3.2.1. The Cast Thin Section Identification

This was conducted according to the national standard SY/T5368-2016 “Identification of Rock Thin Section” [40]. First, the samples are vacuum-impregnated with a reaction mixture containing epoxy resin, diluent, and hardener to remove the sample gas, and then dried at 50 °C. The blue epoxy resin is injected into the sample at 50 MPa pressure and cured at 60 °C. The sample is then ground into a 30 μm cast sheet using a rock grinder. The stained part of the slice represents the pore structure of the rock surface. Under a polarizing microscope, the rock texture is analyzed by observing the mineral particle size and the contact relationship between minerals, the optical characteristics are analyzed to analyze the cementation characteristics, and the geometry, size, and connectivity of the pore space are analyzed to evaluate the influence of geological factors on the pore type and diagenesis on the pore structure [41].

3.2.2. Physical Property Test

This was conducted according to the national standard GB/T29172-2012 “Core Analysis Methods” [42]. First, the core samples are made into short cylindrical cores with a diameter of 2.54–3.81 cm and a length of 2.54–3.81 cm. Then, the pore volume is measured by the gas expansion method. The core sample is placed in a sealed chamber and filled with helium until the pressure stabilizes, after which the helium is transferred to a known-volume container. When the pressure is stable again, the pore volume is calculated using Boyle’s law based on the initial and final pressure. In addition, the core samples are stored at constant pressure in the core holder, and the permeability is measured by the pressure attenuation method [43].

3.2.3. Scanning Electron Microscope

According to the national standard SY/T 5162-2021 (Rock Sample Scanning Electron Microscope Analysis Method) [44], the instruments used are a dual-probe low-vacuum field-emission scanning electron microscope (FE-SEM) and a hydrogen ion polishing instrument. The field emission scanning electron microscope uses a field emission electron source to produce a high-energy electron beam and focuses the electrons onto the sample surface through a lens system. When the electron beam hits the sample, it generates signals such as reflection, scattering, and secondary electrons, which are collected and converted into images to enable observation and analysis of the surface microstructure of the sample. Before the start of the field emission scanning electron microscope experiment, the sample needs to undergo argon ion polishing and vacuum coating pretreatments. The argon ion precision polishing device uses argon gas to generate an argon ion source through the patented Penning gauge ion gun, and carries out bombardment grinding on the surface of rock or micropore samples. The rock or micropore sample after argon ion polishing has a smooth cross-section, which can be used to observe the reservoir structure of the rock or micropore sample, calculate the quantitative statistics of the reservoir pores, and determine the porosity, etc. The sample size is 10 mm × 10 mm × 4 mm. After the calibration of the field emission scanning electron microscope instrument, nitrogen is injected and the vacuum degree of the sample chamber is unloaded to open the sample chamber, put the sample in, and restore vacuum. After the vacuum value reaches the target, the filament is started. In the imaging process, the real-time working distance (WD), generally ≥ 4 mm, can be obtained under clear focus, and finally, experimental data collection and analysis can be completed [45].

3.2.4. High Pressure Mercury Injection

HPMI is widely used in the study of reservoir pore structure [46]. First, the sample is washed to obtain parameters such as the porosity, permeability, and density. Then, 2–3 g rock samples are dried in an oven at 110 °C. Next, the dried sample is placed in a 1 cubic centimeter dilatometer inside a nitrogen-filled glove box. Finally, the dilatometer is placed into the porosimeter for low pressure degassing, and liquid mercury is injected for the high pressure mercury injection test. This process requires overcoming the capillary pressure generated by the pore throat. In the high-pressure mercury injection experiment, the mercury injection pressure increases, pushing metal mercury from the larger pore throat system into the smaller system. The capillary pressure curve of the sample is plotted by correlating the mercury injection pressure with the amount of mercury injected under each pressure [47].

3.2.5. Nuclear Magnetic Resonance

The experiment was carried out in accordance with SY/T 6490-2007 (Laboratory Measurement Specification for Nuclear Magnetic Resonance Parameters of Rock Samples) [48], and the core magnetic resonance was measured by a MARAN DRX/2 nuclear magnetic resonance core analyzer produced by the Resonance Instrument Company of the United Kingdom. The main operating parameters are as follows: the test temperature is 35 °C, the operating frequency is 2 MHz, and two pulse gradient magnetic fields are equipped. The instrument has the characteristics of a fast test speed, good repeatability, and high signal-to-noise ratio. The basic test parameters of the experiment are as follows: echo interval 0.2 ms, waiting time 6 s, echo number 16,384, and scan times 128. During the experiment, the dry weight, saturated weight, and water weight of the rock sample should first be measured, and then a 10,000 ppm NaCl solution should be configured. The rock sample is evacuated for over 12 h, followed by pressurized saturation with the prepared solution for another 12 h under in situ pressure conditions. Then, the core saturation and centrifugation measurements of the NMR T₂ spectra are analyzed [49,50].

3.2.6. Lower Limit Evaluation of Physical Properties

The lower limit of physical properties is an important parameter for reservoir effectiveness evaluation and resource calculation. There are many previous evaluation methods for the lower limit of physical properties of tight sandstone reservoirs, including the empirical statistical method, maximum pore throat flow radius method, productivity simulation method, single-layer gas test method, cumulative frequency method, bound water saturation method, distribution function curve method, etc. [51,52,53,54]. Based on geological data such as formation testing and physical property analysis, this paper evaluates the lower limit of the reservoir physical properties of T₃X₂ in the Anyue area by combining the experimental statistical method, productivity simulation method, pore–permeability relation method, and minimum flow pore throat radius method, which provides a basis for further fine reservoir classification.

(1)

Bound water saturation method

The bound water saturation method is a method to determine the lower limit of reservoir physical properties through the relationship between bound water saturation and physical properties [54]. The upper limit of water saturation is determined mainly through the gas–water capillary pressure analysis data of the semipermeable baffle method and the gas phase permeability, combined with the relative permeability curve under simulated formation conditions. By determining the upper limit of bound water saturation and establishing the relationship between porosity and bound water saturation, an empirical formula is derived to calculate the porosity lower limit.

(2)

Productivity simulation method

The productivity simulation method is to establish different simulated production pressure differences, ranging from low to high, under the full simulated formation conditions in the laboratory for seepage simulation experiments. On the basis of obtaining unidirectional seepage velocity, this velocity is then converted into daily gas production per well under radial flow conditions, so as to construct the correlation diagram between reservoir physical properties and gas production per well. When the gas production of a single well reaches the industrial gas flow standard, the corresponding physical property condition is the lower limit of effective physical properties of the reservoir [53,54].

(3)

Pore–permeability relationship method

The study of the porous and permeability intersection method shows that the relationship between porosity and permeability generally presents a three-stage formula. The porosity of the first section increases and the permeability slightly increases, indicating that the porosity of the section is poor and the permeability remains nearly unchanged. The porosity of the second section increases and the permeability increases obviously, indicating that the seepage capacity is gradually enhanced. In the third section, with the increase of porosity, the permeability increases sharply, indicating that the seepage capacity is rapidly enhanced [51]. Based on the measured porosity and permeability data of core samples, a porosity–permeability crossplot is drawn to establish the trend curve. The inflection point where permeability begins to increase significantly with the increase of porosity is taken as the lower limit of reservoir physical properties.

(4)

Minimum flow throat radius method

The macroscopic porosity and permeability characteristics of rock reflect the microscopic pore structure and throat size of the rock. Pores and throats of rocks are spaces or channels for oil and gas accumulation and flow. Whether oil and gas can flow out of rocks under a certain pressure difference depends on the size of the throats, that is, the size of the pore throat radius. The smallest pore channel that can store oil and gas and enable oil and gas seepage is called the minimum flow pore throat radius. High bound water saturation is one of the significant characteristics of low-permeability reservoirs. Pores controlled by a smaller than the minimum effective throat are saturated with bound water, and only pores with a radius larger than the bound water film thickness are effective reservoir spaces. Therefore, the water film thickness can be used as the lower limit of the minimum flow pore throat radius [51,53]. After the minimum flow pore throat radius is determined, the lower limit of reservoir physical properties is determined according to the relationship between the pore throat radius and conventional physical property parameters.

4. Result

4.1. Basic Characteristics of Reservoir

4.1.1. Petrological Characteristics

The core and thin section identification results show that the reservoir rocks of T₃X₂ in the Anyue area are mainly medium-grained and fine-grained lithic feldspar sandstones and feldspar lithic sandstone (Figure 4a), with medium to good sorting, sub-angular to sub-circular grinding, and predominantly pore-contact cementation. Calcite intercrystalline cementation is also distributed in segments in each well section, corresponding to low core porosity in general (Figure 3). The content of quartz in the clastic component of the reservoir rock of T₃X₂ is 55–70%, with an average of 65.9%. The feldspar content is 14–20%, with an average of 17.6%. The cuttings consist of metamorphic cuttings, sedimentary cuttings, and extrusive cuttings, and the content is 12.14–24.43%, with an average of 16.82%. The interstitial materials are generally composed of sericite, clay, and other argillaceous matrix, as well as calcareous and siliceous cements. The cementation is mainly composed of calcite and silica, and the content is 2.36–4.23%, with an average of 3.4%. The hetero content was generally 3.24–4.14%, with an average of 3.73%. Some intervals contain 1–2% (mean 1.51%) chlorite cement, forming chlorite ring edges.

4.1.2. Physical Characteristics

The measured physical property data of more than 3637 cores show that the porosity distribution of sandstone in T₃X₂ in the Anyue area is between 0.34% and 11.7%, with an average porosity of 7.53%. The sandstone permeability ranges from 0.000486 to 323 mD, with an average permeability of 0.927 mD. The sandstone porosity of T₃X₂ in the Anyue area is mainly distributed in the range of 6–10%, accounting for 77.51% of the total samples; the samples with porosity greater than 10% account for 6.60% of the total, and the samples with porosity less than 6% account for 15.89% (Figure 4b). Permeability was mainly distributed in the range of 0.01–1 mD, accounting for 87.06% of the total number of samples; samples with permeability greater than 1 mD accounted for only 4.19%, and samples with permeability less than 0.01 mD accounted for 8.74% (Figure 4b). This is a typical low-porosity and ultra-low-permeability reservoir with a wide porosity distribution and strong heterogeneity in the sand body. In general, there is a positive correlation between the porosity and permeability of the reservoir rock in T₃X₂ in the Anyue area, and the permeability increases with the increase of porosity. When the porosity is greater than 11%, the porosity–permeability correlation is stronger, and it has obvious pore type reservoir characteristics. In addition, when the porosity is less than 11%, the pore permeability correlation is poor, and some samples show the characteristics of a low-porosity and high-permeability fractured-porosity reservoir. The distribution of these types of sandstone samples deviate significantly from the positive correlation trend (Figure 4b), and internal fractures developed, which greatly improved the reservoir permeability.

4.1.3. Types and Characteristics of Reservoir Space

Through the macroscopic core observation, combined with the microscopic cast thin section and SEM data analysis, the main storage and permeability spaces in the study area are pores and microcracks, and throat development can be observed in some areas. Among them, pores are the main reservoir space, and micro-fractures are the main seepage channels.

It is found that pore development of different types and sizes can be seen in almost every thin section of the reservoir in T₃X₂ in the Anyue area, except for some samples, which are dense due to calcite bonding and almost no pore development. The pore size is mostly medium to small pores, and the pore types are mainly primary residual intergranular pores, secondary intragranular dissolution pores, and intergranular dissolution pores, while cement, hybrid solution pores, and cast film pores supplement the reservoir space. The residual intergranular pores are triangular or long strips distributed in the contact areas of quartz, feldspar, or hard rock chips, with sizes generally ranging from 2 to 5 μm; these are one of the main pore types in the T₃X₂ reservoir. In general, the residual intergranular pore development interval has a higher face rate, up to 13% (Figure 5a,b). There are obvious traces of dissolution at the edges of intergranular solution pores, which are in various forms, mostly irregular and estuarine shapes, with a size of 2–5 μm, and are one of the main pore types of the T₃X₂ reservoir in the study area (Figure 5e). The intragranular dissolution pores in the particles are mainly those in feldspar grains, and the dissolution pores in the feldspar are mostly distributed along the cleavage direction. When the dissolution is strong, the dissolved feldspar is skeleton-like with a honeycomb residual, with a size of about 1–2 μm, and it is also one of the main pore types of the X2 reservoir in the study area (Figure 5d). The cementation and the solution pores of the hybrid base are micro-networked and peak-shaped, and the edges of the cementation powder and fine crystal calcite are serrated or bay-shaped, and are mainly found in the fine-grained lithic sandstone. These pores are small, between 0.2 and 0.5 μm in size, and are occasionally found in the region as a supplement to the pore space (Figure 5i).

Throats are the narrow and thin parts between pores. The size, distribution, and geometry of the throat not only affect the flow of fluid in the reservoir, but also have a significant impact on the development of oil and gas reservoirs. According to the thin section identification and SEM data, the main types of reservoir throats in T₃X₂ are lamellar throats, constricted-neck throats, and bundle throats. Constricted-neck throats are more developed in reservoirs where sandstone is supported by particles, the contact mode between particles is point contact, and the connectivity is relatively good, and the reservoirs with these types of throats have higher permeability (Figure 5a,b,e,f). Lamellar throats are in a thin shape, so that the pores between particles are connected in a network. With throat widths of 0.1–0.5 μm, their connectivity falls between that of constricted-neck throats and bundle-like throats. These reservoirs developed with more pores between the residual particles (Figure 5a), which is of great significance for the reservoir pore connectivity. Bundle throats are distributed in the shape of crosses and branches, thin and narrow, and usually consist of many small, nearly parallel channels, with a generally small diameter between 0.1 and 0.2 μm, with the worst connectivity, and developed in reservoirs with poor physical properties in line contact and concave–convex contact (Figure 5i).

For the low-porosity and low-permeability sandstone reservoir in the Xujiahe Formation, the degree of fracture development plays an important role in improving reservoir permeability and single well productivity. Logging, mud logging, and core data show that the Xujiahe Formation of the Anyue gas field has a flat structure and large scale faults are not developed, and the fractures are relatively developed near some small highs and faults. According to the core observations of 13 coring wells, there are 403 fractures, which can be divided into two types of fractures: structural fractures and interlayer fractures. Most of the interlayer fractures are near-horizontal fractures filled with argillaceous carbon, and normally develop along the bedding plane. The structural fractures include low-angle, medium-angle, high-angle, and near-horizontal fractures. The core-observed fracture lengths range from 5 to 15 cm, and the fracture width is mainly less than 3 mm, which is mostly filled by quartz and calcite (Figure 6d–f). Combined with the crack identification results of imaging logging, the E–W strike fractures of T₃X₂ in the Anyue area are the most developed, and the type is mainly medium-angle structural fractures, and the fractures are mainly half-filled, followed by fully filled, with relatively few unfilled (Figure 6a–c). Microcracks under the microscope generally appear as dendritic bifurcated cracks that pass through multiple particles or develop along the edges of mineral particles and cut rock fabric. The width of the cracks varies from 0.01 to 0.05 mm. In some slices, intragranular pressure cracks formed by rigid particles such as quartz due to strong compaction can be observed (Figure 5c,d).

4.1.4. Pore Structure Characteristics

The pore throat structure refers to the size, connectivity, and matching relationship of pores and throats. The pore determines the reservoir capacity, and the throat controls the seepage capacity of the pore. HPMI and NMR experiments are usually used to evaluate the pore structure of the reservoir, and the experimental results can reflect the pore–throat connectivity and pore–throat distribution characteristics of tight sandstone reservoirs [55,56]. In this paper, HPMI experiments were carried out on a total of 60 samples, and 4 samples were selected for NMR experiments to characterize the overall pore structure of the studied interval (Figure 7). Combined with the characteristics of the mercury injection curve (Figure 7a) and the analysis of mercury injection parameter data (

Table 1. HPMI and NMR parameters.

Sample Number	Depth (m)	Physical	Property	NMR			HPMI
		Por (%)	Perm (mD)	T2cutoff (ms)	Swi (%)	Swm (%)	Pd (Mpa)	SHg-max (%)	RP-t-avg (μm)	Rmax (μm)	P50 (Mpa)	R50 (μm)	WE (%)
Y3-25	2275.0	7.2	0.0511	41.6	85.13	14.87	1.371	77.24	0.152	0.536	8.70	0.084	31.48
Y112-5	2442.5	8.2	0.1090	80.31	86.38	13.62	0.672	81.89	0.140	1.094	8.61	0.085	33.60
Y3-22	2280.2	7.6	0.3690	33.40	65.28	34.72	0.30	82.72	0.485	2.481	1.87	0.393	30.63
Y113-3	2288.1	8.5	15.1000	17.30	57.54	42.46	0.138	83.88	0.661	5.337	2.59	0.284	45.80

Annotation: “Por” represents porosity; “Perm” represents permeability; “T₂cutoff“ represents the T₂ cutoff value; “Swi” represents the nuclear magnetic resonance irreducible water saturation; “Swm” represents the movable fluid saturation; “P_d“ represents the displacement pressure; “S_Hg-max” represents the maximum mercury saturation; “R_P-t-avg” represents the average pore–throat radius; “R_max” represents the maximum connected pore–throat radius; “P₅₀” represents the median pressure; “R₅₀” represents the median radius; and “WE” represents the mercury withdrawal efficiency.

), the mercury injection curve has two forms: concave and convex. The drainage pressure in the study area ranges from 0.138 to 4.123 MPa, with an average of 1.121 MPa, and the maximum communication radius of a pore–throat ranges from 0.178 to 25.282 μm. The average value is 1.264 μm, the displacement pressure varies widely, and the reservoir heterogeneity is strong. The median pressure is between 0.965 and 107.497 MPa, with an average value of 9.998 MPa; the median radius ranges from 0.007 to 0.577 μm, with an average value of 0.135 μm; and the mean radius ranges from 10.32 to 14.20 μm, with an average value of 11.78 μm. According to the classification level of throats, this belongs to the fine-micro throat classification. The separation coefficient varies from 1.465 to 3.209, with an average of 2.192, and the coefficient of variation is between 0.138 and 1.783, with an average of 0.233, indicating that the pore–throat separation was medium and the distribution was relatively concentrated. The mercury removal efficiency ranges from 28.358% to 47.996%, with an average of 35.733%, and the pore–throat connectivity is good.

The NMR test results show (Figure 7b–e) that the NMR T₂ spectrum has two types: unimodal and bimodal. The Y3-25 and Y3-22 samples are unimodal, and Y112-5 and Y113-3 samples are bimodal. The NMR T₂ spectrum can indirectly reflect the pore size distribution; each relaxation time represents the pore size of a scale, and the longer the relaxation time, the larger the pore size. According to the relaxation time of the T₂ spectrum, the pores can be divided into three categories: micro pores (T₂ < 10 ms), medium pores (10 ms ≤ T₂ ≤ 100 ms), and large pores (T₂ > 100 ms). The peak value of unimodal sample Y3-25 is distributed in the range of 1–10 ms, and micro pore–throats are dominant, and the pore permeability is low. The peak value of Y3-22 is distributed in the range of 10–100 ms, mainly medium pore–throats, and the permeability is relatively high. The peak value of bimodal samples is high on the left and low on the right, indicating that the pore type is mainly small pore–throats and relatively few large pore–throats. The T₂ spectrum parameters after centrifugation can be used to obtain the occurrence characteristics of the movable fluid of the sample, indirectly reflecting the heterogeneity and connectivity of the pore–throat. After centrifugation, the fluid in a larger pore–throat is thrown out, while the bound fluid is mainly distributed in a small pore–throat. The greater the difference in peak area of the two T₂ spectra before and after centrifugation, the higher the saturation of the movable fluid. The movable fluid saturation of the four samples ranges from 13.62 to 42.46% (Table 1), and the occurrence characteristics of the movable fluid has a certain correlation with the pore–throat structure. The movable fluid saturation of Y3-22 and Y113-3 is higher, the pore–throat is relatively large, and the pore–throat connectivity is better.

To sum up, the pore structure of the reservoir in T₃X₂ in the Anyue area is dominated by small and medium pore–throats, the sorting is medium, the pore–throat connectivity is different, and the pore structure is highly heterogeneous.

4.1.5. Lower Limit of Reservoir Physical Properties

Based on geological data such as formation testing and physical property analysis, this paper evaluates the lower limit of physical properties of the reservoir in T₃X₂ in the Anyue area by the experimental statistical method, productivity simulation method, pore–permeability relationship method, and minimum flow pore–throat radius method.

The upper limit of bound water saturation of the tight sandstone reservoir in the study area was determined by the bound water saturation method to be 55%. The relationship between porosity and bound water saturation was established. The empirical formulas are as follows:

Sw = −1.1487 lnΦ + 6.0828

(1)

lnSw = −0.3598 lnK + 3.1571

(2)

In Formulas (1) and (2), Sw is water saturation (%), Φ is porosity (%), and K is permeability (mD).

According to the relationship between water saturation and porosity, when the water saturation is 55%, the corresponding porosity is 6.3%. Therefore, the lower limit of porosity is 6.3% (Figure 8a,b).

Based on the productivity simulation method, this paper simulated the relationship between gas production and the porosity and permeability of a 15 m reservoir under different production pressure differences, under the formation conditions of the T₃X₂ gas reservoir in the Anyue gas field, and further established the relationship between gas production and porosity and permeability under a 5 MPa production pressure difference of a 15 m reservoir on this basis:

lnQ = 1.6165 lnK + 3.5215

(3)

lnQ = 1.3202 ln(Φ × K) + 0.1511

(4)

In Formulas (3) and (4), Q is the gas production of a 15 m reservoir under a production pressure difference of 5 MPa (m³), Φ is porosity (%), and K is permeability (mD).

The lower limit of the effective reservoir porosity can be obtained by substituting the lowest industrial gas flow standard of 5000 m³ in the gas reservoir (Figure 8c,d).

In the pore–permeability intersection method, the inflection point at which permeability begins to increase significantly with the increase of porosity on the pore–permeability intersection diagram is taken as the lower limit of reservoir physical properties. According to the pore–permeability intersection diagram, the inflection point at which the porosity relationship changes significantly between Members 1 and 2 is observed, and the corresponding porosity is 7%. It is considered that 7% porosity can be taken as the lower limit of physical properties of tight sandstone reservoirs in T₃X₂ in the Anyue area (Figure 8e).

The minimum flow pore–throat radius method is used to determine the lower limit of reservoir physical properties. The average water film thickness of the core samples of the T₃X₂ reservoir in the Anyue gas field is 0.0744 μm, so the minimum gas throat radius of the T₃X₂ reservoir is 0.0744 μm. By bringing the minimum gas-bearing throat radius into the relation between the porosity and median throat radius, the lower limit of the reservoir porosity of T₃X₂ in the Anyue area can be obtained as 6.5% (Figure 8f).

Based on the analysis of various methods, 7% porosity is taken as the lower limit of the physical properties of the reservoir in T₃X₂ in the Anyue area.

4.2. Reservoir Classification

According to the differences in physical properties, pore–throat types, and pore–throat structures of the T₃X₂ reservoir, the reservoir can be divided into four categories (Figure 9). The porosity of a Type I reservoir is >11%, the permeability is >0.2 mD, the pore type is mainly residual intergranular pores, followed by intra-granular dissolution pores with a few intergranular dissolution pores, the main throats are constricted-neck throats, the mercury injection curve is concave, the pore–throat radius is large, the distribution is uniform, and the connectivity is good. The lithology is mainly medium sandstone and the reservoir type is porous, which is the most favorable reservoir target. The porosity of a Type II reservoir is 7–11%, the permeability is >0.2 mD, the pore types are mainly intragranular dissolution pores with a few intergranular dissolution pores, micro-fractures are very developed, the throat development is poor, the types are mainly lamellar throats and constricted-neck throats, the mercury injection curve is concave, the pore–throat radius is large, the distribution is more uniform, and the connectivity is good. The lithology is mainly medium sandstone and the reservoir type is the fracture-pore type, which is a favorable reservoir target. The porosity of a Type III reservoir is 7–11%, the permeability is 0.04–0.2 mD, and the pore types are mainly intergranular dissolution pores, followed by intragranular dissolution pores, and a few residual intergranular pores. The throats are mainly constricted-neck throats and lamellar throats, and some fractures can be seen. The mercury injection curve is concave, the pore–throat radius is small, the sorting is relatively poor, the distribution is uniform, and the connectivity is relatively good. The lithology is mainly medium sandstone, with a small amount of fine sandstone, the reservoir type is mainly the fracture-pore type, and the reservoir quality is poor. The porosity of a Type IV reservoir is <7%, the permeability is < 0.04 mD, and a small number of intergranular and intragranular dissolution pores are developed. The throats are mainly bundle-shaped, the throats and fractures are less developed, the mercury injection curve is convex, the pore–throat radius is small, the sorting is poor, and the connectivity is poor. The lithology is mainly medium-fine sandstone, which cannot be used as an effective reservoir (

Table 2. Characteristics of the different types of reservoirs.

Reservoir Classification		Type I	Type II	Type III	Type IV
Reservoir type		Pore type	Fracture-pore type		Ultra-tight type
Physcial properties	Porosity (%)	>11	7~11	7~11	<7
	Permeability (mD)	>0.2	>0.2	0.04~0.2	<0.04
Rore structure	Main pore type	residual intergranular pore	Intragranular dissolved pore	Intergranular dissolved pore	dissolved pore
	Seepage channel	constricted-neck and laminar throat	micro-fracture	micro-fracture and constricted-neck	tubular-bundle throat
High-pressure mercury injection curve
Microscopic characteristics

).

5. Discussion

5.1. Formation Mechanism of Tight Sandstone Reservoir

The development of a tight sandstone reservoir is the result of the comprehensive action of many geological factors. Sedimentation, diagenesis, and tectonism are the main factors controlling the development of reservoir quality. However, factors such as abnormal high pressure, oil and gas charging, and the geothermal field indirectly affect the reservoir quality by influencing the diagenetic evolution process of the reservoir [57,58]. In the process of diagenetic evolution, the reservoir of T₃X₂ in the Anyue area is relatively stable in structure, the structural uplift occurred in the late Cretaceous diagenetic stage B, and the reservoir micro-fractures developed, which played a certain role in improving the reservoir quality. This article mainly studies the controlling effects of sedimentary, diagenetic, and tectonic activity intensities on the reservoir in T₃X₂ in the Anyue area from aspects such as the sedimentary microfacies, sandstone grain size, content of mineral particles, types and contents of cements, hydrocarbon-generating fluids, fracture development, and the relationship between fractures and faults. It aims to clarify the formation mechanism of tight sandstone reservoirs.

5.1.1. Sedimentation

Sedimentation controls the formation of reservoir materials, and factors such as clastic particle composition, particle size, sorting, grinding, and impurity content not only determine the size of the original porosity of rocks, but also affect the diagenesis and physical evolution process during reservoir burial [59]. Tight sandstone reservoir deposition is controlled by many factors, including the parent material source, distance and direction of the source, sedimentary environment, and hydrodynamic conditions. The composition and structure of the parent rock determine the initial characteristics of the clastic material, and then affect the petrological characteristics and reservoir performance of the sandstone. The provenance distance has significant influence on the granularity and sorting of sediments. The sedimentary environment affects the mineral particle size, sorting, and roundness of the reservoir, which further affects the distribution and physical properties of the reservoir. Hydrodynamic conditions directly affect the sediment transport and deposition process, and the change of hydrodynamic conditions leads to the vertical and horizontal heterogeneity of sand bodies, which affects the connectivity and permeability of the reservoir [60]. The provenance of the tight sandstone in T₃X₂ in the Anyue area is mainly from the orogenic belt around the basin, and the parent rock types include granite, metamorphic rock, and sedimentary rock. The weathering products of different parent rocks provide a rich variety of clastic materials, such as granite weathering providing a large number of quartz and feldspar particles. The debris composition includes metamorphic rock fragments, sedimentary rock fragments, and extrusional rock fragments. The interstitial material is generally composed of hydromica, clay, and other hybrid bases, and calcareous and siliceous cements, which are the main components of sandstone.

The results of core and thin section identification show that the reservoir rocks of T₃X₂ in the Anyue area are mainly medium-grained and fine-medium-grained lithic feldspar sandstone and feldspar lithic sandstone. The sorting is medium to good, the grinding is sub-angular to sub-round, and most of them are pore-contact cementation. In the study area, there are multiple source directions in the reservoir of T₃X₂ in the Anyue area, and materials in different source directions mix with each other, which enhances the heterogeneity of the reservoir. The sedimentary facies are subfacies of a delta front, mainly developed subaqueous distributary channel and mouth bar microfacies, and in some areas, developed interdistributary bay microfacies. The microfacies of the subaqueous distributary channel and mouth bar are favorable reservoir microfacies (Figure 10a). The sand body size is mainly medium-grain, the sorting is relatively good, the reservoir porosity and permeability are high, and the reservoir has good reservoir performance. Sedimentary differences lead to different types of reservoir mineral particle types, content, and particle size (Figure 10b–f). Statistical analysis of the mineral particle content and rock particle size of different types of reservoirs shows that the rock particle size of a Type I reservoir is mainly medium, with the content of medium particles up to 95%, and contains a small amount of fine-grained sandstone. The quartz content ranges from 57 to 67.2%, with an average content of 60.475, the feldspar content ranges from 14 to 29.5%, with an average content of 19.95, the debris content ranges from 8.6 to 17.9%, with an average content of 13.85%, and the mica content is less, about 0.3–1%, with an average content of 0.675%. The rock granularity of a Type II reservoir is mainly medium-grained, with the content of medium-grained sandstone about 73%, followed by 27% fine-grained sandstone, a quartz content in the range of 58.4~73.8%, with an average content of 64.696%, a feldspar content of 7.6~24.4%, with an average of 15.663%. The content of rock fragments is between 6.8 and 22.4%, and the average content is 14.002%, and the mica content ranges from 0 to 3.5%, and the average is 0.333%. In Type III reservoirs, medium-grained sandstone is the main particle size, accounting for 76%, followed by coarse-grained sandstone, and fine-grained sandstone is less, accounting for only 3%. The quartz content ranges from 44 to 74.4%, with an average content of 65.363%, the feldspar content ranges from 3.7 to 32.2%, with an average content of 16.851%, the debris content ranges from 6.4 to 28.2%, with an average content of 12.604%, the mica content is 0.1–2.5%, and the average mica content is 0.508%. The sandstone size of a Type IV reservoir is mainly fine-grained, followed by medium-grained sandstone, in addition to a small amount of siltstone, the quartz content is distributed in the range of 42.8~76%, with an average of 64.350%, the feldspar content to mineral content is between 4.8 and 38%, with an average of 13.685%, the rock fragment content is between 4.3 and 26.3%, with an average of 12.894%, and the mica content is higher, ranging from 0 to 4.5%, and the average is 0.758%. Comprehensive analysis of the four types of the reservoir clastic particles’ content and overall performance, reveals, for the quartz content, Type III > Type II > Type IV > Type I; for the feldspar content, Type I > Type II > Type III > Type IV; for the lithic content, Type II > Type I > Type IV > Type III; and for the mica content, Type IV > Type I > Type III > Type II. The composition and particle size of mineral detrital particles have certain effects on the strength of diagenetic compaction, formation of cement, and dissolution, and sedimentation affects the subsequent diagenesis.

5.1.2. Diagenesis

Diagenetic Types and Facies

Through the observation and analysis of cores, cast thin slices, and the scanning electron microscope, the reservoir of T₃X₂ in the Anyue area mainly experienced diagenesis such as compaction, cementation, and dissolution. Compaction and cementation reduce the porosity and permeability of the reservoir, which belongs to destructive diagenesis and is the main cause of reservoir densification. Dissolution and fracture are constructive diagenesis, which play a role in increasing reservoir porosity and permeability, and are conducive to the formation of relatively high-quality reservoirs in a tight sandstone background [61]. The reservoir of T₃X₂ in the Anyue area has experienced the syndiagenetic stage, early diagenetic stage, and middle diagenetic stage A, and is currently in the middle diagenetic stage B. Diagenetic processes of multiple types and stages play an important role in reservoir formation [31].

In the process of reservoir formation in T₃X₂ in the Anyue area, compaction is dominant, and the overall compaction is relatively strong. Mechanical compaction is the main influencing factor of porosity reduction [62], which begins in the late Triassic syndiagenetic stage and is strongest at the end of the early diagenetic stage A of the early Jurassic. Under the microscope, it shows point contact and line contact between particles, concave and convex contact can be seen in some tight reservoirs, particles are closely arranged, and extrusion deformation such as mica and plastic cuttings can be seen. The internal cracking of rigid quartz particles and quartz cuttings formed microcracks in grains (Figure 11). After the early diagenetic stage A, with the increasing of burial depth, mechanical compaction weakened and gradually changed into pressure dissolution. In the process of pressure dissolution, SiO₂ produced by the dissolution of quartz particles precipitates as cement to form a secondary enlarging edge of quartz, which reduces the porosity of the reservoir.

The cement types in the reservoir of T₃X₂ in the Anyue area are mainly siliceous and carbonate, followed by chlorite and illite. There are two stages of siliceous cementation observed in the cast sections. The first stage of siliceous cementation is the secondary increase of quartz, which develops in the early diagenetic stage B. The siliceous cementation mainly comes from the pressure dissolution of quartz particles. The second stage of siliceous cementation includes secondary quartz edge cementation and authigenic quartz particle filling pores, and the siliceous material mainly comes from the dissolution of mineral particles. The average content of siliceous cement is about 3.3%, occupying pore space, resulting in reduced porosity and poor physical properties of the reservoir (Figure 11b). The carbonate cementation in the study area is mainly calcite cementation, and a small amount of red-colored calcite cementation can be observed on the thin sections of the cast body. In some ultra-tight reservoir sections, calcite intercrystalline cementation can be seen to fill pores (Figure 11e,i). Because the Xujiahe formation in Anyue is a coal measure formation, the formation water is acidic, resulting in less carbonate cementation in the early stage. In the late A stage of middle petrogenesis, the water medium began to change to alkaline, so late calcite is relatively common [63]. Late carbonate cements are mostly filled with intragranular dissolution pores in feldspar; the average content is 3.5%, and the volume fraction of intergranular cemented calcite can reach 10%. The carbonate cements occupy certain pore space and reduce the reservoir physical properties. In addition to siliceous and carbonate cementation, clay mineral cementation such as chlorite and illite cementation is also common (Figure 11c), which is filled in intergranular pores in the form of sheet and filigree. Chlorite is also usually cemented in the form of pore liner, forming chlorite ring edges on the particle surface, which reduces the reservoir physical properties. However, chlorite ring edges can inhibit the development of a quartz secondary widening edge, and at the same time, it plays an anti-compaction role and reduces the porosity reduction of compaction and cementation, so reservoirs with developed chlorite rims have well-developed residual intergranular pores.

Under the microscope, it is found that dissolution of the reservoir in T₃X₂ is common, mainly in feldspar dissolution, followed by the dissolution of rock fragments. A large number of ingrain and intergrain dissolution holes can be seen, and mold holes can be seen in some sections (Figure 11a,f). The dissolution occurs mainly after oil and gas charging, and is most intense at the end of the middle diagenetic stage A, and the acidic fluid generated by hydrocarbon generation is the main reason for the dissolution [64]. The dissolution in the study area is dominated by the dissolution of feldspar, followed by the dissolution of rock fragments. The organic acid produced by hydrocarbon generation reacts with CO₂ and feldspar to produce a large amount of SiO₂ and K⁺, which is conducive to the precipitation of late quartz cement. Meanwhile, under K⁺ rich conditions, the unstable kaolinite produced by feldspar dissolution is easy to transform into illite [65], so no kaolinite can be seen under the microscope, but illite cement can be seen. Dissolution generally increases the pore space of the reservoir and is the main constructive diagenesis.

Diagenetic facies are the synthesis of the diagenetic environment and diagenetic minerals in the diagenetic environment, that is, the sum of petrological, geochemical, and petrophysical characteristics reflecting the diagenetic environment. They are a direct manifestation of diagenesis, tectonism, and sedimentation which directly determine the form and content of diagenesis. Through diagenetic analysis, synthetic diagenetic facies are divided into single factor diagenetic facies corresponding to each diagenesis, and used to analyze the influencing factors of structure and sedimentation. On this basis, synthetic diagenetic facies are divided by superposition [66,67,68]. Observing the cast thin sections, the strengths of diagenesis of different types of reservoir are different, mainly reflected in the contact relationship between mineral particles, the type of pore space, the size and structure of pores, the type and content of cement, and the development of micro-fractures. According to the different diagenetic intensity, the tight sandstone reservoirs in T₃X₂ in the Anyue area can be divided into five diagenetic facies, which are weak compaction facies, micro-fracture facies, unstable dissolution facies, compact-dense facies and carbonate cementation facies (Figure 12).

The weak compacted mineral particles show point-line contact, chlorite ring cementation is developed, diagenetic compaction and quartz secondary enlargement are inhibited, residual intergranular pores and constricted-neck throats are developed, the pore reduction due to compaction is 22.16%, and the compaction effect is weak. In addition to the secondary increase of quartz, the pores are filled with authigenic quartz particle cementation, a small amount of illite cementation, and almost no carbonate cementation; the pore reduction due to cementation is 7%, and the cementation strength is moderate. A small number of intragranular and intergranular dissolution pores of feldspar and rock fragments can be seen, with an average dissolution-induced pore increase of 4.82%, indicating a relatively moderate dissolution effect. Micro-fractures are not well-developed in this type of reservoir. The mineral particles of the micro-fracture facies are mainly in linear contact, and the residual intergranular pores are not developed. The throat development is relatively poor, and the types are mainly lamellar throats and constricted-neck throats. The pore reduction due to compaction is 33.31%, and the compaction effect is relatively strong. The carbonate cement and authigenic quartz particles are developed, the pore reduction caused by cementation is 4.5%, and the cementation effect is relatively weak. The dissolution pores are generally developed, mainly in the particles, and the dissolution pores increase by 5.18%, so the dissolution effect is strong. Micro-fracture development can be observed in the thin sections. In the unstable solution facies, the particles are in linear contact, with a few residual pores. The throats are mainly constricted-neck throats and lamellar throats, and under the force compaction, the porosity is reduced by 31.1%. Siliceous cementation is predominant, the average pore reduction due to cementation is 4.90%, and the cementation is relatively weak. Intergranular dissolution pores are the main pore space, followed by intragranular dissolution pores, which can increase the porosity by 6.24%, and the dissolution effect is strong. The development of micro-fractures can be seen in some sections. The compact-dense facies are affected by force compaction, the porosity is greatly reduced, the mineral particles are in line or concave–convex contact, with almost no residual intergranular pores, the throats are mainly tube bundles, the throat and fracture development degrees are low, plastic minerals are strongly deformed by extrusion, the pore reduction due to compaction is 34.42%, showing a strong compaction effect, the content of cementing substances is low, and the pore reduction caused by cementation is only 3.25%, indicating that the cementation effect is weak. A small number of intergranular and intragranular pores are developed, and the dissolution effect is relatively weak, with a pore increase of 3.36%. In the carbonate cementation facies, the early calcite cementation filled the primary pores and inhibited compaction, the particles are in point-line contact, and the compaction is relatively weak, reducing pores by 24.32%. A large number of calcite intergranular cementation results in 14% porosity reduction and strong cementation. The pore type is mainly a small number of corrosion pores, and the dissolution effect is relatively weak, with a pore increase of 4%.

In conclusion, the main diagenetic characteristics of the weak compaction facies are weak compaction, medium cementation, and medium dissolution. The micro-fracture facies show relatively strong compaction, relatively weak cementation, medium dissolution, and intense fracturing. The unstable dissolution facies are characterized by relatively strong compaction, relatively weak cementation, and strong dissolution. The diagenetic characteristics of the compact-dense facies are mainly strong compaction, followed by weak cementation and weak dissolution. The diagenesis of the carbonate cementation facies is characterized by relatively weak compaction, strong cementation, and relatively weak dissolution.

Compaction

Compaction is an important mechanism causing the decrease of primary intergranular pores in tight sandstone reservoirs and the key to reservoir densification. Generally, rigid particles of sedimentary debris, such as quartz and feldspar, have a strong resistance to the pressure brought by overlying strata during the later diagenesis, which enables the preservation of the original pores, while plastic mineral particles are easy to be compacted and deformed and have weak compaction resistance, which is not conducive to the preservation of the original pores and the development of secondary pores [69]. The reservoir in T₃X₂ has experienced a long burial depth, the maximum burial depth is up to 4600 m, and the study area has suffered strong compaction, and the point-line contact between particles and the extrusion deformation of mica, plastic rock fragments, and other particles can be observed under the microscope. However, in the process of diagenetic evolution, due to the influence of rigid minerals such as quartz, feldspar, plastic minerals, and early chlorite cementation, there is a differential compaction phenomenon in the target interval of the study area. The pore reduction range of the reservoir in T₃X₂ is between 22 and 35%, and the pore loss rate caused by compaction is 55.4–86.05%. The pore reduction of cementation is 3.25–14%, and the pore loss rate is 8.13–35%. The original pore loss rate caused by compaction is obviously higher than that caused by cementation, so compaction is the main factor causing the reservoir densification in T₃X₂ in the Anyue area. Rigid particles such as quartz and feldspar can inhibit the compaction of the reservoir and protect the primary pore–throat, while plastic particles mainly developed in the study area, such as mica, mudstone debris, and phyllite debris, will have strong plastic deformation under continuous formation pressure, crowding the pore space between the primary particles, blocking the throats, and degrading the reservoir physical properties.

Statistically analyzing the composition of detrital grains in the reservoirs of T₃X₂ in the Anyue area, and conducting an analysis in combination with the cast thin sections, the higher the content of rigid minerals such as quartz and feldspar, the weaker the compaction effect, and the higher the content of plastic debris and mica, the stronger the compaction effect. According to the statistical results in Figure 10, the rigid mineral content of quartz and feldspar in Type I reservoirs ranges from 72.9 to 86.5%, with an average content of 80.425%, and the plastic mineral content of rock fragments and mica is 8.9 to 20.8%, with an average of 14.525%. The rigid mineral content of Type II reservoirs ranges from 73.1 to 88.5%, with an average of 80.359%, and the plastic mineral content ranges from 7 to 22.9%, with an average of 14.335%. The total content of rigid minerals in Type III reservoirs is 60.3~90.5%, with an average content of 82.214%, and the content of plastic minerals is 6.6~30.7%, with an average content of 13.111%. The rigid mineral content of Type IV reservoirs ranges from 53.2 to 93.8%, with an average of 78.035%, and the plastic mineral content ranges from 4.5 to 29%, with an average of 13.652%. The contents of rigid and plastic minerals in various reservoirs were compared. The content of rigid minerals can be ordered as Type III > Type I > Type II > Type IV, and the content of plastic minerals can be ordered as Type I > Type II > Type IV > Type III (Figure 10e,f).

From the perspective of the clastic particle structure, the sandstone particle size has a certain control effect on the primary porosity and mechanical compaction process of the reservoir. The more uniform the particle size, the stronger the anti-compaction effect of the reservoir [70]. According to the statistical findings of the clastic particle size in the study area (Figure 10b), the graininess of Type I, Type II, and Type III reservoirs is mainly medium-grained, with a small amount of fine-grained and coarse-grained sandstone; the rock granularity of Type I reservoirs is almost only medium-grained sandstone. The rock granularity of Type II reservoirs is mainly medium-grained, followed by fine-grained sandstone. In Type III reservoirs, in addition to medium-fine-grained sandstone, a small amount of coarse sandstone is also developed. Type IV reservoirs are mainly fine-grained sandstones, and siltstones are also developed.

Cementation

Cementation is another important diagenetic factor leading to the densification of a sandstone reservoir. The porosity reduction in cementation ranges from 3.25 to 14%, and the pore loss rate of cementation ranges from 8.13 to 35%. Siliceous and carbonate cementation are the main types of cementation developed in T₃X₂ in the Anyue area. In addition, chlorite rim cementation can be observed in Type I reservoirs. Siliceous cementation is common in the study area, and two stages of siliceous cementation can be observed in the cast thin sections. The first stage is in the form of quartz with enlarged edges, and the second stage is mainly in the form of authigenic quartz particles. There are also two stages of carbonate cementation. Late carbonate cementation is rare and mainly filled with feldspar dissolution pores. Only in some Type IV reservoirs can the early calcite intergranular cementation be observed. The cementation content of clay minerals is relatively small, is dominated by chlorite in the early stage, and is wrapped in the form of a chlorite ring edge, which inhibits the formation of an early quartz secondary enlarging edge and the intensity of compaction, and protects the primary pores. The weak compaction effect of Type I reservoirs is related to the development of chlorite ring edges. In Type IV reservoirs where calcite intergranular cementation is well-developed, the content of carbonate cement is much higher than that in other Type IV reservoirs, so the content of carbonate cements in Type IV reservoirs is divided into two categories: high carbonate cements and low carbonate cements. According to the statistical diagram of cement content (Figure 13a,b) and the analysis of cast thin sections, the higher the cement content, the greater the cementation strength and the higher the pore loss rate. The average total cement content of a Type I reservoir is 3.15%, Type II reservoir is 1.867%, and Type III reservoir is 1.701%. In Type IV reservoirs, the content of low carbonate cements is 2.215%, and the content of high carbonate cements is up to 30%, with an average content of 30.04%. The content of siliceous cements in Type I, II, and III reservoirs is higher than that of carbonate cements, while the content of siliceous cements in Type IV low carbonate cements is similar to that of carbonate cements, and the content of carbonate cements in Type IV high carbonate cements is much higher than that of siliceous cements.

Dissolution

The cast thin sections show that the dissolution of T₃X₂ in the Anyue area is mainly manifested as the dissolution of feldspar and other soluble minerals, and the dissolution pore types are mainly intergranular and intragranular pores. The content of soluble minerals in the reservoir is one of the factors affecting the dissolution intensity. The study shows that the peak of the dissolution in T₃X₂ is at the end of the middle diagenetic stage A, that is, after the first hydrocarbon generation peak, so the acidic fluid generated by hydrocarbon generation is another key factor affecting the dissolution. Strong acidic dissolution of feldspar and rock fragment particles is the main factor improving the reservoir quality in in T₃X₂ in the Anyue area. The large amount of acidic fluid generated during the thermal evolution of the source rock in the study area is a favorable condition for the dissolution of feldspar particles. With the increase of the formation burial depth, the rise of the ground temperature, and the gradual maturation of organic matter, a large amount of organic acids and hydrocarbons were generated under the action of thermal degradation. After the production peak of organic acids and hydrocarbons, feldspar underwent acid washing again, the dissolution degree was further enhanced, the dissolution holes were increased, and even mold pores can be observed. The dissolution process began in the late Jurassic and was a long-lasting process, and the reservoir physical properties improved with the development of the dissolution pores. Different types of reservoirs have different soluble mineral particle content, resulting in certain differences in dissolution intensity. According to the mineral content statistical diagram and box diagram (Figure 10c,d), the total soluble mineral content of a Type I reservoir is 33.8%, Type II reservoir is 29.665%, and Type III reservoir is 29.455%. The total content of soluble minerals in a Type IV reservoir is 26.579%. Through comprehensive analysis, the content of soluble minerals in the four types of reservoirs shows the following order: Type I > Type II > Type III > Type IV. By observing the cast thin sections, it is found that the dissolution pores in Type III reservoirs are the most developed. Therefore, there is not a completely linear correlation between the dissolution intensity and the content of dissolution minerals.

In summary, reservoir compaction is related to the content of rigid minerals such as quartz and feldspar, and plastic minerals such as rock fragments and mica. The cementation strength is mainly controlled by the content of carbonate cement, and the dissolution strength is mainly affected by soluble minerals and hydrocarbon-generating acidic fluids. The content of rigid minerals can be ordered as Type III > Type I > Type II > Type IV, the content of plastic minerals can be ordered as Type I > Type II > Type IV > Type III, the content of cement as a whole can be ordered as Type IV > Type I > Type II > Type II > Type IV, and the content of soluble minerals can be ordered as Type I > Type II > Type III > Type IV. Combined with the analysis of cast thin sections, the content of rigid and plastic minerals in Type I reservoirs is relatively high. Due to the influence of chlorite rim cementation, the compaction and secondary increase of quartz are inhibited, showing weak compaction and medium cementation, fewer dissolution pores under the microscope, and the dissolution action is relatively weak, corresponding to the weak compaction facies. Type II reservoirs have low rigid mineral content, relatively high plastic mineral content, and weak compaction resistance, which are manifested as relatively strong compaction, low cement content, weak cementation, and high soluble mineral content. Many dissolution pores and micro-fractures are observed under the microscope, and the dissolution effect is strong, corresponding to micro-fracture facies. In Type III reservoirs, the particles are in line contact with each other under the microscope, the compaction is relatively strong, the cementation content is low, and the cementation is relatively weak. The pore type is dominated by dissolution pores, showing strong dissolution characteristics and belonging to the unstable dissolution facies. Type IV reservoirs are divided into two categories: one is a carbonate cementation facies with a high content of carbonate cements, strong cementation, point-line contact between particles, weak compaction, little soluble mineral content, and underdeveloped dissolution pores; the other is a reservoir with linear and concave–convex contact between particles, strong compaction, a small number of dissolution pores, and relatively weak dissolution, corresponding to compact-dense facies.

5.1.3. Tectonism

Structural fractures play a key role in increasing permeability and forming fractured tight sandstone reservoirs. In general, permeability is positively correlated with fracture development, indicating that the fracture network caused by the matching of macroscopic and microscopic fractures greatly improves the permeability of tight sandstone reservoirs. It is important to study the main controlling factors affecting fracture development in tight sandstone reservoirs. Imaging logging of T₃X₂ in the Anyue area shows that the fractures in the reservoir are mainly in the E–W direction, followed by the NW–SE and NE–SW trends, which are basically consistent with the fault trends, indicating that the fractures in the study area are mainly controlled by faults (Figure 14a). Moreover, the fracture angle, density, and filling degree are correlated to the fault scale and fault–fracture distance (Figure 14b–e). The fracture density associated with the first and second class faults is significantly negatively correlated with the fault–fracture distance. With the increase of the fault–fracture distance, the fracture density gradually decreases. The fracture density is higher within 200 m distance from the fault, and the fracture density controlled by the larger class of faults is greater than that controlled by the smaller class of faults (Figure 14b,c). The angle of the fault is also correlated with the distance of the fault–fracture. The closer the distance is, the more the middle- and high-angle fractures develop (Figure 14d). The fractures in the study area are mainly half-filled and full-filled, and the fractures of various filling degrees tend to decrease with the increase of the fault–fracture distance (Figure 14e). Type II reservoirs are the main fracture-developed reservoirs, and their reservoir quality is greatly affected by fractures, showing high permeability characteristics.

5.2. The Genetic Model of Tight Sandstone Reservoirs

Based on the lithology, physical properties, pore structure characteristics, and reservoir type classification of the tight sandstone reservoir in T₃X₂ in the Anyue area, the controlling effects of sedimentation, diagenesis, and tectonism on the reservoir formation process were comprehensively analyzed, and the genetic mechanism and model of the reservoirs in T₃X₂ in the Anyue area are summarized (Figure 15):

The porosity of Type I reservoirs is >11%, the permeability is >0.2 mD, the rock granularity is mainly medium, the pore type is mainly residual intergranular pores, followed by intragranular dissolution pores with few intergranular dissolution pores, and the throats are mainly neck-constricted throats, with a large pore–throat radius, uniform distribution, and good connectivity. The content of rigid and plastic minerals is high. Due to the influence of chlorite rim cementation, compaction and the secondary increase of quartz are inhibited, showing weak compaction and medium cementation, with fewer dissolution pores under the microscope and weak dissolution, belonging to weak compaction diagenetic facies. The porosity of Type II reservoirs is 7–11%, the permeability is >0.2 mD, and the rock granularity is mainly medium, followed by fine sandstone. The pore types are mainly intragranular dissolution pores with a small number of intergranular dissolution pores, micro-fractures are very developed, and the throat development is poor. The types are mainly lamellar throats and neck-constricted throats, the pore–throat radius is relatively large, the distribution is relatively uniform, and the connectivity is relatively good. The content of rigid minerals is low, the content of plastic minerals is high, the anti-compaction ability is weak, the performance is strong compaction, and the content of cement is low, so the cementation is relatively weak, the content of soluble minerals is high, more dissolution pores and microcracks are observed under the microscope, the dissolution is strong, and the diagenetic facies are micro-fracture facies. The porosity of Type III reservoirs is 7–11%, and the permeability is 0.04–0.2 mD. The sandstone size of Type III reservoirs is mainly medium-grained, followed by coarse-grained sandstone, with less fine-grained sandstone. The pore type is mainly intergranular dissolution pores, followed by intragranular dissolution pores, with a few residual intergranular pores. The pore–throat radius is small and the sorting is relatively poor. Under the microscope, the particles are in line contact, the compaction is strong, and the cement content is low, so the cementation is weak. The pore type is dominated by dissolution pores, showing strong dissolution characteristics, and belonging to the unstable dissolution facies. The porosity of Type IV reservoirs is <7%, the permeability is <0.04 mD, and the granularity of sandstone is mainly fine, followed by medium-grained sandstone, and in addition, there is a small amount of siltstone. There are a small number of intergranular and intragranular dissolution pores, the throats are mainly bundle-shaped, the throat and fracture development degrees are low, the pore–throat radius is small, and the sorting and connectivity is poor. Type IV reservoirs can be divided into two diagenetic facies: one is the carbonate cementation facies with a high content of carbonate cement, strong cementation, point-line contact between particles, weak compaction, low content of soluble minerals, and underdeveloped dissolution pores; the other is the compact-dense facies with linear contact and concave–convex contact between particles, strong compaction, and a small number of dissolution pores, and the dissolution is relatively weak.

In addition, Type II reservoirs are the main fracture-developed reservoirs, and their reservoir quality is greatly affected by fractures, showing high permeability characteristics. Fracture development is controlled by the fault scale and fault–fracture distance. The larger the fault scale, the closer the fault–fracture distance, the greater the fracture density and the development of middle-high angle fractures, and the more half-filled and full-filled fractures.

5.3. Analysis of Result Reliability

This study argues that sedimentation, diagenesis, and tectonism are the dominant factors controlling the development of the reservoir quality in T₃X₂ in the Anyue area. Among them, the sedimentary microfacies, sandstone grain size, mineral particle content, type and content of cement, hydrocarbon-generating fluids, fracture development, and the relationship between fractures and faults are the main controlling factors determining the intensity of sedimentation, diagenesis, and tectonism in the reservoir.

To verify the reliability of the conclusions, an investigation was conducted on the genetic mechanisms of tight sandstone in other basins and compared with our research results. The investigation shows that the main controlling factors for the formation of Jurassic tight sandstone reservoirs in the Lenghu area of the Qaidam Basin are diagenetic processes, including compaction, cementation, and dissolution. Compaction reduces primary pores, cementation exacerbates densification, and dissolution improves physical properties by forming secondary pores, collectively shaping the reservoir characteristics. The tight sandstones of the Lianggaoshan Formation in the Fuling area of eastern Sichuan are influenced by sedimentary microfacies, diagenesis, and source rocks. Thick, coarse-grained underwater distributary channel sand bodies form the basis for high-quality reservoirs. Compaction and carbonate cementation lead to densification, while chlorite envelopes protect pores, and dissolution improves physical properties, with stronger dissolution in sandstones close to hydrocarbon generation centers and source rock layers. In the southern Dagang exploration area, the Permian tight sandstones are influenced by multiple factors: high-maturity medium-coarse sandstones serve as the material basis, early uplift and erosion lead to secondary pores formed by freshwater leaching and dissolution, and in the late closed system, source rock-derived acid dissolution regulates pores, while early hydrocarbon charging inhibits cementation, favoring pore preservation. Tectonic movements control the diagenetic evolution process. In the Bozi-Dabei area of the Kuqa Depression, the lower Cretaceous tight sandstones are controlled by sedimentary facies, with compaction (vertical and lateral) and cementation as the main pore-reducing factors, and dissolution as the pore-increasing factor. The overlying gypsum-salt layers protect the reservoir due to their low density, strong plasticity, and high thermal conductivity. Abnormal fluid pressure reduces effective stress, and fractures improve fluid flow, with the reservoir experiencing densification before hydrocarbon accumulation. The research results on reservoir formation mechanisms in other basins are consistent with our conclusions, verifying the reliability of this study.

6. Recommendations for Improving Recovery Methods

Based on the research on reservoir classification and the formation mechanisms of various reservoir types in this paper, we believe that Type I, Type II, and Type III reservoirs can be exploited. Type I reservoirs with good porosity and permeability and Type II reservoirs with developed fractures should be prioritized as key mining targets, while Type III reservoirs can also be developed. Type IV reservoirs are not recommended as mining targets. According to the different formation mechanisms of each reservoir type, we provide mining recommendations more suitable for each type of reservoir:

The core design concept for Type I reservoir mining is to maintain the original pore structure of the reservoir, optimize fluid flow efficiency, delay production decline, and prevent hydrate risks. It avoids strong modification that may damage the connectivity of pore throats and adopts a combination of mild stimulation, efficient displacement, and fine management technologies. The specific measures are as follows: ① Use high-inclination vertical wells or horizontal wells. High-inclination vertical wells are preferred to traverse the main gas-bearing sand bodies, with perforated completion (perforation density: 16–20 holes/m, phase angle: 60°) to avoid fluid-carrying challenges caused by long horizontal sections. If the sand body thickness is >10 m, deploy short horizontal wells (horizontal section: 300–500 m) with staged perforation (stage length: 80–100 m) to expand the gas drainage area. ② For drainage gas recovery and velocity control, adopt gas-lift drainage gas recovery technology, producing at the critical fluid-carrying velocity in the early stage to avoid bottom-hole liquid accumulation. Equip downhole gas–liquid separators to reduce wellbore backpressure and increase single-well production. Real-time monitor the casing pressure and bottom-hole flowing pressure. When the flowing pressure drops below the dew point pressure, inject methanol (100–150 L/d) to prevent hydrate blockage, while maintaining a production pressure difference of 10–15 MPa. ③ For CO₂ flooding to increase reserves and production, implement CO₂ gas flooding huff-n-puff for gas reservoir energy attenuation issues. Inject CO₂ with shut-in (injection volume: 5–8% of geological reserves), and resume production after 72 h of shut-in. CO₂ can displace adsorbed gas and reduce gas phase viscosity, increasing single-well cumulative gas production by 15–20%. ④ For intelligent monitoring and reservoir protection, deploy downhole fiber-optic distributed acoustic sensing (DAS) to track gas–water interface migration in real time, and implement temporary plugging agent plugging (such as gel-based plugging agents) in active bottom-water areas. Use non-damaging kill fluid (low-salinity brine + 0.5% KCl) before production to avoid clay mineral swelling and damage to pore throats.

The core mining strategy for Type II reservoirs is to activate micro-fracture networks, strengthen dissolution pore expansion, and prevent sand production, adopting a combination of fracture-cavity collaborative stimulation, composite displacement, and intelligent water control technologies. The specific technical solutions are as follows: ① Volume fracturing and temporary plugging diversion: Adopt low-viscosity slickwater and degradable fiber volume fracturing, with construction pressure controlled at 1.1–1.2 times the reservoir breakdown pressure. Force fracturing fluid to divert to micro-fracture-developed areas through fiber temporary plugging of fractured cracks, forming a network fracture system. Use low-density ceramsite (density < 1.2 g/cm³) as the proppant with a sand–fluid ratio of 25–30% to ensure long-term fracture conductivity. ② Acidization-fracturing combined operation: Preacidize with organic acids (formic acid + acetic acid, concentration: 8–10%) to dissolve soluble minerals (such as feldspar and carbonate) and expand throats, followed by fracturing. Add clay stabilizers (such as polyquaternium salts) to the acidizing fluid to prevent plastic mineral swelling and throat blockage, with permeability increasing by 30–50% after acidization. ③ Sand control completion and drainage gas recovery: Adopt screen pipe and gravel packing completion, with the screen slot width matched to the reservoir median particle size (recommended: 50–80 μm) to prevent plastic mineral particle migration. In the early production stage, use velocity string drainage gas recovery to increase gas flow velocity to the critical fluid-carrying velocity by reducing the wellbore inner diameter, avoiding bottom-hole liquid accumulation. ④ CO₂ huff-n-puff and intelligent zonal control: Implement CO₂ huff-n-puff once every 6–8 months, with an injection volume of 3–5% of the recoverable reserves and a shut-in period of 5–7 days, using CO₂’s low viscosity and micro-expansivity to activate stagnant gas in micro-fractures. Equip intelligent zonal switches to shut in high-water-producing zones in real time based on DAS fiber monitoring results, improving water control and gas stabilization effects by more than 20%.

The core mining strategy for Type III reservoirs is centered on collaborative stimulation of fractures and dissolution pores, efficient flow conductivity support, and refined production, constructing a composite seepage system of “artificial fractures and natural dissolution pores” through fracturing to connect dissolution pore clusters. The specific technical solutions are as follows: ① Horizontal well and cluster-controlled fracturing: Deploy horizontal wells (horizontal section: 800–1000 m) to traverse dissolution pore-developed zones, using pre-set bridge plug staged cluster fracturing (stage spacing: 40–60 m, 3–4 clusters per stage). Use low-damage guar gum fluid (viscosity: 30–50 mPa·s) as the fracturing fluid, and 40/70 mesh quartz sand with 10% degradable fibers as the proppant. Force fractures to divert to dissolution pore-dense areas through fiber temporary plugging, forming a dendritic fracture–dissolution pore network with a target fracture complexity index > 2.5. ② Acidic pretreatment and in-fracture acid fracturing: Pretreat the formation near the wellbore with mud acid (HF 3% + HCl 12%) before fracturing to dissolve pore-throat plugging materials (such as clay and carbonate), improving the skin factor to –3–2; and implement in-fracture acid fracturing during fracturing (acid fluid proportion: 20–25%) to etch fracture walls into rough grooves and improve long-term fracture conductivity (target conductivity > 50 mD·m). ③ Pressure-depletion production and velocity control: Use small-diameter tubing to increase the gas flow velocity to the critical fluid-carrying velocity, with the initial production pressure difference controlled at 15–20 MPa to avoid intergranular clay migration caused by excessive pressure drawdown. Equip downhole vortex tools to enhance gas–liquid separation efficiency, with the bottom-hole liquid accumulation height controlled within 200 m. ④ Intelligent monitoring and reservoir protection: Use electromagnetic imaging logging to identify dissolution pore distribution, and evaluate fracture network effectiveness through pulsed neutron monitoring after fracturing; inject KCl anti-swelling fluid (concentration: 2%) before production to stabilize clay minerals and avoid velocity sensitivity damage, with a reservoir protection efficiency > 90%.

7. Conclusions

The experimental statistics method, productivity simulation method, pore–permeability relationship method, and minimum flow pore–throat radius method are used to evaluate the lower limit of reservoir physical properties, and 7% porosity is taken as the lower limit of reservoir physical properties. On this basis, the reservoir in T₃X₂ in the Anyue area is divided into four types by using the large amount of reservoir physical property data, mercury injection parameters, reservoir space types, and pore structure observations obtained from the cast thin sections, HPMI experiment, NMR experiment, and core physical property test.

The characteristics of the four types of reservoirs are as follows: The porosity of Type I reservoirs is >11%, the permeability is >0.2 mD, the pores are dominated by residual intergranular pores, followed by intragranular dissolution pores and a few intergranular dissolution pores, the main type of throat is the neck-constricted throat, the pore–throat radius is large, the distribution is uniform, the connectivity is good, and the storage type is pore type, which is the most favorable reservoir target. The pores of Type II reservoirs are mainly intragranular dissolution pores with a few intergranular dissolution pores, micro-fractures are very developed, throat development is poor, the pore–throat radius is large, distribution is more uniform, connectivity is better, and the reservoir type is the fracture-pore type, which is a more favorable reservoir target. The pores of Type III reservoirs are mainly intergranular dissolution pores, followed by intragranular dissolution pores and a few residual intergranular pores. The throats are mainly neck-constricted throats and lamellar throats, and fractures can be seen in some reservoirs, with a small pore–throat radius and relatively poor sorting. The reservoir type is mainly the fracture-pore type, and the reservoir quality is poor. In Type IV reservoirs, a small number of intergranular and intragranular dissolution pores are developed, and the throats are mainly bundle-shaped, with a low development degree of throats and fractures, small pore–throat radius, and poor sorting and connectivity, so they cannot be used as effective reservoirs.

Reservoir sedimentation determines the size and content of mineral particles, compaction is related to the content of rigid minerals such as quartz and feldspar and plastic minerals such as rock fragments and mica, cementation strength is mainly controlled by the content of carbonate cements, dissolution strength is jointly affected by soluble minerals and hydrocarbon-generating acidic fluids, and the development of tectonic fractures is closely related to the fault scale and fault–fracture distance.

The effect of sedimentation on the four types of reservoirs is as follows: Through a comprehensive analysis of the content of detrital particles in the four types of reservoirs, it is generally shown that the content of quartz is in the order of Type III > Type II > Type IV > Type I, the content of feldspar is in the order of Type I > Type II > Type III > Type IV, the content of rock fragments is in the order of Type II > Type I > Type IV > Type III, and the content of mica is in the order of Type IV > Type I > Type III > Type II. The grain size of rocks in Type I reservoirs is mainly medium-grained. The grain size of rocks in Type II reservoirs is mainly medium-grained, followed by fine-grained sandstone. The grain size of sandstone in Type III reservoirs is mainly medium-grained, followed by coarse-grained sandstone, with less fine-grained sandstone. The grain size of sandstone in Type IV reservoirs is mainly fine-grained, followed by medium-grained sandstone. In addition, there is also a small amount of siltstone.

The influence of diagenesis on the four types of reservoirs is as follows: The content of rigid minerals is in the order of Type III > Type I > Type II > Type IV, and the content of plastic minerals is in the order of Type I > Type II > Type IV > Type III. Overall, the content of cements is in the order of Type IV > Type I > Type II > Type III, and the content of soluble minerals is in the order of Type I > Type II > Type III > Type IV. Based on the mineral content and combined with the analysis of the cast thin sections, Type I reservoirs are in weak compaction facies featuring weak compaction, medium cementation, and medium dissolution. Type II reservoirs are in micro-fracture facies with relatively strong compaction, weak cementation, medium dissolution, and intense fracturing. Type III reservoirs are in unstable dissolution facies with relatively strong compaction, weak cementation, and strong dissolution. Type IV reservoirs include compact-dense facies mainly characterized by strong compaction, followed by weak cementation and weak dissolution, as well as carbonate cementation facies with weak compaction, strong cementation, and weak dissolution.

Influence of tectonism: The fracture angle, density and filling degree have a certain correlation with the fault scale and fault–fracture distance. The larger the fault scale, the closer the fault–fracture distance, the greater the fracture density and the development of middle-high angle fractures, and the more half-filled and full-filled fractures. The fracture development of Type II reservoirs is more affected by tectonism and shows the characteristics of high permeability.