Geological Characteristics of Deep Shale Gas and Their Effects on Shale Fracability in the Wufeng-Longmaxi Formations of the Southern Sichuan Basin, China

Shale gas is a natural gas often distributed in a thick and widely occurring shale source rock in a basin, with abundant reserves, and is clean and efficient. The Sichuan Basin is a key area for shale gas exploration and development in China. The Upper Sinian Doushantuo Formation, Lower Cambrian Shuijingtuo Formation (Niutitang Formation, Jiulaodong Formation, and Qiongzhusi Formation), and Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation are rich in organic matter. In particular, the marine organic-rich shale of the Wufeng Formation-Longmaxi Formation has a high total organic carbon (TOC) content, very large thickness, high maturity, and good brittleness [1-5]. To date, shale gas fields such as Changning, Zhaotong, Weirong, and Luzhou have been exploited. Many Chinese scholars have made great progress in the study of shale gas enrichment conditions in China. For the deep shale gas reservoirs of the Wufeng Formation-Longmaxi Formation in the southern Sichuan Basin, due to the old age, complex genesis, and strong tectonic activity of these formations, the shale gas reservoirs are nonhomogeneous and have developed natural fractures during a complex pore evolution [6-9]. Due to the different factors controlling shale gas enrichment and high gas production, the complex geological conditions influence the efficacy of network fracturing in shale reservoirs.

To date, most studies on the expansion of hydraulic fractures have been based on the establishment of homogeneous reservoir models, while few studies have examined multifracture propagation in heterogeneous reservoirs. The fracture network formed by natural shale fractures or artificial fracturing has a significant influence on the enrichment of shale gas in reservoirs, the improvement of reservoir performance, and the production capacity [10-12]. Previous studies have shown that different reservoir stresses and geological conditions affect fracture propagation. The mechanical parameters of deeply buried shale, such as the elastic modulus, compressive strength, tensile strength, and Poisson’s ratio, are significantly different from those of shallowly buried shale and have the characteristics of high ground stress and high ground stress differences [13-18]. Scholars have studied the effect of reservoir heterogeneity on fracture propagation patterns, and they have concluded that the complexity of the fracture network formed after being influenced by natural fractures is not only related to the ground stress but also influenced by parameters such as the brittleness index, rock mechanical parameters, natural fracture parameters, and fracturing construction parameters [19-28]. In other words, hydraulic fracture propagation is controlled by both geological and engineering factors [29-34]. Geological factors are mainly reflected in the following three aspects: (1) The physical and mechanical properties of shale affect hydraulic fracture propagation. The higher the content of brittle minerals is, the lower the content of clay minerals, the greater the elastic modulus, and the smaller the Poisson’s ratio; thus, the easier it is to form complex fracture networks. (2) The in situ stress is the most important factor affecting fracture propagation. The in situ stress mode, horizontal and vertical in situ stress difference, and formation pressure all affect the direction and shape of fracture propagation. (3) In shale reservoirs, natural weak surfaces such as bedding and natural fractures are well developed, and the properties, occurrence, and stress of these weak surfaces will jointly determine the propagation of hydraulic fractures. Many studies have been carried out on the influence of bedding and natural fractures on hydraulic fracture propagation [35-37]. In situ stress is the main geological factor affecting fracture propagation, while weak surfaces such as bedding and natural fractures are the key geological factors that determine whether hydraulic fractures can form fracture networks [38-40]. The main engineering factors controlling hydraulic fracture propagation are the influence of construction displacement, fracturing fluid properties, and perforation method. The construction displacement and the viscosity of the fracturing fluid can affect the complexity of the fracture in a certain range. Fracturing fluids with low displacement and viscosity can better conduct pressure and communicate more natural fractures and weak bedding surfaces. The perforation method can affect the complexity of the resulting fractures; the fracture obtained by spiral perforation is the most complex, and that obtained by plane perforation is the simplest [41-45].

Therefore, this study takes the organic-rich shale of the Wufeng-Longmaxi Formations in the southern Sichuan Basin as an example. A systematic analysis of the geological conditions of shale reservoir formation, the sedimentary environment, and the geological and engineering factors affecting the network fracturing effect on shale reservoirs was conducted to improve the accuracy of fracturing evaluation of shale reservoirs and improve the fracturing effect.

After the mud shale of the Silurian Longmaxi Formation in the Sichuan Basin was sedimented, it experienced five major tectonic movements. In the Luzhou area, a Northeast-trending structure is the major structure, and a broom-like structure develops from the Northeast to the Southwest. The strength of the tectonic fold gradually weakens, and there are two main faults in the Northeast–Southwest and East–West directions. The main faults have a large fracture spacing and play a controlling role in the tectonic form, with a large local dip angle and the development of a zone of fractures and microamplitude structures, resulting in more events during the drilling process, such as well leaks and stuck drilling; therefore, identifying the ideal location and performing drilling are difficult, and reservoir fracturing is very challenging. The early Silurian Longmaxi period in the Sichuan Basin experienced two sea level changes, each of which started with rapid seawater intrusion and ended with slow seawater recession, and a set of terrigenous clastic sediments was mainly deposited during the early Silurian Longmaxi period. In the study area, the continental environment provided a major depositional area, and the materials were mainly sourced from the surrounding ancient land [35, 36] (Figure 1(a)). During the deposition of shale reservoirs in the Luzhou area, the sea level rose and fell frequently and was affected by paleotectonic and late-stage tectonic movements. The vertical and horizontal reservoir physical properties, organic carbon content, mineral composition, fracture distribution characteristics, gas-bearing properties, and brittle mineral content vary greatly, and the nonhomogeneity of shale reservoirs is high, making it difficult to predict favorable targets of high-quality shale gas. Most shale reservoirs in the Luzhou area are deeply buried, with a high pressure coefficient, high fracturing pressure, and great difficulty in sand filling [10, 37]. High-quality shale reservoirs are well developed in the Wufeng Formation-Longmaxi Formation. The first microlayer at the bottom of the Longmaxi Formation is characterized by a high content of organic matter, high content of brittle minerals, and high gas content. The sedimentary environment is dominated by the outer shelf, and it is the best shale gas development layer (Figure 1(b)) [46, 47]. Strong vertical inhomogeneity of this reservoir affects the fracture height, resulting in low vertical production of the reservoir. After multistage tectonic movement, natural fractures are formed in many stages, the angle between the natural fractures and the maximum principal stress is small, and the horizontal stress difference is large, and conditions are not conducive to the formation of a complex fracture network after volume fracturing [48-50].

In this study, Wufeng Formation-Longmaxi Formation cores were sampled from three wells, including wells L203H79-4, Y101H3-8, and Y101H41-2 in the Luzhou area, and whole-rock X-ray diffraction analyses, gas-bearing property tests, shale porosity tests, and rock mechanical parameter tests were performed. In addition to the coring of the Wufeng Formation-Longmaxi Formation, in five wells, namely, L203H57-3, L203H79-4, L203H153-8, L210, and Y101H65-5, experimental tests on pore types and microscopic pore structure were performed (Table 1).

The shale mineral contents were measured by whole-rock X-ray diffraction. The X’Pert MPD Pro X-ray diffractometer manufactured by PANalytical (the Netherlands) was used as the analytical instrument, and the test was based on Chinese standard SY/T 5163-2010 [51, 52]. The powder sample was ground to a particle size of 320 mesh, approximately 40 µm, and a mass of approximately 3 g was used. The sample was placed in the effective test area within 5–12 mm from the vertical plane of the sample table on the axis of the goniometer. For the goniometer, the sample was placed horizontally, with a 2θ angle ranging from 1° to 160°. During the test, the position of the sample remained unchanged. The X-ray tube and the detector rotated relative to the sample and continuously scanned the sample.

The focused ion beam scanning electron microscopy (FIB-SEM) instrument was a Helios 660 dual-beam scanning electron microscope manufactured by FEI. For FIB-SEM, a gallium ion beam with an angle of 52° to the electron beam was used with a field emission electron microscope, with the ion beam cutting perpendicular to the sample surface and the electron beam scanning at an angle of 38° to the sample surface for imaging. A series of continuous slices with a thickness of 10–20 nm were obtained by setting the thickness of a single slice. The three-dimensional volume structure was obtained through subsequent software reconstruction so that the pores, organic matter content, and connectivity could be quantified, and then calculation and simulation were performed using the established model [53, 54]. The cutting area for sample preparation was 10 × 15 μm, the section thickness was 10 or 20 nm, the ion beam voltage was 500 V–30 kV, and the electron beam voltage was 1 –24 kV.

The gas content was measured mainly by the on-site desorption method using a shale gas content measuring instrument/shale residual gas measuring device, and the measurement was performed according to Chinese standard SY/T 6940-2013 [55, 56]. A method to obtain the desorption gas content by placing the drilling cores in the desorption device can accurately characterize the underground gas content of the shale. The total gas content is composed of three parts: desorption gas, lost gas, and residual gas. Desorption gas content is the amount of gas measured using a desorption device after the core has been loaded into the desorption tank, residual gas content is the amount of residual gas that cannot be desorbed when the core is ground up after the desorption has been terminated, and lost gas content is the amount of gas that escapes during the core lift and surface exposure. In the desorption method for measuring shale gas, the amount of desorption gas and the amount of residual gas are directly measured, and the error is relatively small. The amount of lost gas is mainly based on the time from core drilling to loading into the desorption tank and the measured desorption data, and various desorption data processing methods, such as the U.S. Bureau of Mines method, are used.

The rock mechanical parameter testing was completed by the Rock Mechanics Laboratory of the State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University. A triaxial rock compressive strength test can determine mechanical parameters such as Young’s modulus, Poisson’s ratio, and fracturing pressure. Dynamic and static parameter relationship testing was also conducted to establish the relationship between the acoustic logging data and the shear strength. In the acoustic emission (AE) testing for ground stress, sampling is generally performed in three different directions, that is, 0°, 45°, and 90°, in a horizontal plane perpendicular to the axis of the drilling core. In this paper, the maximum horizontal principal stress and rock mechanical parameters were determined using the RTR-1000 high-temperature and high-pressure triaxial rock mechanical test system manufactured by GCTS. Cylindrical samples with a standard size of 2:1 (50 × 25 mm) were made, according to the International Society of Rock Mechanics standards [57-60]. In this experiment, we did not consider the size effect in the analysis of the rock mechanical parameters. The tests were carried out in accordance with Chinese standards GB/T 23561.11-2009, GB/T 50266-2013, and SY/T 6351-1998 [61-63].

The lithology of the Longyi ₁ submember of the Wufeng Formation in southern Sichuan is mostly carbonaceous shale, calcareous shale, and siliceous shale, the colors of which are mainly black, dark gray, and gray. The bottom of the Longmaxi Formation is mainly dark siliceous shale, mainly black and dark gray, which is rich in graptolite fossils [64-66]. As the amount of organic matter increases, and paleontological features, such as graptolites, increase. Whole-rock X-ray diffraction showed that there are large differences in the mineral contents in the Wufeng Formation and Longmaxi Formation rocks. Quartz and clay minerals are the most abundant, followed by feldspar, calcite, and dolomite, and pyrite is the least abundant. The rest of the minerals, such as calcite, apatite, white mica, black mica, rutile, and gypsum, comprises less than 1% of the mineral content on average. In the high-quality shale segment, from the top to the bottom, the illite content in the lithology of sublayers gradually decreases from Longyi ₁⁴ to Longyi ₁¹, and the quartz content gradually increases (the quartz changes from larger, more dispersed particles to a contiguous distribution; i.e., the proportion of silicone gradually increases). The main organic matter shifts from being mainly distributed between quartz grains to being distributed between clay mineral grains, while the organic matter in large grains with regular shapes increases.

In the sublayers of Longyi ₁¹ to Longyi ₁³ in the Luzhou area, the average content of brittle minerals is 78.0%, the average quartz content is 56.4%, the average feldspar content is 4.1%, and the average clay mineral content is 17.6%. In the sublayers of Longyi ₁⁴, the average content of brittle minerals is 69.3%, the average content of quartz is 38.3%, the average content of feldspar is 9.7%, and the average content of clay minerals is 27.7%. In the Wufeng Formation, the average content of brittle minerals is 65.7%, the average content of quartz is 34.3%, the average content of feldspar is 4.7%, and the average content of clay minerals is 31.0% (Table 2). Overall, the content of brittle minerals in the study area is relatively high, and the brittle minerals are mainly quartz, followed by feldspar, and small amounts of dolomite, calcite, and pyrite are developed.

Shale gas exists in the pores in a free or adsorbed state, and the reservoir properties and migration capacity are determined by the pore type and pore structure. The microscopic characteristics of shale pores from the Wufeng Formation to the Longyi ₁ submember in the Luzhou area were analyzed using the casting thin sections of the sample and argon ion polishing SEM. The pore size is mostly at the nanometer to micron level; the main pore types include intergranular pores of clastic minerals, intercrystal pores of clay minerals, internal intercrystal pores of pyrite framboids, organic matter pores, and intragranular dissolution pores. The organic matter pores (Figures 2(a) and 2(b)), intragranular dissolution pores (Figures 2(c) and 2(d)), and intercrystal pores of clay minerals (Figure 2(e)) are the most developed [67-70]. The natural microfractures inside shale can greatly improve the effectiveness of hydraulic fracturing, thereby improving the seepage capacity of shale and providing the necessary migration pathways for shale gas to enter the wellbore from the bedrock pores [71-73]. The observation and description of the cores showed that the macroscopic fractures of the Longmaxi Formation are unevenly developed in different cores (from different wells), most of the macroscopic fractures are completely filled with calcite and pyrite, and a small amount of quartz is also observed. Some microfractures are also be observed in the casting thin sections of the samples, which are mainly tectonic fractures (Figure 2(f)), diagenetic fractures (Figures 2(g) and 2(h)), and shale bedding fractures, which are often filled with calcite, quartz, organic matter, gypsum, and pyrite. Some microfractures penetrating the grains or at grain edges (Figure 2(i)), microfractures between clay flakes and microfractures due to hydrocarbon expulsion and pressure release of organic matter expulsion are also observed, and the fractures are mostly filled with organic matter.

From the Wufeng Formation to the Longyi ₁ submember in the Luzhou area, the proportion of micropores and mesopores is high, and microfractures and natural fractures are developed. In the vertical direction, the porosities of the Longyi ₁¹ sublayer, the Longyi ₁² sublayer, and the Longyi ₁³ sublayer are relatively high, while the Longyi ₁⁴ sublayer and the Wufeng Formation have relatively low porosities. The porosity of the Longyi ₁¹ to Longyi ₁³ sublayers is 2.5%–5.6%, with an average of 4.4%; the porosity of the Longyi ₁⁴ sublayer is relatively low at 2.6%–4.1%, with an average of 3.3%; and the porosity of the Wufeng Formation is relatively low at 3.2%–4.0%, with an average of 3.6%.

The total gas content of the cores from the Wufeng Formation to the Longyi ₁ submember in the Luzhou area is 1.2–8.0 m³/t, with an average of 3.7 m³/t; the total gas content of the cores from the Longyi ₁¹ to Longyi ₁³ sublayers is 1.2–8.0 m³/t, with an average of 4.3 m³/t; in the vertical direction, the total gas contents of the Longyi ₁¹ sublayer, the Longyi ₁² sublayer, and the Longyi ₁³ sublayer are relatively high, and the Longyi ₁⁴ sublayer and Wufeng Formation have relatively low total gas contents. The total gas content of the Longyi ₁¹ sublayer is the highest at 4.2–8.0 m³/t, with an average of 5.7 m³/t; the total gas content of the Wufeng Formation is the lowest at 1.4–5.2 m³/t, with an average of 3.1 m³/t. The gas saturation of the cores from the Wufeng Formation to the Longyi ₁ submember in the Luzhou area is between 48.9% and 91.5%, with an average of 69.8%; and the gas saturation of the Longyi ₁¹ to Longyi ₁³ sublayers is between 58.2% and 91.5%, with an average of 75.6%. Among them, the Longyi ₁¹ sublayer and Longyi ₁² sublayer have the highest gas saturations at 83.7% and 77.7%, respectively, and the Longyi ₁⁴ sublayer has the lowest at 59.0% (Table 3). The gas saturation is mainly distributed between 50% and 80%, and the proportion of samples with gas saturation greater than 60% is 73.3%.

In the process of hydraulic fracturing, shale fracability is a key parameter to evaluate whether shale can be effectively fractured [74, 75]. Shale fracability is mainly affected by factors such as shale brittleness, rock mechanical properties, and ground stress. The results of the triaxial compressive strength test showed that the Poisson’s ratio of the samples from the Wufeng Formation-Longyi ₁ submember in the Luzhou area is in the range of 0.155–0.264, with an average of 0.21; the elastic modulus is in the range of 32456.0–44214.5 MPa, with an average of 37358.9 MPa; the triaxial compressive strength is in the range of 79.8–389.4 MPa, with an average of 234.6 MPa. As the burial depth increases, the compressive strength and elastic modulus of the sample increase, and Poisson’s ratio decreases. From the perspective of the relationships between the brittleness and elastic modulus, Poisson’s ratio, and compressive strength, the sample’s brittleness exhibits a good correlation with the peak strength, elastic modulus, and Poisson’s ratio, and the brittleness is positively correlated with the peak strength and elastic modulus and negatively correlated with Poisson’s ratio. From the perspective of the fracture mode and brittleness trends of samples under different temperature and pressure conditions, with increasing burial depth (confining pressure and temperature), the variation pattern of the fracture mode gradually transitions from complex to single and from splitting to shear failure, the angle between the shear planes gradually increases, and the shale brittleness decreases. Based on the AE results, the distribution range of the maximum horizontal principal stress in the target area is 97.82–116.40 MPa, with an average of 107.09 MPa, and the distribution range of the minimum horizontal principal stress is 85.46–100.40 MPa, with an average of 93.16 MPa. The Wufeng Formation-Longyi ₁ submember in the study area has a high content of brittle minerals, high Young’s modulus, low Poisson’s ratio, appropriate fracturing pressure, and small net stress difference; therefore, this area has a high shale fracability and easily fractured reservoir, and a complex fracture network can be formed, which is conducive to gas production testing.

Previous studies have shown that sedimentary facies characteristics can be analyzed according to shale biogenic silicon, TOC content, and U/TH content [4, 10, 66, 76]. Wingnall used the V/(V + Ni) ratio to reflect the oxidation‒reduction conditions of the sedimentary environment. When this ratio is less than 0.46, it indicates an oxidizing environment; when this ratio is between 0.46 and 0.57, it indicates a weak oxidizing environment; when the ratio is between 0.57 and 0.83, it indicates an anoxic environment; and when this ratio is between 0.83 and 1.0, it is a still sea environment [77]. Jones and Manning believed that the Ni/Co ratio can also be used to determine the sedimentary environment. When the Ni/Co ratio is greater than 7.00, it indicates a reducing environment; when this ratio is between 5.00 and 7.00, it indicates an anoxic environment; and when this ratio is less than 5.00, it indicates an oxidizing environment [78]. In addition, the V/Cr ratio can reflect the sedimentary environment. When the ratio is less than 2, it indicates an oxygen-rich environment; when the ratio is between 2 and 4.25, it indicates an oxygen-poor environment, and when the ratio is greater than 4.25, it indicates a hypoxic to anoxic environment [78, 79]. Combined with the classification of sedimentary facies types of the Wufeng-Longmaxi Formations in the southern Sichuan Basin by some scholars [66, 76, 80, 81], we determined the main sedimentary facies types and distribution characteristics in the study area (Figure 3).

During the sedimentary period of the Wufeng Formation in southern Sichuan, the relative sea level rose, the surface productivity of the water body increased, and the bottom water body presented an anoxic environment due to insufficient oxygen circulation, forming organic-rich shale sediments [66, 76]. In the early Silurian period (Longyi ₁¹ sublayer), the gradual melting of glaciers injected a large amount of fresh water into the ocean, and accompanied by large-scale seawater intrusion, an anoxic environment formed (Figure 3(b)) [82, 83]. The anoxic condition of the bottom water body may have caused the recycling of nutrients, which promoted the high productivity at the ocean surface, resulting in a strong reducing environment in the bottom water body. The organic matter was abundant (the Type I and Type II kerogens were rich), the water body was deep, and the water body energy was weak. Affected by volcanic activity, many algal organisms were produced. In the Longyi ₁² sublayer of the Longmaxi Formation, the relative sea level decreased temporarily, and the water body was still in an anoxic and strong reducing environment, forming organic-rich shale sediments (Figure 3(c)) [66]. The TOC content was low (Type I kerogen), the water body became shallow, the hydrodynamic force was relatively strong, and the reducing environment was strong, conditions that were more conducive to the preservation of organic matter. In the early stage of the Longyi ₁³ sublayer of the Longmaxi Formation, the relative sea level rose, the surface productivity of the water body increased, an anoxic environment formed at the bottom, organic matter was abundant (the Type I kerogen is rich), the water body was deep, and the energy of the water body was weak (Figure 3(d)). In the early stage of the Longyi ₁⁴ sublayer, the overall sea level dropped rapidly, the water body became shallow, the sediment grain size became large (coarse grains), the sedimentary facies transitioned from the deep-water continental shelf to the shallow-water continental shelf (Figures 3(e)–3(g)), the level of organic matter was low (Type I kerogen), the water body slowly became shallow, and the hydrodynamic force was strong [84, 85].

The main sedimentary microfacies of the Wufeng Formation in the deeply buried shale gas block in southern Sichuan are the organic-rich siliceous deep-water continental shelf microfacies and organic-rich calcium-bearing silt deep-water continental shelf microfacies, which are distributed in a northeasterly belt (Figure 3). The Longyi ₁¹ to Longyi ₁² sublayers have organic-rich deep-water continental shelf microfacies (Figures 3(b) and 3(c)), and in the area Northwest of Well L203, the organic-rich calcium-bearing silt deep-water continental shelf microfacies is the major microfacies. The Longyi ₁³ sublayer has an organic-rich deep-water continental shelf microfacies distributed in the Northeast direction, the area of Wells L203 and Y101 is mainly characterized by the organic-rich deep-water continental shelf microfacies, and the area North of Well L207 and the area west of Well Y201-H2 are characterized by an organic-rich, silicon-bearing deep-water continental shelf microfacies (Figure 3(d)). Section a of Longyi ₁⁴ has an organic-rich silicon-bearing deep-water continental shelf microfacies and organic-rich calcium-bearing silt deep-water continental shelf microfacies, while Section b has an organic-rich calcium-bearing silt deep-water continental shelf microfacies. In the area of Well Y101H10-3, a calcium-bearing clay-rich deep-water continental shelf microfacies develops in the Southwest direction, and in the area of Well L210, a calcareous clay-based deep-water continental microfacies develops in the Southeast direction. Section c has an organic-rich calcium-bearing silt deep-water continental shelf microfacies, the area North of Well L203 has a calcareous clay deep-water continental shelf microfacies, and in the area of Well L210, a clay-rich deep-water shelf microfacies develops in the Southeast direction (Figures 3(e)–3(g)).

The sedimentary water body of Longyi ₁¹ was deep, and the formation of quartz particles was relatively weakened by transport. The content of clastic quartz, mainly authigenic quartz biogenic silicon, decreased over time, and the particle sizes of the quartz particles are mostly 0–30 μm. Biogenic quartz is well developed in Longyi ₁²: the amount of terrigenous clastic quartz increased over time, and the particle sizes of this quartz are larger than 20 µm. The sedimentary water body of Longyi ₁³ was deep, dominated by the development of biological silicon. The proportion of authigenic quartz increased over time, and the content of clastic quartz decreased; the particle sizes of these quartz particles decreased to 0–10 μm. The quartz particle sizes at the bottom of Longyi ₁⁴ are mostly 0–10 μm, the quartz particle sizes are 0–20 μm at the top of Longyi ₁⁴, and the sedimentary water body was shallow. The hydrodynamic force at the top of Longyi ₁⁴ is stronger than that of Longyi ₁³, and the content of clastic quartz formed by transportation increased over time [86, 87]. The differences in the quartz particle size and genetic type were affected by the sedimentary depth, oxygen content, and volcanism. Overall, the quartz particles of Longyi ₁¹ and Longyi ₁² are obviously larger than those of Longyi ₁³ and Longyi ₁⁴ (Table 4).

Hertz contact theory shows that under the same load, the smaller the mineral particle size is, the greater the mineral indirect contact stress [88, 89]. Brittle minerals with relatively large grains are conducive to not only the formation of natural fractures but also fracture initiation, increasing the fracture size. The contents of quartz of different particle sizes in the A sample are almost the same, and the quartz particles in the B sample are mainly large (Figure 4). The fracturing simulation test of the A sample and the untested B sample was performed with MAPS, and the differential effect of fracture production was observed on the microscale. Almost no fractures were found near uniformly small particles, and most of the fractures were distributed along the edge of large particles (Figures 5(a) and 5(b)). Based on the comparison of the fracturing simulation test results, most of the fractures extend along the edge of larger particles. On the one hand, the occurrence of fractures depends on the rigid characteristics of rock and grains, especially the content of quartz grains. On the other hand, the particle size of quartz particles also restricts the effect and extension of fracture production (Figures 5(c)–5(f)) [90]. Therefore, Longyi ₁¹ and Longyi ₁² in the study area are more favorable for fracturing.

According to digital core samples with different component contents (the samples are mainly composed of pores, organic matter, quartz, clay, and carbonate), the elastic moduli of the samples were calculated by iCore software, and the effects of organic matter, porosity, and quartz on the elastic moduli are analyzed. When the organic matter content increases by 0.5%, the porosity remains unchanged, the mineral composition decreases accordingly, and then the shear and bulk moduli decrease with increasing organic matter content (Figures 6(a) and 6(b)). If the organic matter content remains unchanged, the porosity increases by 1%, and the mineral composition decreases accordingly; then, the shear and bulk moduli decrease with increasing porosity content. When the porosity is greater than 1% the acceleration decreases (Figures 6(c) and 6(d)). In addition, we also analyzed the correlation between Young’s modulus and carbonate content. With the decrease in quartz content and the increase in carbonate content, the Young’s modulus decreased. The shear modulus of quartz is 44 GPa, the bulk modulus is 37 GPa, and the shear modulus is larger than the bulk modulus; however, the shear modulus of calcite is 32 GPa, the bulk modulus is 76.8 GPa, and the shear modulus is less than the bulk modulus. Therefore, Young’s modulus is proportional to the content of quartz (Figures 6(e) and 6(f)). The porosity, TOC content, and brittle mineral content of the Wufeng Formation-Longyi ₁¹ in the study area are higher; these results, as well as the higher Young’s modulus and lower Poisson’s ratio, show that the target layer has good fracability [93-95].

The shale reservoir of the horizontal section of Well L205 is located at a depth of 4300.0–6063.0 m, and the section is 1763.0 m long (Figure 7). A total of 1708.1 m of Class I reservoir is encountered, with a drilling encounter rate of 96.9%, and 54.9 m of Class II reservoir is encountered, with a drilling encounter rate of 3.1%. Based on the quality of shale reservoirs and the development of natural fractures, the accuracy of the fracability evaluation of shale reservoirs is improved, the positions and layers of perforation wells are optimized, and the fracturing effect is improved [96, 97]. A total of 32 fracturing sections are delineated, and 186 perforation clusters are placed. Among them, the twenty-second through twenty-seventh fracturing sections are dominated by Class II shale reservoirs, and the other fracturing sections are mainly Class I shale reservoirs, with good shale reservoir quality. Fractures in the Longmaxi Formation are relatively developed in the fourteen horizontal sections of fracturing Sections 2–3, 10–11, 18–19, 22–23, 25–26, 28–29, and 31–32.

To analyze the fracturing effect and the subsequent gas production, different chemical tracers are used in each fracturing section. Figure 8 shows the gas production contribution percentage of each fracturing section reflected by the tracers used in Well L205. The gas production ratio of the thirty-two sections of Well L205 is between 0.7% and 7.6%. Among them, 8% of sections have a gas production ratio >4%, seventeen are between 2% and 4%, and seven are <2%. Further comparison of reservoir evaluation results and fracturing parameters showed that the physical properties and engineering parameters of the fracturing section with a gas production ratio >4% are as follows: the TOC content is 2.3%–4.6%, the total gas content is 3.9–6.0 m³/t, the total amount of sand added in a single section is 120–163 tonnes, and the amount of fluid used in a single section is 1673–2012 m³; those of the fracturing section with a gas production ratio between 2% and 4% are as follows: the TOC content is between 2.3% and 4.3%, the total gas content is 3.9–5.8 m³/t, the total amount of sand added in a single section is 76–168 tonnes, and the liquid volume used in a single section is 945–2197 m³. Type I shale reservoirs mainly exist as hydrocarbon source rocks and have large oil production potential. The gas production ratio is positively correlated with the TOC content and total gas content. For the sections in the same layer, when the fracturing scale is equivalent, the gas production ratio in the sections with natural fractures is higher than that in the sections without natural fractures. The larger the deep shale fracturing parameters are, the more total sand and fluid used in a single section, the greater the fracture extension length, width, and height, and the better the fracturing effect.

1. High-quality shale reservoirs are widely distributed in the Wufeng-Longmaxi Formations of the southern Sichuan Basin. The mineral contents in the high-quality shale reservoirs vary greatly, with the quartz content being the highest, followed by the clay, feldspar, calcite, and dolomite contents. The main pore types include intergranular pores, intercrystalline pores, organic matter pores, and intragranular dissolution pores, and they are mainly micro-pores and mesopores. Overall, the sedimentary environment has an important influence on the organic matter, and the type of organic matter is due to the combined effects of factors such as sea level change, ocean current conditions, hydrodynamics, oxygen-poor conditions, reducing environmental conditions, algae bioenrichment, and tectonic conditions.

2. The Wufeng Formation-Longyi 1¹ submember has a high content of brittle minerals, a high Young’s modulus, a low Poisson’s ratio, an appropriate fracturing pressure, and a small net stress difference. Therefore, it has a high shale fracability and is an easily fractured reservoir, which is conducive to gas production testing. In view of the geological characteristics of the study area, the fracturing process of multicluster perforation, temporary plugging near the wellbore, and multistage fracturing should be adopted, and the near-wellbore hydraulic fracture complexity should be increased, which can improve the hydraulic fracturing effect.

The authors declare that the study was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

This study was financially supported by the Key R & D Projects of the Deyang Science and Technology Plan (Nos. 2022SZ049 and 2021SZ002), the Open Fund of Natural Gas Geology Key Laboratory of Sichuan Province (No. 2021trqdz05), and the Open Fund of Shale Gas Evaluation and Exploitation of the Key Laboratory of Sichuan Province (No. YSK2022002). We thank all editors and reviewers for their helpful comments and suggestions.