Shengxian Zhao,Majia Zheng,Shaojun Liu,Bo Li,Yongyang Liu,Yuanhan He,Gaoxiang Wang,Xunxi Qiu
Multi-scale Fractures and Their Influence on Shale Gas Deliverability in the Longmaxi Formation of the Changning Block, Southern Sichuan Basin, China
The capacity and deliverability of shale gas are closely linked to the presence of multi-scale fractures, including fractures and faults, within organic-rich shales. This study aims to investigate the fracture system of the Longmaxi Formation shale in the Changning Block of the southern Sichuan Basin and quantify the influence of multi-scale fractures on shale gas capacity and deliverability. The fracture system was analyzed through outcrop, core observations, and 3D seismic interpretation. Criteria for fault classification were established based on the horizon, throw, azimuth (phase), extension, and dip angle. The Longmaxi Formation shale mainly comprises shear fractures that form under multi-phase tectonic stress, characterized by large dip angles, small extensions, small apertures, and high density. The high content of organic matter and brittle minerals in the Long 1-1 Member facilitates the occurrence of natural fractures, which somewhat enhance shale gas capacity. Reverse faults with a dip angle of 45–70° exist vertically, while laterally, there are early-stage nearly E-W faults, middle-stage NE faults, and late-stage NW faults. Based on the established criteria, faults that cut upward through the strata in and above the Permian with a throw greater than 200 m and a dip angle greater than 60° have the greatest influence on shale gas preservation and deliverability. These results provide important guidance for shale gas exploration and development in the Changning Block and contribute to our understanding of the relationship between multi-scale fractures and shale gas capacity and deliverability.
Multi-scale Fractures and Their Influence on Shale Gas Deliverability in the Longmaxi Formation of the Changning Block, Southern Sichuan Basin, China

The capacity and deliverability of shale gas are closely linked to the presence of multi-scale fractures, including fractures and faults, within organic-rich shales. This study aims to investigate the fracture system of the Longmaxi Formation shale in the Changning Block of the southern Sichuan Basin and quantify the influence of multi-scale fractures on shale gas capacity and deliverability. The fracture system was analyzed through outcrop, core observations, and 3D seismic interpretation. Criteria for fault classification were established based on the horizon, throw, azimuth (phase), extension, and dip angle. The Longmaxi Formation shale mainly comprises shear fractures that form under multi-phase tectonic stress, characterized by large dip angles, small extensions, small apertures, and high density. The high content of organic matter and brittle minerals in the Long 1-1 Member facilitates the occurrence of natural fractures, which somewhat enhance shale gas capacity. Reverse faults with a dip angle of 45–70° exist vertically, while laterally, there are early-stage nearly E-W faults, middle-stage NE faults, and late-stage NW faults. Based on the established criteria, faults that cut upward through the strata in and above the Permian with a throw greater than 200 m and a dip angle greater than 60° have the greatest influence on shale gas preservation and deliverability. These results provide important guidance for shale gas exploration and development in the Changning Block and contribute to our understanding of the relationship between multi-scale fractures and shale gas capacity and deliverability.

In the Sichuan Basin, a major shale gas province in China, organic-rich shales occur in the Upper Sinian Doushantuo Formation, Lower Cambrian Shuijingtuo Formation (Niutitang Formation, Jiulaodong Formation, and Qiongzhusi Formation), and Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation (“Wufeng Formation–Longmaxi Formation”). The Wufeng Formation–Longmaxi Formation organic-rich marine shales feature high TOC, large thickness, high maturity, a high brittleness index, and high gas content. Some shale gas fields, including Jiaoshiba, Changning, Zhaotong, Weirong, and Luzhou, have been established. The age-old over-mature shales in the Longmaxi Formation underwent multi-phase structural deformation; thus, shale gas preservation conditions vary greatly from area to area. Owing to the dual effects of the Tethyan tectonic and Circum Pacific tectonic domains, the Sichuan Basin (especially the basin margin) experienced complicated structural evolution and severe structural deformation, giving rise to diverse structural styles, which led to various complicated preservation conditions. There are many factors affecting shale gas preservation, and the most dominant factor is the occurrence of fractures (including faults and fractures). The formation of fractures is governed by the mechanical properties and stress loads acting on rocks. In the absence of stress, rocks remain crack-free. However, under continuous stress, rocks undergo deformation and develop microcracks. As stress increases further, these microcracks may progress into visible fractures, eventually forming faults. That is to say, faults gradually evolve from microcracks. In general, we can classify it into three types: microscale, small-scale, and large-scale. Folds and faults dominate rock deformation and natural fracture density and consequently control the shale gas enrichment and deliverability. Especially, fault properties, size, association, phase, and derivative structural fractures are major factors for shale gas preservation. In complex structure zones with fractures at the basin margin, multi-scale fractures may have greater effects on shale gas deliverability. Hence, it is important to characterize the fractures in complex structure zones and investigate their influences on shale gas-bearing capacity and deliverability for high-efficiency shale gas exploration and production. The Changning Block lies at the southern margin of the Sichuan Basin and is a national shale gas demonstration area in China. A package of organic-rich shales (generally thicker than 25 m) is consistently deposited in a deep-water shelf environment in the first member of the Longmaxi Formation (Long 1 Member). This is the material basis of shale gas enrichment. However, different gas testing results and production capacities in minor-yield wells, dry wells, and high-yield wells indicate the close relationship between fractures and shale gas deliverability, which has not been quantified. In this paper, with the shales of the Longmaxi Formation in the Changning Block as an example, the fracture system is comprehensively investigated through outcrop and borehole core observations and 3D seismic interpretation to identify the features of fractures of different sizes and types in high-graded shale gas accumulations. Then, the criteria for fault classification are established, and the relation between natural fractures and shale gas-bearing capacity and the relation between faults and shale gas deliverability is clarified. The study results provide technical support for efficient shale gas exploration and production in the complex structural zones with fractures at the basin margin.

The Changning Block is located at the intersection of the southern Sichuan fold belt and the Loushan faulted fold belt, the major part of which lies in the Jianwu syncline. Structurally, it is adjacent to the Changning anticline, Xuyong syncline, and Gaomuding structures on the east, the Baiyanglin and Dazhai anticlinal structures on the south, the Jiacunxi structure on the west, and the Lianhuasi, Laowengchang, and Fujiamiao structures on the north (Figure 1A). The study area experienced multi-phase, multi-directional tectonic movements in the Caledonian, Hercynian, Indosinian, Yanshanian, and Himalayan, with the structural style finalized at the end of the Himalayan. It is in a structural triangle against compressive stress from the eastern Sichuan-western Hunan and Hubei structural belt on the east, remote compressive stress transfer from the Longmenshan Mountains on the west, the constraint of the Sichuan Basin and Huayingshan fracture zone on the north, and compression and uplifting caused by structural transformation in the Ziyun-Luodian fracture zone on the south, where there are diverse and complex structural systems, including folds, faults, and fractures. The Changning anticline is axially in the NWW direction. Radiating from the core to the margin, the Cambrian, Ordovician, Silurian, Permian, Triassic, and Jurassic strata crop out in turn. A series of thrust faults, mostly in the NE and NNW directions, often penetrate the Cambrian in the core. Within the anticline, there are well-developed secondary folds. At the steep NE flank, the Dongguancun nosing structure extends in the NE direction, and the east end plunges into the Yingpanshan anticline and Xuyong syncline and vanishes into the nearly E-W-trending Xuyong syncline. The SW flank is gentle and transits gradually to the Jianwu syncline. The Middle Jurassic strata crop out in the core, and the Lower Jurassic and Triassic strata crop out at both wings of the Jianwu syncline (Figure 1A). Owing to the Duyun tectonic movement, most of the Sichuan Basin was enclosed by the Central Sichuan Underwater Uplift, the Niushoushan-Central Guizhou Uplift, and the Jiangnan-Xuefeng Uplift to form a large deep-water shelf-dominated depression from the late Ordovician to the early Silurian. Rapid transgression in the depression gave rise to an extensive dysoxic/anoxic deep-water shelf environment, in which cemented fiberized or lumpy remains and excrement of prolific lower siliceous ancient organisms, e.g., graptolite, sponge spicules, and foraminifera, settled underwater. As a result, a package of deep-water organic-rich black siliceous shales formed in the early Rhuddanian–Aeronian. From the middle and late Aeronian to the Telychian, when the dysoxic/anoxic environment was destroyed due to sea level drop, a package of black silty shales was deposited in the semi-deep to shallow-water shelf, which changed from the deep-water depression, with extraneous terrigenous clastic sediments. The cumulative thickness of organic-rich (TOC >2%) shales exceeds 30 m (Figure 1B).

For fault interpretation, a 3D merged seismic survey across Wells N201, N209, and N216 in the Changning Block was acquired. Good data quality allows reliable correlation and tracking for detailed structural interpretation. This study focuses on the faults and folds in the Longmaxi Formation. Seismic data were evaluated to meet the requirements of the technical regulations. The production data of 49 horizontal wells (incl. N201, N209, N213, and N203) with a similar production system in the study area were collected to investigate the correlation between fault features and shale gas deliverability. Outcrop and borehole core observations were performed to obtain the fracture parameters.

Through observations with 190 outcrop fracture photos taken at 8 points (e.g., Meidong, Shuanghe, Yanshatian, Xiazitian, Nanzhulin, and Shizitan) at the NE and SW flanks of the Changning anticline and 221 core fracture photos of 191 m borehole cores acquired from 6 wells (i.e., NH18-7, N209, N213, N215, N216, and N227), the fracture extension, aperture, density, degree of filling, and occurrence (strike and trend) were obtained.

Seismic data processing and interpretation were performed using LANDMAK2003.12.13 with the bin of 10 × 10 to investigate multi-phase fault extension, intersection, and evolution and obtain some fundamental fault parameters (incl. fault strike, extension, fault throw, faulted horizon, and dip angle).

Based on the average daily output of 49 horizontal wells with a similar production system in a year, the average daily output and midpoint distance between A (the starting point of the horizontal section) and B (the endpoint of the horizontal section) were mathematically fitted. Then, the fault effects on shale gas deliverability were investigated using different classification criteria based on the threshold of the average daily output of 10 × 104 m3/d to separate high-yield wells from low-yield wells. In addition, we analyzed the relationship between the degree of fracture development and gas content. Obtaining gas content data for shale gas typically involves core analysis or logging. The physical parameters and gas content of shale gas reservoirs can be determined by obtaining shale core samples and making thin sections for observation and testing. Electronic, sonic, radiation, and other logging tools are used to measure the formation within the wellbore, and based on measurement results, the gas content of shale gas can be calculated. In this paper, we did not conduct actual measurements but used existing data.

Due to multi-phase tectonic processes in the topographically complex Changning anticline, the Longmaxi Formation shales are rich in fractures, mainly shear, tensile, and regional vertical fractures. Shear fractures, including plane and sectional fractures, feature straight, smooth fracture faces, most of which are closed. Plane shear fractures formed before the fold and were widely distributed in the study area. These fractures with straight fracture faces and regular occurrence intersect rock formations vertically (75–90°) or at a high angle (45–75°) and usually occur inside formations (Figure 2A,B). Sectional shear fractures are similar to plane shear fractures, except they intersect rock formations at low angles. Sectional shear fractures form later than plane shear fractures and are the product of folding deformation (Figure 2C,D). Tensile fractures were generated by tensile stress and feature rough faces, irregular geometry, and small extensions. These fractures were heavily weathered and may only be observed at the turning point of the anticline. However, in outcrops, it is difficult to observe tensile fractures. Regional vertical fractures are structural fractures generated by regional shearing after the major structure was shaped, and these fractures could be detected at some observation points. They may have been formed by regional horizontal shear deformation. According to the statistics, outcrop fractures in the Longmaxi Formation shales mostly extend for less than 1 m (30.9%) and 1.0–2.0 m (39.1%) inside the formations, followed by 2.0–4.0 m (16.7%) and 4.0–6.0 m (10.2%). Only 3.1% of fractures, mainly sectional fractures, extend for more than 6.0 m and penetrate the formations (Figure 3A). Fractures in the Longmaxi Formation shales with a linear density of 3.0–8.0/m account for 50.3%, followed by fractures with a density less than 3/m, accounting for 31.4%, and of 8/m, accounting for 18.3% (Figure 3B), regardless of folds and faults. Fracture spacing refers to the distance between two neighboring fractures at the same observation point. Fractures with a spacing < 1.0 m account for 67.4%, mainly occurring in mudstones. Fractures with a spacing of 1.0–3.0 and 3.0–6.0 m account for 20.6 and 10.3%, respectively. About 1.7% of fractures show a spacing of >6.0 m (Figure 3C). In the Longmaxi Formation shales, high-angle and vertical fractures are dominant, accounting for 58.1 and 29.5%, respectively, followed by low-angle fractures (9.4%); horizontal fractures are seldom observed (Figure 3D). The occurrence of more than 490 groups of outcrop fractures observed at the Changning anticline was restored to its original state before stratigraphic deformation, and rose diagrams were made for plane shear fractures and sectional shear fractures. There are six groups of azimuthally predominant plane shear fractures in E-W (275° ± 5°), NW (325° ± 10°), NNE (15° ± 5°), SW (225° ± 5°), NEE (70° ± 5°), and SSE (160° ± 5°) directions, and three groups of azimuthally predominant sectional shear fractures in NWW (280° ± 5°), NE (30° ± 10°), and SE (220° ± 5°) directions in the Longmaxi Formation shales (Figure 3E). According to genetic mechanisms and regional structural evolution, six groups of plane shear fractures were classified into three packages. The early-phase X-shaped conjugated plane shear fractures of groups (1) and (4) and the sectional shear fractures of group (7) correspond to palaeo-tectonic stress in a nearly SN direction. Plane shear fractures of groups (2) and (5) and sectional shear fractures of group (8) constitute a package with the maximum principal stress in the NW direction. Plane shear fractures of groups (3) and (6) and sectional shear fractures of group (9) are the product of a uniform stress field with the maximum principal stress in a NE direction.

In light of their geologic origin, fractures in the Longmaxi Formation shales are classified into structural and non-structural fractures, with the structural fractures in dominance. Fractures of tectonic origin include shear fractures, tensile fractures, compound fractures, and slip fractures generated by tectonic processes. Shear fractures are characterized by straight, smooth fracture faces and large extensions. A single shear fracture with a smooth face often penetrates the core, and several fractures may intersect at specific angles (Figure 4A,B). Tensile fractures can only be observed on some cores and are characterized by rough faces, small extensions, and heterogeneous widths. Tensile fractures may intersect to form a network and are usually partially or completely filled with calcites (Figure 4C). Early shear fractures generated by shear stress may be reworked by late local tensile stress to form compound fractures, generally open with a large aperture (width) and completely or partially filled with thick calcites (Figure 4D). Slip fractures generated by tectonic processes are the product of intra-stratal slippage along mud shale bedding planes and are usually filled with calcites, and they are characterized by obvious scraping traces and mirror faces (Figure 4E). Non-structural fractures include pressolutional fractures and interbedded lamellation fractures. Pressolutional fractures are the product of resolution induced by sedimentary loading in the diagenetic process of mud shales or differential corrosion of mud shales. Interbedded lamellation fractures occur at the weak planes of rocks under strong hydrodynamic conditions and are generally unfilled or partially filled with calcites and pyrites (Figure 4F). According to the statistics, the borehole core fracture density is far below the outcrop fracture density and varies with wells. Horizontal fractures, mainly horizontal slip, interbedded, and nearly horizontal shear fractures, only account for 11% of the Longmaxi Formation shales. High-angle and vertical structural fractures account for 46 and 35%, respectively (Figure 5A). This indicates intense tectonic stress after the deposition of Longmaxi Formation shales. The borehole core fractures with an aperture of 0.5–1 mm account for 34%; those with an aperture < 0.5 mm, mainly microfractures partially filled with calcites, account for 16%. Some large vertical fractures completely filled with calcites were observed to be over 3 mm wide and extend long distances (Figure 5B). Partially filled and completely filled borehole core fractures account for 22.8 and 51.2%, respectively; unfilled fractures only account for 26.4% (Figure 5C). Fractures are mainly filled with calcites, followed by hybrid calcites and pyrites and some clay minerals, asphaltene, and quartz (Figure 5D). The fractures in the Long 1–1 Member in Wells N201 and N209 interpreted from logging data were analyzed to examine fracture density in the vertical direction. It is found that Long 1–1 is rich in fractures, mainly bedding fractures and microfractures, as well as some oblique fractures. The fracture density mostly ranges from 2 to 30/m and increases downward. It is small in Layer 4# and reaches over 30/m at the bottom, close to the Wufeng Formation, due to numerous bedding and net-shaped fractures (Figure 6). In addition, the tectonism-dominated high-angle fractures (including vertical fractures) are rare, mainly in Layers 1–3# and at the bottom of Layer 4#, where the fracture density is 0–3/m. The high-angle fracture density at Well N201 in the central part of the study area is smaller than at Well N209 (Figure 6).

Fault features are complex in the vertical and lateral directions. Vertically, there are mainly reverse faults. Following faulted horizon and size, the reverse faults are classified into three types: reverse faults cutting from the Wufeng Formation–Longmaxi Formation to the Permian, reverse faults cutting from the Cambrian bottom to the Wufeng Formation–Longmaxi Formation, and reverse faults cutting the Wufeng Formation–Longmaxi Formation. Laterally, there are mainly NE and NW faults and nearly E-W faults. The faults in the western part are large and mainly extend in a NE direction; these faults mostly penetrate the Permian. The faults in the central part are small and extend inside the Wufeng Formation–Longmaxi Formation. In the N209 well field in the eastern part, except for two large faults extending to the surface, other faults extend in NE and NW directions with different dip angles and penetrate the formations from the Cambrian bottom to the Wufeng Formation–Longmaxi Formation (Figure 7). Inconsistent fault strikes in the Longmaxi Formation exhibit obvious multi-phase reworking, particularly the NE faults, which generally extend in a NE direction and have two or three branches in NE and NW (NWW) directions. According to the mechanism of compressive stress, the NE faults formed earlier than the NW faults. It is supposed that small-scale, underdeveloped faults extending in a nearly E-W direction formed earlier than the NE faults because there are no distinct superposed faults. In general, fault evolution in the study area is mainly related to 3-phase tectonic movements, which agrees with the relationship derived from outcrop fractures. The compression from south to north in the Daloushan structural belt at the early stage gave rise to the folds and faults in a nearly E-W direction. The compression in an NW direction caused by the uplifting of the Qinghai-Tibet Plateau at the middle stage led to extensive NE faults in the study area. The compressive stress in a NE direction caused by the combined effect of the Jiangnan–Xuefeng Uplift and Central Sichuan Uplift at the late stage resulted in NW faults. All the above faults constitute the fault system nowadays in the study area. According to the statistics, fault extension is mainly within 10 km and seldom larger than 3 km. The faults with the extension <1 and 1–3 km account for 46 and 35%, respectively (Figure 8A). Fault throw ranges from 20 to 900 m, and most are small-scale faults (Figure 8B). The dip angle ranges from 30 to 70°. The faults with dip angles <45°, 45–60°, and >60° account for 53, 16, and 31%, respectively (Figure 8C).

Fault type, phase (occurrence), size, association, and relation with in situ stress are the major controls on shale gas deliverability. Large faults may destroy shale gas preservation conditions. The faults with appropriate size may be less destructive to shale gas accumulations, and associated (derivative) natural fractures may facilitate shale gas desorption and improve gas-bearing capacity. There are no unified criteria for fault classification in the industry. Here, the classification criteria for faults in the Longmaxi Formation are established with the faulted horizon, fault throw, phase, extension, and dip angle of the fault surface (Table 1 and Figure 9).

The vertical core fractures in the Long 1-1 Member in Wells N201 and N209 were observed and collected to investigate the relation between fracture density and shale gas-bearing capacity. Two obvious characteristics are found. First, natural fractures are remarkably developed in the Long 1-1 Member in both wells. The fractures mainly include bedding fractures and microfractures. Some medium-angle and high-angle shear fractures are observed at local intervals. Net-shaped fractures are seen at the bottom, close to the Wufeng Formation, and are mostly filled with calcites and pyrites. Second, fractures mainly occur in Layers 1–3# and at the bottom of Layer 4# in the Long 1-1 Member. The fracture density ranges from 2.3 to 30/m. There are numerous bedding and net-shaped fractures in some intervals, with the fracture density up to 50/m locally. According to the log data of Wells N201 and N209, brittle mineral content, TOC, and gas content in the target intervals directly correlate with fracture density. In other words, large fracture densities often correspond to high brittle mineral content, TOC, and gas content. Further analysis reveals that small fractures developed within the formation without disrupting the continuity of the top and bottom plates can be an advantageous channel for the lateral migration of shale gas and a favorable site for the local accumulation of shale gas. Under good preservation conditions, generally, the higher the density of the fracture development within the formation, the higher the gas content of the shale. For Well N201, the correlation coefficients between fracture density, relative brittle mineral content, and TOC are estimated to be 0.58 and 0.53, respectively. When the brittle mineral content is >50% and TOC is >3%, the fracture density is usually >2.4/m. Meanwhile, the gas content increases with the linear fracture density. Given the largest fracture density of 27/m, the brittle mineral content is 68.9%, TOC is 9.7%, and the gas content is 9.8 m3/t (Figure 10A,B). For Well N209, the correlation coefficients between fracture density, brittle mineral content, and TOC are estimated to be 0.51 and 0.61, respectively. Given the largest fracture density of 29.5/m, the gas content is 8.9 m3/t, the relative brittle mineral content is 63.2%, and the TOC is 8.0% (Figure 10C,D). Obviously, the degree of fracture development has already reached a point where it disrupts the preservation conditions of shale gas. In that case, there may not be a positive correlation between fracture density and gas content but rather a negative correlation. Natural fracture density is closely linked to brittle mineral content and TOC. At the bottom of the Longmaxi Formation, the brittle mineral content and TOC increase quickly, and the fracture density peaks. These well-developed fractures serve as the pore space for shale gas accumulation and pathways for gas flow. This integrated source-reservoir mechanism further improves the shale gas-bearing capacity.

Initially, we attempted to use the test production rate to quantify the relationship between faults and gas production. However, we found that many factors, especially engineering measures, influenced the testing production rate, and the development of faults was only a small aspect. Therefore, we used the daily production rate for one year to illustrate their relationship for statistical analysis accurately.

Shale gas deliverability is closely related to fault throw (Figure 11). The 1st-order and 2nd-order faults have large throws and develop crushed zones and large-scale fractures, which are favorable for hydrocarbon expulsion but not for shale gas preservation. The wells close to the 1st-order and 2nd-order faults generally demonstrate low yield. In contrast, the wells 1.7 km from the 1st-order faults and 1.3 km from the 2nd-order wells obtain a high yield (≥10 × 104 m3/d on average). The 3rd-order faults have relatively small throws and low destructibility. The wells 0.9 km from the 3rd-order faults can obtain a high yield. The 4th-order and 5th-order faults have small throws and thus little influence on shale gas preservation and deliverability. The wells 0.4 km from the 4th-order and 5th-order faults can obtain high yields.

If a fault cuts many horizons, the long crushed zone extending in the vertical direction will lead to insufficient sealing capacity. Particularly, a deep-seated fault that cut downward into the basement and extends upward to the surface is unfavorable for shale gas preservation. According to the relation between the faulted horizon and average daily shale gas output, the 1st-order faults cut from the Cambrian to the surface; in the zones 5 km near these faults, almost all shale gas accumulations are destroyed, with no oil/gas showing in almost all wells. The 2nd-order faults cut from the Wufeng Formation to the Permian (Figure 12A). Shale gas may migrate along the fault surface into conventional reservoirs when the target interval is sufficiently connected with the strata cut by the 2nd-order faults. As the fault throw decreases, the probability of strata connectivity declines, and the sealing capacity is enhanced accordingly. The 2nd-order faults are classified into large-scale and small-scale faults per the fault throw of 200 m. According to the statistics, the wells should be drilled at least 1 and 0.8 km away from large-scale 2nd-order faults and small-scale 2nd-order faults to obtain a high yield (≥10 × 104 m3/d on average). The 3rd-order faults cut from the Cambrian to the Longmaxi Formation and mainly occur in the lower part of shale gas zones; theoretically, such faults have a small impact on shale gas preservation (Figure 12B). The 3rd-order faults are also classified into large-scale faults and small-scale faults in accordance with the fault throw of 200 m for regression analysis. It is indicated that the wells should be deployed at least 1 km away from the large-scale 3rd-order faults to obtain a high yield. The wells close to the 4th-order faults within the Wufeng Formation–Longmaxi Formation all demonstrate high yield (Figure 12C), indicating that such small faults and associated fractures facilitate the desorption of adsorbed gas and serve as migration pathways for shale gas enrichment.

The faults in the study area can be divided into early-stage nearly E-W faults, middle-stage NE faults, and late-stage NW faults. The early-stage, nearly E-W faults are fold-associated small faults and are in the minority in the study area. Such intra-stratal faults with small throws are almost non-destructive to shale gas preservation (Figure 13A). The middle-stage NE faults are extensive in the study area, with greatly varied throws and usually cutting from the Longmaxi Formation to the Permian. These faults are classified into large-scale and small-scale faults as per the fault throw of 200 m. According to the statistics, the wells should be deployed at least 1.1 km from such large-scale faults to obtain a high yield (Figure 13B). The late-stage NW faults usually cut from the Longmaxi Formation to the Ordovician; the wells should be deployed at least 1.2 km away from such large-scale faults to obtain a high yield (Figure 13C). In summary, the early E-W faults in the study area positively affect shale gas deliverability to some extent. For NW and NE faults with varied sizes, small-scale faults with a throw below 200 m have a small impact on shale gas preservation, while large-scale faults with a throw above 200 m are unfavorable for shale gas preservation.

Fault extension has little influence on the sealing capacity. The faults with small extensions often occur within strata and are nondestructive to shale gas preservation. The faults with large extensions may cut a number of horizons and destroy the top and bottom of shale gas zones or turn up within strata, which depends on fault throw, dip angle, and faulted horizon. According to the statistics, the average daily shale gas output is irrelevant to fault extension (Figure 14). Shale gas preservation depends on fault throw, faulted horizon, and azimuth, which are irrelevant to fault extension. A fault extending over 5 km may terminate at the Wufeng Formation and not incise overlying young formations; thus, such faults have little influence on shale gas preservation.

The dip angle of the fault surface greatly impacts vertical sealing capacity. A high-angle fault and its associated high-angle fractures may somewhat impair the self-sealing performance of shale gas reservoirs, which is unfavorable for shale gas preservation. A low-angle fault with a small throw may have limited horizons. Sealing performance tends to be good at the turning point from large to small dip angles. The faults in the study area are classified into low-angle, medium-angle, and high-angle faults. According to the statistics of the relation between fault types with different dip angles and average daily shale gas output, the wells should be deployed at least 1.4 km away from high-angle faults, 1 km away from medium-angle faults, and 0.4 km away from low-angle faults to obtain a high yield (Figure 15). This means that low-angle faults may facilitate shale gas preservation, whereas medium- to high-angle faults are unfavorable for shale gas preservation, particularly high-angle faults, which may play a destructive role.

Outcrop fractures in the Longmaxi Formation in the Changning Block, southern Sichuan Basin, are mainly shear fractures of tectonic origin, followed by some tensile fractures and regional vertical fractures, which generally feature a large dip angle, a small extension, and a large density. Borehole core fractures involve shear fractures, tensile fractures, compound fractures, and slip fractures generated by tectonic processes, as well as non-structural pressolutional fractures and interbedded lamellation fractures. Structural fractures are mainly high-angle and vertical shear fractures with small widths, most of which partially or completely filled with calcites. Fault features are complex in the vertical and lateral directions in the study area. Vertically, there are mainly reverse faults with a dip angle of 45–70°, which include the faults extending to the surface at the east boundary, the faults cutting from the Wufeng Formation–Longmaxi Formation to the Permian, the faults cutting from the Cambrian bottom to the Wufeng Formation–Longmaxi Formation, and the faults within the Wufeng Formation–Longmaxi Formation. Laterally, there are mainly NE and NW, followed by the nearly E-W faults. Fractures and faults are mainly the products of 3-phase tectonic movements. The E-W faults are the earliest products, followed by the NE faults; the NW faults are the latest. The classification criteria for faults in the Longmaxi Formation are established in accordance with the faulted horizon, fault throw, azimuth (phase), extension, and dip angle of the fault surface. Faults of different orders and types have different impacts on shale gas deliverability. Fault throw, faulted horizon, azimuth (phase), and dip angle are the major controls. The faults upwardly incising the Permian and its overlying formations with a throw >200 m and a dip angle >60° have a great impact on shale gas preservation and deliverability. Fault extension does not correlate well with shale gas deliverability. The study of multi-scale fractures and their influence on shale gas deliverability is of great reference value for efficient shale gas exploration and development.