Wei He,Tao Li,Bixin Mou,Yuxue Lei,Jinhui Song,Zhicheng Liu
Lithofacies Types and Physical Characteristics of Organic-Rich Shale in the Wufeng–Longmaxi Formation, Xichang Basin, China
The shale of the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation in the Xichang Basin is the main replacement horizon for the shale gas exploration being conducted in the Sichuan Province, except for the Sichuan Basin. The fine identification and classification of the types of shale facies are important for shale gas exploration and development evaluation. However, the lack of systematic experimental studies on rock physical characteristics and micro-pore structures leads to a lack of physical evidence for the comprehensive prediction of shale sweet spots. Therefore, the present study used different means, such as core observation, total organic carbon content (TOC), helium porosity measurement, X-ray diffraction analysis, and mechanical properties analysis, in combination with the analysis of the whole rock mineral composition and characteristics of shale, for the identification and classification of the lithofacies of the shale layer, the systematic petrology and hardness measurement of the shale samples with different lithofacies, and discussion of the dynamic and static elastic properties of the shale samples and the control factors. It was revealed that nine types of lithofacies existed in the Wufeng Formation— the Long11 sub-member in the Xichang Basin, among which moderate organic carbon content–siliceous shale facies, moderate organic carbon content–mixed shale facies, and high-organic carbon content–siliceous shale facies were the best lithofacies with the optimum reservoir conditions, providing sufficient space for shale gas accumulation. The siliceous shale facies mainly developed organic pores and fractures, and the pore texture was excellent overall. The mixed shale facies mainly developed intergranular pores and mold pores, with a preference toward pore texture. The argillaceous shale facies mainly developed dissolution pores and interlayer fractures, and the pore texture was relatively poor. The geochemical characteristics of the organic-rich shale samples with TOC > 3.5% revealed that the sample was composed of microcrystalline quartz grains as the rock support framework, while the intergranular pores were located between the rigid quartz grains, which exhibited hard pores in the analysis of their mechanical properties. In the relatively organic-poor shale samples with TOC < 3.5%, the quartz source was mainly terrigenous clastic quartz, and the sample was composed of plastic clay minerals as the rock support skeleton, while the intergranular pores were located between argillaceous particles, which exhibited soft pores in the analysis of their mechanical properties. The difference in the rock fabric of the shale samples resulted in an ″initial increase followed by a decrease″ trend of velocity with quartz content, with the organic-rich shale samples exhibiting low velocity–porosity and velocity–organic matter content change rate, and the two kinds of rocks were easier to distinguish in the correlation diagram of the combined elastic parameters such as the P-wave impedance–Poisson ratio and the elastic modulus–Poisson ratio. The samples dominated by biogenic quartz exhibited greater hardness and brittleness, while the samples dominated by terrigenous clastic quartz exhibited lower hardness and brittleness. These results could serve as a basis for logging interpretation and seismic ″sweet spot″ prediction of high-quality shale gas reservoirs in Wufeng Formation–Member 1 of the Longmaxi Formation.
Lithofacies Types and Physical Characteristics of Organic-Rich Shale in the Wufeng–Longmaxi Formation, Xichang Basin, China

The shale of the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation in the Xichang Basin is the main replacement horizon for the shale gas exploration being conducted in the Sichuan Province, except for the Sichuan Basin. The fine identification and classification of the types of shale facies are important for shale gas exploration and development evaluation. However, the lack of systematic experimental studies on rock physical characteristics and micro-pore structures leads to a lack of physical evidence for the comprehensive prediction of shale sweet spots. Therefore, the present study used different means, such as core observation, total organic carbon content (TOC), helium porosity measurement, X-ray diffraction analysis, and mechanical properties analysis, in combination with the analysis of the whole rock mineral composition and characteristics of shale, for the identification and classification of the lithofacies of the shale layer, the systematic petrology and hardness measurement of the shale samples with different lithofacies, and discussion of the dynamic and static elastic properties of the shale samples and the control factors. It was revealed that nine types of lithofacies existed in the Wufeng Formation— the Long11 sub-member in the Xichang Basin, among which moderate organic carbon content–siliceous shale facies, moderate organic carbon content–mixed shale facies, and high-organic carbon content–siliceous shale facies were the best lithofacies with the optimum reservoir conditions, providing sufficient space for shale gas accumulation. The siliceous shale facies mainly developed organic pores and fractures, and the pore texture was excellent overall. The mixed shale facies mainly developed intergranular pores and mold pores, with a preference toward pore texture. The argillaceous shale facies mainly developed dissolution pores and interlayer fractures, and the pore texture was relatively poor. The geochemical characteristics of the organic-rich shale samples with TOC > 3.5% revealed that the sample was composed of microcrystalline quartz grains as the rock support framework, while the intergranular pores were located between the rigid quartz grains, which exhibited hard pores in the analysis of their mechanical properties. In the relatively organic-poor shale samples with TOC < 3.5%, the quartz source was mainly terrigenous clastic quartz, and the sample was composed of plastic clay minerals as the rock support skeleton, while the intergranular pores were located between argillaceous particles, which exhibited soft pores in the analysis of their mechanical properties. The difference in the rock fabric of the shale samples resulted in an ″initial increase followed by a decrease″ trend of velocity with quartz content, with the organic-rich shale samples exhibiting low velocity–porosity and velocity–organic matter content change rate, and the two kinds of rocks were easier to distinguish in the correlation diagram of the combined elastic parameters such as the P-wave impedance–Poisson ratio and the elastic modulus–Poisson ratio. The samples dominated by biogenic quartz exhibited greater hardness and brittleness, while the samples dominated by terrigenous clastic quartz exhibited lower hardness and brittleness. These results could serve as a basis for logging interpretation and seismic ″sweet spot″ prediction of high-quality shale gas reservoirs in Wufeng Formation–Member 1 of the Longmaxi Formation.

Shale gas has emerged as a key unconventional oil and gas resource in China due to the rapid increase in overall energy demand. The black shale of the Upper Ordovician Wufeng–Lower Silurian Longmaxi Formation in the Sichuan Basin and its periphery has become the main location of shale gas exploration and development in China as it has a high organic matter content, moderate burial depth, and high organic matter evolution. Since 2009, Sinopec has had breakthroughs in the Fuling–Jiaoshiba region, and Petrochina has had breakthroughs in the Weiyuan–Changning block of Sichuan Province, thereby further promoting the commercial exploitation of shale gas in China. Currently, the most direct and effective methods available for shale gas exploration and development are the ones based on seismic data. For instance, seismic interpretation and attribute analysis are utilized to determine the structural form, mineral composition, reservoir physical properties, and organic matter content of shale reservoirs in the early exploration stage. In the later stage of development, the anisotropy, brittleness, and in situ stress characteristics of shale reservoirs are determined using seismic inversion and attribute modeling. The petrophysical characteristics of shale are the direct means to obtain the physical and mechanical characteristics of a shale reservoir based on seismic properties. The seismic elastic properties of shale and the associated influencing factors are studied mainly by performing systematic rock physics experiments and using the quantitative seismic rock physics model. Unlike China, foreign nations have been conducting studies on shale reservoir petrophysics for a long time. Vernik and Nur performed shale rock physics experiments and analyzed the effects of the organic matter content and maturity on rock velocity and anisotropy features by examining the anisotropy characteristics of Bakken shale under dry conditions. The authors indicated that the anisotropic characteristics of shale rocks are determined by the orientation of the rock minerals and the degree of fracture development parallel to bedding. Sondergeld and Rai experimentally measured the acoustic properties of Kimmeridge shale and reported a positive correlation between the organic matter content and the anisotropy intensity of the shale. In addition, it was reported that the increase in the organic matter content weakened the formation compaction. The authors also indicated that the hypothesis of weak anisotropy was no longer suitable for shale seismic forward modeling. Dewhurst analyzed the influence of maturity and principal stress direction on the anisotropy of shale. Deng Jixin et al. analyzed the variation law of the seismic elastic characteristics of Longmaxi shale rock through microstructure observation and petrophysical experiments and also discussed the influence of the differences in the sedimentary and diagenetic processes on the seismic elastic properties of Longmaxi shale rock. The experimental results revealed evident differences in the seismic elastic properties of shales in different regions and different layers, which were affected by the organic matter content, pore characteristics, composition characteristics, rock fabric, and reservoir conditions. In addition, certain systematic studies have been conducted on the lithophysical model for the quantitative characterization of the seismic elastic properties of shale. The main modeling methods include the use of the anisotropically self-consistent and differential equivalent modulus formulas to calculate the elastic anisotropy model of shale and then discuss the effects of the distribution characteristics of clay, TOC, and pore structure on the seismic elastic properties. Guo Zhiqi et al. proposed the relationship of the reservoir physical properties of organic matter, minerals, and fractures with the elastic anisotropy of shale based on organic matter, pores, and the spatial occurrence states of the main constituent minerals. Zhang Feng and Li Xiangyang studied the theoretical model of rock physics for organic-rich shale and discussed the influence of pore shape and mineral composition on the elastic properties of shale based on the self-consistent model and the differential equivalent medium model. Peng et al. suggested that the specific types and forms of quartz play a major role in controlling rock physical properties in shale. The above-stated experimental and petrophysical model studies on shale well support the ″sweet spot″ seismic prediction technology for shale gas reservoirs at the present stage. However, due to the limitations of the shale gas development technology and economic benefits, the domestic experimental studies on the seismic petrophysical properties of shale gas reservoirs remain focused on the middle–shallow reservoirs in the Sichuan Basin, particularly the Wufeng–Longmaxi Formation (buried depth of less than 3500 m). Wufeng–Longmaxi shale in the Xichang Basin has a large area of distribution in the middle and shallow layers, and research on the petrophysical properties of shale gas is scarce. The tectonic units of the Wufeng–Longmaxi shale in the Xichang Basin are considerably different from those in the Sichuan Basin. Differences exist in the shale mineral composition, rock fabric, pore structure, occurrence state of the organic matter, and stress field between the two basins. Consequently, certain differences exist in the seismic petrophysical properties of the middle–shallow shales in the Sichuan Basin, which cannot be arbitrarily applied. The exploration and development of the Wufeng–Longmaxi shale reservoirs in the Xichang Basin objectively require a systematic experimental study on the petrophysical properties of shale in the target region. In the present study, a systematic evaluation of the seismic petrophysical characteristics, static mechanical properties, and petrological characteristics of the shale samples from the Wufeng Formation and Longmaxi Formation in the Xichang Basin was performed, the change rules of the rock physical characteristics of the shale samples were summarized, and the main geological factors affecting the change in the rock physical properties were analyzed. The objective was to provide a basis for a good logging interpretation and seismic ″sweet spot″ prediction of the shale gas reservoirs in the Wufeng–Longmaxi Formation.

The Xichang Basin is located in the region where the Yangtze plate connects to the eastern margin of the Qinghai–Tibet Plateau, and this geotectonic position belongs to the southwest margin of the Yangtze plate, which spans the two secondary tectonic units of the Kang–Yunnan axis and the Upper Yangtze platform (Figure 1a). The Xichang Basin is located at the western margin of the Upper Yangtze plate, bounded by the Ebyan–Meigu fault in the east, the Zemuhe fault in the south, the Aninghe fault in the west, and the Dadu River in the north. This is a Mesozoic foreland basin that spreads from south to north and comprises five secondary depressions, namely, Mishi, Zhaojue, Ganluo, Magushan, and Meigu. The basement of the basin is composed of carbonate rocks, clastic rocks, and basalts of the Early Paleozoic and Middle Triassic eras. The area covered is approximately 16,000 km2. Since the formation of the basement, the basin has experienced multiple stages of tectonic movement. Currently, the basin mainly develops the north–south structure, which is dominated by a low and gentle open fold, which is the structural product of the Himalayan period. The Marine organic-rich mud shales deposited in the basin mainly span from the Upper Ordovician Wufeng Formation (O3w) to the Lower Silurian Longmaxi Formation (S1l) and are widely distributed in the Ganluo–Ebian region in the north of the basin, Meigu in the east, and Butuo and Zhaojue in the southeast, with an integration with the lower Upper Ordovician as well. The proximity of the basin to the Kangdian ancient land margin has led to great changes in the sedimentary environment of the basin, and the lithology has evident differences. According to the lithology and logging characteristics, the Longmaxi Formation is divided into the Long 1 member and the Long 2 member. The Long 2 member mainly comprises dark gray calcium siltstone with a small amount of gray–dark-gray limestone and is rich in graptolites, including Akidograptus sp. and Rastrites sp. The lithology of the Long 1 member is dominated by the gray–black shale and is rich in graptolites, such as Climacograptus sp. The Long 1 member has been the main exploration horizon between the two members and may be subdivided into the 2 layer (S1l12) and the 1 layer (S1l11) from shallow to deep. The Wufeng Formation (O3w)—the 1 layer (S1l11)—is the main shale gas-producing horizon and is further divided into 1–5 small layers (Figure 1b). The shale samples of the Wufeng–Longmaxi Formation measured in the present study were selected from four wells and six sections in Xichang Basin. A total of 125 plunger samples were drilled out (mainly vertical bedding samples), covering all five layers of the Wufeng Formation–Longl1 sub-member. The core was drilled into a standard plunger sample with a height of over 70 mm and then cut into a height of 40–55 mm through wire cutting. The end face was ground flat to ensure that the slope of the end face was less than 0.05 mm. This was to facilitate the accurate evaluation of the dynamic and static elastic properties. A few parts of the sample were analyzed using argon ion polishing scanning electron microscopy (AIM-SEM) to determine the mineral composition, microstructure, and pore characteristics of the sample. Meanwhile, the cut sample was also used for geochemical analyses, including the PANalytical X-ray diffractometer analysis and the determination of the total organic carbon content (TOC). In addition, the progressive and static elastic properties of the shale samples were evaluated under ″relative″ drying conditions (only crystal water and clay-bound water in the sample). The ultrasonic pulse penetration method was used for measuring the P- and S-wave velocities of the samples. The main frequencies of the P- and S-wave PZT transducers were 0.8 and 0.35 MHz, respectively, and the test errors of the P- and S-wave velocities were ±1.25 and ±2%, respectively. The confining pressure of the sample was maintained at 40 MPa, which is approximately equal to the effective pressure under reservoir conditions. After evaluating the dynamic elasticity of the sample, the Boolean hardness was measured to reflect the static mechanical properties of the sample.

The shale in the Xichang Basin was classified using the three-terminal diagram of siliceous minerals–clay minerals–carbonate minerals. The organic-rich shales (TOC ≥ 2.0%) were mainly located in the Wufeng Formation–Longl1 sub-member, the TOC of the 5 layer (S1l15) and the 4 layer (S1l14) was between 2.0 and 3.0%, and the lithology was mainly composed of mixed shale, with only a small amount of siliceous shale and argillaceous shale (Figure 2a). The average contents of siliceous minerals, clay minerals, carbonate minerals, and TOC in these samples were 41, 41, 18, and 2.37%, respectively. The total organic content (TOC) of some samples from layer 4 (S1l14) and layer 3 (S1l13) were between 2.0 and 3.0%, and the lithology was mainly composed of mixed shale, with a small amount of siliceous shale and argillaceous shale (Figure 2b). The average contents of siliceous minerals, clay minerals, and carbonate minerals in these samples were 49, 36, and 15%, respectively. The 3 layer (S1l13), 2 layer (S1l12), and 1 layer (S1l11) presented a TOC of over 3.5%, and the lithology was dominated by siliceous shale and mixed shale, with only a small amount of argillaceous shale (Figure 2c), in which the average clay mineral content was 30%, the average siliceous mineral content was 58%, the average carbonate mineral content was 12%, and the average TOC content was 4.22%.

Quartz grains are the main constituent minerals of the shale samples and also an important product of different shale diagenesis. Therefore, their variation characteristics are important indicators of the diagenetic process and structural differences of shale. The source of silica reportedly exerts an important influence on the diagenetic process of Longmaxi shale. The biological source of the siliceous components represents the flourishing of organisms, such as radiolarians, and also indicates that the primary productivity in the water reaches a high level, which causes the total organic carbon content to be high. A large amount of siliceous bio-decomposition renders pore water rich in silicon. With the increase in the buried depth, the reservoir temperature increases, and the amorphous SiO2 undergoes a change of spontaneous cementation of the quartz grains such that opal-A → opal-CT → compact microcrystalline quartz aggregates, forming a rock fabric with the microcrystalline quartz aggregates as the force skeleton. Meanwhile, this early cementation increases the rigidity of the skeleton, which weakens the effect of mechanical compaction and the orientation of clay particles while also preserving the primary intergranular pores, which is more conducive to the occurrence of organic matter. Therefore, the shale samples dominated by biogenic quartz have the characteristics of microcrystalline quartz grains constituting the rock skeleton and a high TOC content. In the shale segment dominated by terrigenous quartz, no early biogenic siliceous cementation occurs, and the clay particles rotate and orient under the action of the overlying pressure in the mechanical compaction stage to form the stress skeleton of the rock. Therefore, the terrigenous quartz-dominated shale is characterized by clay particles forming the rock skeleton and a relatively low TOC content. The early diagenetic cementation of biogenic quartz and its influence on the subsequent diagenetic process results in the evident difference in the rock fabric between the relatively organic-poor shale and the organic-rich shale, that is, the structure of the shale is controlled by bio-silicon. The variations in the rock fabric (skeleton supporting particles) of different shale samples also lead to a difference in the petrophysical properties and reservoir space. The contents of the major elements play important roles in the identification of siliceous genesis. Siliceous shale with different genesis has different petrochemical characteristics. Biogenic shales have high SiO2 and low Al2O3, FeO, and MgO characteristics. The trace element zirconium (Zr) can also be used to trace the source of quartz in shale samples. Zirconium is mainly present in heavy mineral zircon, representing terrigenous detrital quartz. The positive correlation between the content of trace elements zirconium and quartz (SiO2) reflects the contribution of terrigenous quartz to siliceous rocks, while the negative correlation between the content of trace elements zirconium and quartz represents the contribution of biogenic quartz to siliceous rocks. The content of trace elements zirconium and quartz in the experimental samples showed an inverted ″V″ shape (Figure 3). When the content of quartz was less than 48%, the content of trace elements zirconium and quartz were positively correlated, and the corresponding samples were mainly samples of relatively organic-poor shale (4 layer (S1l14) and the 5 layer (S1l15)), indicating that terrigenous clastic quartz was dominant in these shale samples. When the content of quartz is greater than 48%, there is a negative correlation between the content of zirconium and quartz, and the corresponding samples are mainly from organic-rich shale, indicating that the quartz in these samples is mainly biogenic quartz.

The key geological parameter of the ″North American shale gas revolution″ is the hydrocarbon generation potential of shale, and the key engineering technology used is horizontal well and fracturing. Since organic carbon is the material basis of shale gas enrichment and the influence behind the difference in the brittle mineral composition on the engineering technology of compressibility in shale gas reservoir development, the key to selecting lithofacies markers is to determine whether the markers are capable of reflecting the sedimentary environment and whether these would serve as a guide for the production practice. Reasonable selection of the markers for lithofacies classification should follow the following principles: ① effective reflection of the sedimentary environment factors; ② simple constituent lithofacies classification and evident and practical distinguishing marks; and ③ quantifiability, easy determination, and strong operability. The rock mineral composition is the direct reflection of the rock development environment and the fundamental factor that causes the diversity of rock types. Organic matter content indicates the hydrocarbon enrichment characteristics of fine-grained sedimentary rocks and plays an important role in reservoir classification and evaluation. Therefore, based on the traditional lithofacies classification and by integrating the fields of geology, development, and engineering, Peng Yongmin proposed the concept of petrological facies types by selecting three key parameters: lithology (lithology combination), organic carbon content (TOC), and mineral combination type. The aim was to determine the characteristics of hydrocarbon generation, storage, and late transformation of shale gas and thereby provide a direction for the optimization of shale gas exploration and development targets. The two key parameters of organic carbon content (TOC) and mineral assemblage type could be accurately obtained through experiments, causing the results of the lithofacies classification to be highly accurate. Therefore, in the present study, the mineral components and TOC were selected as the lithofacies classification indices to establish a comprehensive classification scheme for the shale lithofacies of the Wufeng–Longmaxi Formation (Figure 4a). The mineral components of the organic-rich shale in the Wufeng–Longmaxi Formation mainly include siliceous minerals, clay minerals, and carbonate minerals. As the first element of the lithofacies classification, the mineral composition may be accurately and quantitatively obtained using whole-rock X-ray diffraction analysis. The shale lithofacies were divided according to the three terminal tuples of siliceous minerals (quartz + feldspar), carbonate minerals, and clay minerals (Figure 4). When the siliceous mineral content was over 50%, it was classified as siliceous shale facies (S); when the clay mineral content was over 50%, it was classified as argillaceous shale facies (C); when the content of carbonate minerals was over 50%, it was classified as calcareous shale facies (CA); when the contents of all three kinds of minerals were below 50%, it was classified as mixed shale facies (M). Organic matter content is the second factor for the lithofacies division. Using the TOC content values of 2.0 and 3.5% as the limits, three types of shale were classified: shale with high organic carbon content (H) (TOC > 3.5%), shale with moderate organic carbon content (M) (3.0% ≤ TOC ≤ 3.5%), and shale with lower organic carbon content (L) (2.0% ≤ TOC < 3.0%) (Figure 4a). Gas content is a key indicator of whether the shale gas reservoirs have development potential; the lower limit of the gas content for the commercial exploitation of shale gas in the Longmaxi Formation of the Lower Silurian in China is 2.0m3/t. The gas content of shale in the Wufeng Formation–Long11 sub-member of the Zhaodi 1 well and Bucan 1 well in the Xichang Basin was 0.58–2.56 m3/t. Considering the gas content of 2.0 m3/t as the standard, the correlation fitting between the gas content and TOC was conducted. When the gas content was greater than 2.0 m3/t, the corresponding TOC content was approximately 3.5%; when the gas content was 1.5 m3/t, the corresponding TOC content was approximately 3.0%. In view of this, the limits of 3.0 and 3.5% were set for the TOC content. According to the above division principles, nine shale facies were identified in the organic-rich shale of the Wufeng Formation–Long11 sub-member in the Xichang Basin: lower organic carbon content–argillaceous shale facies (L-C), lower organic carbon content–siliceous shale facies (L-S), lower organic carbon content–mixed shale facies (L-M), moderate organic carbon content–argillaceous shale facies (M-C), moderate organic carbon content–siliceous shale facies (M-S), moderate organic carbon content–mixed shale facies (M-M), high-organic carbon content–argillaceous shale facies (H-C), high-organic carbon content–siliceous shale facies (H-S), and high-organic carbon content–mixed shale facies (H-M) (Figure 4b).

The main criteria for determining the dominant lithofacies include organic matter type and abundance, reservoir space type and development degree, and mineral type and content. The type and abundance of organic matter determine the hydrocarbon generation potential of shale. The hydrocarbon generation potential of type II kerogen is better than that of type III kerogen. The reservoir space type and development degree affect the shale reservoir performance. The content, rock fabric, and forms of brittle minerals determines the fracturing ability of shale. The higher the brittleness of the rock, the better the fracturing effect. The three types of lithofacies, S-M, M-M, and S-H, were developed in shallow gulf and lagoon environments, and their organic matter originated from lower marine organisms, planktic algae, and terrestrial plants, belonging to type III kerogen. These types are less affected by terrestrial input, and the organic matter is more enriched, with a high TOC of 3.5–5.85% and a high core gas content of 1.5–2.56 m3/t. Figure 5a depicts the variation in the TOC content with the quartz content in the shale samples. In the shale samples of the organic-rich shale section, the TOC content exhibited a positive correlation with the increase in the quartz content, while the relatively low-organic carbon shale sample (S1l15) presented no evident correlation between the two. The content of quartz, particularly biogenic quartz, indicates high primary productivity in the ancient ocean. Meanwhile, the biogenic quartz is involved in the early cementation process to increase the rigidity (compressive resistance) of the sediment skeleton, which leads to the preservation of the primary intergranular pores, thereby improving the retention rate of organic matter. The above reasons lead to a certain coupling relationship between the quartz content and the TOC content, and accordingly, the S1l11, S1l12, and S1l13 samples presented relatively high TOC content. Owing to the inhomogeneity of the organic-rich shale section, terrigenous quartz largely remains the silica source of certain samples, which results in the low TOC content of these samples. It is also possible that the sampled strata are close to the terrestrial source in the paleo-sedimentary environment, and the possibility of a mixed source of quartz grains exists, that is, the biogenesis and detrital quartz exist simultaneously. Figure 5b presents the variation in the shale sample porosity with the TOC content. The variation range of the shale sample porosity was 1.57–9.25%, and the porosity of shale with a relatively low organic carbon was generally not over 5%. However, the organic matter pores in high-quality shale contributed greatly to the total porosity of the shale, and the porosity and TOC content usually exhibited an evident positive correlation. The porosities of the siliceous shale phase and the mixed shale phase samples were evidently larger than that of the argillaceous shale samples.

The SEM mineral quantitative analysis of the typical samples of different lithofacies of shale revealed that the quartz particles in the siliceous shale facies samples formed a continuous rock skeleton through point and line contact and the illite and feldspar minerals were ″floating″ in the quartz skeleton. On the other hand, the shale samples of the argillaceous shale phase had the illite particles interlinked to form the rock skeleton, and the rigid particles, such as quartz, were ″suspended″ in the clay skeleton. The rock skeleton was gradually transformed from the clay grain support of the S1l15 to the quartz grain support of the S1l11, which was the result of differences in the sedimentation and diagenesis of shale with different rock facies. The pore types of the Wufeng–Longmaxi Formation mainly included organic pores (organic pores and organic fissures) and inorganic pores (denudation pores, interbedded cracks, intergranular pores, inter-crystal pores, and moldic pores) (Figure 6a–c). Pore composition differed significantly among different rock phases. In the siliceous shale facies samples, the organic pores, represented by organic pores and organic fractures, were relatively developed (Figure 6d–f). In the argillaceous shale facies samples, the inorganic pores, represented by denudation pores and interbedded cracks, were relatively developed (Figure 6b). In the mixed shale facies samples, the inorganic pores, represented by denudation pores and interbedded cracks, were relatively developed (Figure 6g–i). In general, the S-M, M-M, and S-H lithofacies exhibited various reservoir space types, excellent pore structure parameters, and good pore openness and connectivity. In particular, the S-H lithofacies had the best pore system development, providing a good space for shale gas accumulation (Figure 6a). These three types of lithofacies mainly developed clumpy, interstitial, and massive organic matter. The organic matter in the strips was characterized by primitive stomata with a simple structure, scattered distribution, and a pore size of less than 20 nm (Figure 6b). Intergranular pores developed between the interstitial organic matter and mineral particles, with a pore size of several hundreds of nanometers (Figure 6c). In the clumps of organic matter, liquid hydrocarbon bubble pores had developed, which were complex in structure and distributed in clusters, with pore sizes generally larger than 50 nm (Figure 6h,i).

The burial and uplift process of shale in the Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation could be roughly divided into four stages. The Silurian–Carboniferous stage: After the Longmaxi Formation was deposited, the study region remained calm in general, with the higher terrain in the northwest and the lower terrain in the southeast. It was a shelf environment, with the Shiniulan Formation mainly composed of carbonate rocks and the Hanjiadian Formation mainly composed of carbonate rocks and shale deposited continuously. At this time, the Longmaxi shale had its first burial depth. Under the influence of the Guangxi Movement and the Dian–Qian–Gui uplifting movement, the basin was uplifted as a whole and underwent weathering denudation for a long duration. The Devonian strata developed only in the graben formed by the Xiaojiang fault. In this period, the Longmaxi Formation of the basin experienced the first uplift. The Permian–Early Middle Triassic stage: In the Early Permian phase, with the rise of the global sea level, the southern part of the basin gradually deposited the Liangshan Formation and Qixia Formation, while the northern Biji Mountain was not deposited. As the sea continued to advance southward, the whole region was submerged and reduced to a broad sea carbonate platform. In the Late Permian, the strong action of the Tungwu Movement resulted in a regional uplift and stretching, thereby causing the differential uplift and fall in the Xichang Basin. The western part of the Xiaojiang fault rose and then underwent denudation, resulting in the absence of the Longmaxi shale in the western region. The Late Triassic–Paleogene stage: In the thermal subsidence stage of the Late Triassic, a tectonic transition occurred, and the Xichang basin evolved into a foreland basin that deposited the clastic rocks of Baiguowan Formation, which was thousands of meters thick. With the deposition of the Baiguowan Formation, the black shale of the Longmaxi Formation entered the oil generation stage under the influence of deep burial. With the continuous deepening of the burial depth, the black shale of the Longmaxi Formation completely entered the gas generation stage during the Middle Jurassic (burial depth exceeding 4000 m). The late Paleogene stage (the present stage): Under the influence of the Himalayan movement, the basin experienced multiple stages of uplift and denudation, and this large uplift of the basin led to the continuous uplift of the Longmaxi shale. According to the denudation thickness, present burial depth, rock mechanical parameters of the shale, and pressure variation during the process of hydrocarbon generation, the evolution of the pressure system in the process of burial uplift of shale was estimated. The fracture of the rock relies mainly on the lithology and its effective stress. The effective stress is associated mainly with the abnormal formation pressure during the hydrocarbon generation period, the temperature decrease caused by the strong uplift and denudation, and the horizontal tensile strain. Xichang Basin was in the stage of subsidence and burial from Paleozoic to Mesozoic, with a maximum burial depth of approximately 6500 m (Late Cretaceous), a static rock pressure of approximately 239 MPa (Figure 7A), and an effective pressure of approximately 76 MPa (Figure 7C). In the main hydrocarbon generation period, the continuous generation of hydrocarbon fluid, on one hand, increased the formation pressure and on the other hand, led to fluid retention between 2 and 3 km, and the underlying formation was overpressured (the calculated pressure coefficient of the inclusions was above 1.49). The increase in the formation pressure led to a decrease in the horizontal principal stress, as illustrated in Figure 7Ba, and the Longmaxi shale became prone to shear fracture. In the Yanshanian period, the maximum effective tectonic stress of Longmaxi shale was approximately 90.71 MPa, which is lower than the strength limit of shale (buried depth of 2 km, strength limit of 300 MPa) (Figure 7Bd), and the shale would not fracture due to tectonic stress. After the Cenozoic period, the Xichang Basin was in the stage of intense denudation and uplift, and the deep stratum temperature continued to decrease. Every 43 °C decrease was accompanied by a stress variation in the horizontal direction of 10 MPa (Figure 7Bc). The strong uplift denudation was accompanied by a change in the horizontal tensile strain. The greater the paleo-maximum burial depth, the greater the additional strain tensor induced by temperature during the uplift and denudation, as illustrated in Figure 7Bb. Therefore, the strong uplift greatly reduced the formation stress, the effective stress decreased by approximately 50 MPa, the pressure coefficient dropped to approximately 1.05, the pore pressure (hydrostatic pressure) was greater than the horizontal minimum principal stress, and the shale became prone to tensile fracture (Figure 7C). The research design adopted in the present study included different temperature and pressure conditions to simulate the three natural conditions prevalent underground at the depths of 2300 m (Figure 8a,b) and 1000 m (Figure 8c,d) and on the surface (Figure 8e,f). As visible in Figure 8, in the triaxial compression test, the shale underwent three stages–elasticity, shaping, and failure. In the initial stage of pressurization, the shale underwent a typical elastic deformation in both the axial and radial directions, and the curve was roughly linear. Next, the curve bent significantly until it reached the ultimate point of shale strength, and the stress dropped rapidly, resulting in rock fracture and loss of continuous integrity. The test results revealed that the mechanical failure of mud shale had a significant brittle fracture character. It was revealed that the axial strain and radial strain of the shale were highly complex under constant temperature and pressure compared to those under a certain temperature and pressure. Under the conditions of an underground depth of 2300 m (temperature, 66 °C; confining pressure, 58.6 MPa; and pore pressure, 19.6 MPa), the shale strength limit was approximately 300 MPa. When the underground depth was 1000 m (temperature, 38 °C; confining pressure, 25.5 MPa; and pore pressure, 9.8 MPa), the shale strength limit was approximately 160 MPa. However, the strength limit of shale decreased to approximately 80 MPa under surface conditions. The higher the confining pressure, the fewer microcracks were generated, and the shear failure was the main failure mode. The lower the confining pressure, the further significant the fracture characteristics of the rock, and the rupture failure became dominant. The dynamic elastic modulus and Poisson’s ratio of the shale samples could be expressed as follows: Figure 9a presents the correlation between the P-wave impedance and Poisson’s ratio of the shale samples under different confining pressures. The longitudinal and shear wave velocities calculated through vertical bedding propagation were used. In terms of P-wave impedance, the samples from the organic-rich shale and those from relatively organic-poor shale had an evident overlap. It was difficult to classify the reservoir types using just a single attribute of P-wave impedance. The shale samples in the organic-rich section exhibited a low Poisson’s ratio (less than 0.22), which reflected the elastic properties of their quartz particles. The shale samples in the relatively organic-poor section exhibited a gradually increasing Poisson’s ratio with the increase in the P-wave impedance. These samples were composed of clay as the rock framework, and the total porosity of the samples decreased with the increase in the clay content, resulting in the gradual increase in the P-wave impedance and Poisson’s ratio. Figure 9b presents the correlation between the elastic modulus of the shale samples and their Poisson’s ratio. The organic-rich shale samples mainly exhibited the characteristics of a high elastic modulus (greater than 30 GPa) and a low Poisson’s ratio (less than 0.22), which also reflected the elastic characteristics of quartz particles in the skeleton. The brittleness of rocks is a key index to evaluate the geomechanical properties and the fracture capacity of shale reservoirs. Two methods were used for evaluating the brittleness of rock based on logging and two-dimensional seismic. One was to calculate the rock brittleness using the elastic modulus and Poisson’s ratio, with the latter reflecting the initial fracture ability of the rock under stress, while the elastic modulus reflected the ability of the fracture to maintain its characteristics. The rock brittleness coefficient (B1) was then defined based on the elastic parameters as follows: The other method for evaluating the brittleness of the rocks was based on the brittle and plastic mineral composition. In this method, quartz and dolomite in the shale samples were regarded as the main brittle minerals, and the brittleness coefficient of the rock (B2) was defined based on the mineral composition as follows: Figure 10 presents the relationship between sample hardness and the brittleness index. A positive correlation was observed between the hardness value and the brittleness indices B1 and B2, and the samples in the organ-rich layer exhibited higher hardness and brittleness index values, which indicate that the sample hardness could represent the change in the brittleness. Since a small sample area was affected by the hardness evaluation, the sample was more susceptible to local changes in the mineral components. Meanwhile, the contribution of calcite and other minerals to the brittleness and plasticity of the sample depended on the experimental conditions, resulting in the correlation between hardness and B1 being higher than the correlation between hardness and B2. Figure 11 presents the relationship between the hardness (brittleness) of the sample and the main mineral components. Since the TOC content is characterized by low density and low elastic modulus, several experimental results revealed that an increase in the TOC content significantly reduced the elastic modulus of shale and increased its Poisson’s ratio, increasing the plasticity of shale. In over-mature shale samples, hardness was positively correlated with TOC in general, particularly for the high-quality shale samples (Figure 11a). The main reason for this phenomenon was that during the increase in the TOC content, the supporting skeleton of the shale samples changed from plastic clay particles forming the supporting skeleton to brittle quartz particles forming the supporting skeleton. Meanwhile, the organic matter of the over-mature shale samples mainly existed in the pores between quartz primary grains rather than acting as force carriers. The increase in the TOC content reduced the hardness of the sample less than the increase in the elastic properties of the supporting particles, resulting in the overall high hardness (brittleness) of the high-quality shale with a high TOC content. When the quartz content was over 62%, the shale sample had biogenic quartz forming the rock skeleton. The increase in the quartz content implied that the organic matter and porosity of the sample with ″soft″ mechanical properties would increase (Figure 13a,b), causing the hardness (brittleness) of the sample to decrease with the increase in the quartz content. Because of the above reasons, the relationship between quartz content and hardness was consistent with the P-wave velocity in general. With a quartz content of 46% as the limit, the P-wave velocity decreased with the increase in the quartz content (Figure 13b). When the quartz content was below 46%, the hardness had a weak positive correlation with the quartz content. When the quartz content was over 46%, the hardness (brittleness) had a significant negative correlation with the quartz content (Figure 11b). The hardness (brittleness) of the sample dominated by biogenic quartz was significantly higher than that of the sample dominated by terrigenous quartz. However, the higher the quartz content of the sample, the greater the hardness (brittleness) did not hold, and the increase in the terrigenous quartz content did not significantly change the hardness of the sample. Clay minerals were the most important plastic minerals in shale, and their strong plastic characteristics led to a negative correlation between the hardness of the samples and their clay contents. When the quartz content was below 46%, the shale samples were supported by clay particles, and the overall mechanical properties of the samples were controlled by the characteristics of the clay minerals. Consequently, the relationship of the hardness with the quartz content and the clay content did not change significantly. Similarly, no evident correlation existed between calcite and the hardness of the sample, which indicated that although calcite was considered a brittle mineral, it was not the main factor affecting the hardness (brittleness) of the deep Longmaxi shale or that the hardness-increasing effect of calcite (brittleness) in the Longmaxi shale sample would be offset by the hardness-decreasing effect of the other factors.

The organic-rich shale reservoirs of the Wufeng Formation–Long11 sub-member in the Xichang Basin are over-pressured in general. However, due to the low permeability of the shale samples during the experiment, the pressure equilibrium process during the loading of pore pressure was relatively long. Therefore, the effective pressure condition of pore pressure was not considered in the sample velocity measurement during the experiment. In comparison to the effective pressure conditions considering pore pressure, if pore pressure is not considered, the P- and S-wave velocity would be slightly higher, which is equivalent to the increase in the velocity caused by the fluid filling in the pore, although it does not affect the analysis of the change rule of the overall seismic elastic properties of the sample. As depicted in Figure 12, the experimental effective pressure was 40 MPa, and the intersection results of the vertical bedding propagation of the P- and S-wave velocities and the quartz content of the shale samples revealed that the sample velocity as a whole presented an asymmetric trend of ″an initial increase followed by a decrease″, with 62% quartz content as the limit. When the content was lower than this limit, the P- and S-wave velocities first increased with the increase of quartz content, while the change trend was the opposite when the content was higher than 62%. The limit of 62% quartz content indicated that the samples were dominated by terrigenous clastic quartz or biogenic quartz. The samples with terrigenous clastic quartz were dominated by clay grains forming the rock skeleton, while the samples with biogenic quartz were dominated by microcrystalline quartz forming the rock skeleton. This change in the sample structure characteristics determined the overall change in the velocity with the quartz content. When the quartz content was less than 62%, the clay particles with softer elastic properties served as the skeleton of the rock. At this time, an increase in the quartz content did not change the original microscopic rock fabric of the argillaceous particles as the stressed skeleton. The rigid quartz particles continued to ″float″ in the plastic clay matrix, and the softer clay particles acted as the carrier of elastic wave propagation to control the macroscopic dynamic elastic properties of the rock, resulting in a relatively low S-wave velocity of the sample (Figure 12b). The increase in the P- and S-wave velocities with the increase in the quartz content was mainly the result of a decrease in the porosity and TOC content (Figure 13a,b). However, this decreasing trend of porosity was evidently different from the variation rule of traditional pure mudstone → sandy mudstone. The variation of porosity in the process of pure mudstone → sandy mudstone was caused by the difference in sorting, while the decreasing trend in the porosity of the shale samples was the result of the gradual decrease of the denudation pores and TOC content with the calcium content. This indicated that low-velocity samples corresponded to high calcium content and high porosity, while high-velocity samples corresponded to low calcium content and low porosity (Figure 13b,d). However, when the quartz content was higher than 62%, the sample was characterized by rigid quartz particles as the stressed skeleton. In this case, the ″hard″ quartz particles serve as the carrier of elastic wave propagation to control the macroscopic elastic properties of the rock, resulting in a relatively high S-wave velocity in this part of the sample (Figure 12b). The samples dominated by biogenic quartz exhibited a positive correlation between the quartz content and the TOC content as well as between the TOC content and porosity (Figure 5). The content and porosity of the organic matter with softer elastic properties increased with the increase in the quartz content, causing the velocity of the organic-rich samples to be negatively correlated with the quartz content (Figure 13a,b). Since a small number of samples dominated by terrigenous quartz existed in the S1l11, the variation patterns of sample velocity and quartz content in this sub-member also presented an ″initial increase followed by a decrease″ trend. As demonstrated by the above experimental results, the overall variation law of the dynamic elastic properties of deep shale was mainly controlled by the microscopic mechanical skeleton characteristics of the rock, while the porosity and TOC content were secondary factors affecting the change in the dynamic elastic characteristics, with the middle–shallow shale exhibiting the same regularity. The velocity–quartz content change pattern of deep shale samples was consistent with the velocity change pattern of pure mudstone → sandy mudstone → argillaceous sandstone → pure sandstone series, which was controlled by the rock fabric. The porosity evolution of the two was not the same, and the deep shale cannot be simply similar to the continuous velocity change of the pure mudstone → sandy mudstone → argillaceous sandstone → pure sandstone series. As depicted in Figure 14, the effective pressure was 40 MPa, and the intersection results of the vertical bedding propagation velocity and porosity of the shale samples revealed that the velocity exhibited an overall trend of decreasing with the increase in the porosity, and its slope reflected the pore structure characteristics of the sample. The change in the P-wave velocity with porosity could be distinguished into two distinct modes (Figure 14a). First, the samples in the organic-poor shale section exhibited a large slope of P-wave velocity–porosity change, with several intergranular argillaceous pores in the sample pores. Such pores, due to the effect of the strong compaction and orientation of argillaceous particles, usually appeared as ″soft″ pores with smaller vertical and horizontal dimensions and were similar to microfractures in terms of their mechanical properties. The existence of a small number of pores could significantly reduce the P-wave velocity, resulting in a large slope of the P-wave velocity–porosity relationship. Second, the samples in the organic-rich shale segment exhibited a small velocity–porosity change slope. A greater number of intergranular pores of quartz particles were present in the pores of the sample, representing ″hard″ pores with a high aspect ratio. The change in porosity exerted a small effect on the velocity, resulting in a small longitudinal wave velocity–porosity change slope. The shear modulus of the skeleton minerals of the two types of shale samples were significantly different. While the shear modulus of the quartz particles was 45 GPa, that of clay minerals was just 9 GPa. Consequently, the shear wave velocity of the organic-rich shale samples was significantly higher than that of the relatively organic-poor shale samples (Figure 14b). The insensitivity of the S-wave velocity to pore shape also resulted in little difference in the slope of the S-wave velocity–porosity change between the two types of samples.

In this study, the lithofacies of organic-rich shale in the Wufeng–Longmaxi formation were identified and classified. On this basis, the shale samples of different lithofacies were systematically measured by petrology and hardness, and the dynamic and static elastic characteristics of the shale samples and their controlling factors were discussed. The following conclusions can be obtained. (1) The organic-rich shale samples of the Wufeng–Longmaxi Formation in the Xichang Basin was mainly composed of argillaceous-containing siliceous shales, while the organic-poor shales was mainly composed of siliceous argillaceous shales. The source of quartz in the organic-rich shale was mainly the biogenic siliceous allochems of the early diagenesis (synsedimentary), which was characterized by microcrystalline quartz grains forming the rock support framework. The quartz in the relatively organic-poor shale was mainly derived from terrigenous detrital quartz, which was characterized by plastic clay minerals forming the rock support skeleton. (2) The overall variation patterns of the velocity–quartz content, velocity–porosity, and velocity–organic matter content of the shale samples were mainly controlled by the rock fabrics (the elastic characteristics of the skeleton supported the particles), which also caused the velocity-rich shale samples and relatively organic-poor shale samples to have better zoning in the correlation diagram of combined elastic parameters, such as P-wave impedance–Poisson’s ratio and elastic modulus–Poisson’s ratio. (3) The hardness of the shale samples exhibited a significant positive correlation with B1 and B2. The hardness and brittleness of the samples were also controlled by the rock fabric, resulting in an asymmetric ″initial increase followed by a decrease″ pattern with the quartz content and a negative correlation with the clay content. In the relatively organic-poor matter content samples with plastic clay minerals forming the rock support particles, the increase in the terrigenous quartz content did not significantly change the hardness (or brittleness) of the samples.