1 Introduction
With the significant success of shale oil development in North America, shale oil has become an important part of the global energy industry chain, and an increasing number of countries are becoming increasingly important. According to the Energy Information Administration (EIA), Advanced Resources International, Inc. (ARI), China National Petroleum Corporation (CNPC), and China Petroleum & Chemical Corporation (SNP), the total exploitable shale oil resources worldwide are approximately 47.1 billion tons, distributed across 104 basins in 46 countries (
EIA, 2015;
ARI, 2015). China’s developable shale oil resources exceed 3 billion tons, ranking third worldwide (
Zou et al., 2013;
ARI, 2015). This huge resource potential has driven the large-scale commercial development of shale oil in China.
Exploration experience has shown that underground sandstone or carbonate rocks have better reservoir and fracturing properties than shale. Therefore, sandstone and limestone interlayers in thick shale formations are favorable exploration targets for shale oil. Based on this principle, China has successively conducted shale oil explorations in major basins and achieved remarkable results. China has achieved small-scale exploitation of shale oil in the Junggar, Ordos, Songliao, and Bohai Bay Basins (
Zhao et al., 2020;
Li et al., 2022a;
Hu et al., 2022). According to successful exploration and development experience, the shell limestone interlayers in the Jurassic Da’anzhai Formation are also considered favorable conditions for shale oil development.
To investigate the shale oil development potential of the Da’anzhai Formation in the Sichuan Basin, more than ten wells have been deployed in the CNPC and SNP since 2019. So far, only the LA1 (gas 2000 m
3/day; oil 1.76 tons/day) and LX1 (gas 3.36 × 10
4 m
3/day; oil 22.4 m
3/day) wells have achieved limited success. Both of these wells have geological conditions of high maturity (
Ro > 1.5%), high formation pressure coefficient (> 1.3), and high organic matter abundance (TOC > 1.5%) (
He et al., 2022). This sharply contrasts with the major shale oil-producing layers worldwide (
Jarvie, 2012;
Liu et al., 2021b). Therefore, shale oil development in the Da’anzhai Formation has reached a bottleneck.
To investigate the particularity of limestone and shale assemblages, this study used advanced technical means to evaluate different lithofacies’ reservoir properties, oil-bearing, and oil-movable conditions. The reasons for unsuccessful exploration were analyzed, and favorable exploration targets were identified. This study provides a theoretical basis and technical support for shale oil exploration in the Da’anzhai Formation of the Sichuan Basin. This is also important for shale oil exploration in limestone and shale assemblages worldwide.
2 Geological background
The Sichuan Basin is located in southwest China, between north latitude 28°–32°40′ N and east longitudes 102°30′–110° E, with a total area of approximately 18 × 10
4 km
2 (
Li et al., 2020;
Xiao et al., 2021;
Wang et al., 2024). The Sichuan Basin is a large negative tectonic basin formed by the compression and collision of the Indian and Eurasian plates, which also caused the overall uplift of the Yangtze platform (Fig. 1(a)) (
Liu et al., 2016). The Sichuan Basin is located to the north of the Yangtze Platform (Fig. 1(b)). Its western edge is the Longmen Mountain fault zone, its northern edge is Micang Mountain, its north-eastern edge is the Daba Mountain and Qiyue Mountain fold zones, its south-eastern edge is the Daluoshan fold zone, and its south-western edge is the Emei-Daliang Mountain fault zone (Fig. 1(c)).
The Da’anzhai Formation records the largest lake leaching in the Sichuan Basin and develops its primary source rocks (
Su et al., 2018;
Zhang et al., 2022a). From the plane view (Fig. 1(c)), when the Da’anzhai Formation was deposited, the Nanbu-Yingshan area was the sedimentary center, and half-deep lake mud developed. Large-scale shell beaches have developed in shallow lakes (
Lei et al., 2023;
Xu et al., 2023). The thickness of the Da’anzhai Formation is 60–100 m. According to its sedimentary evolution, it can be divided into three members from bottom to top: D
3, D
2, and D
1 (Fig. 1(d)). The D
2 member is further divided into three sub-members: D
2a, D
2b, and D
2c.
The thickness of the D
3 member is 5–15 m, and the lithology is mainly composed of thick blocks of brownish-gray shell limestone with thin layers of black shale. The D
2 member has a thickness of 35–60 m, mainly developing thick black shale with differences in lithology among each sub-member (
Zhang et al., 2022a). The D2a sub-member typically develops an interlayer of black shale and shell limestone. The lithology of the D
2b sub-member is mainly thick black shale with thin layers of shell limestone. Thick, massive black shales develop in the D
2c sub-member. The thickness of the D
1 sub-member is 20–30 m, mainly developing thick-shelled limestone (
Chen et al., 2020).
3 Samples and methods
3.1 Samples
Eight rock samples from wells G6 and RA1 were observed using a polarization microscope and field emission scanning electron microscopy (FE-SEM). X-ray diffraction (XRD) tests were performed on 74 samples from wells PC1, G10, NC2H, and LA1. Eleven rock samples from PC1 and G10 were tested for low-temperature N2 adsorption (Table 1). High-pressure mercury injection (HPMI) testing was performed on five samples collected from wells RA1, PC1, and G10 (Table 2). The nuclear magnetic resonance (NMR) experiments were conducted on 15 samples from well LA1 (Table 3). Rock pyrolysis analysis of samples from wells PC1, G10, RA1, LA1, and LQ104X was conducted. Rock pyrolysis data were obtained from the Exploration and Development Research Institute of the PetroChina Southwest Oil and Gas Field Company.
3.2 Experimental methods
3.2.1 FE-SEM
Scanning electron microscopy (SEM) was performed using an FEI Quanta 650 FEG field-emission scanning electron microscope. The samples were prepared into rectangular blocks with a length of 8 mm, a width of 8 mm, and a height of 3 mm and were then ground with ultra-thin emery paper with particle sizes of 30 µm, 15 µm, 9 µm, 6 µm, 3 µm, 1 µm, and 0.1 µm until the surface was flat. Polishing was then performed under vacuum using a Hitachi IM 4000 argon-ion polisher. The polished thick shale samples were imaged with secondary electrons using a Hitachi dual-beam scanning electron microscope to obtain high-resolution pore structure images.
3.2.2 XRD
X-ray diffraction analysis is currently a simple and efficient experimental method for identifying, analyzing, and quantifying the characteristics of shale mineral compositions. A small shale sample was first ground to 200 mesh and dried at 110°C. A PANalytical X’ Pert PRO X-ray diffractometer was used in the experiments. The instrument was equipped with a Co target and operated at 31 kV and 0.4 mA. Diffraction angles (2θ) were measured over a range of 3°–55° with a scanning interval of 0.02° (2θ). Semiquantitative analysis was performed using the X-Powder software.
3.2.3 N2 adsorption and desorption
First, approximately 3 g of the shale sample was weighed and crushed to pass through a 60–120 mesh sieve. Then, the samples were degassed and dried at 110°C and a vacuum of less than 10 mmHg for more than 10 h. The experiment was performed using a Quantachrome NOVA4200e specific surface-area porosimeter. The relative pressure was set to 0.005–0.995. Using high-purity N2 as the adsorbate, an adsorption curve under liquid-nitrogen temperature conditions was obtained.
3.2.4 HPMI
The sample was cut into small cubes (1.0 cm3) with a cutting machine. The samples were washed with organic solvent and dried for 2 h at 110°C for dehydration. After the pretreatment, the samples were loaded into a dilatometer with a volume of 1 cm3, taking care to prevent secondary contamination. The dilatometer containing the sample was transferred to a pore gauge and vacuumed under low pressure for degassing. Finally, the pore structure data of the samples were obtained using a Quantachrome Pore Master GT 60 automatic mercury intrusion instrument (Konta, USA).
3.2.5 NMR
Core plug samples were used for the NMR experiments. The samples were placed in a vacuum saturation chamber and evacuated for 1 h to remove air and adsorbed impurities. The samples were then saturated with crude oil at a fluid pressure of 30 MPa for 24 h for NMR testing. The nuclear magnetic resonance experimental instrument was a MesoMR23/12-060H-I nuclear magnetic NMR instrument produced by the Niumag Company. The magnetic field strength was 0.3 ± 0.03 T. The primary frequency (SF) was 12 MHz. NMR T2 analysis adopted CPMG echo sequence, and the experimental parameters were set as echo interval time (TE) 0.1 ms, echo number (NECH) 16000, waiting time (TW) 6 000 ms, scan number (NS) 32.
3.2.6 Rock pyrolysis
Approximately 10 mg of powdered rock samples was prepared. Experiments were performed using a Vinci Rock-Eval 6 instrument. The total organic carbon (TOC, wt.%), free hydrocarbon (S1, mg/g), pyrolytic hydrocarbon (S2, mg/g), and maximum pyrolysis temperature (Tmax, °C) were obtained. The oil content index (S1/TOC) was calculated to characterize the oil content of the shale.
4 Results
4.1 Mineral composition
The XRD results of the 74 samples showed that the main mineral components were quartz, calcite, and clay. The proportions of plagioclase, dolomite, and pyrite were relatively low. In comparison (Fig. 2), the clay mineral content was the highest, averaging 48% (19%–71%). The quartz content took second place, averaging 30% (10%–49%). The calcite content was relatively low, averaging 13% (0%–64%). The average plagioclase, dolomite, and pyrite contents were less than 5%.
4.2 Organic geochemical characteristics
The rock pyrolysis test results showed that the TOC content of the shale was between 0.09% and 5.58%, with an average value of 1.38%. The
S1 value was between 0.01 mg/g and 9.47 mg/g, with an average value of 1.05 mg/g. The value of
S1 +
S2 was between 0.04 mg/g and 26.97 mg/g, with an average of 3.64 mg/g. As seen from the cross-plot of TOC and
S1 +
S2 (Fig. 3), the abundance of organic matter in the Da’anzhai Formation shale was mainly at a medium-good level, and some samples (accounting for 16.0%) reached an excellent level. The
S2-TOC chart was selected to distinguish the organic matter type of the shale (Fig. 4) (
Langford and Blanc-Valleron, 1990;
Elika et al., 2006), which showed that the organic matter type of the shale was mainly types II and III. The average value of
Tmax was 443°C (320°C–485°C), indicating the samples have reached maturity to high maturity.
4.3 Pore structure characteristics
4.3.1 N2 adsorption
The results of the low-temperature N2 adsorption experiments showed that the samples had different curve shapes (Fig. 5). According to the classification of IUPAC (the International Union for Pure and Applied Chemistry), four curve shapes were identified: H2 (Fig. 5(a)), mixed H2 and H3 (Fig. 5(b)), H3 (Fig. 5(c)), and mixed H3 and H4 (Fig. 5(d)).
The BET-specific surface area (SSA), total pore volume (TPV), and pore diameter (Dp) of crushed samples can be obtained by analyzing N
2 adsorption data (
Clarkson et al., 2011;
Han et al., 2016). From the statistical results (Table 1), the SSA, TPV, and Dp of the H
2 type were relatively high, with average values of 10.535 m
2/g, 0.0130 cm
3/g, and 3.133 nm, respectively. The SSA, TPV, and Dp of the mixed types of H
2 and H
3 ranked second, with average values of 5.515 m
2/g, 0.0127 cm
3/g, and 3.078 nm, respectively. The SSA, TPV, and Dp values of the H
3 type were small, with average values of 2.448 m
2/g, 0.0127 cm
3/g, and 3.093 nm, respectively. The SSA, TPV, and Dp of the mixed type of H
3 and H
4 were the smallest, with average values of only 2.507 m
2/g, 0.0075 cm
3/g, and 3.054 nm, respectively.
4.3.2 HPMI
The results of the HPMI test (Table 2) showed that the Da’anzhai Formation reservoir was generally tight. The porosity was between 1.40%–7.68%, and the threshold pressure was 0.67–12.97 MPa. The pore structures of different samples varied significantly. The TPV was 0.005–0.033 mL/g, and the average pore diameter was 15.98–651.97 nm. Interestingly, the porosity, TPV, and SSA were positively correlated with each other but negatively correlated with the pore diameter. This phenomenon indicates that the Da’anzhai Formation has abnormal characteristics of independent macropores and intensive micropores. As shown in the cumulative mercury intake and pore diameter distribution curves (Fig. 6), the pore diameters of the study samples were mainly below 100 nm.
4.3.3 NMR
The T
2 distribution of the rock samples saturated with oil exhibited a three-peak shape (P
1, P
2, and P
3) (Fig. 7), indicating that the pore structure was relatively complex. In general, the P
1 peak fallss within the range of T
2 < 10 ms, the P
2 peak within 10 ms < T
2 < 100 ms, and the P
3 peak within 100 ms < T
2 < 1000 ms.
Zhang et al. (2022b) proposed that the three peaks in the NMR spectrogram represent micropores, mesopores, and macropores, respectively. Among the three peaks of the Da’anzhai Formation samples, the P
1 peak showed the strongest signal. In contrast, the P
2 and P
3 peaks had weak signals, indicating that the proportion of micropores in all samples is relatively large.
5 Discussion
5.1 Lithofacies types and assemblages
Research on shale lithofacies is scarce. Researchers have used various lithofacies classification schemes for different purposes. For example,
Loucks and Ruppel (2007) divided lithofacies by combining rock mineral components with total organic carbon (TOC).
Liu et al. (2018) divided lithofacies by comprehensively considering rock structure, organic matter abundance, and mineral composition.
Yue et al. (2021) classified lithofacies based on the mineral composition of rocks.
Feng et al. (2021) classified lithofacies based on sedimentological and ichnological characteristics.
Mohammed et al. (2022) divided lithofacies according to differences in their biological types. Given the critical role of rock structure in shale oil occurrence and flow, this study combined rock structure and lithology to divide the lithofacies.
5.1.1 Rock structures
Based on core observations and microscopic identification, the rock structure of the Da’anzhai Formation is generally divided into four types: massive, layered, laminated, and foliated. Shell limestone (Figs. 8(a) and 8(h)), argillaceous shell limestone (Figs. 8(b) and 8(i)), and shell-bearing shale (Figs. 8(c) and 8(j)) exhibit massive structures. The hybrid sedimentary rocks of shale, shell limestone, and siltstone were generally layered (Figs. 8(d), 8(e), and 8(k)) or laminated (Figs. 8(f) and 8(l)), and the organic-rich shale was foliated (Figs. 8(g) and 8(m)). The calcareous bands in the hybrid sedimentary rocks were mainly composed of veined calcite with a superimposed structure (Figs. 8(n) and 8(o)).
5.1.2 Lithology and Lithofacies
The lithology was classified using a ternary diagram of mineral components (
Hickey and Henk, 2007;
Lazar et al., 2015;
Liu et al., 2020). The composition plots of the 78 samples revealed that eight lithologies are mainly developed in the Da’anzhai Formation (Fig. 9). Shale can be classified into silty and silty-bearing clayey shales. Small amounts of shell shale, shell-bearing clayey shale, and clayey shale are also observed. The carbonate rocks can be subdivided into shell limestones and argillaceous shell limestones. A certain proportion of argillaceous siltstones also present. According to the rock structure and lithology, the Da’anzhai Formation can be divided into ten lithofacies (Fig. 10): A-massive shell limestone; B-massive argillaceous shell limestone; C-massive shell-bearing clayey shale; D-massive clayey shale; E-layered argillaceous shell limestone; F-layered shell shale; G-layered silty shale; H-layered argillaceous siltstone; I-laminated shell-bearing clayey shale; J-foliated silty-bearing clayey shale.
The lithofacies reflect a relatively fine (decimeter scale) sedimentary environment. However, it is difficult to guide the exploration of shale oil based on lithofacies because of the variable sedimentary environment and frequent overlapping of lithofacies in a set of strata. Therefore, it is necessary to divide the larger scale (meter scale) lithological assemblages according to the overall evolutionary trend of the sedimentary environment (
Bai et al., 2020;
Mohammed et al., 2022;
Nabawy et al., 2022).
5.1.3 Lithological assemblages
Based on the vertical stacking characteristics of the lithofacies observed in the core wells and field outcrops (Fig. 11), lithofacies A was mainly distributed in D1 and D3 members. Lithofacies B is mainly distributed in the D2a and D2b sub-members. Lithofacies C and D are mainly developed in the D2c sub-member. Lithofacies E and F occur mainly in the lower parts of the D1 member and D2a sub-member. Lithofacies G and H are predominantly present in the transition zone between the D1 member and D2a sub-member. Lithofacies I and J are mainly distributed in the D2b sub-member.
Among these, lithofacies G and H represent delta plain facies restricted to the lake basin margin. They are often associated with lithofacies E and are < 3 m thick. Lithofacies E and F share similar structure characteristics, commonly co-occur, and are predominantly composed of by lithofacies F. Lithofacies D, which does not contain shells at all, rarely occurs and is associated with lithofacies C. Lithofacies A and B usually coexist. The Da’anzhai Formation comprises five main lithological assemblages: A, E–A, F–B, C–D, and I–J (Fig. 11).
5.2 Pore structure of main lithofacies
5.2.1 Microcosmic differences
The pore structure of shale influences its occurrence characteristics and fluidity of shale oil (
Zargari et al., 2015;
Zang et al., 2022). The pore structures of different rock samples from the Da’anzhai Formation were different. In the N
2 adsorption pore diameter distribution curve calculated by the Barrett-Joyner-Halenda (BJH) method, the H
2 type (Fig. 12(a)) was typically characterized by double peaks at 3–5 nm and 20–50 nm, indicating the coexistence of micropores and mesopores. The mixed type of H
2 and H
3 (Fig. 12(b)) was characterized by a single peak at 20–50 nm, indicating that mesopores were mainly developed. The H
3 type (Fig. 12(c)) and H
3 and H
4 mixed type (Fig. 12(d)) formed a single peak at 50–100 nm, indicating that macropores were mainly developed.
Corresponding to the mineral components, the specific surface area of the Da’anzhai Formation shale tended to increase with increasing clay content (Fig. 13(a)). At the same time, it decreased with increasing calcium content (Fig. 13(b)). This indicates that the recrystallization and dissolution of carbonate rocks in the Da’anzhai Formation were weak. Clay intergranular pores constituted the main reservoir space of shale oil.
The Da’anzhai Formation shale developed clay intergranular pores (Fig. 14(a)), pyrite intergranular pores (Fig. 14(i)), organic matter pores (Fig. 14(h)), quartz intergranular pores (Fig. 14(f)), calcite intergranular pores (Fig. 14(c)), organic matter edge pores (Figs. 14(g) and 14(h)), and microfractures (Figs. 14(d) and 14(e)). The morphology of the clay intergranular pores is complex (Fig. 14(a)). It is large-scale and distributed nearly linearly in the shale (Fig. 14(b)). Organic matter pores were mainly developed in amorphous asphaltenes (Fig. 14(h)) and were distributed in strips or irregular shapes. The organic matter pores in the target shale are poorly developed. Intergranular pores of calcite were formed between the calcite crystals, with a regular shape, small aperture, and disconnection (Fig. 14(c)). It is almost undeveloped in the argillaceous and calcareous interbeds (Fig. 14(e)). These phenomena confirm that carbonate minerals make a very limited contribution to the reservoir properties.
5.2.2 Macroscopic differences
Because the N
2 adsorption experiment used powder samples, it can only reflect the micropores of rock and cannot characterize the influence of rock structure on reservoir properties. The HPMI experiment can obtain a wide range of pore diameters, which can be used to characterize the reservoir space characteristics of shale (
Lu et al., 2018;
Wang et al., 2019). The HPMI test results of the main lithofacies show that (Table 3, Fig. 6): lithofacies A and F had larger average Dp but smaller porosities,TPV, and SSA. In contrast, the average Dp of lithofacies J is smaller; however, its porosity, TPV, and SSA are larger. The Dp of lithofacies I and C is between those of the above two cases. This indicates that with an increase in shale content, the TPV of the lithofacies increases, but the Dp decreases. This is consistent with the N
2 adsorption experiments.
The T
2 values of NMR can be used to characterize the pore diameter distribution of shale from micrometers to nanometers, which is an effective full-aperture characterization method (
An and Apostolos, 2002;
Lu et al., 2018). By comparing the T
2 spectrum of NMR with the pore diameter distribution curve of HPMI based on the same sample and establishing the relationship between T
2 values and pore diameters, we can use the T
2 values to study the pore diameter distribution of rocks.
By jointly analyzing the NMR-T2 spectrum and HPMI pore diameter (r) distribution curve of the same lithofacies sample in the Da’anzhai Formation, and by establishing a conversion formula between T2 value and pore diameter (R = 10T2), the relative and absolute proportions of macropores, mesopores, and micropores in the different lithofacies were calculated (Fig. 15).
The contents of macropores in lithofacies A and F were relatively high, accounting for more than 75% on average. In contrast, the contents of micropores and mesopores were relatively low, accounting for less than 25% on average. The contents of micropores and mesopores in lithofacies C and I increased, accounting for more than 35%, and the content of macropores decreased accordingly. The contents of micropores and mesopores in lithofacies J were the highest, accounting for 80%, whereas the content of macropores was low, accounting for less than 20%. Comparing the proportion of pore diameters of various lithofacies, it was found that with an increase in shale content, the average pore diameter decreased (Fig. 15(a)), but the total pore volume increased. There were relatively more macropores in the layered, laminated, and foliated shales (Fig. 15(b)), related to the extremely developed bedding fractures in the rock structures.
5.3 Enrichment conditions and exploration direction of shale oil
5.3.1 Oil-bearing properties of different lithofacies
The oil saturation index (OSI = S
1/TOC, mg/g·TOC
−1) defined by
Pepper (1991) can indicate the exploitable properties of shale oil.
Jarvie (2012) suggested that shale oil reservoirs with OSI > 100 mg/g·TOC
−1 exhibit good oil production pontential, while shale oil reservoirs with OSI less than 70 mg/g·TOC
−1 are generally coonsidered non-recoverable.
Wang et al. (2014) proposed that the shale oil reservoirs with OSI > 100 mg/g·TOC
−1 exhibit the “Oil Crossover” phenomenon, which is a good, fractured shale oil reservoir.
The overall OSI values of the Da’anzhai Formation range from 10.6 to 339.2 mg/g·TOC−1, with an average of 95.0 mg/g·TOC−1. The OSI values of the lithofacies differed significantly (Fig. 16). The OSI values of lithofacies J are the largest, averaging 100.1 mg/g·TOC−1, and 52.7% of samples with OSI > 100 mg/g·TOC−1. The average OSI values are 98.2 mg/g·TOC−1 and 98.9 mg/g·TOC−1 for lithofacies I and F. The proportions of samples with OSI > 100 mg/g·TOC−1 are 40.0% and 38.5%, respectively. The OSI values of lithofacies C were moderate, averaging 72.5 mg/g·TOC−1. The samples with OSI > 100 mg/g·TOC−1 account for 26.7%. The OSI values of lithofacies A are small; the average value is only 49.8 mg/g·TOC−1, and 20.0% of samples with OSI > 100 mg/g·TOC−1.
The Da’anzhai Formation has unique characteristics compared with shale oil formations in North America and other basins in China. Shale oil in North America is produced primarily in marine formations. The primary shale oil production layers typically comprise fine sandstone, siltstone, and dolostone. They are characterized by high porosity and permeability. The clay mineral content in the shale oil production layers is generally less than 30% (
He et al., 2023). The OSI in the sandstones or dolostones of the Williston Bakken Formation and Gulf of Mexico Eagle Ford Formation can reach up to 600 mg/(g·TOC
−1) (
Jarvie, 2012), which determines that the interlayers are the most favorable targets for exploration.
The lithology of commercially developed shale oil reservoirs in China is similar to that of the reservoirs in North America. Fine sandstone, siltstone, and lacustrine carbonate interbeds are the main contributors to shale oil productivity in China. For example, the shale oil in the 7th member of the Triassic Yanchang Formation in the Ordos Basin is mainly produced from siltstone and fine sandstone interlayers (
Guo et al., 2022). The shale oil production layer of the Lucaogou Formation in the Junggar Basin is dominated by silty dolomite and dolomitic siltstone (
Zhi et al., 2023). The main exploration targets for shale oil in the Fengcheng Formation of the Mahu Depression are felsic shale or sandstone interlayers (
Jiang et al., 2023).
In the Da’anzhai Formation, the degree of recrystallization of the shell limestone was relatively low, and the intercrystalline pores of calcite were undeveloped with small and independent pore sizes (Figs. 14(c), 14(d), and 14(e)). The physical properties of the shell limestone and hybrid sedimentary rocks were much worse than those of pure shale. The porosity and permeability of the reservoir increased with increasing shale content (Fig. 13). In the HPMI data (Table 2), the porosity of pure shale was five times that of shell limestone, and the mercury inflow is even 6.6 times that of shell limestone. The OSI value indicates that the oil content of the shell limestone and hybrid sedimentary rocks is lower than that of pure shale (Fig. 16), which is not conducive to shale oil enrichment. This also differs from the shale oil from the Shahejie Formation in the Bohai Bay Basin of China and the Barnett Formation in the Fort Worth Basin of North America. The organic-rich layered calcareous shale in these formations is a favorable target because the recrystallized intercrystalline pores in the calcite provide shale oil occurrence space (
Jarvie et al., 2011;
Li et al., 2022b,
2024;
Liang et al., 2022). Therefore, shale oil exploration in sandstone or limestone interlayers is not feasible in the Da’anzhai Formation in the Sichuan Basin.
5.3.2 The importance of fracture systems for shale oil development
These results show that lithofacies I and J have the best reservoir properties and oil-bearing conditions in the Da’anzhai Formation. However, the clay content of pure shale is very high, and the pore diameter is small. Large adsorption and molecular forces exist between the fluid and the surrounding media in shale reservoirs, resulting in restricted oil flow (
Zou et al., 2012;
Ou and Li, 2017). To achieve shale oil breakthroughs in such lithofacies, it is necessary to rely on the high oil content of the target reservoir (
Xu et al., 2022). The average TOC value of the Da’anzhai Formation shale is only 1.38%, with an average S
1 value of 1.05 mg/g, indicating insufficient hydrocarbon richness to support the commercial development of pure shale-type shale oil.
Researchers generally agree that the development of bedding fractures enhances reservoir storage capacity, improves permeability, and plays a critical role in enhancing the effectiveness of subsequent hydraulic fracturing effect. These factors are essential for achieving high oil productivity in pure shale reservoirs (
Jiang et al., 2020;
Su et al., 2020;
Liu et al., 2021a;
Meng et al., 2021). Fractured shale oil does not require exceptionally high oil content for economic production. Therefore, fractured shale oil has a high commercial exploitation value in low-oil-bearing shale formations. The commercial breakthrough of pure shale oil from the Qingshankou Formation in the Gulong Sag and Shahejie Formation in the Jiyang Depression relies on both the high organic content and improved connectivity of pores and throats due to bedding fractures (
Song et al., 2020;
Pang et al., 2023).
The Da’anzhai Formation has mainly developed interlayer fractures, foliation fractures, and calcite joints. Interlayer fractures developed on the contact surface between the shale and limestone layers (Figs. 17(a), 17(c), and 17(d)). Foliation fractures are controlled by differential deposition rates and are formed on weak mechanical surfaces of shale (
Meng et al., 2021). After being placed on the ground, a clear page-like structure was formed (Fig. 17(b)). Joint fissures mainly developed in the calcite veins. It is interconnected with the interlayer fractures and constitutes an effective seepage channel for shale oil (Figs. 17(c) and 17(d)). Many oil traces appeared in the carbonate interlayers of the layered shale in the core and field outcrops (Figs. 17(e) and 17(g)). The crude oil migrates along the joint and page fractures (Figs. 17(f) and 17(h)).
Therefore, for the Jurassic Da’anzhai Formation in the Sichuan Basin, shale oil has two enrichment modes. 1) Hybrid sedimentary rock-type shale oil. The key to the breakthrough of shale oil lies in finding vein calcite developed in interlayer fractures and joint fissures (Fig. 18(b)) rather than the simple interbedding of shell limestone and shale (Fig. 18(a)). 2) Pure shale-type shale oil. This shale oil must be commercially exploited with high oil content and highly developed foliation fractures (Fig. 18(c)). Massive shale was excluded because of undeveloped microcracks (Fig. 18(d)).
Various lithofacies of the Da’anzhai Formation were superimposed vertically. The dominant lithofacies were not concentrated in the fixed well section. In the comprehensive histogram of well RA1 (Fig. 11), the D2b member (2458–2478 m) corresponds to the I-J lithological assemblage. The average TOC value of this section reaches 1.54%, the average S1 value reaches 2.55 mg/g, the average OSI value reaches 160 mg/(g·toc−1), and the average porosity value reaches 7.5%, indicating good oil content and reservoir property. Therefore, the D2b member is a key exploration target for shale oil in the Da’anzhai Formation.
6 Conclusions
The Da’anzhai Formation can be divided into 10 lithofacies based on the rock structure and lithology. Massive shell limestone, massive shell-bearing clay shale, layered shell shale, laminated shell-bearing shale, and foliated silty-bearing clay shale are the five most typical lithofacies. Different lithofacies were superimposed in space and can be grouped into five main lithological assemblages.
The shale of the Da’anzhai Formation is dominated by clay intergranular pores, while dissolved pores are poorly developed. The pore diameter tended to decrease with an increase in clay content, but the total pore volume gradually increased. The physical properties of shale are significantly better than those of shell limestone. Bedding fractures constitute effective seepage channels for shale oil.
The Da’anzhai Formation has developed two types of shale oils. The breakthrough of hybrid sedimentary rock-type shale oil depends on vein calcite with interlayers and joint fractures. Pure shale-type shale oil must be commercially exploited with high oil content and highly developed foliation fractures. The I-J lithological assemblage of the D2b sub-member is a favorable section for shale oil exploration.
PDF
(12389KB)
