Hydrocarbon Geological Characteristics and Factors Controlling Hydrocarbon Accumulation of Jurassic Da’anzhai Continental Shale

Abstract

Continental shale in China is a key exploration target with regard to unconventional hydrocarbons. Systematic research on the mineral composition, organic geochemistry, and hydrocarbon mobility has been performed in the Da’anzhai (J₁dn) lacustrine shale oil reservoirs, clarifying the factors controlling shale oil accumulation. The results suggest that J₁dn consists of three sub-members, with an organic-rich interval developed within the second sub-member. Three types of lithological associations have developed within the organic-rich interval: Type 1 represents the interbedding relationship between shale and shell limestone and Type 2 represents shale with intercalated limestone, followed by Type 3. The brittleness index of the J₁dn continental organic-rich shale is relatively low. The porosity of the Da’anzhai lacustrine shale ranges between 0.5% and 10.5% (average value of 5.89%). The porosity is predominantly due to inorganic pores, with a small amount being attributable to nanoscale microfractures and organic pores. The average porosity of the shell limestone is only 1.2%, but fractures at the micron and centimeter scales are well developed. The organic matter in the J₁dn continental shale is mainly II₁–II₂, with maturity in the oil generation stage. The average oil saturation of the J₁dn continental shale is 3.15%, with most samples having oil saturation of less than 4%. The J₁dn continental shale has great exploration potential with regard to shale oil. Type 1 shale oil is affected by multiscale fractures, including bedding fractures, and has the best mobility. The high hydrocarbon generation capacity of lacustrine shale, coupled with the multiscale fractures within shell limestone and shale, is the principal controlling factor for hydrocarbon enrichment. Based on exploration practices, the Type 1 shale association may represent the optimal interval for future shale oil exploration in the Da’anzhai Member.

1. Introduction

China has made breakthroughs in lacustrine shale oil exploration in multiple basins, such as the Bohai Bay and Songliao Basins [1,2]. By the end of 2022, over 350 shale oil drilling wells were deployed in China, with annual production of 300 × 10⁴ t, marking the realization of commercial exploitation [3]. Jurassic shale oil deposits in the Sichuan Basin have shown enormous resource potential and broad development prospects [4,5,6,7]. This provides an important strategic replacement resource to increase the hydrocarbon reserves and production. In chronological order, Jurassic oil and gas exploration in the Sichuan Basin has undergone three stages: the conventional hydrocarbon stage, the tight reservoir stage, and the shale oil and gas stage [8,9,10]. Before 2010, the exploration targets were the Jurassic Lianggaoshan tight sandstone and Da’anzhai (J₁dn) tight limestone reservoirs, and production was achieved using sand fracturing technology. From 2011 to 2018, the exploration focus shifted to the tight sandstones of the Shaximiao Formation. With the increased focus on Jurassic shale oil, the exploration targets have shifted from sandstone and limestone to lacustrine shale, and a series of breakthroughs have been made [11,12,13].

Three sets of organic-rich continental shales developed within the Jurassic terrestrial strata in the Sichuan Basin [14]. Industrial hydrocarbons were obtained from these shale strata, and the exploration results of the Dongyuemiao (J₁d) shale and Lianggaoshan (J₁l) shale were significantly better than those of the J₁dn shale. For example, Well PA 1 in the J₁l shale achieved considerable hydrocarbon production in 2020 (112.8 m³/d of oil and 11.45 × 10⁴ m³/d of natural gas). The single-well testing of the J₁d shale led to significant hydrocarbon production [15]. Many studies have reported that J₁dn has favorable conditions for shale oil accumulation, and some researchers have proposed that the lacustrine shale within the second sub-member of J₁dn has high porosity, high brittle mineral content, and a high degree of pore fracture development, which benefit shale oil accumulation [16,17]. However, the actual exploration results indicate that the predicted potential has not been realized, and therefore further study is required to improve the poor-quality testing of the J₁dn shale and determine the main controlling factors for shale oil enrichment. Based on field outcrops, drilling data, logging data, and experimental measurements, this study illustrates the hydrocarbon geological characteristics of shale oil, summarizes the fundamental factors controlling shale oil accumulation in J₁dn, and provides a reference for future exploration.

2. Geological Setting

During the Late Triassic, the Sichuan Basin gradually evolved into an inland basin due to the Indo-Sinian movement [18]. Large asymmetric lacustrine basins with steep northern and gentle southern slopes formed within the basin. During the Yanshan and Himalayan movements, the tectonic activity changed from uplift to horizontal compression. During the Early Jurassic, the basin became a freshwater lacustrine environment, ultimately forming the Ziliujing Formation (Figure 1a). Based on the changes in lithology and sedimentary characteristics, the Ziliujing Formation is divided into four members, from bottom to top (J₁z, J₁d, J₁m, and J₁dn) (Figure 1b). During J₁dn deposition, the orogenic activity decreased, reducing the input of terrigenous debris and resulting in a subsiding basin [19]. The subsidence rate exceeded the sedimentation rate, forming the largest Jurassic lacustrine basin [16]. On this plane, semi-deep lacustrine facies dominated the central to eastern parts of the basin. Shallow lacustrine facies dominated other areas and shell shoals were irregularly distributed in a circular pattern in shallow lakes. The thickness of J₁dn is between 60 and 110 m. According to the lithology and electrical characteristics of the strata, J₁dn is further subdivided into three sub-members (Figure 2). The three sub-members represent the period of water intrusion and basin expansion with the development of shell limestones. The second sub-member represents the maximum lacustrine intrusion period, with the most well-developed shale. The first sub-member represents a period of lacustrine basin recession and shrinkage with the development of shell limestone. Overall, the Sichuan Basin underwent a complete cycle of lacustrine-level variation while J₁dn was formed.

3. Sample and Methods

3.1. Sample Information

Seven core wells and two field profiles were selected from the Daanzhai section of the Jurassic in the Sichuan Basin of Southwestern China (Figure 1), and a large number of lacustrine shale core samples were collected to analyze the pore structure and pore fluid behavior. The samples in this study were subjected to TOC, X-ray diffraction (XRD), porosity and permeability analysis, rock pyrolysis (S₁), argon ion polishing scanning electron microscopy (SEM), fluorescence thin section analysis, N₂ adsorption, nuclear magnetic resonance (NMR), and centrifugation experiments. Among them, the porosity and permeability analysis were used to obtain the shale’s physical properties; rock pyrolysis (S₁) and fluorescence thin sections were used to obtain the shale oil content characteristics; SEM and N₂ adsorption were used to obtain the pore structure characteristics; and NMR was used to characterize the pore fluid behavior under different treatment conditions.

3.2. Experimental Methods

3.2.1. Total Organic Content Test (TOC) and Mineral Composition

The shale was crushed to <100 mesh and 3 g of the sample was weighed. The sample was reacted with acid for 24 h to remove carbonate components, and then dried at 100 °C for 24 h to prepare it for TOC testing. The TOC content was measured using a Var10EL III elemental analyzer.

Shale powder with less than 200 mesh was used for mineral composition analysis. The mineral composition content was obtained using a Rigaku XRD Rigaku Ultima IV, made in Japan.

3.2.2. Rock Pyrolysis (S₁)

Rock pyrolysis was performed using the Rock Eval6 pyrolysis instrument, and the rock was kept at a constant temperature of 300 °C for 3 min to obtain the free hydrocarbon content (S₁).

3.2.3. Argon Ion Polishing Scanning Electron Microscope (SEM)

Argon ion polishing SEM was performed using an American FEI Quanta 650 FEG scanning electron microscope. Firstly, the sample was processed into a 20 mm × 20 mm × 10 mm cube and then mechanically polished with 600 to 4000 grit sandpaper, followed by performing argon ion polishing to obtain a smoother surface and improve the observation efficiency of the nanopores. Finally, the polished sample was subjected to a short-term gold plating treatment to improve its conductivity and enhance the resolution of the scanning electron microscopy image observation.

3.2.4. Low-Pressure N₂ Adsorption

The adsorption of N₂ was measured using the Micrometerics ASAP 2460 gas adsorber, manufactured by the Mike Company in the United States. Firstly, the shale sample was crushed into 60–80 mesh (180–250 μm). The particles were dried in an oven at 110 °C for more than 24 h, and then degassed under a high vacuum (<10 mmHg) at 12 °C to remove residual moisture at 110 °C. The N₂ bath temperature was set to −196 °C (77.15 K). The DFT model was used to explain the mesoporous surface area and volume of N₂ adsorption data collected on fragmented samples.

3.2.5. NMR and Centrifuge Experiment

The nuclear magnetic resonance experiment was completed using the nuclear magnetic resonance nanopore analyzer NMRC12-010V, designed and produced by the Suzhou Newmai Company. The experimental temperature was maintained at 30 °C. The experimental parameters were as follows: TE was 0.055 ms, NECH was 12,000, NS was 64 times, TW was 4000 ms, and the saturation medium was dodecane. The LG-25M ultra-high-speed centrifuge produced by the Sichuan Shuke Instrument Company was used for the centrifugation experiments, with a maximum speed of 21,000 rpm.

Firstly, the NMR transverse relaxation time (T₂) spectral response characteristics of four plunger samples in the saturated dodecane state were tested, and the peak distribution of the NMR T₂ spectra of different samples in the saturated oil state was obtained. Four typical samples were selected, saturated, and crushed with dodecane (diameter about 1 cm); then, the plunger was centrifuged and samples were crushed at different speeds of 2000 rpm to 16,000 rpm, with a centrifugation time of 30 min for each experiment. The NMR T₂ spectrum characteristics of the samples were determined under different centrifugation conditions. When the peak shape and NMR signal remained unchanged, the reduced fluid in the plunger sample was considered movable oil.

Secondly, based on the centrifugal experiment, the plug samples were dried at temperatures of 60 °C, 80 °C, 100 °C, 120 °C, 140 °C, 160 °C, 200 °C, and 240 °C, and the NMR T₂ spectral characteristics were measured (drying time was 24 h). As the drying temperature increased, the extent of the NMR signal in the sample continued to decrease and stabilized after a certain temperature. The fluids lost during the drying process included bound oil and adsorbed oil.

All samples were weighed with the same NMR testing parameters to obtain the fluid content in different states within the same sample.

4. Results

4.1. Hydrocarbon Geological Characteristics

4.1.1. Lithological Association and Mineral Composition

Based on the rock types and their association relationships, the second sub-member of J₁dn was subdivided into three lithological associations (Figure 2). In Type 1, shale and medium-thick shell limestones were interbedded. Type 2 was mainly composed of shale, with the frequent development of thin interlayers of shell limestone. Type 3 was composed of pure shale. Brittle minerals are internal factors that determine whether a fracture network forms within a reservoir. The changes in the clay mineral content and the brittleness index displayed opposing trends [20,21]. The results indicated that in Type 1, the brittle mineral content in continental shale was 57.68%. In Type 2, the brittle mineral content in continental shale was 59.25%. In Type 3, the brittle mineral content in continental shale was 56.03% (Figure 2). The brittle mineral content in the J₁dn shale was high (Figure 2). The calcite was mostly distributed in the clay matrix as shell laminae; therefore, the fracture easily expanded along the laminae interfaces, and the fracture easily closed again, which reduced the rock fracturing ability. Therefore, if only considering the content of felsic minerals and pyrite, the brittleness index of the J₁dn shale was low (4.1%~59.1%, with an average of 38.9%) [17].

4.1.2. Reservoir Space and Physical Characteristics

The multiscale observation results of hand specimens, thin sections, and scanning electron microscopy (SEM) showed that the pore space in the J₁dn shale oil reservoir included nanoscale pores and fractures. The pore type was primarily mineral matter pores (Figure 3a), with a small number of organic pores. The inorganic pores were mainly clay-related intercrystalline pores (Figure 3b–d), followed by calcite intracrystalline pores (Figure 3e), feldspar intracrystalline pores (Figure 3f), and a small number of pyrite intercrystalline pores (Figure 3g). Organic pores were distributed in the bitumen and had a low degree of development (Figure 3h,i). Multiple-scale fractures developed in the J₁dn continental shale (Figure 4a), such as nanoscale (Figure 4b,c), micrometer-scale (Figure 4d–f), and centimeter-scale fractures. Nanoscale microfractures may develop in the clay matrix, around the organic matter (OM), and within the shell. Micron- and centimeter-sized fractures mainly developed in the shell limestone (Figure 4g–i).

The core sample analyses indicated that the porosity of the J₁dn limestone varied from 0.19% to 10.73% (average value 1.2%) (Figure 5a), and the permeability varied from 0.01 to 28.57 mD (average value 0.25 mD) (Figure 5b). The limestone was characterized by low porosity and low permeability. The porosity and permeability of the J₁dn lacustrine shale were significantly higher than those of the J₁dn shell limestone. The porosity of the shale ranged from 0.5% to 10.5% (Figure 5c), with an average of 5.89%, and the permeability ranged from 0.02 to 32 mD (Figure 5d). In Type 1, the porosity of the lacustrine shale was between 0.76% and 8.23% (average value of 5.99%) (Figure 5e). The porosity of Type 2 ranged from 0.98% to 10.5%, with an average of 6.15% (Figure 5f). The porosity of the Type 3 lacustrine shale varied from 0.5% to 7.61% (average value 5.21%) (Figure 5g).

4.1.3. Organic Geochemical Features

The total organic carbon (TOC) content of the J₁dn continental shale was between 0.09% and 4.48%, with an average of 1.41% (Figure 6a). Of these, 61% accounted for more than 1%. The degree of thermal evolution varied from 1.1% to 1.2%. The TOC content of the J₁dn lacustrine shale varied from 0.22% to 3.24% (average value of 1.28%), and the organic matter abundance was moderate to good [17]. The TOC value of Type 1 varied from 0.09% to 4.48%, with an average of 1.22% (Figure 6b). The TOC value of Type 2 varied from 0.72% to 3.07%, with an average of 1.72% (Figure 6c). The TOC value of Type 3 varied from 0.35% to 3.76%, with an average of 1.3% (Figure 6d). The principal types of OM were II₁ and II₂ (Figure 7a), and the OM was in the oil generation stage (Figure 7b).

4.1.4. Oil-Bearing Property

The evaluation parameters for shale oil content included oil saturation, pyrolysis S₁, chloroform asphalt “A” content, and OSI (S₁/TOC) [22]. The oil saturation of the J₁dn lacustrine shale varied from 0.94% to 5.72%, with an average of 3.15%. Most samples had oil saturation of less than 4% (Figure 8a). The content of free hydrocarbons (S₁) ranged from 0.08 to 5.27 mg/g (average value 1.34 mg/g) (Figure 8b). The hydrocarbon generation potential (S₁ + S₂) varied from 0.43 to 16.62 mg/g, with an average of 5.9 mg/g. The average OSI content of the J₁dn lacustrine shale was 99.22 mg/g (Figure 8c). The S₁ content of lacustrine shale in Type 1 varied from 0.04 to 19.77 mg/g, with an average of 3.14 mg/g and an average OSI index of 56.93 mg/g (Figure 8d). Shale oil migrated over short distances and accumulated in shell limestone reservoirs, with obvious fluorescence reactions indicating a lighter oil quality. Shale oil mainly existed in the joints and dissolution pores of the shells. The S₁ content of lacustrine shale in Type 2 ranged from 0.86 to 14.19 mg/g (average value 4.55 mg/g), with an OSI index of 118.29 mg/g (Figure 8e). The shale oil remained inside the thick shale layer and was distributed in a dispersed form in the matrix. The fluorescence was star-shaped, and the fluorescence reaction was not obvious, indicating that the oil quality was relatively high. The S₁ content of lacustrine shale in Type 3 varied from 0.08 to 3.87 mg/g (average value 0.98 mg/g), with an average OSI index of 62 mg/g (Figure 8f). Previous studies have shown that reservoirs with OSI > 100 mg/g have good oil production capacity, whereas reservoirs with OSI < 70 mg/g generally do not have recoverability. Vertically, the interval with a higher oil content index (OSI > 100 mg/g) was distributed in Type 2 (Figure 8g–i), indicating that the hydrocarbon expulsion efficiency of the lacustrine shale in Type 2 was low and the shale oil was not discharged promptly through initial migration after generation.

4.2. Mobility Characteristics of Shale Oil

4.2.1. Pore Structure in J₁dn Continental Shale

The low-temperature N₂ adsorption (LTNA) isotherms reflected the morphology of the nanoscale pores in the shale [23,24]. Based on the hysteresis loop classification scheme reported by IUPAC [25], the nano-pore morphology of the shale in Type 1 was “inkbottle-shaped” with larger pores. In Type 2, the pore throat morphology of the shale was “conical plate-shaped” with smaller pores. The pore size distribution ranges of both shale reservoir types were relatively wide, with no relatively concentrated pore size intervals (Figure 9).

4.2.2. Movable Oil Content in J₁dn Continental Shale

Shale oil is usually composed of three parts, (1) the bound part, (2) the movable part, and (3) the adsorbed part, of which the movable and adsorbed oils are the effective exploitation parts [26]. This study used a method of gradual centrifugation and drying to distinguish the fluid types of shale oil using a plunger and crushed samples and to clarify the occurrence status of different fluid types. The experimental results indicated that as the centrifugal speed increased, the NMR porosity gradually decreased, and the decrease in NMR porosity represented a corresponding decrease in the movable part. The centrifugation process reduced the amount of movable oil, and the NMR T₂ spectrum showed a peak decrease of more than 10 ms. Gradual drying slowly removed the bound and adsorbed oils, and the nuclear magnetic resonance T₂ spectrum showed a decrease in the signal of the second peak, followed by a decrease in the first peak. The T₁/T₂ value of a fluid is related to its occurrence state, and the T₁/T₂ value of adsorbed or bound oil was higher than that of free oil (Figure 10). The NMR T₁/T₂ spectra of saturated oil, with centrifugation at 16,000 rpm, 140 °C, and 240 °C, revealed the NMR response of the shale oil under different occurrence states (Figure 11a). Therefore, the pores in the J₁dn lacustrine shale were divided into easily flowing pores (>10 ms), bound pores (0.3–10 ms), and adsorption (<0.3 ms) pores. When the centrifugal force reached infinity, the movable oil was considered free oil. The average proportion of free oil reached 22.94% (Figure 11b); in Type 1, the proportion of free oil in lacustrine shale was relatively high (average value 29.41%).

5. Discussion

5.1. Favorable Combination Types

Shale oil is mostly self-generated, self-stored, or accumulated after short-distance migration; therefore, the quality of the hydrocarbon generated by shale forms the foundation of shale oil accumulation. The relationship between the oil content and TOC value determines the prescribed minimum TOC for shale hydrocarbons. The cross-plot between the TOC and OSI in the J₁dn shale shows that when the TOC < 1.5% (Figure 12a), the OSI exhibited a gradually increasing trend, indicating that the oil and gas generated at this time did not fill the reservoir space of the shale [17]. When the TOC > 1.5%, the OSI began to change slightly with an increase in TOC, indicating that the shale had reached a saturated oil state, and the oil and gas generated subsequently were expelled. Therefore, 1.5% was used as the lower TOC limit for the J₁dn continental shale [17]. The degree of thermal evolution of the shale is another important factor affecting its oil content. The maturity mainly affects the oil quality and gas/oil ratio and subsequently affects the mobility of shale oil. The higher the maturity, the lighter the oil quality, and the higher the gas/oil ratio, which benefits the flow of shale oil, facilitating higher production yields. The Ro-OSI cross-plot suggests that before Ro < 0.9% (Figure 12b), the OSI of the J₁dn continental shale gradually increased with thermal evolution, with shale pores being gradually filled by the generated crude oil. When Ro = 0.9%, the OSI reached its maximum, and the shale reached its maximum oil saturation adsorption state. After Ro > 0.9%, the shale continued to generate hydrocarbons, the gas/oil ratio increased, and the flowability of crude oil improved. Some shale was discharged, and, in addition to the loss of light hydrocarbons in the pyrolysis experiments, the OSI gradually decreased. Therefore, Ro = 0.9% was used as the lower maturity limit for Da’anzhai shale.

The porosity of the J₁dn lacustrine shale reservoir was high; however, the pore size distribution was less than 100 nm, which resulted in poor permeability and mobility (Figure 5). In addition, shale reservoirs have high clay content and moderate brittleness, which are not conducive to hydraulic fracturing. Joints and bedding planes create a network of fractures that play a key role in reservoir permeability. They establish mechanical and hydraulic connectivity in the limestone, shale, and sandstones [29,30]. Although the porosity of shell limestone is lower than that of shale reservoirs, it can form fractured or fractured pore-type reservoirs under the communication of fractures at various scales (Figure 13). The early exploration of such reservoirs has been successful, which is significant in the search for high-quality hydrocarbon reservoirs in J₁dn. First, fractures serve as communication channels between organic-rich shale and shell limestone (Figure 4g), providing pathways for organic acid dissolution and oil and gas migration during burial. They are also important reservoir spaces for shale oil (Figure 4h). The measurement results of the mobile oil content indicated that bedding fractures were easily formed between the shell limestone and shale, which benefited the flow of shale oil (Figure 13). The movable oil saturation was significantly higher than the other lithological association types.

5.2. Favorable Exploration Direction

The experimental results suggested that among the various types of shale, the Type 1 shale had the best pore structure, oil content, and oil mobility. This is confirmed by early exploration results. Type 1 shale has the geological conditions needed to achieve a high yield. Crude oil production in different areas of Da’anzhai in the Sichuan Basin has shown that the frequency of shell limestone interlayer development gradually increases from the center to the margin of the lake basin, and the daily production of a single well also shows a gradual upward trend (Figure 14). In areas with a shell limestone interlayer, the daily production of a single well can reach up to 10.6 t/d. Exploration has shown that the Type 1 shales are highly suitable for shale oil.

6. Conclusions

(1)

The Jurassic Da’anzhai lacustrine shale oil reservoir was divided vertically into three sub-members. Organic-rich continental shales developed within the second sub-member. Three types of lithological association developed in the organic-rich shale interval. Generally, the brittleness index of the organic-rich Da’anzhai lacustrine shale was relatively low. The porosity of the J1dn continental shale varied from 0.5% to 10.5% (average value of 5.89%). The pores were predominantly composed of inorganic pores, with a small proportion of organic pores. The average porosity of the shell limestone was only 1.2%, but fractures at the micron and centimeter scales were well developed.

(2)

The OM types of the J₁dn continental shale were II₁–II₂, with a small amount of Type 1. The maturity of the OM was observed in the oil generation stage. The average oil saturation of the J₁dn continental shale was 3.15%, with most samples having oil saturation of less than 4%. The average free hydrocarbon (S₁) value was 1.34 mg/g, the average hydrocarbon generation potential (S₁ + S₂) was 5.9 mg/g, and the OSI content was 99.22 mg/g. The J₁dn continental shale has high shale oil exploration potential. Type 1 shale oil is affected by multiscale fractures, including bedding fractures, and has the best mobility. The high hydrocarbon generation quality of continental shale, coupled with the multiscale fractures within the shell limestone and continental shale, is the principal factor controlling shale oil enrichment.

(3)

Based on the differences in the macroscopic parameters of shale reservoirs under different lithological association conditions, the Type 1 shale association was selected as the most favorable lithological association type. Type 1 shale has the best shale oil enrichment conditions, providing an exploration target for the development of Jurassic Da’anzhai shale oil in the Sichuan Basin. Further analysis of the differences in micro-enrichment patterns and controlling factors of shale oil under different lithological associations is required.