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Key factors controlling shale oil enrichment in saline lacustrine rift basin: implications from two shale oil wells in Dongpu Depression, Bohai Bay Basin

Key factors controlling shale oil enrichment in saline lacustrine rift basin: implications from... Comparative analyses of petroleum generation potential, reservoir volume, frackability, and oil mobility were conducted on 102 shale cores from the Dongpu Depression. Results show the shale has high organic matter contents composed of oil-prone type I and type II kerogens within the oil window. Various types of pores and fractures exist in the shale, with a porosity of up to 14.9%. The shale has high brittle mineral contents, extensive fractures, and high potential for oil mobility due to high seepage capacity and overpressure. Although the petroleum generation potential of the shale at Well PS18-8 is relatively greater than that at Well PS18-1, oil content of the latter is greater due to the greater TOC. The porosity and fracture density observed in Well PS18-1 are greater and more conducive to shale oil enrichment. Although the shales in Wells PS18-1 and PS18-8 have similar brittle mineral contents, the former is more favorable for anthropogenic fracturing due to a higher pre- existing fracture density. Besides, the shale at Well PS18-1 has a higher seepage capacity and overpressure and therefore a higher oil mobility. The fracture density and overpressure play key roles in shale oil enrichment. Keywords Petroleum generation potential · Reservoir volume · Frackability · Oil mobility · Shale oil enrichment · Dongpu Depression · Saline lacustrine rift basin 1 Introduction Shale oil refers to the oil generated in organic-rich shales and stored in them or adjacent organic-lean intervals (Jarvie Edited by Jie Hao and Chun-Yan Tang 2012). Shale oil has been found in the USA, such as Barnett and Antelope tight shale oil, Bakken and Monterey frac- * Tao Hu tured shale oil, and Bakken and Eagle Ford hybrid shale oil thu@cup.edu.cn systems (Jarvie 2012). The USA’s successful marine shale Xiong-Qi Pang oil revolution has boosted confidence in recreating success pangxq@cup.edu.cn in lacustrine basins. Numerous lacustrine basins are distrib- Fu-Jie Jiang uted across the world, such as the USA (Katz 1995), Brazil jiangfj@cup.edu.cn (Mello et al. 1991), India (Saikia and Dutta 1980), Indone- State Key Laboratory of Petroleum Resources sia (Katz and Kahle 1988), and China (Wang et al. 2019), and Prospecting, China University of Petroleum, containing numerous shale oil resources. China is rich in Beijing 102249, China lacustrine shale oil resources with a recoverable amount of College of Geosciences, China University of Petroleum, 43.5×10 t, ranking the third in the world (EIA 2008). which Beijing 102249, China were found in the Dongying Depression (Wang et al. 2015a), Energy & Geoscience Institute, University of Utah, Dongpu Depression (DD) (Wang et al. 2014, 2015a), Cang- Salt Lake City, UT 84108, USA dong Sag (Zhao et al. 2019), and Zhanhua Depression (Li Research Institute of Exploration and Development, et al. 2017) in Bohai Bay Basin, the Bohai Sea area (Jiang Zhongyuan Oilfield Company, SINOPEC, et al. 2016), and the Qingshankou Formation in Songliao Puyang, Henan 457001, China Vol.:(0123456789) 1 3 3360 688 Petroleum Science (2021) 18:687–711 Basin (Liu et al. 2017). In particular, for the Kongdian For- the shale oil enrichment laws of productive shale oil plays mation in Cangdong Sag, the natural daily yields of two hor- in the USA to China. izontal shale oil wells GD-1701H and GD1702H achieved Recently, attempts have been made to investigate the 20–30 m for more than 300 days by now. Besides, the well shale oil enrichment in lacustrine basins and identify fac- G1608 obtained a peak daily oil yield of 60 m after frac- tors for the enrichment. Liu et al. (2013) investigated the turing, producing for 105 days and reaching a cumulative shale oil enrichment laws for Lucaogou Formation, Malang oil production of more than 1704 m (Zhao et al. 2019). Depression, Santanghu Basin, and hold that the fractures These discoveries suggest promising shale oil exploration would promote the oil and gas loss in the shale system prospects in lacustrine shale oil (Li et al. 2014; Wang et al. and result in the decreasing oil and gas enrichment. This 2019). is consistent with the studies conducted by Rodriguez Significant differences exist between marine and lacus- and Paul (2010). Li et al. (2014) studied shale oil system trine shale oil plays. Marine shales are widely distributed in Hetaoyuan Formation of Biyang Depression, Nanxiang and have high organic matter contents, high thermal matu- Basin, and found that oil enrichment was controlled by the rity, high brittle mineral contents, and high formation pres- oil generation capacity, reservoir volume, and preservation sure. They contain good-quality organic matter dominated conditions and the producibility was controlled by the shale by type II kerogen and generate light oils with low wax con- frackability, oil density, and development scheme. Finally, tent and viscosity (Enderlin et al. 2011; Ferrill et al. 2014; Li et al. (2014) concluded thermal maturity is the key fac- Jarvie et al. 2007; Nie et al. 2016; Wang et al. 2014). By tor controlling shale oil enrichment, and the southeastern contrast, lacustrine shales are distributed over a small area regions with deep burial depth are favorable for shale oil and exhibit a strong heterogeneity. The organic matter in the enrichment, which is consistent with the studies conducted shales shows large variations in contents and compositions by Nie et al. (2016) and Wang et al. (2017). Bai et al. (2017) dominated by type I and type II kerogens, which have low hold that the oil generation capacity and evolution, reservoir thermal maturity, low quartz mineral content and mainly volume, and overpressure control the oil enrichment, the oil generate waxy oil (Katz and Lin 2014; Chen et al. 2015; density, viscosity, and gas–oil ratio control the oil movabil- Wang et al. 2014, 2015a, b, 2019; Nie et al. 2016). Clearly, ity, the lithological combination and brittle mineral contents lacustrine basins and marine basins have distinct differences of shale control the frackability. Liu et al. (2018) studied in geological and geochemical characteristics (Jiang et al. the petrological characteristics and shale oil enrichment in 2017; Wang et al. 2019). It is difficult to arbitrarily apply Qingshankou Formation of Gulong Sag, Songliao Basin, 114°50′ 115°00′ 115°10′ (c) 04 8 km 1 km Beijing PC Bohai Bay Basin LT HBZ Dongpu Depression H96 MG 35° 35° HZJ WL 40′ 40′ (a) QLY W21 Town name 11 HTJ W218 HBZ-Hubuzhai H72 PC-Pucheng Fault name MG-Maogang W19 1.Lanliao PS18 WL-Wenliu 2.Gaopingji HZJ-Huzhuangji 35° 2 35° 3.Liuta QLY-Qianliyuan 18 20 PS18-1 30′ 30′ 4.Mazhai W39 HTJ-Haitongji 5.Shijiaji WC-Weicheng 6.Changyuan LT-Liutun 7.Weixi 9 1 PS18-8 8.Wenxi 9.Huanghe 10.Puchenge W120 11.Duzhai12.Machang W246 W142 13.Sanchunji14.Weidong 15.Wendong 16.Liangzhaung 17.Xulou Sampled Well Fault 18.Yuhuangmiao 35° 35° 13 19.Madong 20.Litun well 20′ 12 20′ Predicted Structural Shale-oil contour (b) Town Fault Reservoir 114°50′115°00′ 115°10′ Fig. 1 Geological map of Liutun Sag, Dongpu Depression (DD). a Overview map of China showing the location of the Bohai Bay Basin and DD, b regional structural map of the DD showing the location of the Liutun Sag (modified after Wang et al., 2015a), and c structure contour map of the Es (an upper sub-member of third member of the Paleogene Shahejie Formation) and key wells in the Liutun Sag 1 3 Xingzhuang fault Wenxi fault 2960 Petroleum Science (2021) 18:687–711 689 and concluded that the laminated siliceous mudstone with Neogene strata. Located in the central western region of moderate TOC is most favorable for shale oil enrichment. the DD (Fig. 1), the Liutun Sag is the second-largest petro- Lots of saline lacustrine rift basins develop in China and are leum generating sag. The strata consist of the Paleogene rich in shale oil resources. Although many studies have been Kongdian, Shahejie and Dongying Formations, Neogene conducted on the factors controlling shale oil enrichment, Minghuazhen and Guantao Formations, and the Quater- few systematic analyses about the macrogeological condi- nary Pingyuan Formation. The strata have a thickness of tions have been made, which are significant in “sweet spots” approximately 6000 m, with Es as the main source rock prediction in shale oil system. and reservoir (Wang et al. 2015a). The Es shale is divided U M L The DD is a typical saline lacustrine rift basin in China, into Es, Es , and Es (middle and lower submember of 3 3 3 in which the third member of the Paleogene Shahejie Forma-the Es ), from top to bottom. The shale oil play was devel- tion (Es ) is thick and rich in shale oil resources (Wang et al. oped in Es at a burial depth of 3200–4000 m, consist- 3 3 2014, 2015a, 2019). Since 1976, oil shows had been discov- ing of clastic mudstones, carbonate rocks, and evaporites ered from the Es shale of Wells Wen 6, Wen 300, and Wen (Fig.  2). Faults are not developed in the central Liutun 201 in the DD and even yielded some oil (Mu et al 2003; Sag. However, due to the impact of the marginal faults at Leng et al. 2006). In 2010, the Well PS18-1 obtained a daily the eastern and western sides of the sag, numerous small oil yield of 430 m with a 5 mm size nozzle in the depth of secondary faults occur near these faults and are favorable 3,255–3,258 m in the Es shale (Zhang et al 2015), which for fracture development (Wang et al. 2004, 2015a). is the highest single-well production obtained in a shale oil exploration well recently (Zhang et al. 2012; Wang et al. 2014). However, only oil shows were observed in subsequent drilling Well PS18-8, which was located only approximately 800 m to the south of Well PS18-1. Under similar structural conditions, why do these two wells exhibit such a remark- System Formation symbol Lithology Deposition system able difference in shale oil yield? Obviously, the two wells Quaternary Py Fluvial are excellent objects for conducting shale oil enrichment Nm studies. However, in the DD, the subsequent studies mainly Neogene Fluvial Ng investigated the generally geological and geochemical char- acteristics of the Es shale (Deng et al. 2015; Wang et al. 3 Ed Fluvial and flood plain 2014, 2015a; Zhang et al. 2015), rarely focused on the shale oil enrichment laws. Shallow-semideep Es lacustrine and delta Targeting the Es shales in the Wells PS18-1 and PS18- 8, this study utilized continuous cores to reveal key factors Shore-shallow controlling shale oil enrichment. Detailed geological and Es lacustrine, fan delta fluvial, and flood plain geochemical studies were carried out to examine petroleum generation potential, reservoir capacity, frackability, and oil Paleogene Es Es mobility. Comparative analyses were conducted regarding Semideep-deep saline their differences in production capacity. Finally, the key fac- Es lacustrine, delta Es turbidite and fan delta tors controlling shale oil enrichment were proposed. The results obtained in this study can provide significant refer - Es3 ences for further shale oil exploration in saline lacustrine rift Lacustrine, turbidite basins across the world. Es and fluvial Ek Fluvial 2 Geological background Erosion line Mudstone Sandstone Shale Limestone Salt rock Siltstone The DD, located in the southwestern corner of the Bohai Bay Basin, is a Mesozoic and Cenozoic lacustrine rift Fig. 2 Generalized stratigraphy and depositional system of the Liutun basin in Paleozoic craton with an area of 5300 km (Fig. 1) Sag, DD (modified after Wang et  al., 2015a; Luo et  al., 2016). Es: (Chen et al. 2000). The DD extends to the NNE-SSW and Shahejie Formation; Ed: Dongying Formation; Ng: Guantao Forma- tion; Nm: Minghuazhen Formation; Qp: Pingyuan Formation; Es : is narrow in the south but broad in the north (Chen et al. 3 Third member of Paleogene Shahejie Formation; Es : Lower sub- 2013). Four tectonic movements and six tectonic evolu- M U member of Es; Es : Middle sub-member of the Es; Es : Upper 3 3 3 3 tion stages occurred (Chen et al. 2013), forming a set of sub-member of Es ; Es : Forth member of Paleogene Shahejie For- 3 4 super-thick continental strata dominated by Paleogene and mation; Ek: Paleogene Kongdian Formation 1 3 690 Petroleum Science (2021) 18:687–711 Fig. 3 Lithological column of main intervals of interest in Wells PS18-1 and PS18-8 of the Liutun Sag, DD, showing the locations of the core samples 1 3 Stratum Depth, m Lithology Stratum Depth,m Lithology Mudstone Salt rock Gypsum-salt rock 3 41 42 Gypsiferous mudstone Shale 9 Sample position Es3 17 3270 63 82 21 u Es 69/70 90/91 75/76 Es 102 (b) PS18-8 (a) PS18-1 Petroleum Science (2021) 18:687–711 691 have the greatest and the lowest petroleum generation poten- 3 Samples and methods tial, respectively, and therefore the weighting coefficient are +100 and − 100. Exinite is mainly originated from chitin 3.1 Samples tissues of terrestrial or aquatic higher plants. Esters with higher fatty acids and higher alcohols in the chitin tissues One hundred two shale samples were cored from Wells can be reduced by hydrolysis to generate petroleum. There- PS18-1 (3258–3285 m) and PS18-8 (3155–3193 m) in the fore, the exinite has certain petroleum generation potential, Es shale oil play (Fig. 3). and the weighting coefficient is +50. Vitrinite is mainly formed from xylems of higher plants. During bituminiza- 3.2 Methods tion, the asphaltenes formed by deoxidization of long-chain acids, alcohols, and esters are mainly absorbed by vitrinite. For TOC analysis, 100 milligrams of shale samples was The petroleum generation potential of the vitrinite is greater washed and ground to 100 mesh powder and immersed in than inertinite, but signic fi antly lower than sapropelinite and dilute hydrochloric acid to remove inorganic carbon. Then, exinite. Following the weighting coefficient proposed by the the samples were rinsed repeatedly with distilled water until EXXON, the weighting coefficient of the vitrinite is − 75 a neutral pH was achieved and were subsequently dried in (Cao 1985). The calculation function of the TI is as follows: an oven at 60–80 °C. The samples were then analyzed using a LECO CS-400 instrument (Espitalié et al. 1977). Soxhlet TI = (a × 100 + b × 50 − c × 75 − d × 100)∕100 (1) extraction was performed on the shale samples with chlo- roform for 72 h. To obtain rock extract “A,” the fractions of where a, b, c, d are the contents of the sapropelinite, saturated hydrocarbons, aromatic hydrocarbons, nonhydro- exinite, vitrinite, and inertinite, respectively. The kerogen carbons, and asphaltenes were tested by reference to the Oil with TI > 80 % is type I, that with 0 < TI < 80 % is type II, and Gas Industry Standard of the People’s Republic of China and that with TI < 0 is type III. (Zheng et al. 2008). High-resolution field emission-scanning electron micros- Mineral composition was obtained by X-ray diffraction copy (FE-SEM) was utilized to study the fractures and pores. (XRD) analysis with a Panalytical X’Pert PRO diffractom- The experimental instrument was a FEI Quanta 200F scan- eter at a temperature of 24 °C and humidity of 35% with a ning electron microscope set to a voltage of 20 kV and an 2°/min 2θ rotation speed and a Cu Ka emission source pow- object distance of 10–12 mm. A QUANTAX400 energy ered at 40 kV and 30 mA. This study adopted the Rietveld spectrometer was used in energy spectrum analyses at an method for quantitative phase analysis (Ufer et al. 2008). acceleration voltage of 20 kV with a dead time of 35–40 The biological microscope with fluorescence emission %, and a live time of 100 s. The experiment was conducted was utilized to observe size, morphology, and fluorescence at the temperature of 20 ℃ and humidity of 50 %. To ana- of the organic matter in the shale samples to identify the lyze pores with sizes smaller than one micrometer, the sam- kerogen macerals. Thin slices of the shale samples were pre- ples were first subjected to argon ion polishing (Gatan 691. pared using glycerol and examined with 40× object lens to CS) followed by gold plating (SCD500) prior to taking the determine the representative size of the macerals, which was measurements. The measurements were conducted on the regarded as the standard statistical unit. After that, the visual natural section samples directly for observation of fractures field was moved at equal distance interval relative to the ini- and pores with sizes greater than several micrometers (Jiao tial position. In each visual field, the marcels were identified et al. 2016). and counted. The visual field and the marcels observed in that field were labeled by the coordination of the field center to the initial position. 4 Results and discussion Kerogen type index (TI) was calculated by utilizing the method proposed by Cao (1985), which has been used to 4.1 Petroleum generation potential and shale oil evaluate kerogen types of lacustrine shale (Tao et al. 2012; content Luo et al. 2017). The maceral of kerogen is composed of sapropelinite, exinite, vitrinite, and inertinite. Generally, the 4.1.1 Organic matter content sapropelinite mainly originates from the lower plankton, and the higher the content of sapropelinite is, the more favorable The TOC values of the shale samples range between 0.35 % the kerogen is for petroleum generation. Inertinite is formed and 5.7 % with a mean of 1.83 % (Table 1), showing that 74 from xylems of higher plants by intense carbonization or car- % of the shale is good to excellent source rocks (Fig. 4). The bonization after gelation, with high carbon content and low Es shale is distributed throughout the entire DD, with the hydrogen content. Therefore, the sapropelinite and inertinite greatest thickness (up to 325 m) in the center. The thickness 1 3 692 Petroleum Science (2021) 18:687–711 1 3 Table 1 Total organic carbon (TOC) testing data of Es shale samples in the Liutun Sag, DD Well Sample No. Depth TOC, % Well Sample No. Depth TOC, % Well Sample No. Depth TOC, % Well Sample No. Depth TOC, % PS18-1 1 3258.00 2.11 PS18-1 27 3276.60 2.61 PS18-8 52 3162.52 1.26 PS18-8 77 3175.10 1.30 PS18-1 3 3258.75 3.29 PS18-1 28 3277.20 2.15 PS18-8 53 3163.02 1.03 PS18-8 78 3175.50 0.63 PS18-1 4 3259.10 2.46 PS18-1 29 3278.25 3.12 PS18-8 54 3163.52 1.12 PS18-8 79 3176.20 0.37 PS18-1 5 3259.50 2.82 PS18-1 30 3279.00 2.57 PS18-8 55 3164.10 1.01 PS18-8 80 3177.65 0.35 PS18-1 6 3260.05 4.43 PS18-1 31 3280.20 1.15 PS18-8 56 3164.55 1.11 PS18-8 82 3181.00 2.21 PS18-1 7 3260.51 2.55 PS18-1 32 3281.00 0.80 PS18-8 57 3165.05 0.96 PS18-8 83 3181.70 2.93 PS18-1 8 3261.01 1.93 PS18-1 33 3283.10 3.20 PS18-8 58 3165.50 0.92 PS18-8 84 3181.92 2.71 PS18-1 9 3261.50 2.92 PS18-1 34 3284.30 3.24 PS18-8 59 3165.55 0.78 PS18-8 85 3182.16 1.77 PS18-1 10 3262.10 2.64 PS18-1 35 3284.90 2.85 PS18-8 60 3165.95 2.17 PS18-8 86 3182.54 1.20 PS18-1 11 3262.50 3.24 PS18-8 36 3155.22 3.20 PS18-8 61 3166.35 2.35 PS18-8 87 3182.60 1.44 PS18-1 12 3262.95 1.44 PS18-8 37 3155.72 3.01 PS18-8 62 3166.80 5.58 PS18-8 88 3183.00 0.83 PS18-1 13 3263.61 2.03 PS18-8 38 3156.07 2.08 PS18-8 63 3167.20 2.06 PS18-8 89 3183.40 1.91 PS18-1 14 3267.91 0.88 PS18-8 39 3156.47 2.72 PS18-8 64 3167.60 1.21 PS18-8 90 3183.95 3.37 PS18-1 15 3268.21 1.15 PS18-8 40 3157.12 3.76 PS18-8 65 3167.90 0.60 PS18-8 91 3184.00 1.93 PS18-1 16 3268.51 0.95 PS18-8 41 3157.42 3.94 PS18-8 66 3168.40 0.66 PS18-8 92 3184.60 1.96 PS18-1 17 3269.01 0.76 PS18-8 42 3157.72 3.23 PS18-8 67 3168.75 0.58 PS18-8 93 3185.30 5.18 PS18-1 18 3269.51 0.70 PS18-8 43 3158.32 1.72 PS18-8 68 3169.90 1.26 PS18-8 94 3185.80 2.36 PS18-1 19 3270.45 0.54 PS18-8 44 3158.77 1.11 PS18-8 69 3170.20 2.06 PS18-8 96 3187.10 5.70 PS18-1 20 3270.85 0.78 PS18-8 45 3159.07 1.70 PS18-8 70 3170.20 0.88 PS18-8 97 3187.60 2.58 PS18-1 21 3270.98 0.86 PS18-8 46 3159.67 1.02 PS18-8 71 3170.80 1.08 PS18-8 98 3190.35 1.12 PS18-1 22 3271.78 0.72 PS18-8 47 3160.22 1.08 PS18-8 72 3171.60 0.93 PS18-8 99 3191.00 1.69 PS18-1 23 3272.48 0.94 PS18-8 48 3160.52 1.01 PS18-8 73 3172.10 1.05 PS18-8 100 3191.80 1.60 PS18-1 24 3273.20 3.59 PS18-8 49 3160.97 1.11 PS18-8 74 3174.10 0.69 PS18-8 101 3192.50 1.77 PS18-1 25 3274.30 1.05 PS18-8 50 3161.52 0.98 PS18-8 75 3174.65 0.46 PS18-8 102 3193.00 1.64 PS18-1 26 3275.22 1.01 PS18-8 51 3162.02 1.37 PS18-8 76 3174.70 0.64 PS18 103 3238.00 1.22 Petroleum Science (2021) 18:687–711 693 with SEM (Fig. 5i). These objects are also interpreted as 74.0% Good-Excellent algae fossils due to their shapes. Further energy spectrum PS18-1 (N=34) PS18-8 (N=65) analyses reveal that these fossils are rich in carbon and oxy- gen (Fig. 5j), indicating they are algae fossils (Tyson 1995; Qiu et al. 2015; İnan et al. 2016). The alginite content is low with an average of only 2.5 % (0.3–11.3 %) due to easy decomposition. The exinite primarily consists of hydrogen-poor amor- phous organic matter, sporinite, and cutinite, with average 0.2 0.6 1.0 1.4 1.8 2.2 2.6 3.0 3.4 3.8 4.2 4.6 5.0 5.4 5.8 contents of 27.5 % (0–88.5 %), 2.2 % (0–15.3 %), and TOC, % 1.8 % (0–5.3 %). The hydrogen-poor amorphous organic matter is formed from higher plants degradation, the Fig. 4 Frequency histograms of total organic carbon (TOC), indi- microscopic characteristics of which are similar to hydro- cating that the Es shale is a set of good–excellent source rock. N indicates the number of samples. The evaluation criterion for good- gen-rich amorphous organic matter, exhibiting flat, floc- excellent source rocks was from Peters and Cassa (1994) culent, and cloudy shapes (Fig. 5o), has a high petroleum generation potential but exhibits little fluorescence and some raised folds under the microscope. The precursors gradually decreases to 100 m at the north margin and to 75 of sporinite (Fig. 5k, l, m, and n) are primarily the chitin- m at the south margin (Deng et al. 2015). The average TOC ous tissues of higher plants containing higher fatty acids, value of Well PS18-1 is 1.98 %, and the variation is between alcohols, and lipids, generating petroleum by hydrolysis 0.54 % and 4.43 %, and the average value of Well PS18-8 or reduction (Cao 1985). Vitrinite is mainly composed of is 1.75 %, with a range from 0.35 % to 5.70 % (Table  1), telinite and euvitrinite, with average contents of 7.8 % showing that the organic matter content of the shale varies (1.3–28.3 %) and 0.4 % (0–3.8 %), respectively, which considerably, but the lateral difference between these two originates from wood fibers of higher plants, presenting a wells is not significant. weak fluorescence and primarily generate natural gas. Tel- inite has a clear wood structure characterized by tubular 4.1.2 Organic matter type cells, various conduits, and fibrous structures (Fig.  5p), and the structural clarity and transparency vary with the Maceral composition can be used to determine organic degradation degree. Inertinite is opaque under transmis- matter type of shale (Huang et al. 1984; Tissot and Welte sion light and has a dark brown to black-on-black angu- 1984). Results show that the kerogen of the Es shale is 3 lar shape, which is formed from the xylem fiber tissue on average composed of 59.4 % sapropelinite (1.6–96.7 %), of higher plants by fusainization, from which only trace 31.8 % exinite (0.3–89.7 %), 8.3 % vitrinite (1.3–31.6 %), amounts of natural gas are generated. and 0.5 % inertinite (0–3.0 %) (Table 2). The hydrogen-rich The maceral composition of the Es shale varies with amorphous content, accounting for an average of 57.3 % depth. In detail, the shale samples from the thick and stable (0.9–95.5 %), is predominantly translucent, nonhomogene- shale section are commonly rich in hydrogen-rich amor- ous, and flocculent (Fig.  5a, b, c, and d). The hydrogen-rich phous organic matter and poor in hydrogen-poor amorphous organic matter is amorphous, ranging in size from tens to organic matter, but the opposite is true for the section with hundreds of microns, and mainly exhibits a brown–yellow shale interbedded with evaporites (Fig. 6). This is because color under transmitted light (Fig.  5a, b, c, and d) and a that the former section was mainly developed in deepwater bright-yellow color under the fluorescent microscope. The environment, and the organic matter mainly originates from hydrogen-rich organic matters are the degradation products lower aquatic organisms and algae. of aquatic organisms and algae under strong reducing con- The TI values show that the organic matter of the shale ditions and have a significant petroleum generation poten- from Well PS18-1 is dominated by type II kerogen, while tial (Burgess 1974; Rahman and Kinghorn 1995; Luo et al. the shale from Well PS18-8 is mainly composed of type I 2017). Well-preserved elliptic alginite ranging from tens to and II kerogen. The triangular chart further confirms that hundreds of microns in size is found in the sapropelinite the organic matter of Well PS18-1 shale is entirely type II and exhibits a yellow–brown color under transmitted light kerogen, while that of Well PS18-8 shale is mainly type I (Fig. 5e, f, g, and h). Alginite is the most typical hydrogen- kerogen with a small amount of type II kerogen (Fig.  7). rich microcomponent of sapropelinite and has a strong petro- Lacustrine systems are highly sensitive to climate changes leum generation potential (Luo et al. 2017). Alginite is the (Katz 1995), and the sequent changes in the balance degradation product of algae, and clear degradation traces between precipitation and evaporation further lead to the can be seen (Fig. 5f). Axiohitic objects were also detected salinity variation, which in turn result in great variation in 1 3 Frequency, % 694 Petroleum Science (2021) 18:687–711 1 3 Table 2 Chloroform bitumen “A,” vitrinite reflectance (VR), macerals, and kerogen-type index data of Es shale samples in the Liutun Sag, DD Well Sample Depth, Rock VR % Hydro- Alginite, Hydro- Sporin- Cutinite, Telinite, Euvitrin- Inerti- Sapro- Liptinite, Vitrinite, Inerti- Kerogen No. m extract gen-rich % gen-poor ite, % % % ite, % nite, % pelinite, % % nite, % type, % "A", amor- amor- % ppm phous, % phous, % PS18-1 3 3258.75 11,582 0.91 62.19 0.55 32.05 1.37 0 3.84 0 0 62.74 33.42 3.84 0 76.58 PS18-1 5 3259.5 10,041 - 64.58 0 27.9 5.33 0.31 1.88 0 0 64.58 33.54 1.88 0 79.94 PS18-1 7 3260.51 9183 0.94 61.13 0 32.71 5.33 0 1.33 0 0 61.13 37.54 1.33 0 78.89 PS18-1 10 3262.1 10,402 0.90 62.16 0.81 24.32 5.14 1.62 5.41 0 0.54 62.97 31.08 5.41 0.54 73.92 PS18-1 12 3262.95 3767 - 35.96 0.95 46.37 3.79 2.21 8.52 0 2.2 36.91 52.37 8.52 2.2 54.5 PS18-1 14 3267.91 2668 0.93 47.45 0.9 23.72 15.32 3.3 8.41 0.3 0.6 48.35 42.34 8.71 0.6 62.39 PS18-1 19 3270.45 1577 0.94 0.86 0 81.38 3.72 2.01 11.46 0 0.57 0.86 87.11 11.46 0.57 35.24 PS18-1 23 3272.48 4518 0.96 49.68 0.32 40.26 0.97 0.32 7.48 0.32 0.65 50 41.55 7.8 0.65 64.29 PS18-1 28 3277.2 9581 0.99 35.67 0.88 52.63 2.34 0.58 7.61 0 0.29 36.55 55.55 7.61 0.29 59.69 PS18-1 33 3283.1 8172 - 46.84 2.22 45.89 0.95 0.63 2.84 0 0.63 49.06 47.47 2.84 0.63 70.51 PS18-1 35 3284.9 17,809 0.98 7.9 0 88.45 0.91 0 2.74 0 0 7.9 89.36 2.74 0 51 PS18-8 37 3155.72 12,850 0.82 87.83 3.95 0 0 1.32 6.57 0.33 0 91.78 1.32 6.9 0 87.66 PS18-8 39 3156.47 12,703 0.83 93.26 1.69 0 0 0.28 4.77 0 0 94.95 0.28 4.77 0 91.5 PS18-8 41 3157.42 15,396 0.82 87.5 2.5 2.81 0.94 2.19 2.81 0.94 0.31 90 5.94 3.75 0.31 89.84 PS18-8 42 3157.72 12,787 0.80 56.53 2.13 29.6 0.8 1.33 9.08 0.53 0 58.66 31.73 9.61 0 67.67 PS18-8 43 3158.32 2384 0.81 77.74 1.25 15.67 1.88 1.25 2.21 0 0 78.99 18.8 2.21 0 86.76 PS18-8 45 3159.07 9007 0.83 83.83 1.65 2.97 1.32 2.97 6.93 0 0.33 85.48 7.26 6.93 0.33 84.6 PS18-8 47 3160.22 2261 0.82 52.98 8.78 16.3 1.88 5.33 13.79 0.31 0.63 61.76 23.51 14.1 0.63 62.7 PS18-8 50 3161.52 1905 0.85 41.96 11.31 18.45 4.76 5.06 16.67 1.49 0.3 53.27 28.27 18.16 0.3 54.88 PS18-8 52 3162.52 2717 0.89 21.75 3.57 55.19 2.27 3.9 12.02 0.65 0.65 25.32 61.36 12.67 0.65 46.27 PS18-8 54 3163.52 1982 0.88 29.95 5.22 23.35 2.47 4.12 28.57 3.3 3.02 35.17 29.94 31.87 3.02 23.64 PS18-8 56 3164.55 2238 0.89 69.51 5.49 14.63 1.22 2.74 6.11 0.3 0 75 18.59 6.41 0 79.88 PS18-8 60 3165.95 6607 0.93 79.81 1.89 15.14 0 0.63 2.53 0 0 81.7 15.77 2.53 0 88.19 PS18-8 63 3167.2 8178 0.94 92.66 0.28 0 0.28 0.28 6.22 0 0.28 92.94 0.56 6.22 0.28 88.28 PS18-8 66 3168.4 1771 0.92 12.5 2.98 61.62 3.27 3.27 13.1 1.47 1.79 15.48 68.16 14.57 1.79 36.83 PS18-8 69 3170.2 7963 0.95 78.08 0.62 2.8 1.23 1.23 15.73 0 0.31 78.7 5.26 15.73 0.31 69.21 PS18-8 77 3175.1 4050 - 74.14 2.49 15.26 1.25 1.25 5.3 0 0.31 76.63 17.76 5.3 0.31 83.57 PS18-8 80 3177.65 492 - 1.08 0.54 65.59 2.96 3.49 24.46 0.54 1.34 1.62 72.04 25 1.34 17.54 PS18-8 83 3181.7 13,951 0.93 88.17 2.15 0 0 1.79 7.17 0 0.72 90.32 1.79 7.17 0.72 85.57 PS18-8 87 3182.6 3271 0.95 87.74 0.65 0 0.65 0.97 8.7 0 1.29 88.39 1.62 8.7 1.29 81.87 PS18-8 90 3183.95 12,583 0.94 95.48 1.2 0 0.3 1.2 1.52 0 0.3 96.68 1.5 1.52 0.3 96.01 PS18-8 94 3185.8 5975 0.93 15.38 1.6 71.79 0.64 2.88 7.39 0 0.32 16.98 75.31 7.39 0.32 48.8 PS18-8 99 3191 5559 0.95 88.08 2.33 0 0.29 2.33 2.61 3.78 0.58 90.41 2.62 6.39 0.58 86.34 Petroleum Science (2021) 18:687–711 695 Hydrogen- (a)(b) (c)(d) rich Hydrogen- amorphous rich amorphous Hydrogen- rich Hydrogen- Hydrogen-rich Hydrogen- amorphous rich amorphous rich amorphous amorphous 50 μm 50 μm 50 μm 50 μm (e) (f) (g)(h) Alginite Alginite Alginite Alginite Degradation traces 50 μm 50 μm 50 μm 50 μm (around the algae) Element Intensity, c/s Atomic, % Relative content, % Cnts C 140.87 44.43 31.33 O 229.30 40.39 37.94 (i) (j) (k)(l) Na 59.45 2.78 3.76 Axiohitic Sporinite Mg 37.37 1.21 1.73 3.0K O Al 54.84 1.38 2.19 algae Si 122.20 2.61 4.31 160.23 2.82 5.31 K 6.25 0.10 0.24 Ca 48.60 0.83 1.95 2.0K Fe 124.96 3.43 11.25 Si 1.0K Al Fe Na S Sporinite Al Fe Fe Si Ca K Fe Mg S Fe K Ca K Mg Si Fe Fe 2 μm S Na Al S K Ca 50 μm 15 μm 20 kV 15 kX 05 10 keV (m) (n)(o) (p) Sporinite Hydrogen- Sporinite poor amorphous Telinite 50 μm 50 μm 50 μm 50 μm Fig. 5 Photomicrographs showing typical maceral composition of kerogen in Es shale of Liutun Sag, DD: a Well PS18-1, 3258.75m, ×640, hydrogenrich amorphous; b Well PS18-1, 3259m, ×640, hydrogen-rich amorphous; c Well PS18-8, 3185m, ×640, hydrogen-rich amorphous; d Well PS18-8, 3191m, ×640, hydrogen-rich amorphous; e Well PS18-1, 3262.95m, ×640, alginite; f Well PS18-1, 3283.1m, ×640, alg- inite; g Well PS18-8, 3157.42m, ×640, alginite; h Well PS18-8, 3191m, ×640, alginite; i Well PS18-8, 3193m, 20kV, alginite; j Well PS18-8, 3193m, energy spectrum analysis indicate that the axiohitic object in the (i) is algae; k Well PS18-1, 3258.75m, ×640, sporinite; l Well PS18-1, 3258.75m, ×1020, sporinite; m Well PS18-8, 3182.6m, ×640, sporinite; n Well PS18-8, 3182.6m, ×1020, sporinite; o Well PS18-8, 3175m, ×640, hydrogen-poor amorphous; p Well PS18-8, 3157.72m, ×640, telinite the kerogen composition. As shown in Fig. 3, during Es more shale samples of Well PS18-8 are type I, while few deposition, thick and stable shale was developed in Well samples from Well PS18-1 are (Fig. 7). PS18-1 (3250–3285 m), while the shale in Well PS18-8 was frequently interbedded with evaporites (3167–3178 4.1.3 Thermal maturity m), indicating that although Wells PS18-8 and PS18-1 have similar structural settings, considerable differences exist in Vitrinite reflectance ( VR) is a commonly indicator of thermal depositional environments. For example, the salinity of the maturity (Tissot and Welte 1984). The VR values of Wells depositional water in Well PS18-8 was much more varying PS18-1 and PS18-8 have averages of 0.94 % (0.90–0.99 %) and higher than that of Well PS18-1, resulting in significant and 0.88 % (0.80–0.95 %), respectively (Table 2), showing variations in the kerogen types in Well PS18-8. Generally, that the shales in both wells are in the oil window. The ther- in water with high salinity, the terrestrial higher plant input mal maturity of the shale in Well PS18-1 is slightly higher should be relatively small, while the lower halophilic aquatic than that of the shale in Well PS18-8. organism input should be relatively great (Carbonel 1988; Hu et al. 2018b). Therefore, regarding the kerogen types, 1 3 696 Petroleum Science (2021) 18:687–711 Depth, Depth, Stratum Lithology Maceral composition of kerogen,%Pas Stratum Lithology Maceral composition of kerogen,%Pas m m 020406080 100 020406080 100 u u Es Es 3 3 (a) PS18-1 (b) PS18-8 Hydrogen-rich AlginiteHydrogen-poor Sporinite Cutinite TeliniteEuvitrinite Inertinite amorphous amorphous Fig. 6 Maceral composition profile of kerogens from Es shale in Liutun Sag, DD. %Pas = Particle abundances of individual macerals. (The lithology legend refers to Fig. 3) Oil content is an important parameter in evaluating oil 4.1.4 Petroleum generation potential and shale oil content resource (Jarvie 2008, 2012; Hu et al. 2018a; Wang et al. 2020). The rock extract “A” content can directly assess shale Factors controlling petroleum generation potential of shale include organic matter content, type, and thermal maturity. oil content. The rock extract “A” contents of the shale sam- ples from both wells range between 0.5-17.8×10 ppm with The shales in the DD have similar TOC contents, organic matter type, and thermal maturity to shale oil plays in other a mean of 7.1×10 ppm (Table 1). The rock extract “A” con- tents of Well PS18-1 range from 1.6 to 17.8 ×10 ppm with lacustrine basins in China. In comparison with the typical shale oil plays in the USA (Table 3), despite the lower TOC an average of 8.1×10 ppm, while the extract “A” contents of Well PS18-8 range from 0.5 to 15.4 ×10 ppm with a mean content and thermal maturity, the shale in the study is domi- nated by type I and II kerogens (Fig. 7). Besides, the gross of 6.7×10 ppm. Further analyses show that the oil content of the Es shale has a positive correlation with TOC con- thickness of the shales is much greater, with average and greatest gross thicknesses ranging from 500 m to 910 m tent (Fig. 8a) with a slope of 2248.1 (R-squared = 0.9063), indicating that the higher the TOC is, the higher the shale oil and 800 m to 2610 m, respectively (Wu et al. 2013; Duan et al. 2008). Therefore, the petroleum generation potential content is. The correlation between the oil content and the kerogen TI is slightly positive correlated with a slope of 11.0 of the Es shale might be significant. In comparison, little difference exists in the organic matter contents and thermal (R-squared = 0.4256) (Fig. 8b), revealing that the organic matter type also controls the oil content, and the larger the maturity between the shales at Wells PS18-1 and PS18-8, but the latter exhibits a stronger oil-generating capacity due kerogen TI is, the higher the shale oil content is. However, the effect of the kerogen type on oil content is much less to significantly higher sapropelinite content (Fig.  7). 1 3 Petroleum Science (2021) 18:687–711 697 Exinite, % developed in the Es shale. Tension fractures are formed under tensile stress and not fracturing through minerals 100 0 PS18-1 (N=11) when extending, exhibiting curved extension planes and PS18-8 (N=22) profiles (Fig.  9a and b), which play important roles in con- necting different types of fractures. The tension fractures in 75 25 the study are not only related to the tectonics but also the evaporites. In the Es shale, the evaporites are interbedded II with shale (Fig. 3). Differential compaction and irregular 50 50 plastic flow of evaporites easily occur due to difference in density between evaporites and shales. As shale is clearly more brittle than salt, when the pressure caused by differ - 25 III 75 ential compaction or irregular plastic flow of the evaporites exceeds the critical rupture pressure of the shale, the tension 0 100 fractures form. In the Es shale, seventy percent of tension 100 75 50 25 0 fractures are filled with gypsum, calcite, halite, and asphalt Sapropelinite, %Vitrinite+Inertinite, % (Fig. 9a and b), and the remaining tension fractures are open fractures in which oil impregnation is common (Fig. 9c and Fig. 7 Ternary Diagram of sapropelinite, exinite, vitrinite, and iner- d), as a result of the extensively developed evaporites. Under tinite in Es shale, Liutun Sag, DD, indicating that the kerogen of the influence of tectonic activity and differential compac- Well PS18-1 is type II kerogen and Well PS18-8 is mainly type I ker- tion, the induced tension fractures in the shale interbedded ogen with a small amount of type II kerogen, respectively. N indicates with the evaporites were very easily filled by the flowable the number of samples. (The classification diagram refers to Wang et al. (2015a)) evaporites. However, in the thick shale, the induced tension fractures were filled by the oil generated from the adjacent shales, and the accumulated oil further promoted the preser- vation of fracture space. Shear fractures are mainly formed than TOC content. This conclusion can also be confirmed by shear stress, generally open and having straight and flat by the observation that, although the kerogen type of the planes and profiles (Fig.  9e, f, g, and h). X-shaped conjugate shale at the Well PS18-8 is more oil-prone than that of the joints (width: 1-5 mm) can also be identified (Fig.  9g) and Well PS18-1, the shale oil contents of the Well PS18-8 are were filled with oil (Fig.  9g and h). smaller than that of the Well PS18-1, which is mainly due to Diagenetic fractures are microfractures formed due to dia- the smaller TOC of the shale at the Well PS18-8. genetic compaction (Luo et al. 2015). Interlayer bedding, In summary, although the petroleum generation potential dissolution, and shrinkage fractures are commonly observed of the shale at Well PS18-8 is relatively greater than that of in the Es shale. Interlayer bedding fractures are the most the shale at Well PS18-1, the shale oil content of the lat- 3 common fractures and develop near lithological interfaces ter well is slightly greater due to the slightly greater TOC. (Fig. 9i, j, and k), and the openings are usually small and Therefore, petroleum generation potential is not a key factor were filled (Fig.  9l and m). Dissolution fractures are enlarged affecting the shale oil enrichment between the two wells. primary fractures or newly formed by differential dissolu- tion along the lamina, due to different mineral compositions 4.2 Reservoir volume and particle arrangements between lamina (Luo et al. 2015), which are mostly parallel to rock surfaces (Fig. 9n). Shrink- 4.2.1 Fractures age fractures are commonly formed by change of facies or thermal contraction of different minerals, or in the coring Fractures are faults without significant displacement and and sample preparation process, which are usually short and effective reservoir volume for shale oil (Ferrill et al. 2014). have good connectivity and various apertures, with some Tectonic, overpressure, and diagenetic fractures were identi- filled with illite and halite (Fig.  9o, p, q and r). fied in the study by core samples, fluorescence microscopy, Overpressure fractures refer to fractures at a certain depth and FE-SEM observations. and under a closed pressure system. In shales, these fractures Tectonic fractures refer to those formed by or associated form by overpressure due to hydrocarbon generation, clay with the local tectonics. Tectonic activity was common in mineral dehydration, hydrothermal activity, or authigenic the DD (Chen et al. 2013) and enabled the formation of mineral precipitation (Wang et al. 2015b). The Es shale various derived fractures near the marginal faults (Wang is a set of good to excellent petroleum source rocks within et al. 2015a). Tectonic fractures include tension, shear, and oil window. Petroleum generation in these source rocks can compression fractures, and the former two were primarily cause overpressure (Luo et al. 2015, 2016). The extensively 1 3 698 Petroleum Science (2021) 18:687–711 1 3 Table 3 Basic parameter comparison between terrestrial lacustrine shale oil plays in China and lacustrine and marine shale oil plays in North America Basin/ Strata Age Thickness, Total Kerogen Maturity, Porosity, Quartz, % Carbon- Clay min- Density, g/ Viscosity, Pressure References Depres- m organic type VR, % % ates, % erals, % cm mPa·s coefficient sion carbon, % U 3 Dongpu Es Paleogene 75–325 0.35–5.7 I–II 0.67–1.08 6.7–22.6 4–28 2–52 8–52 0.935 43 × 10 1.4–2.2 Williston Bakken Late Devo- 5–15 7.23–12.9 II 0.65–1.3 5–13 74 25 –50 < 0.820 – 1.35–1.58 (Jarvie, nian- 2008, Early 2012) Carbon- iferous Maverick Eagle Late Cre- 15–92 1–7 I–II 1–1.7 4–15 10–30 20–80 20–30 – - 1.35–1.8 (Jarvie, Ford taceous 2008, 2012) Fort worth Barnett Late Devo- 92–152 4–8 II 0.5–2.3 2–14 40–80 27 0.835–0.845 – 0.99–1.27 (Montgom- nian- ery et al., Early 2005; Carbon- Jarvei iferous et al., 2007; Loucks et al., 2007; Han et al., 2015, 2017a, 2017b) San Monterey Miocene 914–1220 0.7–5.6 II 0.3–1.1 13–29 30–50 – – – – – (Montgom- Joaquin ery et al., 2001; Jar- vie et al., 2008) Ordos Chang 7 Late Trias- 10–45 0.3–36.2 I–II 0.6–1.1 4.8–12.6 27–47 19 19–31 0.83–0.88 6.12 0.75–0.85 (Jiang et al., sic 2016a, 2016b; Liu et al., 2016; Wang et al., 2016b) Songliao Qing- Early Cre- 50–500 0.4–4.5 I–II 0.5–1.5 6–12 15–50 20–31 22–49 – – – (Jiang et al., shankou taceous 2006; 2013; Zou et al., 2013) Santanghu Lucaogou Middle 10–120 1–7 I–II 0.5–0.9 1–6 20–40 20–40 5–48 0.9 738.8 1–1.4 (Zou et al., Permian 2013) Petroleum Science (2021) 18:687–711 699 1 3 Table 3 (continued) Basin/ Strata Age Thickness, Total Kerogen Maturity, Porosity, Quartz, % Carbon- Clay min- Density, g/ Viscosity, Pressure References Depres- m organic type VR, % % ates, % erals, % cm mPa·s coefficient sion carbon, % Subei Fu 4 Paleogene 50–500 0.5–4.1 I–II 0.5–0.8 1.4–15.8 10–50 5–30 25–75 – – 1–1.1 (Zou et al., 2013; Zhang et al., 2015) Fu 2 Paleogene 50–350 0.5–4.7 I–II 0.5–1.3 1–8 10–60 5–35 30–80 – – 1–1.1 (Zou et al., 2013; Zhang et al., 2015) Jiyang Es Paleogene 50–400 2–6 I–II 0.7–0.93 2–8 – – – 0.89–0.94 16.1 –208 1.5–1.7 (Li et al., 2015, 2017; Ning et al., 2017; Wang et al., 2015b; Su et al., 2017) Biyang Well AS1 Paleogene 60–70 1.59–4.53 II 0.57–0.72 3.91–8.92 – – – 0.876 33.52 0.95–1.05 (Chen et al., 2011) 700 Petroleum Science (2021) 18:687–711 100000 100000 (a) (b) PS18-1 (N=11) PS18-1 (N=11) PS18-8 (N=22) PS18-8 (N=22) 1.4863 0.0273x y = 2248.1x y = 825.4e 2 2 R = 0.9063 R = 0.4256 100 100 0.1 1 10 020406080 100 TOC, % Kerogen type index, % Fig. 8 Correlation between rock extract “A” content and a TOC, and b kerogen type index in Es shale, Liutun Sag, DD. N indicates the num- ber of samples Inter-layer Open tension (a) (b) (c) (d) bedding fracture fracture surface between shale (the surface is dyed with oil) and gypsum Pyrite Open tension fracture (the surface is dyed with oil) Tension fracture (filled with gypsum) Tension fracture 2 cm 3 cm 2 cm 2 cm (filled with gypsum) (e) (f) (g)(h) Shear fracture (the surface is dyed with oil) Shear fracture surface (the surface is dyed with oil) X conjugate shear fracture (the surface is dyed with oil) Shear fracture (the surface is dyed with oil) 2 cm 2 cm 2 cm 5 cm (i) (j) (k) (l) Inter-layer Dendritic Inter-layer bedding halite bedding fractures fractures Inter-layer bedding Inter-layer bedding fracture fracture (the surface is dyed with oil) 200 μm 200 μm 100 μm 5 cm Fig. 9 Photos of cores and SEM images showing typical fracture characteristics of Es shale in Liutun Sag, DD. a Well PS18-1, 3259.4m, tectonic fractures and fissures are integrated and filled with gypsum and pyrite; b Well PS18-1, 3260.7m, tectonic fractures and fissures are inte- grated and filled with gypsum; c–d Well PS18-1, 3271.5m, tectonic fractures and diagenetic fractures, the surface of which is dyed with oil; e Well PS18-1, 3273.7m, tectonic fractures, the surface of which is dyed with oil; f Well PS18-1, 3266.68m,vertical tectonic fractures developed in groups and the surface is dyed with oil; g Well PS18-1, 3273.6m, X-type conjugate shear fractures, the surface of which is dyed with oil; h Well PS18-1, 3270.45m, shear fractures, the surface of which bears asphalt; i Well PS18-1, 3265.78m, inter-lamina micro-fractures, yellow fluorescence indicates the filling of oil in the micro-fractures; j Well PS18-8, 3185m, lamination development, lamina fractures present; k Well PS18-8, 3187.8m, micro-lamination development, inter-lamina fractures present; l Well PS18-8, 3186m, fractures are filled with dendritic halite crystals; m Well PS18-8, 3187.8m, lamination development, lamina fractures present; n Well PS18- 1, 3182m, diagenetic dissolution fractures; o Well PS18-8, 3187.8m, flaky illite showing the scale structure, developed with shrinkage fractures; p Well PS18-8, 3161.2m, flaky illite adhered to the surface of halite aggregation, developed with shrinkage fractures; q Well PS18-8, 3163.22m, flaky and silky illite and halite aggregation, developed with shrinkage fractures; r Well PS18-8, 3187.8m, shrinkage fractures are filled with halite aggregation; s Well PS18-1, 3289.8m, natural hydraulic fractures, the surface of which is wormlike with uncertain distribution directions, fractures are open; t Well PS18-8, 3169m, natural hydraulic tension fractures, short and thick, thick in the middle and thin on both ends; u Well PS18-1, 3260.7m, plane polarized light photograph; v Well PS18-1, 3260.7m, ultraviolet light-excited fluorescent photograph showing the oil inclusion with yellow and blue-white fluorescence; w Well PS18-8, 3156.45m, plane polarized light photograph; x Well PS18-8, 3156.45m, ultraviolet light-excited fluorescent photo- graph showing the oil inclusions with yellow fluorescence 1 3 Chloroform bitumen “A”, ppm Chloroform bitumen “A”, ppm Shrinkage fracture Petroleum Science (2021) 18:687–711 701 Flaky illite (m) (n) (o) (p) Diagenetic dissolution fractures Inter-layer Shrinkage bedding fracture fractures Flaky Halite illite 500 μm 1 μm 20 μm 5 μm (q) (r) (s) (t) Overpressure fracture Shrinkage Halite fractures Flaky illite Halite Overpressure fracture Flaky illite 20 μm 20 μm 2 cm 2 cm (u) (v) (w) (x) Oil inclusion Oil inclusion Oil with yellow with Oil inclusion fluorescence bule-white with yellow fluorescence fluorescence Oil Oil Oil Oil inclusion with yellow fluorescence 200 μm 200 μm 200 μm 200 μm Fig. 9 (continued) developed gypsums preserve the overpressure introduced abovementioned two enrichment mechanisms are completely by petroleum generation (Luo et al 2016). The shale will different. In this study, without anthropogenic fracturing, a rupture when the overpressure reaches the critical fractur- shale oil yield of 430 m /d was achieved in Well PS18-1, ing pressure, forming overpressure fractures. Generally, indicating that most of the produced oil should be movable overpressure fractures are randomly distributed in worm- oil in the fractures. The widely distributed oil inclusions in like shapes in the shale plane with no preferred orientation the fractures further prove it (Fig. 9u, v, w, and x). Therefore, (Fig. 9s). Some are short, wide in the middle and thin at the the reservoir volume available for shale oil is mainly deter- tips, exhibiting a spindle-like shape (Fig. 9t). Most overpres- mined by the degree of fracture development, which is usu- sure fractures are constrained by layered gypsum. However, ally evaluated by fracture density (Curtis 2002). The aver- when the gypsum laminae are thin, they can also be cut by age fracture densities of the shale in Well PS18-1 are 2.79, overpressure fractures (Fig. 9t). 4, and 4 stripes/meter in the depth intervals of 3220–3290 Previous studies have shown that the fractures in the m, 3258–3260 m, and 3276–3278 m, respectively, and the Es shale are mainly tectonic and overpressure fractures maximum fracture density is 7 stripes/meter (Fig. 10a). On with a few diagenetic fractures (Luo et al. 2015). This study the contrary, the average fracture density of the interval of found that diagenetic fractures are well developed despite 3140-3190 m of Well PS18-8 is 0.72 stripes/meter, and the their small micron scale (Fig.  9i–r). The large number of maximum fracture density is only 2 stripes/meter at 3157 tectonic and overpressure fractures commonly cut through m, 3171 m, and 3182 m (Fig. 10b). The higher fracture den- the diagenetic fractures, enabling the formation of three- sity of the shale in Well PS18-1 was mainly induced by two dimensional fracture networks, which significantly improve factors: lithology difference and formation pressure differ - seepage capacity (Fig. 9a–h and s–t). Therefore, as for the ence. Firstly, as shown in Fig. 3, compared with the interval reservoir volume, the contribution of the diagenetic fractures of interest (3250–3285 m) in Well PS18-1, the interval of cannot be ignored in the Es shale oil play. interest (3155–3195 m) in Well PS18-8 is characterized by As shown in Section 4.1.4, the TOC content controls the evaporites that are thin and interbedded with shale, which shale oil enrichment, mainly because the organic matter not greatly enhance the plasticity of the strata. Therefore, less only generates oil but also absorb it. However, compared to fractures would form in the Well PS18-8 under similar for- the absorbed oil, the oil accumulated in the shale fractures mation pressure. Secondly, the higher the formation pressure could be either generated from in situ shale or migrated is, the more fractures there are. In comparison, the measured from adjacent shale, which is mainly movable oil. The MDT formation pressure coefficient of Well PS18-1 is 2.2, 1 3 Shrinkage fracture 702 Petroleum Science (2021) 18:687–711 (a) (b) 2.0 1.6 Average = 0.72 1.2 Average = 2.79 0.8 0.4 0 0 3250 3260 3270 3280 3290 3150 3160 3170 3180 3190 3200 Depth, m Depth, m Fig. 10 Fracture development density diagram of Es saline lacustrine shale in a Well PS18-1 and b Well PS18-8 in the Liutun Sag, DD, indi- cating that the fracture development density of shale in Well PS18-1 is significantly higher than that in Well PS18-8 which is significantly greater than that of Well PS18-8, with that most of the pores were formed geologically. In the Es only 1.4. Therefore, due to the greater plasticity and lower shale, pores with different geometries were developed, which formation pressure of the shale intervals, significantly less were collectively controlled by the primary pore geometry fractures were developed in the Well PS18-8. In view of the and diagenesis. The linear shape pores were mainly formed positive correlation between the fracture density and res- between large halite crystals and clay minerals (Fig. 11b and ervoir volume, the reservoir volume of the shale at Well d). The elliptical–triangular pores represent the remaining PS18-1 should be dramatically greater than that at Well pore space between particles that have been subjected to PS18-8, making the former area more conducive to shale compaction and cementation (Fig. 11a and e). The pores oil enrichment. with internal paper-house microstructures are usually open (Fig. 11c and f) and create connectivity among pores. The 4.2.2 Pores pore size of the intercrystalline pores mainly ranges between 2 and 40 μm. Some pores have good connectivity, contribut- The FE-SEM and energy spectrum analyses show that the ing to the formation of an effective pore network and provid- pores in the Es shale samples include interparticle (inter- ing microchannels for the transportation and accumulation crystalline), intraparticle (intracrystalline), and organic mat- of petroleum, which is conducive to shale oil enrichment. ter pores. Interparticle (intercrystalline) pores are mainly Intraparticle (intracrystalline) pores refer to the pores intercrystalline pores (Fig. 11a–g), with a small proportion developed within particles. In this study area, these types of interparticle residual pores (Fig. 11g). These pore fea- of pores mostly formed in the later stage of diagenesis, and tures are mainly related to the hypersaline and strong reduc- few are primary (Wang et al. 2016b). The Es shale has a ing environment during deposition. Compared with marine low content of rigid-grain minerals but a high content of shales, the Es shale has a relatively lower content of rigid- carbonates, clay, and saline minerals, which are susceptible grain minerals such as quartz but a relatively higher content to dissolution and the subsequent formation of intraparti- of clay and saline minerals, leading to a dispersion of the cle (intracrystalline) pores (Wang et al. 2015a, 2016a). The rigid grains among the clay minerals and organic matter, intraparticle (intracrystalline) pores mainly include halite and impeding the formation of a grain-supported structure (Fig.  11d, h, and l) and anhydrite intracrystalline pores (Wang et al. 2016a). Therefore, the interparticle pores are (Fig. 11j and k), followed by moldic pores (Fig. 11i), dis- less developed and can be found between pyrite and halite solution pores between the framboidal pyrites (Fig. 11b), in a few samples (Fig. 11a–f). Furthermore, the abundant and pores within the calcite (Fig. 11m). The moldic pores clay and saline minerals are easily subjected to dissolution formed from the partial dissolution of halite particles. The by organic acids released from petroleum generation and diameters of the intraparticle (intracrystalline) pores range anthropogenic dissolution during drilling and sampling pro- from 1 to 50 μm. cesses, resulting in many intercrystalline pores. To minimize Organic matter pores are intraparticle pores that develop the impact of anthropogenic dissolution, the shale samples in organic matter. The formation, distribution, and size of were placed in cool and dry conditions and the drying cut- these pores are related to the organic matter content, type, ting technique was applied during sample preparation. The and thermal maturity of the shale (Loucks et al. 2012; Wang results show that, as shown in Fig. 11a–f, numerous miner- et  al. 2016b). The organic matter pores in this study are als were adsorbed around most of the salt pores, indicating often connected by shrinkage fractures, dissolution pores, 1 3 Fracture density (stripes/meter) Fracture density (stripes/meter) Petroleum Science (2021) 18:687–711 703 (a) (b) (c) (d) Halite Interparticle pore Flaky illite intercrystalline between halite pore with pyrite Halite Halite intracrystalline Pyrite intercrystalline pore Halite intracrystalline pore pores intercrystalline pores Halite intercrystalline pore 10 μm 5 μm 10 μm 10 μm (e) (f) (g)(h) Halite intracrystalline pore Interparticle residual pore Halite intercrystalline pores Halite Moldic intercrystalline pores pores 10 μm 200 μm 10μm (i) (j) (k) Gypsum intracrystalline (l) Illite Gypsum intracrystalline dissolution pore Halite dissolution pores Moldic pores Halite intracrystalline pores 10 μm 50 μm 20 μm 10 μm Intracrystalline Calcite (m) (n) (o)(p) residual pores intracrystalline Organic dissolution pores matter pores Clay shrinkage Organic intraparticle Organic matter Organic pores matter pores matter pores pores Clay shrinkage Organic Clay shrinkage intraparticle matter Clay shrinkage intraparticle pores pores intraparticle pores pores Fig. 11 SEM images showing typical pore characteristics of Es shale in the Liutun Sag, DD. a Well PS18-8, 3164m, halite aggregation and microfractures, developed with interparticle dissolution pores and intraparticle dissolution pores; b Well PS18-8, 3164m, a small num- ber of microcrystal pyrite crystals present among halite crystals, developed with interparticle dissolution pores and intraparticle dissolution pores; c Well PS18-8, 3162.23m, halite aggregation and micro dissolution pores, developed with interparticle dissolution pores; d Well PS18-8, 3161.2m, halite aggregation and micro dissolution pores, developed with interparticle dissolution pores and intraparticle dissolution pores; e Well PS18-8, 3160.1m, halite aggregation and micro dissolution pores, developed with interparticle dissolution pores; f Well PS18-8, 3162.23m, halite crystals and dissolution pores, developed with interparticle dissolution pores; g Well PS18-8, 3182m, developed with interparticle residual pores; h Well PS18-8, 3177.1m, halite exhibits a hardened shape and the presence of circular intraparticle dissolution pores; i Well PS18-8, 3177.1m, halite crystals form mold pits after dissolution; j Well PS18-1, 3280.4m, anhydrite surface is dissolved, developed with intracrystalline dissolution pores; k Well PS18-1, 3280.4m, surface of angular anhydrite crystals is dissolved, developed with intracrystalline dissolution pores; l Well PS18-8, 3165.1m, halite aggregation and dissolution pores, developed with intraparticle dissolution pores; m Well PS18-1, 3267m, devel- oped with intracrystalline residual pores, organic matter pores, and intra-organic matter contraction pores; n Well PS18- 1, 3267m, intra-organic matter shrinkage pores; o Well PS18-1, 3263.61m, developed with organic matter pores; p Well PS18-8, 3167.2m, developed with organic mat- ter dissolution pores and microfractures, exhibiting strip-like or network-like shale and are generally small, which might be related to the shapes. For example, interconnected pores are introduced low thermal maturity. Generally, the organic matter pores by the connection between organic matter pores and inter- begin to form when the VR of the kerogen reaches 0.8 % crystalline pores formed by clay mineral shrinkage (Fig. 11n (Reed et al. 2012; Katz and Arango 2018), such as the Mis- and o) as well as that between other organic matter pores sissippian Barnett Shale and the Toarcian Posidonia Shale and intraparticle pores formed by clay mineral dissolution in Lower Saxony, Germany (Loucks et al. 2009; Han et al. (Fig. 11p). Due to oil adsorption of the organic matter, the 2014). At present, the VR average of the Es shale is merely organic matter pores are very important for shale oil enrich- 0.9 %, indicating a relatively low thermal maturity, so the ment. Organic matter pores are less developed in the Es organic matter pores in this shale are less developed. 1 3 704 Petroleum Science (2021) 18:687–711 3 3 Acoustic time difference, μs/m Density, g/cm Acoustic time difference, μs/m Density, g/cm 150200 250300 350400 450 1.51.7 1.92.1 2.32.5 2.72.9 1502 2003 50 00 3504 400 50 1.51.7 1.92.1 2.32.5 2.72.9 1500 1500 1500 1500 (a) (b) (c) (d) 1700 1700 2000 2000 1900 1900 2500 2500 2100 2100 2300 2300 3000 3000 2500 2500 3500 3500 2700 2700 2900 2900 4000 4000 3100 3100 4500 4500 3300 3300 3500 3500 5000 5000 Well PS18-1Well PS18-8 Trend line Target stratum Fig. 12 Profiles of depth vs. logging data: a acoustic time difference of Well PS18-1; b mud density of Well PS18-1; c acoustic time difference of Well PS18-8; d mud density of Well PS18-8; showing the abnormal high porosity and strong overpressure Overall, intercrystalline and intracrystalline pores pre- oil play in the DD are very good and are conducive to the dominate in the Es shale, while organic matter pores shale oil enrichment. Similar to the oil enrichment mecha- are less developed. Comparative analyses indicate little nism in the fractures (see Section 4.2.1), the oil accumulated pore difference exist in the shales between Wells PS18-1 in the pores could be oil that either generated from in situ and PS18-8. The average surface porosity tested by liquid shale or migrated a short distance from adjacent shale, which saturation method of five shale samples from Well PS18-1 is mainly movable oil. As for the shale reservoir, the con- is 16.3 % (11.8–22.6 %), while that of five shale samples nectivity between pores is very poor, but most of the oil that from Well PS18-8 is 13.4 % (6.7–20.9 %) (Luo et al. 2013), has accumulated in these pores cannot be recovered without showing that the shale in Well PS18-1 has a higher porosity. anthropogenic fracturing (Jarvie 2012; Li et al. 2014). In this As shown in Figs. 2 and 3, evaporites are well developed study, without anthropogenic fracturing, a shale oil yield of U 3 in Es , and their sealing capacity is excellent and could 430 m /d was obtained at Well PS18-1, indicating that the prevent oil leakage. The strong overpressure developed in produced oil is likely the movable oil from fractures rather this stratum further illustrates this sealing capacity. The than pores. Therefore, the fracture density might be a key acoustic time differences and density logging data in the factor controlling shale oil enrichment. Es target interval (3250–3285 m) of Well PS18-1 have averages of 349 μs/m (252-434 μs/m) and 2.44 g/cm (2.32-4.3 Frackability 3 U 2.58 g/cm ), whereas the respective averages in the Es target interval (3155-3195 m) of Well PS18-8 are 277 μs/m To obtain commercial oil yield from low-porosity and -per- 3 3 (240–300 μs/m) and 2.54 g/cm (2.25–2.65 g/cm ), showing meability shale oil plays, large-scale horizontal wells and that the shale at Well PS18-1 has a higher acoustic time dif- anthropogenic fracturing techniques are required to improve ference but clearly a smaller density than the shale at Well the seepage capacity. Shale frackability depends mainly on PS18-8 (Fig. 12), which may be induced by the evaporites the natural fracture development and mineral composition enrichment. However, as shown in Fig. 3, the development (Jarvie et al. 2007; Wang et al. 2015b). degree of the evaporites in depth interval of 3155m–3195m Natural fractures in shale could reduce the tensile strength of the Well PS18-8 is significantly greater than that of depth of the rock and enhance the fracturing effect. The more interval of 3250m–3285m of the Well PS18-1, further indi- developed the natural fractures are, the more favorable con- cating that the shale in Well PS18-1 has a higher porosity. ditions are for creating interconnected fractures when frac- In comparison, the Es shale oil play in this study has a turing (Montgomery et al. 2005). The natural fractures in the significantly greater porosity compared to the shales in other Es shale are well developed, and the interaction between lacustrine basins in China and typical shale oil plays in the different types of fractures can form complex fracture sys- USA (Table 3), which might be associated with the strong tems, which are favorable for fracture networks formation overpressure. Therefore, the reservoir conditions of the shale by anthropogenic fracturing. Despite the extensive fracture 1 3 Depth, m Depth, m Depth, m Depth, m Petroleum Science (2021) 18:687–711 705 The higher the brittle mineral contents are, the better the Clay mineral fracturing ee ff ct is for the shale (Loucks and Ruppel 2007 ). 0 100 Among the mineral components in the Es shale, the clay Ps18-1 (N=23) Ps18-8 (N=20) minerals have the highest content, which are prone to plastic Barnett shale (N=28) deformation, leading to the blockage of seepage channels and 25 75 subsequent difficulty in shale fracturing (Wilson et al. 2014; Zeinijahromi et al. 2016; Wei et al. 2019). The content of feld- spar, which is unstable and easily dissolved, is also high, with 50 50 an average of 14 % (5–52 %). Quartz, calcite, and dolomite have average contents of 18 % (4–28 %), 15 % (0–47 %), and 12 % (0–45 %), respectively, and brittleness evaluation of the 75 25 shales in the USA (Montgomery and Morea 2001; Loucks and Ruppel 2007) has suggested that these three minerals are favorable for induced fracturing. This study utilizes the brittle- 100 0 ness index (BI) = (quartz + calcite + dolomite + pyrite)/(total 0255075 100 minerals) to characterize the frackability (Wang and Gale Carbonates Quartz+ 2009; Chen et al. 2011; Zou 2011; Qiu et al. 2016). The results Feldspar+Pyrite show that the average BI of the Es shale is 0.47 (0.07–0.72) (Table 4). In general, when BI is larger than 0.4, the shale Fig. 13 Ternary diagram of clay minerals, carbonates, and quartz + has good frackability, such as the Barnett and Woodford shale feldspar + pyrite of Es shale in Liutun Sag, DD. Compared with 3 U (Sondergeld et al. 2010). Thus, the Es shale is suitable for the mineral composition of Barnett shales (Loucks and Ruppel 2007), anthropogenic fracturing. Specifically, the average BI values the Es shale has higher enrichment of carbonates and clay miner- als and a relative lack ofquartz, feldspar, and pyrite. N indicates the of the shale in Wells PS18-1 and PS18-8 are 0.42 (0.07–0.72) number of samples and 0.48 (0.22–0.59), respectively, indicating that the shales in these two wells are similar in frackability. development in the Es shale, nearly 70 % of them are filled In summary, given the mineral compositions, little differ - by calcite and saline minerals, resulting in a decrease in per- ence exists in the frackability of the shales in Wells PS18-1 meability of the shale. However, these fractures are weak and PS18-8, which are both suitable for fracturing. However, surfaces that are easily reopened after anthropogenic fractur- due to the higher fracture density of the shale in Well PS18-1 ing, which is very common in Barnett Shale play (Montgom- compared to Well PS18-8, the former has greater potential ery et al. 2005). Therefore, given the natural fracture density, for anthropogenic fracturing. the Es shale has an excellent frackability. Considering that the fracture density of the shale in Well PS18-1 is higher 4.4 Oil mobility than Well PS18-8, we can infer that the shale in Well PS18-1 has a better frackability. Oil mobility is an important index in evaluating shale oil The XRD analysis shows that the E s shale is composed recovery, which is determined by oil properties, reservoir of detrital minerals (quartz and feldspar), clay minerals, seepage capacity, and formation pressure. carbonates, and saline minerals, with average contents of For low-porosity and low-permeability shale oil plays, 32 % (13–58 %), 28 % (8–52 %), 28 % (2–52 %), and 9 % low-density and low-viscosity oil is more likely to be pro- (0–62 %), respectively. In comparison with shale oil plays duced. This is probably the reason why shale oils produced in other lacustrine basins, the shale oil play in the DD has presently are primarily light oils (Nelson 2009; Zhang et al. lower quartz and clay mineral contents, similar carbonate 2012; Zou et al. 2013; Nie et al. 2016). Generally, the higher contents, but higher saline mineral contents. Unlike the shale the saturated hydrocarbons contents are and the lower the oil plays in the USA, the Es shale has a mineral composi- nonhydrocarbon and asphaltene contents are, the lower the tion that varies significantly and is abundant in carbonates, oil density and viscosity are, and therefore the higher the clay, and saline minerals (Fig. 13; Tables 3, 4) (Montgom- oil mobility is (Kuhn et al. 2012; Li et al. 2014). The oil ery and Morea 2001; Montgomery et al 2005; Jarvie et al. produced from Well PS18-1 in the DD has a high density 3 3 2007; Loucks and Ruppel 2007; Jarvie 2008, 2012; Han of 0.935 g/cm , a high viscosity of 43×10 mPa·s, and very U U et al. 2014). This is because the Es shale comprises a set of poor mobility because the Es shale has a shallow burial fine-grained sediments that developed in a small hypersaline depth and low thermal maturity, resulting in a high contents lacustrine basin with a strong reducing environment, which of nonhydrocarbons (23.06 %) and asphaltenes (26.68 %), provided large amounts of chemical deposits but received and a low contents of saturated hydrocarbons (36.79 %) and less terrestrial clastic material. aromatic hydrocarbons (13.47 %). Therefore, in terms of the 1 3 706 Petroleum Science (2021) 18:687–711 1 3 Table 4 Mineral compositions and brittleness index for Es shale samples in the Liutun Sag, DD Well Depth, m Clay, % Quartz, % Feldspar, % Calcite, % Dolomite, % Pyrite, % Halite, % Anhydrite, % Siderite, % Brittleness index ((Quartz + cal- cite + dolomite + pyrite)/(Total minerals)) PS18-1 3258.70 17 14 18 39 6 4 0 1 1 0.77 PS18-1 3260.35 30 25 10 25 5 0 0 5 0 0.65 PS18-1 3261.50 26 21 10 15 22 2 0 1 3 0.68 PS18-1 3262.30 26 17 12 19 11 3 0 11 1 0.59 PS18-1 3263.50 23 21 20 16 7 4 0 4 5 0.64 PS18-1 3266.08 30 18 11 22 12 2 0 1 4 0.63 PS18-1 3268.08 25 14 9 1 44 2 0 1 4 0.68 PS18-1 3268.38 28 8 10 0 16 0 0 39 0 0.335 PS18-1 3268.98 8 6 7 0 18 1 0 58 2 0.31 PS18-1 3269.78 36 23 12 0 18 4 0 2 5 0.53 PS18-1 3271.46 15 10 5 3 5 0 0 62 0 0.23 PS18-1 3271.78 33 24 13 13 5 5 0 2 5 0.55 PS18-1 3273.30 15 20 15 20 27 0 0 3 0 0.82 PS18-1 3275.30 38 13 14 30 5 0 0 0 0 0.617 PS18-1 3275.80 43 15 14 25 4 0 0 0 0 0.573 PS18-1 3277.50 52 20 17 9 3 0 0 0 0 0.479 PS18-1 3280.40 48 20 23 7 0 0 0 0 0 0.492 PS18-1 3280.40 15 20 10 47 5 0 0 3 0 0.82 PS18-1 3283.30 16 10 29 46 0 0 0 0 0 0.843 PS18-1 3284.40 15 25 10 0 45 0 0 5 0 0.8 PS18-1 3285.60 17 4 24 0 6 0 0 38 11 0.341 PS18-1 3285.80 34 8 43 0 6 0 0 0 8 0.568 PS18-1 3287.60 32 6 52 0 1 0 0 0 10 0.586 PS18-8 3155.22 36 28 10 16 4 4 2 0 0 0.58 PS18-8 3156.99 27 23 14 25 4 5 2 0 0 0.66 PS18-8 3162.32 26 21 8 22 12 5 3 0 0 0.63 PS18-8 3164.00 25 21 10 31 4 6 3 0 0 0.66 PS18-8 3167.37 29 12 10 0 10 2 2 35 0 0.32 PS18-8 3168.36 25 20 10 0 11 5 3 26 0 0.41 PS18-8 3168.95 23 17 16 23 13 8 3 0 0 0.69 PS18-8 3171.60 44 22 12 0 2 2 9 9 0 0.36 PS18-8 3185.84 25 24 14 23 5 4 3 0 0 0.66 PS18-8 3186.57 26 24 15 2 2 10 7 14 0 0.43 PS18-8 3187.32 31 25 8 21 7 4 4 0 0 0.61 PS18-8 3187.80 27 22 16 27 2 4 2 0 0 0.67 Petroleum Science (2021) 18:687–711 707 physical properties of the oil, the oil mobility of the Es shale oil play is poor. The seepage capacity of a shale is mainly related to the fracture density. Previous studies proposed that fractures can increase the shale permeability by 4-5 orders of magnitude (Zhang et al. 2012). As described in Section 4.2.1, the frac- tures in the Es shale are extremely well developed and the shale should have a strong seepage capacity. Specifically, compared with the shale in Well PS18-8, Well PS18-1 has a significantly higher fracture density, indicating that the seepage capacity of the shale in Well PS18-1 should be con- siderably better than Well PS18-8. Overpressure provides natural driving forces for shale oil production and can improve oil flow rates and shale fracturing efficiency significantly (Ronald et  al. 2007). Overpressure is commonly developed in the shale oil plays in the USA (Jarvie 2012). As shown in Fig. 12, the varia- tions in acoustic time differences and mud density logging data with respect to depth indicate that the overpressure conditions should be widely developed in the Es strata, which were also reported in other studies (Li and Zhao 2012; Luo et  al. 2016). However, except for the over- pressure, the high acoustic time differences and low mud density can also be caused by evaporites. Generally, the logging data of the evaporites are characterized by high acoustic time differences and low mud density. Further analyses of the rock lithology assemblage show that, for the Well PS18-1, no evaporites developed in the depth interval of 3250-3285 m, while the evaporites are well developed in the depth interval of 3155-3195 m at Well PS18-8 (Fig. 3). Therefore, in terms of the evaporites, the acoustic time differences of the shale interval of the Well PS18-1 should be lower than Well PS18-8 and the den- sity logging data of the shale interval of the Well PS18-1 should be greater than Well PS18-8. However, as shown in Fig. 12, the acoustic time difference of the Well PS18-1 (349 μs/m (252–434 μs/m)) is significantly greater than Well PS18-8 (277 μs/m (240–300 μs/m)), and the density logging data of the Well PS18-1 (2.44 g/cm (2.32–2.58 g/ 3 3 cm )) are lower than Well PS18-8 (2.54 g/cm (2.25–2.65 g/cm )), indicating that the variations in acoustic time differences and mud density logging data are associated with overpressure, not evaporites. The overpressure indi- cates that the Es shale oil plays have excellent shale oil recovery. In contrast, the variation degree of logging data in the Es strata of the Well PS18-1 is significantly greater than that of the Well PS18-8 (Fig.  12), indicat- ing a greater overpressure, which was further validated by the measured MDT formation pressure (the pressure coefficient of Well PS18-1 is 2.2, while the pressure coef- ficient of Well PS18-8 is 1.4). The overpressure differ - ences between the two wells are closely related to the differential development of evaporites: a. Difference in 1 3 Table 4 (continued) Well Depth, m Clay, % Quartz, % Feldspar, % Calcite, % Dolomite, % Pyrite, % Halite, % Anhydrite, % Siderite, % Brittleness index ((Quartz + cal- cite + dolomite + pyrite)/(Total minerals)) PS18-8 3188.50 29 23 7 10 23 3 5 0 0 0.63 PS18-8 3189.27 33 26 8 14 12 2 5 0 0 0.6 PS18-8 3189.80 28 20 10 5 32 3 2 0 0 0.67 PS18-8 3190.00 26 21 8 10 28 4 3 0 0 0.67 PS18-8 3190.55 31 18 12 20 9 5 5 0 0 0.59 PS18-8 3191.70 26 18 9 16 23 5 3 0 0 0.66 PS18-8 3191.75 37 22 13 18 3 3 4 0 0 0.56 PS18-8 3192.05 22 18 9 14 27 8 2 0 0 0.68 708 Petroleum Science (2021) 18:687–711 assemblage and thickness of the evaporites. As shown in shale system and then result in the decreasing oil and gas Fig. 3, the distribution of the evaporites is uniform and the enrichment (Rodriguez and Paul 2010; Liu et al. 2013). This thickness is thick at Well PS18-1, while the evaporites of should be closely related to extensive evaporites developed Well PS18-8 are thin and interbedded with shale, indicat- in the Dongpu Depression, which significantly increase the ing that the evaporites developed in Well PS18-1 should preservation conditions. This phenomenon can also be seen possess a greater sealing capacity; b. Difference in evapo- in the adjacent Dongying Depression. The fracture density rites location. As shown in Fig. 3, the evaporites of Well is determined by the distance to the faults in a basin, and PS18-1 developed at the top (<3250 m) and the bottom the closer to the faults is, the greater density the fractures is. (>3285 m) of the interval of interest (3250-3285 m), form- The formation pressure was determined by the assemblage ing the typical top and bottom seals for an overpressure and thickness of the evaporites. Furthermore, as indicated compartment, which are very conducive to preserving the in Fig.  12c and d, high abnormal overpressures are very overpressure. In contrast, the evaporites of Well PS18-8 common in strata deeper than the Es . Besides, the oil gen- developed in the middle (3167–3178 m) of the interval erated in deep shales with higher thermal maturity is more of interest (3155–3195 m). Besides, these evaporites are likely to have low density and low viscosity and better oil thin and interbedded with shale at well PS18-8, which are mobility. Therefore, the Es strata in deep depressions are unfavorable for preserving formation pressure. The above also favorable for future shale oil exploration. Similar to two factors jointly caused the formation pressure differ - the general tectonic and depositional settings of the DD, ence between the two wells. Therefore, the shale oil of large amounts of saline lacustrine rift basins were developed the Well PS18-1 should have higher natural driving forces across the world, in which faults and evaporites developed and a higher shale oil yield. Further comparison shows commonly. In future shale oil exploration, the regions and that the study area has a significantly higher formation strata adjacent to the faults and with thick evaporites should pressure compared to the shale oil plays in other lacus- be preferably selected as sweet spots. The results obtained in trine basins in China and the marine basins in the USA this study could be instrumental in future shale oil explora- (Table 3). Therefore, the shale oil play in the DD should tion not only in the DD but also in lacustrine basins across have excellent oil mobility. the world. In summary, despite the high density and high viscos- ity of the oil, the Es shale reservoir has a strong seepage capacity and overpressure, representing excellent conditions 5 Conclusions for shale oil mobility. Given the lower thermal maturity, high-density, high-viscosity oil, and high formation pres-The Es shale in the DD has a high content of organic mat- sure, the study area is similar to the Santanghu Basin, where ter dominated by oil-prone type I and type II kerogens within high shale oil production has been realized from the Luca- oil window, displaying a strong petroleum generation poten- ogou Formation (Table 3) (Nie et al. 2016). In comparison, tial. Despite the petroleum generation potential of the shale due to the superior seepage capacity of the shale reservoir at Well PS18-8 is relatively greater than that of the shale and the greater formation pressure, the oil mobility of the at Well PS18-1, the oil content of the latter well is slightly Well PS18-1 is superior to that of the Well PS18-8 well. Oil greater due to the slightly greater TOC. Various types of mobility is the most important condition determining the pores and fractures are extensively developed in the Es remarkable yield difference between these two wells. shale, with an average porosity of 14.9 %, which is favorable for shale oil enrichment. The porosity and fracture density 4.5 Implications for further shale oil exploration of the shale at Well PS18-1 are both greater than those of the shale at Well PS18-8, suggesting that the former is more By investigating the basic conditions of the shales at Wells favorable for shale oil enrichment. The Es shale has a high PS18-1 and PS18-8, the fracture density and overpressure brittle mineral content and extensive fractures, which are condition are the key factors controlling shale oil enrich- conducive to anthropogenic fracturing. The shale at Well ment in the DD. The extensively developed fractures can not PS18-1 has a better anthropogenic fracturing potential than only increase the reservoir volume of the shale, facilitating that at Well PS18-8 due to higher fracture density. The Es the shale oil accumulation, but also improve the seepage shale oil play has strong seepage capacity and overpressure, capacity of shale reservoirs significantly. Meanwhile, in the both of which are favorable for shale oil mobility. The Es setting of extensively fractures, the overpressure furtherly shale oil play at Well PS18-1 has a better seepage capacity promotes the natural driving forces for the shale oil in the and higher overpressure than that at Well PS18-8, indicating DD, increasing the shale oil mobility. This is contrary to that the shale at Well PS18-1 has a better oil mobility. the previous common perception, which indicated the devel- The key factors controlling shale oil enrichment of the oped fractures would promote the oil and gas loss in the Es shale oil play in the DD are the fracture density and 1 3 Petroleum Science (2021) 18:687–711 709 Curtis JB. Fractured shale-gas systems. AAPG Bull. 2002;86:921– overpressure, which were determined by the development 1938. https:// doi. org/ 10. 1306/ 61eed dbe- 173e- 11d7- 86450 00102 of the faults and the assemblage and thickness of the evapo- c1865d. rites, respectively. Therefore, in future shale oil exploration, Deng ED, Zhang JC, Zhang P, et al. 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Key factors controlling shale oil enrichment in saline lacustrine rift basin: implications from two shale oil wells in Dongpu Depression, Bohai Bay Basin

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Abstract

Comparative analyses of petroleum generation potential, reservoir volume, frackability, and oil mobility were conducted on 102 shale cores from the Dongpu Depression. Results show the shale has high organic matter contents composed of oil-prone type I and type II kerogens within the oil window. Various types of pores and fractures exist in the shale, with a porosity of up to 14.9%. The shale has high brittle mineral contents, extensive fractures, and high potential for oil mobility due to high seepage capacity and overpressure. Although the petroleum generation potential of the shale at Well PS18-8 is relatively greater than that at Well PS18-1, oil content of the latter is greater due to the greater TOC. The porosity and fracture density observed in Well PS18-1 are greater and more conducive to shale oil enrichment. Although the shales in Wells PS18-1 and PS18-8 have similar brittle mineral contents, the former is more favorable for anthropogenic fracturing due to a higher pre- existing fracture density. Besides, the shale at Well PS18-1 has a higher seepage capacity and overpressure and therefore a higher oil mobility. The fracture density and overpressure play key roles in shale oil enrichment. Keywords Petroleum generation potential · Reservoir volume · Frackability · Oil mobility · Shale oil enrichment · Dongpu Depression · Saline lacustrine rift basin 1 Introduction Shale oil refers to the oil generated in organic-rich shales and stored in them or adjacent organic-lean intervals (Jarvie Edited by Jie Hao and Chun-Yan Tang 2012). Shale oil has been found in the USA, such as Barnett and Antelope tight shale oil, Bakken and Monterey frac- * Tao Hu tured shale oil, and Bakken and Eagle Ford hybrid shale oil thu@cup.edu.cn systems (Jarvie 2012). The USA’s successful marine shale Xiong-Qi Pang oil revolution has boosted confidence in recreating success pangxq@cup.edu.cn in lacustrine basins. Numerous lacustrine basins are distrib- Fu-Jie Jiang uted across the world, such as the USA (Katz 1995), Brazil jiangfj@cup.edu.cn (Mello et al. 1991), India (Saikia and Dutta 1980), Indone- State Key Laboratory of Petroleum Resources sia (Katz and Kahle 1988), and China (Wang et al. 2019), and Prospecting, China University of Petroleum, containing numerous shale oil resources. China is rich in Beijing 102249, China lacustrine shale oil resources with a recoverable amount of College of Geosciences, China University of Petroleum, 43.5×10 t, ranking the third in the world (EIA 2008). which Beijing 102249, China were found in the Dongying Depression (Wang et al. 2015a), Energy & Geoscience Institute, University of Utah, Dongpu Depression (DD) (Wang et al. 2014, 2015a), Cang- Salt Lake City, UT 84108, USA dong Sag (Zhao et al. 2019), and Zhanhua Depression (Li Research Institute of Exploration and Development, et al. 2017) in Bohai Bay Basin, the Bohai Sea area (Jiang Zhongyuan Oilfield Company, SINOPEC, et al. 2016), and the Qingshankou Formation in Songliao Puyang, Henan 457001, China Vol.:(0123456789) 1 3 3360 688 Petroleum Science (2021) 18:687–711 Basin (Liu et al. 2017). In particular, for the Kongdian For- the shale oil enrichment laws of productive shale oil plays mation in Cangdong Sag, the natural daily yields of two hor- in the USA to China. izontal shale oil wells GD-1701H and GD1702H achieved Recently, attempts have been made to investigate the 20–30 m for more than 300 days by now. Besides, the well shale oil enrichment in lacustrine basins and identify fac- G1608 obtained a peak daily oil yield of 60 m after frac- tors for the enrichment. Liu et al. (2013) investigated the turing, producing for 105 days and reaching a cumulative shale oil enrichment laws for Lucaogou Formation, Malang oil production of more than 1704 m (Zhao et al. 2019). Depression, Santanghu Basin, and hold that the fractures These discoveries suggest promising shale oil exploration would promote the oil and gas loss in the shale system prospects in lacustrine shale oil (Li et al. 2014; Wang et al. and result in the decreasing oil and gas enrichment. This 2019). is consistent with the studies conducted by Rodriguez Significant differences exist between marine and lacus- and Paul (2010). Li et al. (2014) studied shale oil system trine shale oil plays. Marine shales are widely distributed in Hetaoyuan Formation of Biyang Depression, Nanxiang and have high organic matter contents, high thermal matu- Basin, and found that oil enrichment was controlled by the rity, high brittle mineral contents, and high formation pres- oil generation capacity, reservoir volume, and preservation sure. They contain good-quality organic matter dominated conditions and the producibility was controlled by the shale by type II kerogen and generate light oils with low wax con- frackability, oil density, and development scheme. Finally, tent and viscosity (Enderlin et al. 2011; Ferrill et al. 2014; Li et al. (2014) concluded thermal maturity is the key fac- Jarvie et al. 2007; Nie et al. 2016; Wang et al. 2014). By tor controlling shale oil enrichment, and the southeastern contrast, lacustrine shales are distributed over a small area regions with deep burial depth are favorable for shale oil and exhibit a strong heterogeneity. The organic matter in the enrichment, which is consistent with the studies conducted shales shows large variations in contents and compositions by Nie et al. (2016) and Wang et al. (2017). Bai et al. (2017) dominated by type I and type II kerogens, which have low hold that the oil generation capacity and evolution, reservoir thermal maturity, low quartz mineral content and mainly volume, and overpressure control the oil enrichment, the oil generate waxy oil (Katz and Lin 2014; Chen et al. 2015; density, viscosity, and gas–oil ratio control the oil movabil- Wang et al. 2014, 2015a, b, 2019; Nie et al. 2016). Clearly, ity, the lithological combination and brittle mineral contents lacustrine basins and marine basins have distinct differences of shale control the frackability. Liu et al. (2018) studied in geological and geochemical characteristics (Jiang et al. the petrological characteristics and shale oil enrichment in 2017; Wang et al. 2019). It is difficult to arbitrarily apply Qingshankou Formation of Gulong Sag, Songliao Basin, 114°50′ 115°00′ 115°10′ (c) 04 8 km 1 km Beijing PC Bohai Bay Basin LT HBZ Dongpu Depression H96 MG 35° 35° HZJ WL 40′ 40′ (a) QLY W21 Town name 11 HTJ W218 HBZ-Hubuzhai H72 PC-Pucheng Fault name MG-Maogang W19 1.Lanliao PS18 WL-Wenliu 2.Gaopingji HZJ-Huzhuangji 35° 2 35° 3.Liuta QLY-Qianliyuan 18 20 PS18-1 30′ 30′ 4.Mazhai W39 HTJ-Haitongji 5.Shijiaji WC-Weicheng 6.Changyuan LT-Liutun 7.Weixi 9 1 PS18-8 8.Wenxi 9.Huanghe 10.Puchenge W120 11.Duzhai12.Machang W246 W142 13.Sanchunji14.Weidong 15.Wendong 16.Liangzhaung 17.Xulou Sampled Well Fault 18.Yuhuangmiao 35° 35° 13 19.Madong 20.Litun well 20′ 12 20′ Predicted Structural Shale-oil contour (b) Town Fault Reservoir 114°50′115°00′ 115°10′ Fig. 1 Geological map of Liutun Sag, Dongpu Depression (DD). a Overview map of China showing the location of the Bohai Bay Basin and DD, b regional structural map of the DD showing the location of the Liutun Sag (modified after Wang et al., 2015a), and c structure contour map of the Es (an upper sub-member of third member of the Paleogene Shahejie Formation) and key wells in the Liutun Sag 1 3 Xingzhuang fault Wenxi fault 2960 Petroleum Science (2021) 18:687–711 689 and concluded that the laminated siliceous mudstone with Neogene strata. Located in the central western region of moderate TOC is most favorable for shale oil enrichment. the DD (Fig. 1), the Liutun Sag is the second-largest petro- Lots of saline lacustrine rift basins develop in China and are leum generating sag. The strata consist of the Paleogene rich in shale oil resources. Although many studies have been Kongdian, Shahejie and Dongying Formations, Neogene conducted on the factors controlling shale oil enrichment, Minghuazhen and Guantao Formations, and the Quater- few systematic analyses about the macrogeological condi- nary Pingyuan Formation. The strata have a thickness of tions have been made, which are significant in “sweet spots” approximately 6000 m, with Es as the main source rock prediction in shale oil system. and reservoir (Wang et al. 2015a). The Es shale is divided U M L The DD is a typical saline lacustrine rift basin in China, into Es, Es , and Es (middle and lower submember of 3 3 3 in which the third member of the Paleogene Shahejie Forma-the Es ), from top to bottom. The shale oil play was devel- tion (Es ) is thick and rich in shale oil resources (Wang et al. oped in Es at a burial depth of 3200–4000 m, consist- 3 3 2014, 2015a, 2019). Since 1976, oil shows had been discov- ing of clastic mudstones, carbonate rocks, and evaporites ered from the Es shale of Wells Wen 6, Wen 300, and Wen (Fig.  2). Faults are not developed in the central Liutun 201 in the DD and even yielded some oil (Mu et al 2003; Sag. However, due to the impact of the marginal faults at Leng et al. 2006). In 2010, the Well PS18-1 obtained a daily the eastern and western sides of the sag, numerous small oil yield of 430 m with a 5 mm size nozzle in the depth of secondary faults occur near these faults and are favorable 3,255–3,258 m in the Es shale (Zhang et al 2015), which for fracture development (Wang et al. 2004, 2015a). is the highest single-well production obtained in a shale oil exploration well recently (Zhang et al. 2012; Wang et al. 2014). However, only oil shows were observed in subsequent drilling Well PS18-8, which was located only approximately 800 m to the south of Well PS18-1. Under similar structural conditions, why do these two wells exhibit such a remark- System Formation symbol Lithology Deposition system able difference in shale oil yield? Obviously, the two wells Quaternary Py Fluvial are excellent objects for conducting shale oil enrichment Nm studies. However, in the DD, the subsequent studies mainly Neogene Fluvial Ng investigated the generally geological and geochemical char- acteristics of the Es shale (Deng et al. 2015; Wang et al. 3 Ed Fluvial and flood plain 2014, 2015a; Zhang et al. 2015), rarely focused on the shale oil enrichment laws. Shallow-semideep Es lacustrine and delta Targeting the Es shales in the Wells PS18-1 and PS18- 8, this study utilized continuous cores to reveal key factors Shore-shallow controlling shale oil enrichment. Detailed geological and Es lacustrine, fan delta fluvial, and flood plain geochemical studies were carried out to examine petroleum generation potential, reservoir capacity, frackability, and oil Paleogene Es Es mobility. Comparative analyses were conducted regarding Semideep-deep saline their differences in production capacity. Finally, the key fac- Es lacustrine, delta Es turbidite and fan delta tors controlling shale oil enrichment were proposed. The results obtained in this study can provide significant refer - Es3 ences for further shale oil exploration in saline lacustrine rift Lacustrine, turbidite basins across the world. Es and fluvial Ek Fluvial 2 Geological background Erosion line Mudstone Sandstone Shale Limestone Salt rock Siltstone The DD, located in the southwestern corner of the Bohai Bay Basin, is a Mesozoic and Cenozoic lacustrine rift Fig. 2 Generalized stratigraphy and depositional system of the Liutun basin in Paleozoic craton with an area of 5300 km (Fig. 1) Sag, DD (modified after Wang et  al., 2015a; Luo et  al., 2016). Es: (Chen et al. 2000). The DD extends to the NNE-SSW and Shahejie Formation; Ed: Dongying Formation; Ng: Guantao Forma- tion; Nm: Minghuazhen Formation; Qp: Pingyuan Formation; Es : is narrow in the south but broad in the north (Chen et al. 3 Third member of Paleogene Shahejie Formation; Es : Lower sub- 2013). Four tectonic movements and six tectonic evolu- M U member of Es; Es : Middle sub-member of the Es; Es : Upper 3 3 3 3 tion stages occurred (Chen et al. 2013), forming a set of sub-member of Es ; Es : Forth member of Paleogene Shahejie For- 3 4 super-thick continental strata dominated by Paleogene and mation; Ek: Paleogene Kongdian Formation 1 3 690 Petroleum Science (2021) 18:687–711 Fig. 3 Lithological column of main intervals of interest in Wells PS18-1 and PS18-8 of the Liutun Sag, DD, showing the locations of the core samples 1 3 Stratum Depth, m Lithology Stratum Depth,m Lithology Mudstone Salt rock Gypsum-salt rock 3 41 42 Gypsiferous mudstone Shale 9 Sample position Es3 17 3270 63 82 21 u Es 69/70 90/91 75/76 Es 102 (b) PS18-8 (a) PS18-1 Petroleum Science (2021) 18:687–711 691 have the greatest and the lowest petroleum generation poten- 3 Samples and methods tial, respectively, and therefore the weighting coefficient are +100 and − 100. Exinite is mainly originated from chitin 3.1 Samples tissues of terrestrial or aquatic higher plants. Esters with higher fatty acids and higher alcohols in the chitin tissues One hundred two shale samples were cored from Wells can be reduced by hydrolysis to generate petroleum. There- PS18-1 (3258–3285 m) and PS18-8 (3155–3193 m) in the fore, the exinite has certain petroleum generation potential, Es shale oil play (Fig. 3). and the weighting coefficient is +50. Vitrinite is mainly formed from xylems of higher plants. During bituminiza- 3.2 Methods tion, the asphaltenes formed by deoxidization of long-chain acids, alcohols, and esters are mainly absorbed by vitrinite. For TOC analysis, 100 milligrams of shale samples was The petroleum generation potential of the vitrinite is greater washed and ground to 100 mesh powder and immersed in than inertinite, but signic fi antly lower than sapropelinite and dilute hydrochloric acid to remove inorganic carbon. Then, exinite. Following the weighting coefficient proposed by the the samples were rinsed repeatedly with distilled water until EXXON, the weighting coefficient of the vitrinite is − 75 a neutral pH was achieved and were subsequently dried in (Cao 1985). The calculation function of the TI is as follows: an oven at 60–80 °C. The samples were then analyzed using a LECO CS-400 instrument (Espitalié et al. 1977). Soxhlet TI = (a × 100 + b × 50 − c × 75 − d × 100)∕100 (1) extraction was performed on the shale samples with chlo- roform for 72 h. To obtain rock extract “A,” the fractions of where a, b, c, d are the contents of the sapropelinite, saturated hydrocarbons, aromatic hydrocarbons, nonhydro- exinite, vitrinite, and inertinite, respectively. The kerogen carbons, and asphaltenes were tested by reference to the Oil with TI > 80 % is type I, that with 0 < TI < 80 % is type II, and Gas Industry Standard of the People’s Republic of China and that with TI < 0 is type III. (Zheng et al. 2008). High-resolution field emission-scanning electron micros- Mineral composition was obtained by X-ray diffraction copy (FE-SEM) was utilized to study the fractures and pores. (XRD) analysis with a Panalytical X’Pert PRO diffractom- The experimental instrument was a FEI Quanta 200F scan- eter at a temperature of 24 °C and humidity of 35% with a ning electron microscope set to a voltage of 20 kV and an 2°/min 2θ rotation speed and a Cu Ka emission source pow- object distance of 10–12 mm. A QUANTAX400 energy ered at 40 kV and 30 mA. This study adopted the Rietveld spectrometer was used in energy spectrum analyses at an method for quantitative phase analysis (Ufer et al. 2008). acceleration voltage of 20 kV with a dead time of 35–40 The biological microscope with fluorescence emission %, and a live time of 100 s. The experiment was conducted was utilized to observe size, morphology, and fluorescence at the temperature of 20 ℃ and humidity of 50 %. To ana- of the organic matter in the shale samples to identify the lyze pores with sizes smaller than one micrometer, the sam- kerogen macerals. Thin slices of the shale samples were pre- ples were first subjected to argon ion polishing (Gatan 691. pared using glycerol and examined with 40× object lens to CS) followed by gold plating (SCD500) prior to taking the determine the representative size of the macerals, which was measurements. The measurements were conducted on the regarded as the standard statistical unit. After that, the visual natural section samples directly for observation of fractures field was moved at equal distance interval relative to the ini- and pores with sizes greater than several micrometers (Jiao tial position. In each visual field, the marcels were identified et al. 2016). and counted. The visual field and the marcels observed in that field were labeled by the coordination of the field center to the initial position. 4 Results and discussion Kerogen type index (TI) was calculated by utilizing the method proposed by Cao (1985), which has been used to 4.1 Petroleum generation potential and shale oil evaluate kerogen types of lacustrine shale (Tao et al. 2012; content Luo et al. 2017). The maceral of kerogen is composed of sapropelinite, exinite, vitrinite, and inertinite. Generally, the 4.1.1 Organic matter content sapropelinite mainly originates from the lower plankton, and the higher the content of sapropelinite is, the more favorable The TOC values of the shale samples range between 0.35 % the kerogen is for petroleum generation. Inertinite is formed and 5.7 % with a mean of 1.83 % (Table 1), showing that 74 from xylems of higher plants by intense carbonization or car- % of the shale is good to excellent source rocks (Fig. 4). The bonization after gelation, with high carbon content and low Es shale is distributed throughout the entire DD, with the hydrogen content. Therefore, the sapropelinite and inertinite greatest thickness (up to 325 m) in the center. The thickness 1 3 692 Petroleum Science (2021) 18:687–711 1 3 Table 1 Total organic carbon (TOC) testing data of Es shale samples in the Liutun Sag, DD Well Sample No. Depth TOC, % Well Sample No. Depth TOC, % Well Sample No. Depth TOC, % Well Sample No. Depth TOC, % PS18-1 1 3258.00 2.11 PS18-1 27 3276.60 2.61 PS18-8 52 3162.52 1.26 PS18-8 77 3175.10 1.30 PS18-1 3 3258.75 3.29 PS18-1 28 3277.20 2.15 PS18-8 53 3163.02 1.03 PS18-8 78 3175.50 0.63 PS18-1 4 3259.10 2.46 PS18-1 29 3278.25 3.12 PS18-8 54 3163.52 1.12 PS18-8 79 3176.20 0.37 PS18-1 5 3259.50 2.82 PS18-1 30 3279.00 2.57 PS18-8 55 3164.10 1.01 PS18-8 80 3177.65 0.35 PS18-1 6 3260.05 4.43 PS18-1 31 3280.20 1.15 PS18-8 56 3164.55 1.11 PS18-8 82 3181.00 2.21 PS18-1 7 3260.51 2.55 PS18-1 32 3281.00 0.80 PS18-8 57 3165.05 0.96 PS18-8 83 3181.70 2.93 PS18-1 8 3261.01 1.93 PS18-1 33 3283.10 3.20 PS18-8 58 3165.50 0.92 PS18-8 84 3181.92 2.71 PS18-1 9 3261.50 2.92 PS18-1 34 3284.30 3.24 PS18-8 59 3165.55 0.78 PS18-8 85 3182.16 1.77 PS18-1 10 3262.10 2.64 PS18-1 35 3284.90 2.85 PS18-8 60 3165.95 2.17 PS18-8 86 3182.54 1.20 PS18-1 11 3262.50 3.24 PS18-8 36 3155.22 3.20 PS18-8 61 3166.35 2.35 PS18-8 87 3182.60 1.44 PS18-1 12 3262.95 1.44 PS18-8 37 3155.72 3.01 PS18-8 62 3166.80 5.58 PS18-8 88 3183.00 0.83 PS18-1 13 3263.61 2.03 PS18-8 38 3156.07 2.08 PS18-8 63 3167.20 2.06 PS18-8 89 3183.40 1.91 PS18-1 14 3267.91 0.88 PS18-8 39 3156.47 2.72 PS18-8 64 3167.60 1.21 PS18-8 90 3183.95 3.37 PS18-1 15 3268.21 1.15 PS18-8 40 3157.12 3.76 PS18-8 65 3167.90 0.60 PS18-8 91 3184.00 1.93 PS18-1 16 3268.51 0.95 PS18-8 41 3157.42 3.94 PS18-8 66 3168.40 0.66 PS18-8 92 3184.60 1.96 PS18-1 17 3269.01 0.76 PS18-8 42 3157.72 3.23 PS18-8 67 3168.75 0.58 PS18-8 93 3185.30 5.18 PS18-1 18 3269.51 0.70 PS18-8 43 3158.32 1.72 PS18-8 68 3169.90 1.26 PS18-8 94 3185.80 2.36 PS18-1 19 3270.45 0.54 PS18-8 44 3158.77 1.11 PS18-8 69 3170.20 2.06 PS18-8 96 3187.10 5.70 PS18-1 20 3270.85 0.78 PS18-8 45 3159.07 1.70 PS18-8 70 3170.20 0.88 PS18-8 97 3187.60 2.58 PS18-1 21 3270.98 0.86 PS18-8 46 3159.67 1.02 PS18-8 71 3170.80 1.08 PS18-8 98 3190.35 1.12 PS18-1 22 3271.78 0.72 PS18-8 47 3160.22 1.08 PS18-8 72 3171.60 0.93 PS18-8 99 3191.00 1.69 PS18-1 23 3272.48 0.94 PS18-8 48 3160.52 1.01 PS18-8 73 3172.10 1.05 PS18-8 100 3191.80 1.60 PS18-1 24 3273.20 3.59 PS18-8 49 3160.97 1.11 PS18-8 74 3174.10 0.69 PS18-8 101 3192.50 1.77 PS18-1 25 3274.30 1.05 PS18-8 50 3161.52 0.98 PS18-8 75 3174.65 0.46 PS18-8 102 3193.00 1.64 PS18-1 26 3275.22 1.01 PS18-8 51 3162.02 1.37 PS18-8 76 3174.70 0.64 PS18 103 3238.00 1.22 Petroleum Science (2021) 18:687–711 693 with SEM (Fig. 5i). These objects are also interpreted as 74.0% Good-Excellent algae fossils due to their shapes. Further energy spectrum PS18-1 (N=34) PS18-8 (N=65) analyses reveal that these fossils are rich in carbon and oxy- gen (Fig. 5j), indicating they are algae fossils (Tyson 1995; Qiu et al. 2015; İnan et al. 2016). The alginite content is low with an average of only 2.5 % (0.3–11.3 %) due to easy decomposition. The exinite primarily consists of hydrogen-poor amor- phous organic matter, sporinite, and cutinite, with average 0.2 0.6 1.0 1.4 1.8 2.2 2.6 3.0 3.4 3.8 4.2 4.6 5.0 5.4 5.8 contents of 27.5 % (0–88.5 %), 2.2 % (0–15.3 %), and TOC, % 1.8 % (0–5.3 %). The hydrogen-poor amorphous organic matter is formed from higher plants degradation, the Fig. 4 Frequency histograms of total organic carbon (TOC), indi- microscopic characteristics of which are similar to hydro- cating that the Es shale is a set of good–excellent source rock. N indicates the number of samples. The evaluation criterion for good- gen-rich amorphous organic matter, exhibiting flat, floc- excellent source rocks was from Peters and Cassa (1994) culent, and cloudy shapes (Fig. 5o), has a high petroleum generation potential but exhibits little fluorescence and some raised folds under the microscope. The precursors gradually decreases to 100 m at the north margin and to 75 of sporinite (Fig. 5k, l, m, and n) are primarily the chitin- m at the south margin (Deng et al. 2015). The average TOC ous tissues of higher plants containing higher fatty acids, value of Well PS18-1 is 1.98 %, and the variation is between alcohols, and lipids, generating petroleum by hydrolysis 0.54 % and 4.43 %, and the average value of Well PS18-8 or reduction (Cao 1985). Vitrinite is mainly composed of is 1.75 %, with a range from 0.35 % to 5.70 % (Table  1), telinite and euvitrinite, with average contents of 7.8 % showing that the organic matter content of the shale varies (1.3–28.3 %) and 0.4 % (0–3.8 %), respectively, which considerably, but the lateral difference between these two originates from wood fibers of higher plants, presenting a wells is not significant. weak fluorescence and primarily generate natural gas. Tel- inite has a clear wood structure characterized by tubular 4.1.2 Organic matter type cells, various conduits, and fibrous structures (Fig.  5p), and the structural clarity and transparency vary with the Maceral composition can be used to determine organic degradation degree. Inertinite is opaque under transmis- matter type of shale (Huang et al. 1984; Tissot and Welte sion light and has a dark brown to black-on-black angu- 1984). Results show that the kerogen of the Es shale is 3 lar shape, which is formed from the xylem fiber tissue on average composed of 59.4 % sapropelinite (1.6–96.7 %), of higher plants by fusainization, from which only trace 31.8 % exinite (0.3–89.7 %), 8.3 % vitrinite (1.3–31.6 %), amounts of natural gas are generated. and 0.5 % inertinite (0–3.0 %) (Table 2). The hydrogen-rich The maceral composition of the Es shale varies with amorphous content, accounting for an average of 57.3 % depth. In detail, the shale samples from the thick and stable (0.9–95.5 %), is predominantly translucent, nonhomogene- shale section are commonly rich in hydrogen-rich amor- ous, and flocculent (Fig.  5a, b, c, and d). The hydrogen-rich phous organic matter and poor in hydrogen-poor amorphous organic matter is amorphous, ranging in size from tens to organic matter, but the opposite is true for the section with hundreds of microns, and mainly exhibits a brown–yellow shale interbedded with evaporites (Fig. 6). This is because color under transmitted light (Fig.  5a, b, c, and d) and a that the former section was mainly developed in deepwater bright-yellow color under the fluorescent microscope. The environment, and the organic matter mainly originates from hydrogen-rich organic matters are the degradation products lower aquatic organisms and algae. of aquatic organisms and algae under strong reducing con- The TI values show that the organic matter of the shale ditions and have a significant petroleum generation poten- from Well PS18-1 is dominated by type II kerogen, while tial (Burgess 1974; Rahman and Kinghorn 1995; Luo et al. the shale from Well PS18-8 is mainly composed of type I 2017). Well-preserved elliptic alginite ranging from tens to and II kerogen. The triangular chart further confirms that hundreds of microns in size is found in the sapropelinite the organic matter of Well PS18-1 shale is entirely type II and exhibits a yellow–brown color under transmitted light kerogen, while that of Well PS18-8 shale is mainly type I (Fig. 5e, f, g, and h). Alginite is the most typical hydrogen- kerogen with a small amount of type II kerogen (Fig.  7). rich microcomponent of sapropelinite and has a strong petro- Lacustrine systems are highly sensitive to climate changes leum generation potential (Luo et al. 2017). Alginite is the (Katz 1995), and the sequent changes in the balance degradation product of algae, and clear degradation traces between precipitation and evaporation further lead to the can be seen (Fig. 5f). Axiohitic objects were also detected salinity variation, which in turn result in great variation in 1 3 Frequency, % 694 Petroleum Science (2021) 18:687–711 1 3 Table 2 Chloroform bitumen “A,” vitrinite reflectance (VR), macerals, and kerogen-type index data of Es shale samples in the Liutun Sag, DD Well Sample Depth, Rock VR % Hydro- Alginite, Hydro- Sporin- Cutinite, Telinite, Euvitrin- Inerti- Sapro- Liptinite, Vitrinite, Inerti- Kerogen No. m extract gen-rich % gen-poor ite, % % % ite, % nite, % pelinite, % % nite, % type, % "A", amor- amor- % ppm phous, % phous, % PS18-1 3 3258.75 11,582 0.91 62.19 0.55 32.05 1.37 0 3.84 0 0 62.74 33.42 3.84 0 76.58 PS18-1 5 3259.5 10,041 - 64.58 0 27.9 5.33 0.31 1.88 0 0 64.58 33.54 1.88 0 79.94 PS18-1 7 3260.51 9183 0.94 61.13 0 32.71 5.33 0 1.33 0 0 61.13 37.54 1.33 0 78.89 PS18-1 10 3262.1 10,402 0.90 62.16 0.81 24.32 5.14 1.62 5.41 0 0.54 62.97 31.08 5.41 0.54 73.92 PS18-1 12 3262.95 3767 - 35.96 0.95 46.37 3.79 2.21 8.52 0 2.2 36.91 52.37 8.52 2.2 54.5 PS18-1 14 3267.91 2668 0.93 47.45 0.9 23.72 15.32 3.3 8.41 0.3 0.6 48.35 42.34 8.71 0.6 62.39 PS18-1 19 3270.45 1577 0.94 0.86 0 81.38 3.72 2.01 11.46 0 0.57 0.86 87.11 11.46 0.57 35.24 PS18-1 23 3272.48 4518 0.96 49.68 0.32 40.26 0.97 0.32 7.48 0.32 0.65 50 41.55 7.8 0.65 64.29 PS18-1 28 3277.2 9581 0.99 35.67 0.88 52.63 2.34 0.58 7.61 0 0.29 36.55 55.55 7.61 0.29 59.69 PS18-1 33 3283.1 8172 - 46.84 2.22 45.89 0.95 0.63 2.84 0 0.63 49.06 47.47 2.84 0.63 70.51 PS18-1 35 3284.9 17,809 0.98 7.9 0 88.45 0.91 0 2.74 0 0 7.9 89.36 2.74 0 51 PS18-8 37 3155.72 12,850 0.82 87.83 3.95 0 0 1.32 6.57 0.33 0 91.78 1.32 6.9 0 87.66 PS18-8 39 3156.47 12,703 0.83 93.26 1.69 0 0 0.28 4.77 0 0 94.95 0.28 4.77 0 91.5 PS18-8 41 3157.42 15,396 0.82 87.5 2.5 2.81 0.94 2.19 2.81 0.94 0.31 90 5.94 3.75 0.31 89.84 PS18-8 42 3157.72 12,787 0.80 56.53 2.13 29.6 0.8 1.33 9.08 0.53 0 58.66 31.73 9.61 0 67.67 PS18-8 43 3158.32 2384 0.81 77.74 1.25 15.67 1.88 1.25 2.21 0 0 78.99 18.8 2.21 0 86.76 PS18-8 45 3159.07 9007 0.83 83.83 1.65 2.97 1.32 2.97 6.93 0 0.33 85.48 7.26 6.93 0.33 84.6 PS18-8 47 3160.22 2261 0.82 52.98 8.78 16.3 1.88 5.33 13.79 0.31 0.63 61.76 23.51 14.1 0.63 62.7 PS18-8 50 3161.52 1905 0.85 41.96 11.31 18.45 4.76 5.06 16.67 1.49 0.3 53.27 28.27 18.16 0.3 54.88 PS18-8 52 3162.52 2717 0.89 21.75 3.57 55.19 2.27 3.9 12.02 0.65 0.65 25.32 61.36 12.67 0.65 46.27 PS18-8 54 3163.52 1982 0.88 29.95 5.22 23.35 2.47 4.12 28.57 3.3 3.02 35.17 29.94 31.87 3.02 23.64 PS18-8 56 3164.55 2238 0.89 69.51 5.49 14.63 1.22 2.74 6.11 0.3 0 75 18.59 6.41 0 79.88 PS18-8 60 3165.95 6607 0.93 79.81 1.89 15.14 0 0.63 2.53 0 0 81.7 15.77 2.53 0 88.19 PS18-8 63 3167.2 8178 0.94 92.66 0.28 0 0.28 0.28 6.22 0 0.28 92.94 0.56 6.22 0.28 88.28 PS18-8 66 3168.4 1771 0.92 12.5 2.98 61.62 3.27 3.27 13.1 1.47 1.79 15.48 68.16 14.57 1.79 36.83 PS18-8 69 3170.2 7963 0.95 78.08 0.62 2.8 1.23 1.23 15.73 0 0.31 78.7 5.26 15.73 0.31 69.21 PS18-8 77 3175.1 4050 - 74.14 2.49 15.26 1.25 1.25 5.3 0 0.31 76.63 17.76 5.3 0.31 83.57 PS18-8 80 3177.65 492 - 1.08 0.54 65.59 2.96 3.49 24.46 0.54 1.34 1.62 72.04 25 1.34 17.54 PS18-8 83 3181.7 13,951 0.93 88.17 2.15 0 0 1.79 7.17 0 0.72 90.32 1.79 7.17 0.72 85.57 PS18-8 87 3182.6 3271 0.95 87.74 0.65 0 0.65 0.97 8.7 0 1.29 88.39 1.62 8.7 1.29 81.87 PS18-8 90 3183.95 12,583 0.94 95.48 1.2 0 0.3 1.2 1.52 0 0.3 96.68 1.5 1.52 0.3 96.01 PS18-8 94 3185.8 5975 0.93 15.38 1.6 71.79 0.64 2.88 7.39 0 0.32 16.98 75.31 7.39 0.32 48.8 PS18-8 99 3191 5559 0.95 88.08 2.33 0 0.29 2.33 2.61 3.78 0.58 90.41 2.62 6.39 0.58 86.34 Petroleum Science (2021) 18:687–711 695 Hydrogen- (a)(b) (c)(d) rich Hydrogen- amorphous rich amorphous Hydrogen- rich Hydrogen- Hydrogen-rich Hydrogen- amorphous rich amorphous rich amorphous amorphous 50 μm 50 μm 50 μm 50 μm (e) (f) (g)(h) Alginite Alginite Alginite Alginite Degradation traces 50 μm 50 μm 50 μm 50 μm (around the algae) Element Intensity, c/s Atomic, % Relative content, % Cnts C 140.87 44.43 31.33 O 229.30 40.39 37.94 (i) (j) (k)(l) Na 59.45 2.78 3.76 Axiohitic Sporinite Mg 37.37 1.21 1.73 3.0K O Al 54.84 1.38 2.19 algae Si 122.20 2.61 4.31 160.23 2.82 5.31 K 6.25 0.10 0.24 Ca 48.60 0.83 1.95 2.0K Fe 124.96 3.43 11.25 Si 1.0K Al Fe Na S Sporinite Al Fe Fe Si Ca K Fe Mg S Fe K Ca K Mg Si Fe Fe 2 μm S Na Al S K Ca 50 μm 15 μm 20 kV 15 kX 05 10 keV (m) (n)(o) (p) Sporinite Hydrogen- Sporinite poor amorphous Telinite 50 μm 50 μm 50 μm 50 μm Fig. 5 Photomicrographs showing typical maceral composition of kerogen in Es shale of Liutun Sag, DD: a Well PS18-1, 3258.75m, ×640, hydrogenrich amorphous; b Well PS18-1, 3259m, ×640, hydrogen-rich amorphous; c Well PS18-8, 3185m, ×640, hydrogen-rich amorphous; d Well PS18-8, 3191m, ×640, hydrogen-rich amorphous; e Well PS18-1, 3262.95m, ×640, alginite; f Well PS18-1, 3283.1m, ×640, alg- inite; g Well PS18-8, 3157.42m, ×640, alginite; h Well PS18-8, 3191m, ×640, alginite; i Well PS18-8, 3193m, 20kV, alginite; j Well PS18-8, 3193m, energy spectrum analysis indicate that the axiohitic object in the (i) is algae; k Well PS18-1, 3258.75m, ×640, sporinite; l Well PS18-1, 3258.75m, ×1020, sporinite; m Well PS18-8, 3182.6m, ×640, sporinite; n Well PS18-8, 3182.6m, ×1020, sporinite; o Well PS18-8, 3175m, ×640, hydrogen-poor amorphous; p Well PS18-8, 3157.72m, ×640, telinite the kerogen composition. As shown in Fig. 3, during Es more shale samples of Well PS18-8 are type I, while few deposition, thick and stable shale was developed in Well samples from Well PS18-1 are (Fig. 7). PS18-1 (3250–3285 m), while the shale in Well PS18-8 was frequently interbedded with evaporites (3167–3178 4.1.3 Thermal maturity m), indicating that although Wells PS18-8 and PS18-1 have similar structural settings, considerable differences exist in Vitrinite reflectance ( VR) is a commonly indicator of thermal depositional environments. For example, the salinity of the maturity (Tissot and Welte 1984). The VR values of Wells depositional water in Well PS18-8 was much more varying PS18-1 and PS18-8 have averages of 0.94 % (0.90–0.99 %) and higher than that of Well PS18-1, resulting in significant and 0.88 % (0.80–0.95 %), respectively (Table 2), showing variations in the kerogen types in Well PS18-8. Generally, that the shales in both wells are in the oil window. The ther- in water with high salinity, the terrestrial higher plant input mal maturity of the shale in Well PS18-1 is slightly higher should be relatively small, while the lower halophilic aquatic than that of the shale in Well PS18-8. organism input should be relatively great (Carbonel 1988; Hu et al. 2018b). Therefore, regarding the kerogen types, 1 3 696 Petroleum Science (2021) 18:687–711 Depth, Depth, Stratum Lithology Maceral composition of kerogen,%Pas Stratum Lithology Maceral composition of kerogen,%Pas m m 020406080 100 020406080 100 u u Es Es 3 3 (a) PS18-1 (b) PS18-8 Hydrogen-rich AlginiteHydrogen-poor Sporinite Cutinite TeliniteEuvitrinite Inertinite amorphous amorphous Fig. 6 Maceral composition profile of kerogens from Es shale in Liutun Sag, DD. %Pas = Particle abundances of individual macerals. (The lithology legend refers to Fig. 3) Oil content is an important parameter in evaluating oil 4.1.4 Petroleum generation potential and shale oil content resource (Jarvie 2008, 2012; Hu et al. 2018a; Wang et al. 2020). The rock extract “A” content can directly assess shale Factors controlling petroleum generation potential of shale include organic matter content, type, and thermal maturity. oil content. The rock extract “A” contents of the shale sam- ples from both wells range between 0.5-17.8×10 ppm with The shales in the DD have similar TOC contents, organic matter type, and thermal maturity to shale oil plays in other a mean of 7.1×10 ppm (Table 1). The rock extract “A” con- tents of Well PS18-1 range from 1.6 to 17.8 ×10 ppm with lacustrine basins in China. In comparison with the typical shale oil plays in the USA (Table 3), despite the lower TOC an average of 8.1×10 ppm, while the extract “A” contents of Well PS18-8 range from 0.5 to 15.4 ×10 ppm with a mean content and thermal maturity, the shale in the study is domi- nated by type I and II kerogens (Fig. 7). Besides, the gross of 6.7×10 ppm. Further analyses show that the oil content of the Es shale has a positive correlation with TOC con- thickness of the shales is much greater, with average and greatest gross thicknesses ranging from 500 m to 910 m tent (Fig. 8a) with a slope of 2248.1 (R-squared = 0.9063), indicating that the higher the TOC is, the higher the shale oil and 800 m to 2610 m, respectively (Wu et al. 2013; Duan et al. 2008). Therefore, the petroleum generation potential content is. The correlation between the oil content and the kerogen TI is slightly positive correlated with a slope of 11.0 of the Es shale might be significant. In comparison, little difference exists in the organic matter contents and thermal (R-squared = 0.4256) (Fig. 8b), revealing that the organic matter type also controls the oil content, and the larger the maturity between the shales at Wells PS18-1 and PS18-8, but the latter exhibits a stronger oil-generating capacity due kerogen TI is, the higher the shale oil content is. However, the effect of the kerogen type on oil content is much less to significantly higher sapropelinite content (Fig.  7). 1 3 Petroleum Science (2021) 18:687–711 697 Exinite, % developed in the Es shale. Tension fractures are formed under tensile stress and not fracturing through minerals 100 0 PS18-1 (N=11) when extending, exhibiting curved extension planes and PS18-8 (N=22) profiles (Fig.  9a and b), which play important roles in con- necting different types of fractures. The tension fractures in 75 25 the study are not only related to the tectonics but also the evaporites. In the Es shale, the evaporites are interbedded II with shale (Fig. 3). Differential compaction and irregular 50 50 plastic flow of evaporites easily occur due to difference in density between evaporites and shales. As shale is clearly more brittle than salt, when the pressure caused by differ - 25 III 75 ential compaction or irregular plastic flow of the evaporites exceeds the critical rupture pressure of the shale, the tension 0 100 fractures form. In the Es shale, seventy percent of tension 100 75 50 25 0 fractures are filled with gypsum, calcite, halite, and asphalt Sapropelinite, %Vitrinite+Inertinite, % (Fig. 9a and b), and the remaining tension fractures are open fractures in which oil impregnation is common (Fig. 9c and Fig. 7 Ternary Diagram of sapropelinite, exinite, vitrinite, and iner- d), as a result of the extensively developed evaporites. Under tinite in Es shale, Liutun Sag, DD, indicating that the kerogen of the influence of tectonic activity and differential compac- Well PS18-1 is type II kerogen and Well PS18-8 is mainly type I ker- tion, the induced tension fractures in the shale interbedded ogen with a small amount of type II kerogen, respectively. N indicates with the evaporites were very easily filled by the flowable the number of samples. (The classification diagram refers to Wang et al. (2015a)) evaporites. However, in the thick shale, the induced tension fractures were filled by the oil generated from the adjacent shales, and the accumulated oil further promoted the preser- vation of fracture space. Shear fractures are mainly formed than TOC content. This conclusion can also be confirmed by shear stress, generally open and having straight and flat by the observation that, although the kerogen type of the planes and profiles (Fig.  9e, f, g, and h). X-shaped conjugate shale at the Well PS18-8 is more oil-prone than that of the joints (width: 1-5 mm) can also be identified (Fig.  9g) and Well PS18-1, the shale oil contents of the Well PS18-8 are were filled with oil (Fig.  9g and h). smaller than that of the Well PS18-1, which is mainly due to Diagenetic fractures are microfractures formed due to dia- the smaller TOC of the shale at the Well PS18-8. genetic compaction (Luo et al. 2015). Interlayer bedding, In summary, although the petroleum generation potential dissolution, and shrinkage fractures are commonly observed of the shale at Well PS18-8 is relatively greater than that of in the Es shale. Interlayer bedding fractures are the most the shale at Well PS18-1, the shale oil content of the lat- 3 common fractures and develop near lithological interfaces ter well is slightly greater due to the slightly greater TOC. (Fig. 9i, j, and k), and the openings are usually small and Therefore, petroleum generation potential is not a key factor were filled (Fig.  9l and m). Dissolution fractures are enlarged affecting the shale oil enrichment between the two wells. primary fractures or newly formed by differential dissolu- tion along the lamina, due to different mineral compositions 4.2 Reservoir volume and particle arrangements between lamina (Luo et al. 2015), which are mostly parallel to rock surfaces (Fig. 9n). Shrink- 4.2.1 Fractures age fractures are commonly formed by change of facies or thermal contraction of different minerals, or in the coring Fractures are faults without significant displacement and and sample preparation process, which are usually short and effective reservoir volume for shale oil (Ferrill et al. 2014). have good connectivity and various apertures, with some Tectonic, overpressure, and diagenetic fractures were identi- filled with illite and halite (Fig.  9o, p, q and r). fied in the study by core samples, fluorescence microscopy, Overpressure fractures refer to fractures at a certain depth and FE-SEM observations. and under a closed pressure system. In shales, these fractures Tectonic fractures refer to those formed by or associated form by overpressure due to hydrocarbon generation, clay with the local tectonics. Tectonic activity was common in mineral dehydration, hydrothermal activity, or authigenic the DD (Chen et al. 2013) and enabled the formation of mineral precipitation (Wang et al. 2015b). The Es shale various derived fractures near the marginal faults (Wang is a set of good to excellent petroleum source rocks within et al. 2015a). Tectonic fractures include tension, shear, and oil window. Petroleum generation in these source rocks can compression fractures, and the former two were primarily cause overpressure (Luo et al. 2015, 2016). The extensively 1 3 698 Petroleum Science (2021) 18:687–711 1 3 Table 3 Basic parameter comparison between terrestrial lacustrine shale oil plays in China and lacustrine and marine shale oil plays in North America Basin/ Strata Age Thickness, Total Kerogen Maturity, Porosity, Quartz, % Carbon- Clay min- Density, g/ Viscosity, Pressure References Depres- m organic type VR, % % ates, % erals, % cm mPa·s coefficient sion carbon, % U 3 Dongpu Es Paleogene 75–325 0.35–5.7 I–II 0.67–1.08 6.7–22.6 4–28 2–52 8–52 0.935 43 × 10 1.4–2.2 Williston Bakken Late Devo- 5–15 7.23–12.9 II 0.65–1.3 5–13 74 25 –50 < 0.820 – 1.35–1.58 (Jarvie, nian- 2008, Early 2012) Carbon- iferous Maverick Eagle Late Cre- 15–92 1–7 I–II 1–1.7 4–15 10–30 20–80 20–30 – - 1.35–1.8 (Jarvie, Ford taceous 2008, 2012) Fort worth Barnett Late Devo- 92–152 4–8 II 0.5–2.3 2–14 40–80 27 0.835–0.845 – 0.99–1.27 (Montgom- nian- ery et al., Early 2005; Carbon- Jarvei iferous et al., 2007; Loucks et al., 2007; Han et al., 2015, 2017a, 2017b) San Monterey Miocene 914–1220 0.7–5.6 II 0.3–1.1 13–29 30–50 – – – – – (Montgom- Joaquin ery et al., 2001; Jar- vie et al., 2008) Ordos Chang 7 Late Trias- 10–45 0.3–36.2 I–II 0.6–1.1 4.8–12.6 27–47 19 19–31 0.83–0.88 6.12 0.75–0.85 (Jiang et al., sic 2016a, 2016b; Liu et al., 2016; Wang et al., 2016b) Songliao Qing- Early Cre- 50–500 0.4–4.5 I–II 0.5–1.5 6–12 15–50 20–31 22–49 – – – (Jiang et al., shankou taceous 2006; 2013; Zou et al., 2013) Santanghu Lucaogou Middle 10–120 1–7 I–II 0.5–0.9 1–6 20–40 20–40 5–48 0.9 738.8 1–1.4 (Zou et al., Permian 2013) Petroleum Science (2021) 18:687–711 699 1 3 Table 3 (continued) Basin/ Strata Age Thickness, Total Kerogen Maturity, Porosity, Quartz, % Carbon- Clay min- Density, g/ Viscosity, Pressure References Depres- m organic type VR, % % ates, % erals, % cm mPa·s coefficient sion carbon, % Subei Fu 4 Paleogene 50–500 0.5–4.1 I–II 0.5–0.8 1.4–15.8 10–50 5–30 25–75 – – 1–1.1 (Zou et al., 2013; Zhang et al., 2015) Fu 2 Paleogene 50–350 0.5–4.7 I–II 0.5–1.3 1–8 10–60 5–35 30–80 – – 1–1.1 (Zou et al., 2013; Zhang et al., 2015) Jiyang Es Paleogene 50–400 2–6 I–II 0.7–0.93 2–8 – – – 0.89–0.94 16.1 –208 1.5–1.7 (Li et al., 2015, 2017; Ning et al., 2017; Wang et al., 2015b; Su et al., 2017) Biyang Well AS1 Paleogene 60–70 1.59–4.53 II 0.57–0.72 3.91–8.92 – – – 0.876 33.52 0.95–1.05 (Chen et al., 2011) 700 Petroleum Science (2021) 18:687–711 100000 100000 (a) (b) PS18-1 (N=11) PS18-1 (N=11) PS18-8 (N=22) PS18-8 (N=22) 1.4863 0.0273x y = 2248.1x y = 825.4e 2 2 R = 0.9063 R = 0.4256 100 100 0.1 1 10 020406080 100 TOC, % Kerogen type index, % Fig. 8 Correlation between rock extract “A” content and a TOC, and b kerogen type index in Es shale, Liutun Sag, DD. N indicates the num- ber of samples Inter-layer Open tension (a) (b) (c) (d) bedding fracture fracture surface between shale (the surface is dyed with oil) and gypsum Pyrite Open tension fracture (the surface is dyed with oil) Tension fracture (filled with gypsum) Tension fracture 2 cm 3 cm 2 cm 2 cm (filled with gypsum) (e) (f) (g)(h) Shear fracture (the surface is dyed with oil) Shear fracture surface (the surface is dyed with oil) X conjugate shear fracture (the surface is dyed with oil) Shear fracture (the surface is dyed with oil) 2 cm 2 cm 2 cm 5 cm (i) (j) (k) (l) Inter-layer Dendritic Inter-layer bedding halite bedding fractures fractures Inter-layer bedding Inter-layer bedding fracture fracture (the surface is dyed with oil) 200 μm 200 μm 100 μm 5 cm Fig. 9 Photos of cores and SEM images showing typical fracture characteristics of Es shale in Liutun Sag, DD. a Well PS18-1, 3259.4m, tectonic fractures and fissures are integrated and filled with gypsum and pyrite; b Well PS18-1, 3260.7m, tectonic fractures and fissures are inte- grated and filled with gypsum; c–d Well PS18-1, 3271.5m, tectonic fractures and diagenetic fractures, the surface of which is dyed with oil; e Well PS18-1, 3273.7m, tectonic fractures, the surface of which is dyed with oil; f Well PS18-1, 3266.68m,vertical tectonic fractures developed in groups and the surface is dyed with oil; g Well PS18-1, 3273.6m, X-type conjugate shear fractures, the surface of which is dyed with oil; h Well PS18-1, 3270.45m, shear fractures, the surface of which bears asphalt; i Well PS18-1, 3265.78m, inter-lamina micro-fractures, yellow fluorescence indicates the filling of oil in the micro-fractures; j Well PS18-8, 3185m, lamination development, lamina fractures present; k Well PS18-8, 3187.8m, micro-lamination development, inter-lamina fractures present; l Well PS18-8, 3186m, fractures are filled with dendritic halite crystals; m Well PS18-8, 3187.8m, lamination development, lamina fractures present; n Well PS18- 1, 3182m, diagenetic dissolution fractures; o Well PS18-8, 3187.8m, flaky illite showing the scale structure, developed with shrinkage fractures; p Well PS18-8, 3161.2m, flaky illite adhered to the surface of halite aggregation, developed with shrinkage fractures; q Well PS18-8, 3163.22m, flaky and silky illite and halite aggregation, developed with shrinkage fractures; r Well PS18-8, 3187.8m, shrinkage fractures are filled with halite aggregation; s Well PS18-1, 3289.8m, natural hydraulic fractures, the surface of which is wormlike with uncertain distribution directions, fractures are open; t Well PS18-8, 3169m, natural hydraulic tension fractures, short and thick, thick in the middle and thin on both ends; u Well PS18-1, 3260.7m, plane polarized light photograph; v Well PS18-1, 3260.7m, ultraviolet light-excited fluorescent photograph showing the oil inclusion with yellow and blue-white fluorescence; w Well PS18-8, 3156.45m, plane polarized light photograph; x Well PS18-8, 3156.45m, ultraviolet light-excited fluorescent photo- graph showing the oil inclusions with yellow fluorescence 1 3 Chloroform bitumen “A”, ppm Chloroform bitumen “A”, ppm Shrinkage fracture Petroleum Science (2021) 18:687–711 701 Flaky illite (m) (n) (o) (p) Diagenetic dissolution fractures Inter-layer Shrinkage bedding fracture fractures Flaky Halite illite 500 μm 1 μm 20 μm 5 μm (q) (r) (s) (t) Overpressure fracture Shrinkage Halite fractures Flaky illite Halite Overpressure fracture Flaky illite 20 μm 20 μm 2 cm 2 cm (u) (v) (w) (x) Oil inclusion Oil inclusion Oil with yellow with Oil inclusion fluorescence bule-white with yellow fluorescence fluorescence Oil Oil Oil Oil inclusion with yellow fluorescence 200 μm 200 μm 200 μm 200 μm Fig. 9 (continued) developed gypsums preserve the overpressure introduced abovementioned two enrichment mechanisms are completely by petroleum generation (Luo et al 2016). The shale will different. In this study, without anthropogenic fracturing, a rupture when the overpressure reaches the critical fractur- shale oil yield of 430 m /d was achieved in Well PS18-1, ing pressure, forming overpressure fractures. Generally, indicating that most of the produced oil should be movable overpressure fractures are randomly distributed in worm- oil in the fractures. The widely distributed oil inclusions in like shapes in the shale plane with no preferred orientation the fractures further prove it (Fig. 9u, v, w, and x). Therefore, (Fig. 9s). Some are short, wide in the middle and thin at the the reservoir volume available for shale oil is mainly deter- tips, exhibiting a spindle-like shape (Fig. 9t). Most overpres- mined by the degree of fracture development, which is usu- sure fractures are constrained by layered gypsum. However, ally evaluated by fracture density (Curtis 2002). The aver- when the gypsum laminae are thin, they can also be cut by age fracture densities of the shale in Well PS18-1 are 2.79, overpressure fractures (Fig. 9t). 4, and 4 stripes/meter in the depth intervals of 3220–3290 Previous studies have shown that the fractures in the m, 3258–3260 m, and 3276–3278 m, respectively, and the Es shale are mainly tectonic and overpressure fractures maximum fracture density is 7 stripes/meter (Fig. 10a). On with a few diagenetic fractures (Luo et al. 2015). This study the contrary, the average fracture density of the interval of found that diagenetic fractures are well developed despite 3140-3190 m of Well PS18-8 is 0.72 stripes/meter, and the their small micron scale (Fig.  9i–r). The large number of maximum fracture density is only 2 stripes/meter at 3157 tectonic and overpressure fractures commonly cut through m, 3171 m, and 3182 m (Fig. 10b). The higher fracture den- the diagenetic fractures, enabling the formation of three- sity of the shale in Well PS18-1 was mainly induced by two dimensional fracture networks, which significantly improve factors: lithology difference and formation pressure differ - seepage capacity (Fig. 9a–h and s–t). Therefore, as for the ence. Firstly, as shown in Fig. 3, compared with the interval reservoir volume, the contribution of the diagenetic fractures of interest (3250–3285 m) in Well PS18-1, the interval of cannot be ignored in the Es shale oil play. interest (3155–3195 m) in Well PS18-8 is characterized by As shown in Section 4.1.4, the TOC content controls the evaporites that are thin and interbedded with shale, which shale oil enrichment, mainly because the organic matter not greatly enhance the plasticity of the strata. Therefore, less only generates oil but also absorb it. However, compared to fractures would form in the Well PS18-8 under similar for- the absorbed oil, the oil accumulated in the shale fractures mation pressure. Secondly, the higher the formation pressure could be either generated from in situ shale or migrated is, the more fractures there are. In comparison, the measured from adjacent shale, which is mainly movable oil. The MDT formation pressure coefficient of Well PS18-1 is 2.2, 1 3 Shrinkage fracture 702 Petroleum Science (2021) 18:687–711 (a) (b) 2.0 1.6 Average = 0.72 1.2 Average = 2.79 0.8 0.4 0 0 3250 3260 3270 3280 3290 3150 3160 3170 3180 3190 3200 Depth, m Depth, m Fig. 10 Fracture development density diagram of Es saline lacustrine shale in a Well PS18-1 and b Well PS18-8 in the Liutun Sag, DD, indi- cating that the fracture development density of shale in Well PS18-1 is significantly higher than that in Well PS18-8 which is significantly greater than that of Well PS18-8, with that most of the pores were formed geologically. In the Es only 1.4. Therefore, due to the greater plasticity and lower shale, pores with different geometries were developed, which formation pressure of the shale intervals, significantly less were collectively controlled by the primary pore geometry fractures were developed in the Well PS18-8. In view of the and diagenesis. The linear shape pores were mainly formed positive correlation between the fracture density and res- between large halite crystals and clay minerals (Fig. 11b and ervoir volume, the reservoir volume of the shale at Well d). The elliptical–triangular pores represent the remaining PS18-1 should be dramatically greater than that at Well pore space between particles that have been subjected to PS18-8, making the former area more conducive to shale compaction and cementation (Fig. 11a and e). The pores oil enrichment. with internal paper-house microstructures are usually open (Fig. 11c and f) and create connectivity among pores. The 4.2.2 Pores pore size of the intercrystalline pores mainly ranges between 2 and 40 μm. Some pores have good connectivity, contribut- The FE-SEM and energy spectrum analyses show that the ing to the formation of an effective pore network and provid- pores in the Es shale samples include interparticle (inter- ing microchannels for the transportation and accumulation crystalline), intraparticle (intracrystalline), and organic mat- of petroleum, which is conducive to shale oil enrichment. ter pores. Interparticle (intercrystalline) pores are mainly Intraparticle (intracrystalline) pores refer to the pores intercrystalline pores (Fig. 11a–g), with a small proportion developed within particles. In this study area, these types of interparticle residual pores (Fig. 11g). These pore fea- of pores mostly formed in the later stage of diagenesis, and tures are mainly related to the hypersaline and strong reduc- few are primary (Wang et al. 2016b). The Es shale has a ing environment during deposition. Compared with marine low content of rigid-grain minerals but a high content of shales, the Es shale has a relatively lower content of rigid- carbonates, clay, and saline minerals, which are susceptible grain minerals such as quartz but a relatively higher content to dissolution and the subsequent formation of intraparti- of clay and saline minerals, leading to a dispersion of the cle (intracrystalline) pores (Wang et al. 2015a, 2016a). The rigid grains among the clay minerals and organic matter, intraparticle (intracrystalline) pores mainly include halite and impeding the formation of a grain-supported structure (Fig.  11d, h, and l) and anhydrite intracrystalline pores (Wang et al. 2016a). Therefore, the interparticle pores are (Fig. 11j and k), followed by moldic pores (Fig. 11i), dis- less developed and can be found between pyrite and halite solution pores between the framboidal pyrites (Fig. 11b), in a few samples (Fig. 11a–f). Furthermore, the abundant and pores within the calcite (Fig. 11m). The moldic pores clay and saline minerals are easily subjected to dissolution formed from the partial dissolution of halite particles. The by organic acids released from petroleum generation and diameters of the intraparticle (intracrystalline) pores range anthropogenic dissolution during drilling and sampling pro- from 1 to 50 μm. cesses, resulting in many intercrystalline pores. To minimize Organic matter pores are intraparticle pores that develop the impact of anthropogenic dissolution, the shale samples in organic matter. The formation, distribution, and size of were placed in cool and dry conditions and the drying cut- these pores are related to the organic matter content, type, ting technique was applied during sample preparation. The and thermal maturity of the shale (Loucks et al. 2012; Wang results show that, as shown in Fig. 11a–f, numerous miner- et  al. 2016b). The organic matter pores in this study are als were adsorbed around most of the salt pores, indicating often connected by shrinkage fractures, dissolution pores, 1 3 Fracture density (stripes/meter) Fracture density (stripes/meter) Petroleum Science (2021) 18:687–711 703 (a) (b) (c) (d) Halite Interparticle pore Flaky illite intercrystalline between halite pore with pyrite Halite Halite intracrystalline Pyrite intercrystalline pore Halite intracrystalline pore pores intercrystalline pores Halite intercrystalline pore 10 μm 5 μm 10 μm 10 μm (e) (f) (g)(h) Halite intracrystalline pore Interparticle residual pore Halite intercrystalline pores Halite Moldic intercrystalline pores pores 10 μm 200 μm 10μm (i) (j) (k) Gypsum intracrystalline (l) Illite Gypsum intracrystalline dissolution pore Halite dissolution pores Moldic pores Halite intracrystalline pores 10 μm 50 μm 20 μm 10 μm Intracrystalline Calcite (m) (n) (o)(p) residual pores intracrystalline Organic dissolution pores matter pores Clay shrinkage Organic intraparticle Organic matter Organic pores matter pores matter pores pores Clay shrinkage Organic Clay shrinkage intraparticle matter Clay shrinkage intraparticle pores pores intraparticle pores pores Fig. 11 SEM images showing typical pore characteristics of Es shale in the Liutun Sag, DD. a Well PS18-8, 3164m, halite aggregation and microfractures, developed with interparticle dissolution pores and intraparticle dissolution pores; b Well PS18-8, 3164m, a small num- ber of microcrystal pyrite crystals present among halite crystals, developed with interparticle dissolution pores and intraparticle dissolution pores; c Well PS18-8, 3162.23m, halite aggregation and micro dissolution pores, developed with interparticle dissolution pores; d Well PS18-8, 3161.2m, halite aggregation and micro dissolution pores, developed with interparticle dissolution pores and intraparticle dissolution pores; e Well PS18-8, 3160.1m, halite aggregation and micro dissolution pores, developed with interparticle dissolution pores; f Well PS18-8, 3162.23m, halite crystals and dissolution pores, developed with interparticle dissolution pores; g Well PS18-8, 3182m, developed with interparticle residual pores; h Well PS18-8, 3177.1m, halite exhibits a hardened shape and the presence of circular intraparticle dissolution pores; i Well PS18-8, 3177.1m, halite crystals form mold pits after dissolution; j Well PS18-1, 3280.4m, anhydrite surface is dissolved, developed with intracrystalline dissolution pores; k Well PS18-1, 3280.4m, surface of angular anhydrite crystals is dissolved, developed with intracrystalline dissolution pores; l Well PS18-8, 3165.1m, halite aggregation and dissolution pores, developed with intraparticle dissolution pores; m Well PS18-1, 3267m, devel- oped with intracrystalline residual pores, organic matter pores, and intra-organic matter contraction pores; n Well PS18- 1, 3267m, intra-organic matter shrinkage pores; o Well PS18-1, 3263.61m, developed with organic matter pores; p Well PS18-8, 3167.2m, developed with organic mat- ter dissolution pores and microfractures, exhibiting strip-like or network-like shale and are generally small, which might be related to the shapes. For example, interconnected pores are introduced low thermal maturity. Generally, the organic matter pores by the connection between organic matter pores and inter- begin to form when the VR of the kerogen reaches 0.8 % crystalline pores formed by clay mineral shrinkage (Fig. 11n (Reed et al. 2012; Katz and Arango 2018), such as the Mis- and o) as well as that between other organic matter pores sissippian Barnett Shale and the Toarcian Posidonia Shale and intraparticle pores formed by clay mineral dissolution in Lower Saxony, Germany (Loucks et al. 2009; Han et al. (Fig. 11p). Due to oil adsorption of the organic matter, the 2014). At present, the VR average of the Es shale is merely organic matter pores are very important for shale oil enrich- 0.9 %, indicating a relatively low thermal maturity, so the ment. Organic matter pores are less developed in the Es organic matter pores in this shale are less developed. 1 3 704 Petroleum Science (2021) 18:687–711 3 3 Acoustic time difference, μs/m Density, g/cm Acoustic time difference, μs/m Density, g/cm 150200 250300 350400 450 1.51.7 1.92.1 2.32.5 2.72.9 1502 2003 50 00 3504 400 50 1.51.7 1.92.1 2.32.5 2.72.9 1500 1500 1500 1500 (a) (b) (c) (d) 1700 1700 2000 2000 1900 1900 2500 2500 2100 2100 2300 2300 3000 3000 2500 2500 3500 3500 2700 2700 2900 2900 4000 4000 3100 3100 4500 4500 3300 3300 3500 3500 5000 5000 Well PS18-1Well PS18-8 Trend line Target stratum Fig. 12 Profiles of depth vs. logging data: a acoustic time difference of Well PS18-1; b mud density of Well PS18-1; c acoustic time difference of Well PS18-8; d mud density of Well PS18-8; showing the abnormal high porosity and strong overpressure Overall, intercrystalline and intracrystalline pores pre- oil play in the DD are very good and are conducive to the dominate in the Es shale, while organic matter pores shale oil enrichment. Similar to the oil enrichment mecha- are less developed. Comparative analyses indicate little nism in the fractures (see Section 4.2.1), the oil accumulated pore difference exist in the shales between Wells PS18-1 in the pores could be oil that either generated from in situ and PS18-8. The average surface porosity tested by liquid shale or migrated a short distance from adjacent shale, which saturation method of five shale samples from Well PS18-1 is mainly movable oil. As for the shale reservoir, the con- is 16.3 % (11.8–22.6 %), while that of five shale samples nectivity between pores is very poor, but most of the oil that from Well PS18-8 is 13.4 % (6.7–20.9 %) (Luo et al. 2013), has accumulated in these pores cannot be recovered without showing that the shale in Well PS18-1 has a higher porosity. anthropogenic fracturing (Jarvie 2012; Li et al. 2014). In this As shown in Figs. 2 and 3, evaporites are well developed study, without anthropogenic fracturing, a shale oil yield of U 3 in Es , and their sealing capacity is excellent and could 430 m /d was obtained at Well PS18-1, indicating that the prevent oil leakage. The strong overpressure developed in produced oil is likely the movable oil from fractures rather this stratum further illustrates this sealing capacity. The than pores. Therefore, the fracture density might be a key acoustic time differences and density logging data in the factor controlling shale oil enrichment. Es target interval (3250–3285 m) of Well PS18-1 have averages of 349 μs/m (252-434 μs/m) and 2.44 g/cm (2.32-4.3 Frackability 3 U 2.58 g/cm ), whereas the respective averages in the Es target interval (3155-3195 m) of Well PS18-8 are 277 μs/m To obtain commercial oil yield from low-porosity and -per- 3 3 (240–300 μs/m) and 2.54 g/cm (2.25–2.65 g/cm ), showing meability shale oil plays, large-scale horizontal wells and that the shale at Well PS18-1 has a higher acoustic time dif- anthropogenic fracturing techniques are required to improve ference but clearly a smaller density than the shale at Well the seepage capacity. Shale frackability depends mainly on PS18-8 (Fig. 12), which may be induced by the evaporites the natural fracture development and mineral composition enrichment. However, as shown in Fig. 3, the development (Jarvie et al. 2007; Wang et al. 2015b). degree of the evaporites in depth interval of 3155m–3195m Natural fractures in shale could reduce the tensile strength of the Well PS18-8 is significantly greater than that of depth of the rock and enhance the fracturing effect. The more interval of 3250m–3285m of the Well PS18-1, further indi- developed the natural fractures are, the more favorable con- cating that the shale in Well PS18-1 has a higher porosity. ditions are for creating interconnected fractures when frac- In comparison, the Es shale oil play in this study has a turing (Montgomery et al. 2005). The natural fractures in the significantly greater porosity compared to the shales in other Es shale are well developed, and the interaction between lacustrine basins in China and typical shale oil plays in the different types of fractures can form complex fracture sys- USA (Table 3), which might be associated with the strong tems, which are favorable for fracture networks formation overpressure. Therefore, the reservoir conditions of the shale by anthropogenic fracturing. Despite the extensive fracture 1 3 Depth, m Depth, m Depth, m Depth, m Petroleum Science (2021) 18:687–711 705 The higher the brittle mineral contents are, the better the Clay mineral fracturing ee ff ct is for the shale (Loucks and Ruppel 2007 ). 0 100 Among the mineral components in the Es shale, the clay Ps18-1 (N=23) Ps18-8 (N=20) minerals have the highest content, which are prone to plastic Barnett shale (N=28) deformation, leading to the blockage of seepage channels and 25 75 subsequent difficulty in shale fracturing (Wilson et al. 2014; Zeinijahromi et al. 2016; Wei et al. 2019). The content of feld- spar, which is unstable and easily dissolved, is also high, with 50 50 an average of 14 % (5–52 %). Quartz, calcite, and dolomite have average contents of 18 % (4–28 %), 15 % (0–47 %), and 12 % (0–45 %), respectively, and brittleness evaluation of the 75 25 shales in the USA (Montgomery and Morea 2001; Loucks and Ruppel 2007) has suggested that these three minerals are favorable for induced fracturing. This study utilizes the brittle- 100 0 ness index (BI) = (quartz + calcite + dolomite + pyrite)/(total 0255075 100 minerals) to characterize the frackability (Wang and Gale Carbonates Quartz+ 2009; Chen et al. 2011; Zou 2011; Qiu et al. 2016). The results Feldspar+Pyrite show that the average BI of the Es shale is 0.47 (0.07–0.72) (Table 4). In general, when BI is larger than 0.4, the shale Fig. 13 Ternary diagram of clay minerals, carbonates, and quartz + has good frackability, such as the Barnett and Woodford shale feldspar + pyrite of Es shale in Liutun Sag, DD. Compared with 3 U (Sondergeld et al. 2010). Thus, the Es shale is suitable for the mineral composition of Barnett shales (Loucks and Ruppel 2007), anthropogenic fracturing. Specifically, the average BI values the Es shale has higher enrichment of carbonates and clay miner- als and a relative lack ofquartz, feldspar, and pyrite. N indicates the of the shale in Wells PS18-1 and PS18-8 are 0.42 (0.07–0.72) number of samples and 0.48 (0.22–0.59), respectively, indicating that the shales in these two wells are similar in frackability. development in the Es shale, nearly 70 % of them are filled In summary, given the mineral compositions, little differ - by calcite and saline minerals, resulting in a decrease in per- ence exists in the frackability of the shales in Wells PS18-1 meability of the shale. However, these fractures are weak and PS18-8, which are both suitable for fracturing. However, surfaces that are easily reopened after anthropogenic fractur- due to the higher fracture density of the shale in Well PS18-1 ing, which is very common in Barnett Shale play (Montgom- compared to Well PS18-8, the former has greater potential ery et al. 2005). Therefore, given the natural fracture density, for anthropogenic fracturing. the Es shale has an excellent frackability. Considering that the fracture density of the shale in Well PS18-1 is higher 4.4 Oil mobility than Well PS18-8, we can infer that the shale in Well PS18-1 has a better frackability. Oil mobility is an important index in evaluating shale oil The XRD analysis shows that the E s shale is composed recovery, which is determined by oil properties, reservoir of detrital minerals (quartz and feldspar), clay minerals, seepage capacity, and formation pressure. carbonates, and saline minerals, with average contents of For low-porosity and low-permeability shale oil plays, 32 % (13–58 %), 28 % (8–52 %), 28 % (2–52 %), and 9 % low-density and low-viscosity oil is more likely to be pro- (0–62 %), respectively. In comparison with shale oil plays duced. This is probably the reason why shale oils produced in other lacustrine basins, the shale oil play in the DD has presently are primarily light oils (Nelson 2009; Zhang et al. lower quartz and clay mineral contents, similar carbonate 2012; Zou et al. 2013; Nie et al. 2016). Generally, the higher contents, but higher saline mineral contents. Unlike the shale the saturated hydrocarbons contents are and the lower the oil plays in the USA, the Es shale has a mineral composi- nonhydrocarbon and asphaltene contents are, the lower the tion that varies significantly and is abundant in carbonates, oil density and viscosity are, and therefore the higher the clay, and saline minerals (Fig. 13; Tables 3, 4) (Montgom- oil mobility is (Kuhn et al. 2012; Li et al. 2014). The oil ery and Morea 2001; Montgomery et al 2005; Jarvie et al. produced from Well PS18-1 in the DD has a high density 3 3 2007; Loucks and Ruppel 2007; Jarvie 2008, 2012; Han of 0.935 g/cm , a high viscosity of 43×10 mPa·s, and very U U et al. 2014). This is because the Es shale comprises a set of poor mobility because the Es shale has a shallow burial fine-grained sediments that developed in a small hypersaline depth and low thermal maturity, resulting in a high contents lacustrine basin with a strong reducing environment, which of nonhydrocarbons (23.06 %) and asphaltenes (26.68 %), provided large amounts of chemical deposits but received and a low contents of saturated hydrocarbons (36.79 %) and less terrestrial clastic material. aromatic hydrocarbons (13.47 %). Therefore, in terms of the 1 3 706 Petroleum Science (2021) 18:687–711 1 3 Table 4 Mineral compositions and brittleness index for Es shale samples in the Liutun Sag, DD Well Depth, m Clay, % Quartz, % Feldspar, % Calcite, % Dolomite, % Pyrite, % Halite, % Anhydrite, % Siderite, % Brittleness index ((Quartz + cal- cite + dolomite + pyrite)/(Total minerals)) PS18-1 3258.70 17 14 18 39 6 4 0 1 1 0.77 PS18-1 3260.35 30 25 10 25 5 0 0 5 0 0.65 PS18-1 3261.50 26 21 10 15 22 2 0 1 3 0.68 PS18-1 3262.30 26 17 12 19 11 3 0 11 1 0.59 PS18-1 3263.50 23 21 20 16 7 4 0 4 5 0.64 PS18-1 3266.08 30 18 11 22 12 2 0 1 4 0.63 PS18-1 3268.08 25 14 9 1 44 2 0 1 4 0.68 PS18-1 3268.38 28 8 10 0 16 0 0 39 0 0.335 PS18-1 3268.98 8 6 7 0 18 1 0 58 2 0.31 PS18-1 3269.78 36 23 12 0 18 4 0 2 5 0.53 PS18-1 3271.46 15 10 5 3 5 0 0 62 0 0.23 PS18-1 3271.78 33 24 13 13 5 5 0 2 5 0.55 PS18-1 3273.30 15 20 15 20 27 0 0 3 0 0.82 PS18-1 3275.30 38 13 14 30 5 0 0 0 0 0.617 PS18-1 3275.80 43 15 14 25 4 0 0 0 0 0.573 PS18-1 3277.50 52 20 17 9 3 0 0 0 0 0.479 PS18-1 3280.40 48 20 23 7 0 0 0 0 0 0.492 PS18-1 3280.40 15 20 10 47 5 0 0 3 0 0.82 PS18-1 3283.30 16 10 29 46 0 0 0 0 0 0.843 PS18-1 3284.40 15 25 10 0 45 0 0 5 0 0.8 PS18-1 3285.60 17 4 24 0 6 0 0 38 11 0.341 PS18-1 3285.80 34 8 43 0 6 0 0 0 8 0.568 PS18-1 3287.60 32 6 52 0 1 0 0 0 10 0.586 PS18-8 3155.22 36 28 10 16 4 4 2 0 0 0.58 PS18-8 3156.99 27 23 14 25 4 5 2 0 0 0.66 PS18-8 3162.32 26 21 8 22 12 5 3 0 0 0.63 PS18-8 3164.00 25 21 10 31 4 6 3 0 0 0.66 PS18-8 3167.37 29 12 10 0 10 2 2 35 0 0.32 PS18-8 3168.36 25 20 10 0 11 5 3 26 0 0.41 PS18-8 3168.95 23 17 16 23 13 8 3 0 0 0.69 PS18-8 3171.60 44 22 12 0 2 2 9 9 0 0.36 PS18-8 3185.84 25 24 14 23 5 4 3 0 0 0.66 PS18-8 3186.57 26 24 15 2 2 10 7 14 0 0.43 PS18-8 3187.32 31 25 8 21 7 4 4 0 0 0.61 PS18-8 3187.80 27 22 16 27 2 4 2 0 0 0.67 Petroleum Science (2021) 18:687–711 707 physical properties of the oil, the oil mobility of the Es shale oil play is poor. The seepage capacity of a shale is mainly related to the fracture density. Previous studies proposed that fractures can increase the shale permeability by 4-5 orders of magnitude (Zhang et al. 2012). As described in Section 4.2.1, the frac- tures in the Es shale are extremely well developed and the shale should have a strong seepage capacity. Specifically, compared with the shale in Well PS18-8, Well PS18-1 has a significantly higher fracture density, indicating that the seepage capacity of the shale in Well PS18-1 should be con- siderably better than Well PS18-8. Overpressure provides natural driving forces for shale oil production and can improve oil flow rates and shale fracturing efficiency significantly (Ronald et  al. 2007). Overpressure is commonly developed in the shale oil plays in the USA (Jarvie 2012). As shown in Fig. 12, the varia- tions in acoustic time differences and mud density logging data with respect to depth indicate that the overpressure conditions should be widely developed in the Es strata, which were also reported in other studies (Li and Zhao 2012; Luo et  al. 2016). However, except for the over- pressure, the high acoustic time differences and low mud density can also be caused by evaporites. Generally, the logging data of the evaporites are characterized by high acoustic time differences and low mud density. Further analyses of the rock lithology assemblage show that, for the Well PS18-1, no evaporites developed in the depth interval of 3250-3285 m, while the evaporites are well developed in the depth interval of 3155-3195 m at Well PS18-8 (Fig. 3). Therefore, in terms of the evaporites, the acoustic time differences of the shale interval of the Well PS18-1 should be lower than Well PS18-8 and the den- sity logging data of the shale interval of the Well PS18-1 should be greater than Well PS18-8. However, as shown in Fig. 12, the acoustic time difference of the Well PS18-1 (349 μs/m (252–434 μs/m)) is significantly greater than Well PS18-8 (277 μs/m (240–300 μs/m)), and the density logging data of the Well PS18-1 (2.44 g/cm (2.32–2.58 g/ 3 3 cm )) are lower than Well PS18-8 (2.54 g/cm (2.25–2.65 g/cm )), indicating that the variations in acoustic time differences and mud density logging data are associated with overpressure, not evaporites. The overpressure indi- cates that the Es shale oil plays have excellent shale oil recovery. In contrast, the variation degree of logging data in the Es strata of the Well PS18-1 is significantly greater than that of the Well PS18-8 (Fig.  12), indicat- ing a greater overpressure, which was further validated by the measured MDT formation pressure (the pressure coefficient of Well PS18-1 is 2.2, while the pressure coef- ficient of Well PS18-8 is 1.4). The overpressure differ - ences between the two wells are closely related to the differential development of evaporites: a. Difference in 1 3 Table 4 (continued) Well Depth, m Clay, % Quartz, % Feldspar, % Calcite, % Dolomite, % Pyrite, % Halite, % Anhydrite, % Siderite, % Brittleness index ((Quartz + cal- cite + dolomite + pyrite)/(Total minerals)) PS18-8 3188.50 29 23 7 10 23 3 5 0 0 0.63 PS18-8 3189.27 33 26 8 14 12 2 5 0 0 0.6 PS18-8 3189.80 28 20 10 5 32 3 2 0 0 0.67 PS18-8 3190.00 26 21 8 10 28 4 3 0 0 0.67 PS18-8 3190.55 31 18 12 20 9 5 5 0 0 0.59 PS18-8 3191.70 26 18 9 16 23 5 3 0 0 0.66 PS18-8 3191.75 37 22 13 18 3 3 4 0 0 0.56 PS18-8 3192.05 22 18 9 14 27 8 2 0 0 0.68 708 Petroleum Science (2021) 18:687–711 assemblage and thickness of the evaporites. As shown in shale system and then result in the decreasing oil and gas Fig. 3, the distribution of the evaporites is uniform and the enrichment (Rodriguez and Paul 2010; Liu et al. 2013). This thickness is thick at Well PS18-1, while the evaporites of should be closely related to extensive evaporites developed Well PS18-8 are thin and interbedded with shale, indicat- in the Dongpu Depression, which significantly increase the ing that the evaporites developed in Well PS18-1 should preservation conditions. This phenomenon can also be seen possess a greater sealing capacity; b. Difference in evapo- in the adjacent Dongying Depression. The fracture density rites location. As shown in Fig. 3, the evaporites of Well is determined by the distance to the faults in a basin, and PS18-1 developed at the top (<3250 m) and the bottom the closer to the faults is, the greater density the fractures is. (>3285 m) of the interval of interest (3250-3285 m), form- The formation pressure was determined by the assemblage ing the typical top and bottom seals for an overpressure and thickness of the evaporites. Furthermore, as indicated compartment, which are very conducive to preserving the in Fig.  12c and d, high abnormal overpressures are very overpressure. In contrast, the evaporites of Well PS18-8 common in strata deeper than the Es . Besides, the oil gen- developed in the middle (3167–3178 m) of the interval erated in deep shales with higher thermal maturity is more of interest (3155–3195 m). Besides, these evaporites are likely to have low density and low viscosity and better oil thin and interbedded with shale at well PS18-8, which are mobility. Therefore, the Es strata in deep depressions are unfavorable for preserving formation pressure. The above also favorable for future shale oil exploration. Similar to two factors jointly caused the formation pressure differ - the general tectonic and depositional settings of the DD, ence between the two wells. Therefore, the shale oil of large amounts of saline lacustrine rift basins were developed the Well PS18-1 should have higher natural driving forces across the world, in which faults and evaporites developed and a higher shale oil yield. Further comparison shows commonly. In future shale oil exploration, the regions and that the study area has a significantly higher formation strata adjacent to the faults and with thick evaporites should pressure compared to the shale oil plays in other lacus- be preferably selected as sweet spots. The results obtained in trine basins in China and the marine basins in the USA this study could be instrumental in future shale oil explora- (Table 3). Therefore, the shale oil play in the DD should tion not only in the DD but also in lacustrine basins across have excellent oil mobility. the world. In summary, despite the high density and high viscos- ity of the oil, the Es shale reservoir has a strong seepage capacity and overpressure, representing excellent conditions 5 Conclusions for shale oil mobility. Given the lower thermal maturity, high-density, high-viscosity oil, and high formation pres-The Es shale in the DD has a high content of organic mat- sure, the study area is similar to the Santanghu Basin, where ter dominated by oil-prone type I and type II kerogens within high shale oil production has been realized from the Luca- oil window, displaying a strong petroleum generation poten- ogou Formation (Table 3) (Nie et al. 2016). In comparison, tial. Despite the petroleum generation potential of the shale due to the superior seepage capacity of the shale reservoir at Well PS18-8 is relatively greater than that of the shale and the greater formation pressure, the oil mobility of the at Well PS18-1, the oil content of the latter well is slightly Well PS18-1 is superior to that of the Well PS18-8 well. Oil greater due to the slightly greater TOC. Various types of mobility is the most important condition determining the pores and fractures are extensively developed in the Es remarkable yield difference between these two wells. shale, with an average porosity of 14.9 %, which is favorable for shale oil enrichment. The porosity and fracture density 4.5 Implications for further shale oil exploration of the shale at Well PS18-1 are both greater than those of the shale at Well PS18-8, suggesting that the former is more By investigating the basic conditions of the shales at Wells favorable for shale oil enrichment. The Es shale has a high PS18-1 and PS18-8, the fracture density and overpressure brittle mineral content and extensive fractures, which are condition are the key factors controlling shale oil enrich- conducive to anthropogenic fracturing. The shale at Well ment in the DD. The extensively developed fractures can not PS18-1 has a better anthropogenic fracturing potential than only increase the reservoir volume of the shale, facilitating that at Well PS18-8 due to higher fracture density. The Es the shale oil accumulation, but also improve the seepage shale oil play has strong seepage capacity and overpressure, capacity of shale reservoirs significantly. Meanwhile, in the both of which are favorable for shale oil mobility. The Es setting of extensively fractures, the overpressure furtherly shale oil play at Well PS18-1 has a better seepage capacity promotes the natural driving forces for the shale oil in the and higher overpressure than that at Well PS18-8, indicating DD, increasing the shale oil mobility. This is contrary to that the shale at Well PS18-1 has a better oil mobility. the previous common perception, which indicated the devel- The key factors controlling shale oil enrichment of the oped fractures would promote the oil and gas loss in the Es shale oil play in the DD are the fracture density and 1 3 Petroleum Science (2021) 18:687–711 709 Curtis JB. Fractured shale-gas systems. AAPG Bull. 2002;86:921– overpressure, which were determined by the development 1938. https:// doi. org/ 10. 1306/ 61eed dbe- 173e- 11d7- 86450 00102 of the faults and the assemblage and thickness of the evapo- c1865d. rites, respectively. Therefore, in future shale oil exploration, Deng ED, Zhang JC, Zhang P, et al. 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Journal

Petroleum ScienceSpringer Journals

Published: May 20, 2021

Keywords: Petroleum generation potential; Reservoir volume; Frackability; Oil mobility; Shale oil enrichment; Dongpu Depression; Saline lacustrine rift basin

References