Occurrence Mechanism and Controlling Factors of Shale Oil from the Paleogene Kongdian Formation in Cangdong Sag, Bohai Bay Basin, East China
by
, ,
Binyu Ma
1,2,*, 
Qinhong Hu
3,4,*,
Xiugang Pu
5,
Shengyu Yang
3,
Xuyang Wang
3,
Wenzhong Han
5 and
Jiacheng Wen
3 1
Key Laboratory of Exploration Technologies for Oil and Gas Resources, Ministry of Education, Yangtze University, Wuhan 430100, China
2
School of Geosciences, Yangtze University, Wuhan 430100, China
3
National Key Laboratory of Deep Oil and Gas, China University of Petroleum (East China), Qingdao 266580, China
4
Laboratory for Marine Mineral Resource, Qingdao Marine Science and Technology Center, Qingdao 266237, China
5
Exploration and Development Research Institute, Dagang Oilfield Company, PetroChina, Tianjin 300280, China
*
Authors to whom correspondence should be addressed.
J. Mar. Sci. Eng. 2024, 12(9), 1557; https://doi.org/10.3390/jmse12091557
Submission received: 8 July 2024
/
Revised: 24 August 2024
/
Accepted: 27 August 2024
/
Published: 5 September 2024
(This article belongs to the Special Issue High-Efficient Exploration and Development of Oil & Gas from Ocean—2nd Edition)
Abstract
:Free oil, rather than adsorbed oil, is the main contributor to shale oil production with current development technologies, and assessing oil contents in different occurrence states (adsorbed oil vs. free oil) is a critical component in evaluating the economics of shale wells and plays. Although various methodologies have been developed, there are still some fundamental issues in assessing the oil contents in different occurrence states in shale. In this study, a new method was developed to estimate the adsorbed and free oil contents in the Second Member of the Eocene Kongdian Formation (Ek2) shales in Cangdong Sag, Bohai Bay Basin. This method combines the results of standard Rock-Eval pyrolysis and multi-step Rock-Eval pyrolysis with thin section petrography, X-ray diffraction for mineralogy, total organic carbon analyses, field emission scanning electron microscopy for pore morphology, and pore structure analyses by nitrogen physisorption and mercury intrusion porosimetry. Nine lithofacies were identified in a total of 50 shale samples, and the results show that the adsorbed and free oil are mainly contained in pores with diameters > 20 nm, and their contents are mainly controlled by organic matter abundance and thermal maturity of shales. While pore space volume influences the storage of shale oil, it is not a major determinant. Models of shale oil occurrence and its evolution are proposed, suggesting that the high S1 contents of organic-rich and -fair shales, which the latter resulted from oil migration, are the most favorable exploration targets of Ek2 shales. The findings of this study will help prioritize shale oil exploration targets in Ek2 shales.
1. Introduction
Although large reserves of oil have been discovered in lacustrine shales in China, economic exploration and development of shale oil are still at an early stage due to the complex properties of lacustrine shales (e.g., high heterogeneity, low thermal maturity) and the poor mobility of shale oil [1,2,3,4,5,6]. In recent years, understanding the accumulation mechanism of shale oil and its controlling factors has attracted considerable attention since they are essential for identifying the “sweet spots” for the occurrence of potentially productive shale oil reservoirs [7,8,9,10]. In addition, the occurrence characteristic of shale oil is a critical factor influencing its sustainable development [11,12]. Generally, shale oil occurs primarily as free oil and adsorbed oil, with free oil being the primary contributor to oil production using current technology [13,14,15]. Consequently, the quantification of free oil content plays a crucial role in the evaluation of shale oil resources and production potential.
The current techniques to quantify the contents of free and adsorbed oil primarily involve the multi-step solvent extraction method, swelling method, and multi-step Rock-Eval pyrolysis method [15,16,17]. For example, using a multi-step solvent extraction method, Zhang et al. (2019) investigated the free and adsorbed oil contents of shales in the Shahejie Formation in Dongying Depression [17]. In their study, core chips (8–10 mm in size) were extracted with a mixed organic solvent (chloromethane: methanol = 9:1 by volume) for 48 h to obtain the extracts as free oil. The extracted core chips were crushed to 2–5 mm in size for another extraction under the same conditions to obtain the adsorbed oil [17]. This method is not only complicated in operation but is also influenced by various factors affecting the amount of extracts, such as the types and ratios of organic solvents, as well as the extraction time [18]. On the other hand, the swelling method has been utilized mainly to study the oil adsorbed by kerogen [19,20,21]. In recent years, some researchers have used the swelling method to study the adsorption of oil on minerals and have found that the adsorbed oil content of clay minerals is higher than that of siliceous and calcareous minerals [16,22,23]. However, it is likely that the adsorbed capacities of minerals extracted from shales or pure minerals do not represent the actual contents of oil adsorbed of minerals in the bulk shale since oil is not adsorbed on all pore surfaces due to variable pore connectivity, wettability, and oil saturation, as shown by scanning electron microscopy (SEM) observations [9,10,24,25]. Consequently, the adsorbed oil obtained using the swelling method is obviously overestimated, occasionally resulting in higher adsorbed oil content than the total oil content [16].
The multi-step Rock-Eval pyrolysis method has been widely used to analyze shale oil contents in adsorbed versus free oil state since free and adsorbed oils volatilize at different temperatures and can be detected and quantified instrumentally [11]. Free oil mainly includes small-sized hydrocarbon molecules, which are released at low temperatures, while adsorbed oil mainly consists of macromolecular hydrocarbons (HC) that are typically released at high temperatures [14]. Consequently, a multi-step Rock-Eval pyrolysis can quantitatively evaluate the contents of free and adsorbed oil using the appropriate temperature ranges. For example, Romero-Sarmiento (2019) proposed a scheme where volatiles at pyrolysis temperatures of <200 °C, 200–350 °C, and 350–650 °C correspond to free, adsorbed, and cracked oil, respectively [15]. In contrast, Li et al. (2020) defined the volatiles released at heating temperatures of <350 °C, 350–450 °C, and >450 °C as free, adsorbed, and cracked oil, respectively [26]. However, it has been confirmed that alkenes crack from kerogen at temperatures above 350 °C, while some residual oils remain in shales at temperatures above 350 °C and even above 450 °C [7,13]. As a result, effectively distinguishing the temperature ranges of free and adsorbed oils by only using the multi-step Rock-Eval pyrolysis method presents challenges.
In this study, a novel method is proposed to quantify the contents of free and adsorbed oils that combines standard Rock-Eval pyrolysis with multi-step Rock-Eval pyrolysis to quantify the contents of free and adsorbed oils in shales. This method not only offers ease of operation but also addresses the inaccuracies associated with solely using multi-step Rock-Eval pyrolysis. Shales from the Second Member of the Kongdian Formation (Ek2) shales in Cangdong Sag, Bohai Bay Basin, were studied to determine the contents of total oil, free oil, and adsorbed oil. In addition, the samples were analyzed to determine the factors controlling their free versus adsorbed oil contents, including TOC contents, thermal maturity, and mineralogy and lithofacies. Models of oil occurrence in Ek2 shales are proposed that can help prioritize favorable shale oil exploration targets in lacustrine-sourced Ek2.
2. Samples and Methods
2.1. Samples
In this study, a total of 50 samples of Ek2 shales were selected from three wells (G108-8, GD12, and GD14) from depths of 2900–4200 m. The locations of the wells are shown in Figure 1, and detailed information about each sample is listed in Table 1. Each sample was prepared in three different forms for the following analyses: (1) cubes (~1 cm × 1 cm × 1 cm) for thin sections and field emission scanning electron microscopy (FE-SEM); (2) grains with a size of 500–841 μm (#20–35 mesh) for low-temperature nitrogen adsorption (LNA) and mercury intrusion porosimetry (MIP) analyses; and (3) powders with a particle size <75 μm (<#200 mesh) for X-ray diffraction (XRD), total organic carbon (TOC), and standard and multi-step Rock-Eval pyrolysis analyses.
2.2. Mineralogical and Geochemical Analyses
An X’Pert Pro X-ray diffractometer from Panalytical Company (Almelo, Holland) was utilized to determine the mineral compositions of shales at a working voltage of 40 kV and a current of 40 mA. The powdered samples were scanned from 3° to 65° with a step of 0.02°, and the mineralogical compositions were semi-quantified by using the K-value method following the Chinese Oil and Gas Industry Standard (SY/T 5163-2010). Thin sections of the Ek2 lacustrine shales were studied using an optical microscope to analyze the laminar structures. The TOC content of the shale was measured using a LECO CS230 instrument (LECO, St. Joseph Charter Township, MI, USA) after undergoing decarbonation treatment, as described in previous studies [28].
Standard Rock-Eval pyrolysis analyses were performed using the Rock-Eval 7 Analyzer manufactured by Vinci Technologies (Nanterre, France). The powdered samples were initially heated at 300 °C for 3 min and then heated to 650 °C with a heating rate of 25 °C/min. Free hydrocarbon content (S1), thermal cracking hydrocarbon content (S2), and pyrolysis peak temperature for S2 (Tmax) were obtained [29]. Then, a second series of pyrolysis analyses using the same procedures and equipment were performed on the samples after they had been extracted using a mixture of dichloromethane and methanol (volumetric ratio of 93:7) for seven days to remove residual oil [30].
The multi-step Rock-Eval pyrolysis experiments were also carried out using the Rock-Eval 7 Analyzer. Using the pyrolysis procedures outlined by Romero-Sarmiento (2019) [15], powdered shales (~100 mg) were initially heated at 200 °C for 5 min to obtain Sh0, then heated to 350 °C with a heating rate of 25 °C/min and held for 5 min to obtain Sh1, and followed by heating to 650 °C at a rate of 25 °C/min to obtain Sh2.
2.3. Field Emission Scanning Electron Microscopy Imaging
A FEI Quanta FEG 650 scanning electron microscope (FEI, Lexington, KY, USA) equipped with an energy-dispersive spectrometer was used to analyze the pore morphology of shales. A surface of a cubic sample oriented perpendicular to the laminae was polished using a GATAN Ilion Ⅱ 697 Argon Beam Milling System (GATAN, San Diego, CA, USA) and then coated with a 10-nm-thick carbon film to enhance the electrical conductivity and SEM image resolution.
2.4. Low-Temperature Nitrogen Adsorption Analyses
The LNA analyses were performed using a Micromeritics ASAP 2460 instrument (Micromeritics, Norcross, GA, USA) to analyze the pore structure of shales. Granular shale samples were first extracted with a mixed organic solvent (dichloromethane and methanol at a volumetric ratio of 93:7) for seven days and then oven-dried at 110 °C for 24 h to eliminate the residual oil and moisture. The dried and organic solvent-extracted shales were degassed at 110 °C for 24 h and then adsorbed with nitrogen incrementally at 77.3 K. The relative pressure P/P0 (the ratio of absolute pressure to saturation pressure) ranged from 0.002 to 0.998. The specific surface area, pore volume, and pore size distribution were determined using the BET (Brunauer-Emmette-Teller) and BJH (Barrette-Joynere-Halenda) methods, respectively [31,32]. To investigate the distribution of residual oil in shales, a second series of LNA analyses were carried out by using as-received (non-extracted) shales, following the same procedures outlined above.
2.5. Mercury Intrusion Porosimetry Analyses
Similar to LNA analyses, two sets of granular shale samples were analyzed: a set of organic solvent-extracted shales for pore structure evaluation and a set of as-received shales for residual oil distribution. The samples were prepared for MIP analyses using a Micromeritics AutoPore Ⅳ 9520 instrument (Micromeritics, USA) at an incremental intrusion pressure of mercury from 0.2 psi (0.001 MPa) to 60,000 psi (414 MPa). To eliminate the conformance effect caused by voids between shale grains, which artificially increases the total pore volume, the effective pressure range of MIP tests for data analyses was set at 20–60,000 psi (0.138–414 MPa), corresponding to a pore-throat size range of 2.8 nm–12 μm, based on the Washburn Equation and the nanopore confinement correction [33,34], as described in previous studies [35].
3. Results
3.1. Petrological and Geochemical Properties
The mineral composition of Ek2 shales is dominated by quartz, feldspar, calcite, dolomite, analcime, and clays, as well as minor minerals such as pyrite and siderite (Table 1). The quartz content ranges from 6.0 to 20.0%, with an average of 13.8%, while the feldspar content ranges from 5.0 to 68.0%, with an average of 23.5%. The average contents of calcite and dolomite are 8.9 and 23.7%, respectively. The content of clay minerals ranges from 4.0 to 36.0%, with an average of 17.9%, while analcime content ranges from 0 to 41.0%, with an average of 11.3%. The average content of other minerals is only 1.3%. According to the relative contents of siliceous minerals (quartz and feldspar), carbonates (calcite, dolomite, and siderite), and clay minerals, the Ek2 shales can be categorized into siliceous shale, mixed shale, and calcareous shale (Figure 2) [36]. The lithology is mainly composed of mixed and calcareous shales in Well G108-8, siliceous and mixed shales for Well GD12, and mainly siliceous and calcareous shales in Well GD14.
The TOC contents of Ek2 shales range from 0.39 to 6.74%, with a mean value of 2.90% (Table 1). The shales are categorized into organic-rich shale (TOC > 2%) and organic-fair shale (TOC < 2%) [37]. The S1 and S2 values of as-received shales vary from 0.11–6.71 to 0.48–49.71 mg HC/g rock, with averages of 1.92 and 16.78 mg HC/g rock, respectively, indicating good source rock potential (Table 2). The free hydrocarbon content (S1E) and thermal cracking hydrocarbon content (S2E) of the organic solvent-extracted shales have decreased to 0.02–0.33 and 0.05–40.22 mg HC/g rock, respectively (Table 2).
In Figure 3, thin section petrography images of the shales show a range of lamina types, including siliceous lamina (SIL), calcareous lamina (CAL), clay lamina (CLL), organic matter lamina (OML), analcime lamina (ANL), and mixed organic matter-clay lamina (OM-CLL) (Figure 3a–f). The Ek2 shales are mainly classified as laminated shales and massive shales depending on the extent of the development of laminae (Figure 3).
Considering the mineral compositions, TOC contents, and the development of laminae of shales, nine lithofacies are identified, including organic-rich laminated siliceous shale (ORLS), organic-rich laminated mixed shale (ORLM), organic-rich massive calcareous shale (ORMC), organic-rich laminated calcareous shale (ORLC), organic-fair laminated siliceous shale (OFLS), organic-fair massive mixed shale (OFMM), organic-fair laminated mixed shale (OFLM), organic-fair massive calcareous shale (OFMC), and organic-fair laminated calcareous shale (OFLC), among which ORLS, ORLM and ORMM are the main lithofacies (Table 1). In the organic-rich shales, the ORLM and ORLC shales have higher TOC contents but lower S1 contents compared to ORLS and ORMC shales (Figure 4). This is possibly influenced by the variation in thermal maturities (expressed as the vitrinite reflectance Ro) of the shale core samples at different depths. Zhao et al. (2020) found that the Ro values of shales from the shallow Well G108-8 ranged from 0.66 to 0.91%, with an average of 0.76%, while shales from the deep Wells GD12 and GD14 have similar Ro values, ranging from 0.80 to 1.21%, with a mean value of 1.02% [27].
3.2. Pore Properties
3.2.1. Qualitative Description of Pore Morphology from FE-SEM Imaging
According to the classification scheme proposed by Loucks et al. (2012), the matrix-related pores in shales can be categorized into interparticle, intraparticle, and OM-hosted pores [38]. All of these pore types have been observed in this study. Examples of interparticle pores are shown in Figure 5a–c: these pores mainly occur between quartz, feldspar, and dolomite grains, and typically have angular or rounded shapes. They are usually coated with an OM film (bitumen) varying from tens to hundreds of nm in thickness. This film is thought to have been formed by migration of mobile bitumen, suggesting good connectivity of pre-existing pores [39,40]. Additionally, there are some primary and secondary interparticle pores without OM films in Ek2 shales, mainly developed between brittle minerals or between brittle minerals and clay minerals, with sizes ranging up to a dozen microns (Figure 5d–f). The secondary interparticle pores are mainly developed at the edges of feldspar, probably resulting from the dissolution of minerals by organic acids released during kerogen maturation (Figure 5e,f) [41].
Intraparticle pores include both dissolved intraparticle and intercrystalline pores. The former mainly develops in calcite and dolomite, have rounded shapes and range from tens of nm to several microns in size (Figure 5g,h). Intercrystalline pores occur mainly between clay aggregates and occasionally in dolomite framboids. They have angular or rounded shapes and also range from tens of nm to several microns in size (Figure 5i–l). The OM films also occur in intraparticle pores, suggesting good connectivity of these pores.
Examples of OM-hosted pores are shown in Figure 5l–o, and can be classified as inherited OM pores and hydrocarbon-generating OM pores. The inherited OM pores are densely distributed with rounded shapes and range in size from hundreds of nm to tens of microns (Figure 5m,n). Their genesis is probably related to the OM types rather than thermal maturity [40]. The hydrocarbon-generating OM pores are developed mainly within OM and between OM and minerals, exhibiting rounded and crescent shapes with sizes up to several microns (Figure 5l,o).
In addition, microfractures are widely observed in Ek2 shales, mainly at the edges of OM and minerals (clay and calcite), and can be tens of microns in length, which are speculated to be related to hydrocarbon generation and mineral transformations, respectively (Figure 5a,i,p). Some microfractures occur within or cut through mineral particles, possibly resulting from overpressure induced by compaction and/or hydrocarbon generation (Figure 5q). Shale oil can be observed in microfractures, indicating the enhancement of shale oil mobility by microfracturing (Figure 5r).
3.2.2. Quantitative Analyses of Pore Structure from LNA Analyses
Typical N2 adsorption/desorption curves of organic solvent-extracted shale samples and their corresponding pore size distributions, ranging from ~2 to 200 nm in diameters, are shown in Figure 6. The pore size distribution curves gradually change from unimodal to bimodal patterns with increasing maximum adsorption volumes (Figure 6). Zou et al. (2015) found that the oil seepage through shale pores exhibited lower and upper thresholds at 20 nm and 200 nm, respectively [42]. It was observed that oil did not penetrate pores with diameters smaller than 20 nm, while pores with diameters exceeding 200 nm were easily permeable to oil regardless of the chemical or physical conditions. So that pores in shales can be classified into three types: non-seepage-pores (<20 nm in diameter), potential seepage-pores (20–200 nm in diameter) and seepage-pores (>200 nm in diameter). The LNA mainly analyzes the characteristics of non-seepage-pores and potential seepage-pores.
The specific surface areas and pore volumes for the organic solvent-extracted shale samples are shown in Table 3. The specific surface area ranges from 0.85 to 19.63 m2/g, with an average of 6.58 m2/g. The pore volume ranges from 3.41 to 35.77 mm3/g, with an average of 14.34 mm3/g. In general, the specific surface areas and pore volumes of organic-rich shales are lower than those of organic-fair shales (Figure 7a), possibly due to pore filling by bitumen. Among the organic-rich shales, the ORMC lithofacies exhibit the highest specific surface area, pore volume, non-seepage-pore and potential seepage-pore volume. Other organic-rich shales and organic-fair shales have similar potential seepage-pore volumes but differ significantly in non-seepage-pore volumes. This difference is probably the cause of the high specific surface areas and pore volumes of organic-fair shales (Figure 7b).
3.2.3. Quantitative Analyses of Pore Structure from MIP Analyses
Table 4 shows the porosity and total pore volume of organic solvent-extracted shales obtained from MIP analyses. The porosity and total pore volume of Ek2 shales range from 1.80–12.95% and 7.16–43.87 mm3/g, with averages of 5.18% and 22.49 mm3/g, respectively. The volumes of non-seepage-pores, potential seepage-pores and seepage-pores are 8.56, 4.57, and 9.36 mm3/g, with relative proportions of 38%, 20%, and 42%, respectively, indicating that a significant proportion of pore space is contained in the non-seepage-pores. The volume of non-seepage-pores is higher than potential seepage-pores, which is different from the results from LNA analyses. This discrepancy is probably due to the different measurement methodologies, since the measured pore volume using MIP represents the volume of throats and their controlling pore bodies, while the latter are measured by LNA [33,43,44].
The pore structures of organic solvent-extracted shales of different lithofacies are shown in Figure 8. The porosities and total pore volumes of the extracted organic-rich shales are higher than those of organic-fair shales, and the organic-rich shales also have higher volumes of potential seepage-pores and seepage-pores volumes compared with organic-fair shales. This indicates that the promotion of OM to larger pores, which is consistent with the findings from FE-SEM observations (Figure 5i–o). In the organic-rich shales, the ORLS and ORLM lithofacies have the higher volumes of potential seepage-pores and seepage-pores, followed by ORLC lithofacies, showing a higher potential for shale oil storage (Figure 8b).
3.3. Estimation of Total Oil Content
According to the method proposed by Jarvie (2012) [45], the residual oil content of shale can be determined by Equation (1):
where S1 and S2 are the free and thermal cracking hydrocarbon contents of as-received shale samples, while S1E and S2E are the free and thermal cracking hydrocarbon contents of organic solvent-extracted shales. The S1E of organic solvent-extracted shales is possibly the residual oil in isolated pores that are inaccessible by organic solvent [46]. Thus, the residual oil content can be calculated by Equation (2):
According to Equation (2), the oil content contains the light-medium oil (S1) and heavy oil (S2 − S2E), but still does not account for the light hydrocarbons lost due to volatilization during storage, so that the contents of total oil and movable oil are clearly underestimated [47]. Zhao et al. (2021) compared the S1 contents of Ek2 shales that had been frozen by liquid nitrogen and those exposed to air for several days and determined the correction factor for light hydrocarbon loss is a value of 2.1 [48]. Although it is strictly inappropriate to apply the same correction factor to all shales, the lack of sealed core data is evident. The estimated total oil content can be obtained using Equation (3):
The total oil contents of Ek2 shales range from 0.91 to 21.25 mg HC/g rock, with an average of 8.62 mg HC/g rock, while the contents of heavy oil range from 0.40 to 12.56 mg HC/g rock (Table 2), with a mean value of 4.59 mg HC/g rock, accounting for 53.2% of the total oil content, which is unfavorable for shale oil mobility. The total oil contents of shales from different lithofacies are shown in Figure 9, in which the total oil contents of organic-rich shales are generally higher than those of organic-fair shales, and the ORLS and ORLM shales have slightly higher total oil contents compared with ORMC and ORLC shales. In addition, there are some organic-fair shales, such as samples GD14 4095 (OFLM), GD14 4115 (OFLC), and GD14 4117 (OFMC) that have higher total oil contents than some organic-rich shales (Table 2); probably due to the migration of fluids from adjacent organic-rich intervals [49,50,51].
3.4. Estimation of Oil Contents in Different Occurrence States
As described above, the contents of shale oil in different occurrence states cannot be accurately determined solely by multi-step Rock-Eval pyrolysis analyses. In this study, by combining the standard Rock-Eval pyrolysis results of both as-received and organic solvent-extracted shales with the data for multi-step Rock-Eval pyrolysis of as-received shales, the shale oil contents in different occurrence states can be obtained. As illustrated in Figure 10, Sh0 means light hydrocarbons in 0–200 °C; Sh1-1 means light-medium hydrocarbons in 200–300 °C and is the difference between S1 and Sh0 of as-received shale; Sh1-2 are medium hydrocarbons in the 300–350 °C range and are determined by the difference between Sh1 and Sh1-1 of shale; Sh2-1 means heavy hydrocarbons, determined by the difference between Sh2 of as-received shale and S2E of organic solvent-extracted shale; Sh2-2 means hydrocarbons generated by the cracking of kerogen, equivalent to S2E of shales. Consequently, free oil contains Sh0, Sh1-1, and Sh1-2, while the adsorbed oil is related to Sh2-1. Since the sum of Sh0, Sh1-1, and Sh1-2 is the residual free oil content, the total free oil content can be determined by the difference between total oil content and adsorbed oil content.
Table 5 shows the contents of adsorbed and free oil, which range from 0.06–11.90 mg HC/g rock and 0.23–15.79 mg HC/g rock, with averages of 4.04 and 4.59 mg HC/g rock, showing a higher proportion of free oil (53.2%) than adsorbed oil (46.8%). Figure 11a presents the adsorbed oil contents of shales of different lithofacies. The ORLS and ORMC shales contain similar adsorbed oil contents that are slightly higher than organic-fair shales but are clearly lower than ORLM and ORLC shales. The free oil contents of shales of different lithofacies are shown in Figure 11b, in which some organic-fair shales (GD14 4095 of OFLM, GD14 4115 of OFLC, GD14 4117 of OFMC) contain higher free oil contents that are higher than some organic-rich shales (Table 5), indicating that the migrated oil increases the content of free oil but not adsorbed oil. The ORLS shales have the highest amount of free oil content, followed by ORMC and ORLM shales, and so have a higher potential for shale oil exploitation (Figure 11b).
4. Discussion
4.1. Occurrence Space of Shale Oil at Ek2
4.1.1. Occurrence Space of Shale Oil Based on LNA Analyses
In previous studies, the shale oil (actually residual oil) distribution was usually determined by the difference in pore size distributions between as-received and organic solvent-extracted shales [10,52]. In this study, the pore volume of as-received shales obtained from LNA analyses and the increase volumes of pores with different types after extraction are shown in Table 3. The increase in pore volume of organic-rich shales (mean value of 5.97 mm3/g) is higher than that of organic-fair shales (a mean value of 2.38 mm3/g), and their ratios to pore volume (diameters < 200 nm) of organic solvent-extracted shales are 53.6% and 11.8%, indicating that more than half of the volume with diameters <200 nm of organic-rich shales is filled with residual oil. The proportions of pore volumes filled by residual oil of ORLS, ORLM, ORMC, and ORLC shales are 58.7%, 55.9%, 44.5%, and 37.4%, respectively. The relative proportions of residual oil in non-seepage-pore and potential seepage-pore are 28.8% and 71.2% (ORLS), 51.0% and 49.0% (ORLM), 49.4% and 50.6% (ORMC), 48.4% and 51.6% (ORLC), in which the ORLS shale shows different residual oil distribution from other organic-rich shales. In addition, there is only a slightly positive relationship between the increase in pore volume and residual oil content of organic-rich shales (Figure 12a), suggesting that amounts of oil being stored in pores with diameters >200 nm.
4.1.2. Occurrence Space of Shale Oil Based on MIP Analyses
The pore-throat size range obtained from MIP analyses is 2.8 nm–12 μm in diameter, which includes almost all the storage space of residual oil. A positive relationship between the increase in pore volume and residual oil content is shown in Figure 12b, indicating the effectiveness of MIP analyses of residual oil distribution. The increases in pore volume are shown in Table 4. The pore volume increases in the organic-rich shale (mean value of 9.86 mm3/g) are obviously higher than that of organic-fair shale (mean value of 3.29 mm3/g), and their ratios to total pore volume of organic solvent-extracted shales are 39.8% and 18.2%, indicating that ~40% of the pore volume is filled by the residual oil in organic-rich shales. The proportions of pore volumes filled by residual oil of ORLS, ORLM, ORMC, and ORLC shales are 35.9%, 47.0%, 35.1%, and 34.6%, respectively, and the relative proportions of residual oil in the three different types of pores are shown in Figure 13. The sums of relative proportions of residual oil in potential seepage-pore and seepage-pore are 80% (ORLS), 70% (ORLM), 35% (ORMC), and 56% (ORLC). This indicates that the laminated ORLS, ORLM, and ORLC shales have higher potential for oil exploitation than the massive ORMC shales.
4.2. Factors Controlling the Total Oil Content
4.2.1. Effects of OM Abundance on Total Oil Content
OM is the source of hydrocarbons and the concentration of OM is a key determinant of the hydrocarbon-generating potential of source rock [53]. In this study, the total oil contents of organic-rich and organic-fair shales (except for three shales in which oil migration has occurred) are 11.2 and 2.60 mg HC/g rock (Table 2), showing a significant difference between the two. The TOC and S1 contents both show good relationships with total oil content, indicating that they are effective parameters for total oil evaluation, especially the S1 (Figure 14a,b).
4.2.2. Effect of Thermal Maturity on Total Oil Content
Previous studies found that Eocene samples from Well G108-8 have lower thermal maturities (Ro values of 0.66 to 0.91%) compared with those from Wells GD12 and GD14 (Ro values 0.80 to 1.21%) [27]. To eliminate the influence of TOC on oil content, TOC normalization is first carried out for total oil content. The TOC-normalized total oil content of organic-rich shales from Well G108-8 ranges from 1.92 to 3.79 mg/g rock with a mean value of 2.70 mg/g rock, which is lower than that of Wells GD12 and GD14, in which the range is 1.93 to 6.33 mg/g rock (mean of 3.63 mg/g rock), indicating shales with higher thermal maturity have higher oil content. In addition, the proportion of heavy oil to total oil of organic-rich shales from Well G108-8 (67.6%) is obviously higher than that of Wells GD12 and GD14 (33.7%), which suggests that the differences in the proportion of heavy oil to light oil are related to differences in thermal maturities between shales from these wells.
4.2.3. Effect of Pore Space on Total Oil Content
A shale oil reservoir is a self-generating and self-storing petroleum system, and generally, the larger the pore volume of shales is, the more oil that can be stored [54]. This is the reason for a positive relationship shown in Figure 14c. However, non-hydrocarbon fluids also occur in pores of shale, such as the formation water [55], and Zhao et al. (2019) found that the average oil saturation of Ek2 shales from Well G108-8 is ~40% [56]. The presence of non-hydrocarbon fluids results in only a slight positive correlation between pore volume and total oil content (Figure 14c).
4.2.4. Effect of Mineral Compositions on Total Oil Content
Statistically, the mean TOC-normalized total oil contents of organic-rich siliceous, organic-rich calcareous, and organic-rich mixed shales are 3.44, 2.91, and 2.81 mg HC/g rock, respectively. This suggests that siliceous minerals are more favorable for the reservoiring of shale oil, possibly due to the pore space being better-preserved in siliceous minerals and shale oil migration from adjacent OM-clays mixed lamina. This concept is supported by the optical microscopy and SEM observations in the literature [48,57].
4.3. Factors Controlling the Adsorbed and Free Oil
4.3.1. Effects of OM Abundance on Adsorbed and Free Oil
Compared with inorganic minerals, OM has stronger adsorbed capacity for shale oil [16]. Figure 15a,c show the relationships between TOC, S1, and S2 and adsorbed oil content, in which positive relationships are observed between TOC, S2 and adsorbed oil content, especially for shales from Well G108-8, indicating the control of TOC on adsorbed oil, and S2 can be used to estimate the amount of adsorbed oil, especially for shales with lower maturity. There is a clearly positive relationship between S1 and free oil content, and there are slight positive relationships between TOC, S2 and free oil content, which suggests that the controlling of TOC on free oil and S1 can be used to estimate the amount of free oil (Figure 15d–f). As the material source of hydrocarbons, the relationships between TOC and adsorbed oil and free oil are predictable, which has also been reported in the literature [58].
4.3.2. Effect of Thermal Maturity on Adsorbed and Free Oil
In Figure 15a,d, the shales from Well G108-8 have higher adsorbed oil contents and lower free oil contents, compared with those of Wells GD12 and GD14 shales with similar TOC contents, probably resulting from the thermal maturities difference between shales from Wells G108-8, GD12, and GD14. Generally, higher thermal maturity means more light and medium oil, as well as more free oil, enhancing the overall mobility of shale oil.
4.3.3. Effects of Mineral Compositions on Adsorbed and Free Oil
Figure 16 shows the relationships between the siliceous, calcareous, and clay minerals contents and the TOC-normalized adsorbed and free oil contents. As can be seen in Figure 16, slightly negative and positive relationships are observed between TOC-normalized adsorbed oil content and free oil content and siliceous minerals, respectively, and there are no relationships with calcareous and clay minerals. The pore space preserved by brittle siliceous minerals and shale oil migrated from adjacent OM-clays mixed lamina, and the lower adsorption capacity of siliceous minerals [16], results in a slightly negative relationship with adsorbed oil (Figure 16a) and positive relationship with free oil (Figure 16b). Although there are abundant pores within and between/in calcareous mineral particles, the organic-rich calcareous shales have lower total oil contents compared with organic-rich siliceous and mixed shales (Figure 9), which is possibly the main reason for the lack of relationships between calcareous minerals content and adsorbed and free oil contents.
4.3.4. Effects of Pore Structure on Adsorbed and Free Oil
It has been generally believed that adsorbed oil occurs on the pore surface, while free oil mainly occurs in the center of pores. Consequently, the volumes of adsorbed and free oil may be related to the pore surface area and pore volume, respectively [9]. However, there is no relationship between adsorbed oil and pore surface area, while a positive relationship is shown between adsorbed oil content and the seepage-pores volume (Figure 17). In addition, there are positive relationships between porosity, potential seepage-pores, seepage-pores volume, and free oil content (Figure 18), suggesting that porosity and abundance of larger pores significantly influence the volume of free oil. This suggests that both the adsorbed and free oil are mainly stored in larger pores (potential seepage-pores and seepage-pores), which is also implied by the occurrence of ~70% residual oil stored in potential seepage-pores and seepage-pores of the organic-rich shales (Figure 13). Liang et al. (2018) proposed that the shale oil preferentially migrates along microfractures and large pores with good connectivity and low resistance, and as a result, the adsorbed and free oil are mainly in large pores [41].
4.4. Models for Shale Oil Occurrence
Generally, the total oil content of Ek2 shales is primarily controlled by TOC contents and thermal maturity, in which variation of the TOC content is the principal factor causing significant differences in total oil content between organic-rich and organic-fair shales. The variations in TOC are combined with differences in thermal maturity to influence total oil volumes. For example, the ORLS shales have lower TOC contents but similar total oil contents compared to the ORLM shales (Figure 4 and Figure 9), which is due to the influence of thermal maturity. The ORLS shales, which predominantly occur in Wells GD12 and GD14, exhibit a higher thermal maturity, while the ORLM shales, mainly found in Well G108-8, show a lower thermal maturity (Table 1). Pore space influences the storage of shale oil, but the variation in oil saturation in shales diminishes the influence of pore space on total oil content. Additionally, the migration of oil causes some organic-fair shales, such as GD14 4095 (OFLM), GD14 4115 (OFLC), and GD14 4117 (OFMC), to have high total oil contents.
The adsorbed oil contents of Ek2 shales are mainly controlled by thermal maturity and TOC contents. Thermal maturity directly controls generated oil components and determines the adsorbed and free oil contents. In addition, OM not only generates oil during the thermal evolution but also has high adsorption capacity for oil. Consequently, low thermal maturity and high TOC contents are the main reasons for high adsorbed oil contents of ORLM and ORLC shales (Figure 4). The free oil contents are also mainly controlled by TOC contents and thermal maturity, which are the main reasons for high free oil content of organic-rich shales, especially the ORLS and ORMC shales. Similar to the factors controlling the total oil content, pore space is a necessary condition for free oil storage but has a smaller influence due to the variation of oil saturation. The organic-fair shales with oil migration (GD14 4095 in OFLM, GD14 4115 in OFLC, GD14 4117 in OFMC) contain high values of free oil contents, some of which are higher than some organic-rich shales (Table 5), indicating that the immigrated oil increases the contents of free oil, not adsorbed oil.
Based on the results and analyses of this study as well as previously published studies of Ek2 shales [24,56,57,58], models of shale oil with different occurrence states in organic-rich laminated shale and organic-fair massive shale are proposed (Figure 19). In shales with a low maturity (such as shales in shallow Well G108-8), the generated oil from OM was first stored in OM pores and then migrated to adjacent large mineral pores, showing a higher proportion of adsorbed oil (heavy hydrocarbons) than of free oil (Figure 19a). With the increase of thermal maturity (such as shales in deep Wells GD12 and GD14), a higher proportion of lighter petroleum and a lower proportion of heavy hydrocarbons were generated, promoting the migration of oil to large pores in mineral laminae and organic-fair shales (Figure 19b). This suggests that the organic-rich shales, especially the ORLS, ORMC, and ORLM shales, and organic-fair shales in which oil migration has occurred are the most favorable exploration targets in the Ek2 shales.
5. Conclusions
In this study, the total oil contents of Ek2 shales of different lithofacies were determined, and the factors controlling the total oil content were found to include OM abundance (TOC contents), thermal maturity, pore space, and mineral compositions. OM abundance and thermal maturity are the primary factors controlling the total shale oil content. Organic-rich shales and organic-fair shales with oil migration show high total oil contents. In organic-rich shales, ~40% of the pore volume is filled with residual oil, and ~70% of this residual oil is stored in pores with diameters >20 nm.
The adsorbed oil contents of Ek2 shales are mainly controlled by thermal maturity and TOC contents: lower thermal maturity and higher TOC content resulted in high adsorbed oil contents. The free oil contents are mainly controlled by TOC and thermal maturity: higher TOC contents and thermal maturity resulted in high free oil content. In addition, S1 can be used to estimate the free oil contents in Ek2 shales.
Oil migration within shale reservoirs can lead to readjustments in both the contents and occurrence states of shale oil. With increasing thermal maturity, a higher proportion of lighter oil and a lower proportion of heavy hydrocarbons were generated, which enhanced the migration of oil to larger pores in mineral laminae and organic-fair shales. The organic-rich shales, especially the ORLS, ORMC, and ORLM shales, and organic-fair shales with oil migration have high free oil contents and are the most favorable exploration targets of Ek2 shales. In addition, in other lacustrine shale reservoirs, organic-fair shales with oil migration may demonstrate a higher proportion of free oil and benefit oil development. Quantifying the content of migration oil in shale reservoirs is a crucial challenge for further research.
Author Contributions
B.M.: writing—original draft preparation, methodology, investigation, data curation. Q.H.: writing—review and editing, conceptualization, funding acquisition, project administration. X.P.: funding acquisition, resources, supervision. S.Y.: writing—review and editing, investigation, formal analysis. X.W.: validation, methodology, data curation. W.H.: funding acquisition, resources, supervision. J.W.: methodology, data curation. All authors have read and agreed to the published version of the manuscript.
Funding
This research was funded by the National Natural Science Foundation of China (No. 42302175), Provincial Major Type Grant for Research and Development from the Department of Science & Technology of Shandong Province (No. 2020ZLYS08), the China Postdoctoral Science Foundation (No. 2024M752744), and Open Fund of Key Laboratory of Exploration Technologies for Oil and Gas Resources (Yangtze University), Ministry of Education (No. K2023-05).
Institutional Review Board Statement
Not applicable.
Informed Consent Statement
Not applicable.
Data Availability Statement
The original data contributions presented in the study are included in the article; further inquiries can be directed to the corresponding author.
Conflicts of Interest
Binyu Ma has received research grants from the National Natural Science Foundation of China and China Postdoctoral Science Foundation, and Key Laboratory of Exploration Technologies for Oil and Gas Resources (Yangtze University), Ministry of Education. Shengyu Yang has received research grants from the Department of Science & Technology of Shandong Province.
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Figure 1.
Location of Cangdong Sag and three sampling wells and stratigraphic column of Ek2 in Cangdong Sag (modified from [27]).
Figure 1.
Location of Cangdong Sag and three sampling wells and stratigraphic column of Ek2 in Cangdong Sag (modified from [27]).
Figure 2.
Ternary mineralogy classification of Ek2 shales from three wells.
Figure 3.
Thin section petrography of typical Ek2 shales: (a) Laminated structure, G108-8 well, 3183.08 m, plane polarized light; (b) Laminated structure, G108-8 well, 3183.08 m, crossed polarized light; (c) Laminated structure, G108-8 well, 3235.44 m, plane polarized light; (d) Laminated structure, G108-8 well, 3235.44 m, crossed polarized light; (e) Laminated structure, GD14 well, 4103.11 m, plane polarized light; (f) Laminated structure, GD14 well, 4103.11 m, crossed polarized light; (g) Massive structure, GD12 well, 3831.92 m, plane polarized light; (h) Massive structure, GD14 well, 4126.07 m, plane polarized light.
Figure 3.
Thin section petrography of typical Ek2 shales: (a) Laminated structure, G108-8 well, 3183.08 m, plane polarized light; (b) Laminated structure, G108-8 well, 3183.08 m, crossed polarized light; (c) Laminated structure, G108-8 well, 3235.44 m, plane polarized light; (d) Laminated structure, G108-8 well, 3235.44 m, crossed polarized light; (e) Laminated structure, GD14 well, 4103.11 m, plane polarized light; (f) Laminated structure, GD14 well, 4103.11 m, crossed polarized light; (g) Massive structure, GD12 well, 3831.92 m, plane polarized light; (h) Massive structure, GD14 well, 4126.07 m, plane polarized light.
Figure 4.
Organic matter abundance of organic-rich shales related to lithofacies.
Figure 5.
SEM images of pore morphologies in Ek2 shales: (a) G108-8 well, 3212.16 m; (b) GD12 well, 3894.93 m; (c) GD14 well, 4082.09 m; (d) G108-8 well, 2949.65 m; (e) G108-8 well, 3204.05 m; (f) G108-8 well, 3212.16 m; (g) G108-8 well, 3212.16 m; (h) GD14 well, 4082.09 m; (i) G108-8 well, 3050.26 m; (j) GD14 well, 4082.09 m; (k) GD14 well, 4136.21 m; (l) G108-8 well, 3204.05 m; (m) G108-8 well, 3204.05 m; (n) G108-8 well, 3212.16 m; (o) G108-8 well, 3212.16 m; (p) G108-8 well, 3212.16 m; (q) GD12 well, 3833.48 m; (r) GD14 well, 4095.27 m. Interp P: interparticle pore; Intrap P: intraparticle pore; Dis Intrap P: dissolved intraparticle pore; Dis Interp P: dissolved interparticle pore; OM P: organic matter pore; Micro F: micro-fracture; Q: quartz; F: feldspar; CAL: calcite; DOL: dolomite; Clay: clay minerals.
Figure 5.
SEM images of pore morphologies in Ek2 shales: (a) G108-8 well, 3212.16 m; (b) GD12 well, 3894.93 m; (c) GD14 well, 4082.09 m; (d) G108-8 well, 2949.65 m; (e) G108-8 well, 3204.05 m; (f) G108-8 well, 3212.16 m; (g) G108-8 well, 3212.16 m; (h) GD14 well, 4082.09 m; (i) G108-8 well, 3050.26 m; (j) GD14 well, 4082.09 m; (k) GD14 well, 4136.21 m; (l) G108-8 well, 3204.05 m; (m) G108-8 well, 3204.05 m; (n) G108-8 well, 3212.16 m; (o) G108-8 well, 3212.16 m; (p) G108-8 well, 3212.16 m; (q) GD12 well, 3833.48 m; (r) GD14 well, 4095.27 m. Interp P: interparticle pore; Intrap P: intraparticle pore; Dis Intrap P: dissolved intraparticle pore; Dis Interp P: dissolved interparticle pore; OM P: organic matter pore; Micro F: micro-fracture; Q: quartz; F: feldspar; CAL: calcite; DOL: dolomite; Clay: clay minerals.
Figure 6.
(a) Nitrogen adsorption-desorption curves; and (b) Pore size distributions of typical organic solvent-extracted Ek2 shales.
Figure 6.
(a) Nitrogen adsorption-desorption curves; and (b) Pore size distributions of typical organic solvent-extracted Ek2 shales.
Figure 7.
Pore structure parameters of organic solvent-extracted shales from LNA analyses; (a) Specific surface area and pore volume; (b) Volume of different types of pores.
Figure 7.
Pore structure parameters of organic solvent-extracted shales from LNA analyses; (a) Specific surface area and pore volume; (b) Volume of different types of pores.
Figure 8.
Pore structure parameters of organic solvent-extracted shales from MIP analyses; (a) Porosity and total pore volume; (b) Volume of different types of pores.
Figure 8.
Pore structure parameters of organic solvent-extracted shales from MIP analyses; (a) Porosity and total pore volume; (b) Volume of different types of pores.
Figure 9.
Comparison of the total oil content of shales of different lithofacies.
Figure 10.
Schematic diagram of pyrolysis spectra of as-received and solvent-extracted shales and division of shale oil into different occurrence states (FID: flame ionization detector).
Figure 10.
Schematic diagram of pyrolysis spectra of as-received and solvent-extracted shales and division of shale oil into different occurrence states (FID: flame ionization detector).
Figure 11.
Comparison of the (a) adsorbed oil content and (b) free oil content of shales of different lithofacies.
Figure 11.
Comparison of the (a) adsorbed oil content and (b) free oil content of shales of different lithofacies.
Figure 12.
Correlations between pore volume increment and residual oil content: (a) Pore volume increment from LNA vs. residual oil content of organic-rich shales; (b) Pore volume increment from MIP vs. residual oil content of all shale samples.
Figure 12.
Correlations between pore volume increment and residual oil content: (a) Pore volume increment from LNA vs. residual oil content of organic-rich shales; (b) Pore volume increment from MIP vs. residual oil content of all shale samples.
Figure 13.
Relative proportions of residual oil in pores with different types.
Figure 14.
Correlations between total oil content and (a) TOC, (b) S1, and (c) total pore volume.
Figure 15.
Relationships between TOC, S1, S2 and adsorbed oil and free oil contents. (a–c) The relationships between TOC, S1, S2 and adsorbed oil content, respectively; (d–f) the relationships between TOC, S1, S2 and free oil content, respectively.
Figure 15.
Relationships between TOC, S1, S2 and adsorbed oil and free oil contents. (a–c) The relationships between TOC, S1, S2 and adsorbed oil content, respectively; (d–f) the relationships between TOC, S1, S2 and free oil content, respectively.
Figure 16.
Relationships between TOC-normalized adsorbed oil content, TOC-normalized free oil content, and siliceous, calcareous, and clay minerals. (a,c,e) The relationships between siliceous, calcareous, clay minerals and TOC-normalized adsorbed oil content, respectively; (b,d,f) the relationships between siliceous, calcareous, clay minerals and TOC-normalized free oil content, respectively.
Figure 16.
Relationships between TOC-normalized adsorbed oil content, TOC-normalized free oil content, and siliceous, calcareous, and clay minerals. (a,c,e) The relationships between siliceous, calcareous, clay minerals and TOC-normalized adsorbed oil content, respectively; (b,d,f) the relationships between siliceous, calcareous, clay minerals and TOC-normalized free oil content, respectively.
Figure 17.
Correlation between adsorbed oil content and parameters of pore structure. (a,b) The relationships between specific surface area, porosity and adsorbed oil content, respectively; (c–e) the relationships between non-seep-pore, potential seep-pore, seep-pore volumes and adsorbed oil content, respectively.
Figure 17.
Correlation between adsorbed oil content and parameters of pore structure. (a,b) The relationships between specific surface area, porosity and adsorbed oil content, respectively; (c–e) the relationships between non-seep-pore, potential seep-pore, seep-pore volumes and adsorbed oil content, respectively.
Figure 18.
Correlation between free oil content and parameters of pore structure. (a,b) The relationships between specific surface area, porosity and free oil content, respectively; (c–e) the relationships between non-seep-pore, potential seep-pore, seep-pore volumes and free oil content, respectively.
Figure 18.
Correlation between free oil content and parameters of pore structure. (a,b) The relationships between specific surface area, porosity and free oil content, respectively; (c–e) the relationships between non-seep-pore, potential seep-pore, seep-pore volumes and free oil content, respectively.
Figure 19.
Models of shale oil occurrence for (a) adsorbed and free oil distribution in shales with lower maturity and (b) adsorbed and free oil distribution in shales with higher maturity.
Figure 19.
Models of shale oil occurrence for (a) adsorbed and free oil distribution in shales with lower maturity and (b) adsorbed and free oil distribution in shales with higher maturity.
Table 1.
Sample list, mineral compositions, and TOC contents of Ek2 shales used in this study.
| Sample ID | Well Name | Depth (m) | Quartz (wt.%) | Feldspar (wt.%) | Calcite (wt.%) | Dolomite (wt.%) | Clays (wt.%) | Analcime (wt.%) | Others (wt.%) | TOC (%) | Lithofacies |
|---|---|---|---|---|---|---|---|---|---|---|---|
| G108-8 2928 | G108-8 | 2928.56 | 13 | 15 | 17 | 24 | 21 | 10 | 0 | 1.78 | OFMM |
| G108-8 2944 | G108-8 | 2944.63 | 12 | 8 | 12 | 36 | 15 | 17 | 1 | 3.98 | ORLC |
| G108-8 2945 | G108-8 | 2945.49 | 12 | 13 | 13 | 21 | 19 | 21 | 1 | 4.68 | ORLM |
| G108-8 2946 | G108-8 | 2946.83 | 13 | 5 | 21 | 26 | 21 | 13 | 1 | 1.21 | OFLC |
| G108-8 2947 | G108-8 | 2947.97 | 19 | 13 | 8 | 11 | 16 | 31 | 1 | 5.00 | ORLM |
| G108-8 2949 | G108-8 | 2949.65 | 12 | 14 | 13 | 28 | 16 | 16 | 1 | 4.55 | ORLC |
| G108-8 2958 | G108-8 | 2958.90 | 17 | 11 | 13 | 10 | 17 | 30 | 3 | 2.59 | ORLM |
| G108-8 2964 | G108-8 | 2964.34 | 7 | 6 | 9 | 63 | 10 | 5 | 0 | 2.63 | ORLC |
| G108-8 2971 | G108-8 | 2971.88 | 13 | 14 | 11 | 20 | 19 | 20 | 4 | 3.47 | ORLM |
| G108-8 2973 | G108-8 | 2973.07 | 9 | 6 | 9 | 48 | 20 | 8 | 1 | 2.18 | ORMC |
| G108-8 3027 | G108-8 | 3027.85 | 16 | 14 | 12 | 24 | 22 | 12 | 1 | 1.07 | OFMM |
| G108-8 3050 | G108-8 | 3050.26 | 16 | 18 | 15 | 23 | 17 | 11 | 1 | 1.36 | OFLM |
| G108-8 3052 | G108-8 | 3052.22 | 16 | 16 | 6 | 4 | 15 | 41 | 2 | 3.23 | ORLS |
| G108-8 3059 | G108-8 | 3059.18 | 14 | 13 | 12 | 19 | 15 | 24 | 3 | 4.19 | ORLM |
| G108-8 3088 | G108-8 | 3088.09 | 10 | 9 | 6 | 38 | 24 | 13 | 0 | 1.15 | OFMC |
| G108-8 3104 | G108-8 | 3104.93 | 12 | 25 | 7 | 9 | 26 | 20 | 3 | 5.58 | ORLM |
| G108-8 3114 | G108-8 | 3114.88 | 14 | 16 | 7 | 38 | 16 | 10 | 0 | 1.81 | OFLM |
| G108-8 3127 | G108-8 | 3127.43 | 14 | 25 | 5 | 13 | 20 | 23 | 1 | 5.53 | ORLS |
| G108-8 3135 | G108-8 | 3135.72 | 11 | 15 | 0 | 50 | 13 | 11 | 0 | 4.46 | ORLC |
| G108-8 3143 | G108-8 | 3143.87 | 16 | 10 | 2 | 26 | 24 | 21 | 2 | 2.49 | ORLM |
| G108-8 3150 | G108-8 | 3150.23 | 19 | 15 | 8 | 7 | 15 | 36 | 1 | 1.66 | OFLS |
| G108-8 3161 | G108-8 | 3161.47 | 16 | 12 | 6 | 32 | 18 | 17 | 0 | 1.56 | OFMM |
| G108-8 3183 | G108-8 | 3183.08 | 20 | 20 | 7 | 24 | 17 | 10 | 2 | 4.58 | ORLM |
| G108-8 3204 | G108-8 | 3204.05 | 20 | 11 | 4 | 33 | 29 | 0 | 4 | 3.56 | ORLM |
| G108-8 3212 | G108-8 | 3212.16 | 19 | 37 | 6 | 1 | 29 | 4 | 4 | 6.74 | ORLS |
| G108-8 3235 | G108-8 | 3235.44 | 11 | 23 | 14 | 26 | 18 | 6 | 2 | 4.74 | ORLM |
| G108-8 3268 | G108-8 | 3268.09 | 17 | 14 | 3 | 8 | 33 | 24 | 1 | 6.44 | ORLM |
| GD12 3823 | GD12 | 3823.87 | 20 | 36 | 1 | 27 | 10 | 7 | 0 | 1.15 | OFLS |
| GD12 3826 | GD12 | 3826.02 | 17 | 14 | 3 | 8 | 33 | 24 | 1 | 0.39 | OFMM |
| GD12 3831 | GD12 | 3831.92 | 20 | 12 | 6 | 5 | 36 | 20 | 1 | 0.48 | OFMM |
| GD12 3833 | GD12 | 3833.48 | 8 | 10 | 8 | 34 | 23 | 16 | 2 | 1.28 | OFMC |
| GD12 3834 | GD12 | 3834.15 | 15 | 9 | 2 | 8 | 29 | 36 | 1 | 0.44 | OFMM |
| GD12 3847 | GD12 | 3847.25 | 18 | 42 | 6 | 12 | 19 | 3 | 0 | 2.79 | ORLS |
| GD12 3855 | GD12 | 3855.72 | 9 | 60 | 1 | 24 | 6 | 0 | 0 | 3.84 | ORLS |
| GD12 3859 | GD12 | 3859.39 | 10 | 64 | 3 | 9 | 11 | 0 | 3 | 4.72 | ORLS |
| GD12 3894 | GD12 | 3894.93 | 18 | 25 | 4 | 31 | 22 | 0 | 0 | 3.37 | ORLM |
| GD14 4078 | GD14 | 4078.07 | 7 | 11 | 21 | 38 | 15 | 7 | 1 | 0.51 | OFLC |
| GD14 4081 | GD14 | 4081.55 | 14 | 47 | 18 | 5 | 13 | 0 | 3 | 2.60 | ORLS |
| GD14 4082 | GD14 | 4082.09 | 10 | 44 | 14 | 17 | 14 | 0 | 2 | 4.38 | ORLS |
| GD14 4084 | GD14 | 4084.38 | 11 | 68 | 11 | 6 | 4 | 0 | 0 | 2.70 | ORLS |
| GD14 4095 | GD14 | 4095.27 | 12 | 34 | 6 | 25 | 20 | 0 | 3 | 1.79 | OFLM |
| GD14 4096 | GD14 | 4096.66 | 14 | 44 | 9 | 15 | 19 | 0 | 0 | 2.02 | ORLS |
| GD14 4103 | GD14 | 4103.11 | 9 | 52 | 10 | 5 | 22 | 0 | 2 | 3.26 | ORLS |
| GD14 4113 | GD14 | 4113.26 | 15 | 41 | 8 | 24 | 13 | 0 | 0 | 2.20 | ORLS |
| GD14 4115 | GD14 | 4115.10 | 8 | 28 | 14 | 39 | 10 | 0 | 1 | 0.92 | OFLC |
| GD14 4116 | GD14 | 4116.29 | 19 | 20 | 10 | 44 | 7 | 0 | 0 | 3.37 | ORMC |
| GD14 4117 | GD14 | 4117.69 | 6 | 16 | 15 | 54 | 10 | 0 | 0 | 1.07 | OFMC |
| GD14 4126 | GD14 | 4126.07 | 14 | 23 | 10 | 43 | 10 | 0 | 0 | 2.40 | ORMC |
| GD14 4134 | GD14 | 4134.52 | 15 | 34 | 15 | 19 | 16 | 0 | 1 | 2.77 | ORLM |
| GD14 4136 | GD14 | 4136.21 | 11 | 44 | 5 | 32 | 6 | 0 | 2 | 4.13 | ORLS |
Table 2.
Results of standard Rock-Eval pyrolysis of as-received and organic solvent-extracted shales and oil contents.
Table 2.
Results of standard Rock-Eval pyrolysis of as-received and organic solvent-extracted shales and oil contents.
| Sample ID | As-Received Shales | Organic Solvent-Extracted Shales | Tmax (°C) | Residual Oil Content (mg HC/g Rock) | Total Oil Content (mg HC/g Rock) | Heavy Oil Content (mg HC/g Rock) | ||
|---|---|---|---|---|---|---|---|---|
| S1 (mg HC/g Rock) | S2 (mg HC/g Rock) | S1E (mg HC/g Rock) | S2E (mg HC/g Rock) | |||||
| G108-8 2928 | 0.58 | 7.09 | 0.11 | 3.98 | 444 | 3.69 | 4.33 | 3.11 |
| G108-8 2944 | 0.94 | 27.17 | 0.09 | 20.27 | 444 | 7.84 | 8.88 | 6.90 |
| G108-8 2945 | 0.95 | 35.86 | 0.15 | 27.31 | 445 | 9.50 | 10.54 | 8.55 |
| G108-8 2946 | 0.19 | 2.09 | 0.06 | 0.18 | 442 | 2.10 | 2.31 | 1.91 |
| G108-8 2947 | 1.52 | 49.56 | 0.03 | 38.43 | 447 | 12.65 | 14.33 | 11.13 |
| G108-8 2949 | 0.86 | 27.25 | 0.08 | 20.33 | 446 | 7.78 | 8.73 | 6.92 |
| G108-8 2958 | 1.33 | 25.05 | 0.04 | 18.55 | 440 | 7.83 | 9.30 | 6.50 |
| G108-8 2964 | 0.87 | 12.73 | 0.07 | 8.55 | 440 | 5.05 | 6.00 | 4.18 |
| G108-8 2971 | 0.90 | 18.53 | 0.11 | 13.26 | 440 | 6.17 | 7.16 | 5.27 |
| G108-8 2973 | 2.20 | 9.82 | 0.06 | 6.19 | 438 | 5.83 | 8.25 | 3.63 |
| G108-8 3027 | 0.17 | 1.03 | 0.11 | 0.18 | 438 | 1.02 | 1.21 | 0.85 |
| G108-8 3050 | 0.11 | 3.44 | 0.09 | 1.02 | 446 | 2.53 | 2.65 | 2.42 |
| G108-8 3052 | 1.03 | 23.48 | 0.15 | 17.55 | 442 | 6.96 | 8.09 | 5.93 |
| G108-8 3059 | 0.95 | 24.93 | 0.06 | 18.45 | 446 | 7.43 | 8.48 | 6.48 |
| G108-8 3088 | 0.13 | 0.90 | 0.03 | 0.18 | 440 | 0.85 | 0.99 | 0.72 |
| G108-8 3104 | 1.80 | 46.49 | 0.08 | 35.94 | 439 | 12.35 | 14.33 | 10.55 |
| G108-8 3114 | 0.25 | 6.94 | 0.04 | 3.86 | 444 | 3.33 | 3.61 | 3.08 |
| G108-8 3127 | 0.99 | 41.97 | 0.07 | 32.27 | 438 | 10.69 | 11.78 | 9.70 |
| G108-8 3135 | 1.60 | 29.51 | 0.11 | 22.16 | 438 | 8.95 | 10.71 | 7.35 |
| G108-8 3143 | 1.28 | 18.08 | 0.25 | 12.13 | 443 | 7.23 | 8.64 | 5.95 |
| G108-8 3150 | 0.81 | 9.68 | 0.19 | 6.79 | 442 | 3.70 | 4.59 | 2.89 |
| G108-8 3161 | 0.54 | 9.62 | 0.16 | 7.02 | 444 | 3.14 | 3.73 | 2.60 |
| G108-8 3183 | 2.00 | 36.54 | 0.17 | 23.98 | 444 | 14.56 | 16.76 | 12.56 |
| G108-8 3204 | 3.21 | 23.82 | 0.06 | 17.55 | 442 | 9.48 | 13.01 | 6.27 |
| G108-8 3212 | 5.60 | 49.71 | 0.11 | 40.22 | 439 | 15.09 | 21.25 | 9.49 |
| G108-8 3235 | 2.12 | 35.85 | 0.20 | 26.82 | 448 | 11.15 | 13.48 | 9.03 |
| G108-8 3268 | 2.61 | 43.83 | 0.33 | 36.44 | 446 | 10.00 | 12.87 | 7.39 |
| GD12 3823 | 0.70 | 2.32 | 0.06 | 1.06 | 445 | 1.96 | 2.73 | 1.26 |
| GD12 3826 | 0.96 | 1.44 | 0.08 | 0.22 | 442 | 2.18 | 3.24 | 1.22 |
| GD12 3831 | 0.29 | 0.59 | 0.07 | 0.18 | 494 | 0.70 | 1.02 | 0.41 |
| GD12 3833 | 0.28 | 7.10 | 0.03 | 3.64 | 444 | 3.74 | 4.05 | 3.46 |
| GD12 3834 | 0.23 | 0.48 | 0.03 | 0.05 | 450 | 0.66 | 0.91 | 0.43 |
| GD12 3847 | 3.93 | 10.81 | 0.11 | 7.62 | 446 | 7.12 | 11.44 | 3.19 |
| GD12 3855 | 2.67 | 22.32 | 0.05 | 17.85 | 442 | 7.14 | 10.08 | 4.47 |
| GD12 3859 | 3.87 | 22.73 | 0.07 | 18.70 | 446 | 7.90 | 12.16 | 4.03 |
| GD12 3894 | 4.45 | 10.97 | 0.02 | 5.03 | 445 | 10.39 | 15.29 | 5.94 |
| GD14 4078 | 0.32 | 0.77 | 0.04 | 0.37 | 439 | 0.72 | 1.07 | 0.40 |
| GD14 4081 | 3.39 | 14.55 | 0.11 | 11.06 | 450 | 6.88 | 10.61 | 3.49 |
| GD14 4082 | 3.25 | 16.35 | 0.12 | 11.02 | 444 | 8.58 | 12.16 | 5.33 |
| GD14 4084 | 6.71 | 12.35 | 0.13 | 9.35 | 447 | 9.71 | 17.09 | 3.00 |
| GD14 4095 | 4.52 | 6.67 | 0.11 | 2.76 | 442 | 8.43 | 13.40 | 3.91 |
| GD14 4096 | 4.02 | 8.46 | 0.09 | 4.69 | 443 | 7.79 | 12.21 | 3.77 |
| GD14 4103 | 2.84 | 17.50 | 0.15 | 16.36 | 447 | 3.98 | 7.10 | 1.14 |
| GD14 4113 | 1.60 | 9.33 | 0.06 | 8.45 | 447 | 2.48 | 4.24 | 0.88 |
| GD14 4115 | 2.52 | 2.50 | 0.03 | 0.34 | 435 | 4.68 | 7.45 | 2.16 |
| GD14 4116 | 3.03 | 8.01 | 0.08 | 4.21 | 443 | 6.83 | 10.16 | 3.80 |
| GD14 4117 | 1.49 | 3.44 | 0.04 | 1.32 | 444 | 3.61 | 5.25 | 2.12 |
| GD14 4126 | 2.47 | 9.11 | 0.07 | 4.56 | 445 | 7.02 | 9.74 | 4.55 |
| GD14 4134 | 2.34 | 12.39 | 0.11 | 11.00 | 448 | 3.73 | 6.30 | 1.39 |
| GD14 4136 | 4.73 | 17.99 | 0.06 | 10.44 | 446 | 12.28 | 17.48 | 7.55 |
Table 3.
Pore parameters of as-received and organic solvent-extracted shales from LNA analyses.
| Sample ID | As-Received Shales | Organic Solvent-Extracted Shales | Increase in Pore Volume (mm3/g) | Increase in Non-Seepage-Pore Volume (mm3/g) | Increase in Potential Seepage-Pore Volume (mm3/g) | ||
|---|---|---|---|---|---|---|---|
| Specific Surface Area (m2/g) | Pore Volume (mm3/g) | Specific Surface Area (m2/g) | Pore Volume (mm3/g) | ||||
| G108-8 2928 | 13.10 | 22.96 | 18.32 | 25.78 | 2.83 | 2.28 | 0.55 |
| G108-8 2944 | 1.05 | 8.82 | 2.32 | 11.27 | 2.45 | 1.39 | 1.06 |
| G108-8 2945 | 0.54 | 3.69 | 1.19 | 5.09 | 1.40 | 0.49 | 0.91 |
| G108-8 2946 | 14.56 | 24.37 | 17.42 | 25.88 | 1.51 | 1.49 | 0.02 |
| G108-8 2947 | 0.62 | 5.09 | 1.68 | 8.57 | 3.48 | 1.25 | 2.23 |
| G108-8 2949 | 0.96 | 7.44 | 2.34 | 11.21 | 3.76 | 1.26 | 2.50 |
| G108-8 2958 | 0.75 | 4.41 | 2.62 | 7.67 | 3.26 | 1.94 | 1.32 |
| G108-8 2964 | 1.99 | 13.61 | 6.50 | 19.39 | 5.78 | 3.82 | 1.96 |
| G108-8 2971 | 1.00 | 5.73 | 7.19 | 17.75 | 12.03 | 5.44 | 6.58 |
| G108-8 2973 | 5.02 | 23.75 | 14.56 | 35.77 | 12.02 | 9.03 | 2.99 |
| G108-8 3027 | 18.10 | 28.33 | 19.14 | 29.80 | 1.47 | 1.08 | 0.39 |
| G108-8 3050 | 9.37 | 18.64 | 11.57 | 19.66 | 1.02 | 0.92 | 0.10 |
| G108-8 3052 | 2.33 | 11.55 | 5.15 | 14.25 | 2.71 | 1.86 | 0.85 |
| G108-8 3059 | 0.49 | 2.27 | 1.83 | 4.76 | 2.49 | 1.32 | 1.17 |
| G108-8 3088 | 18.62 | 25.16 | 19.63 | 26.26 | 1.10 | 0.40 | 0.70 |
| G108-8 3104 | 0.18 | 1.25 | 0.85 | 3.59 | 2.34 | 0.46 | 1.89 |
| G108-8 3114 | 12.26 | 20.92 | 14.61 | 22.30 | 1.38 | 0.84 | 0.55 |
| G108-8 3127 | 0.20 | 1.11 | 2.33 | 3.41 | 2.30 | 1.07 | 1.10 |
| G108-8 3135 | 0.13 | 0.89 | 3.10 | 7.25 | 6.36 | 2.41 | 3.96 |
| G108-8 3143 | 1.04 | 6.32 | 6.16 | 14.93 | 8.61 | 4.71 | 3.90 |
| G108-8 3150 | 3.77 | 16.50 | 6.97 | 19.34 | 2.85 | 1.98 | 0.87 |
| G108-8 3161 | 6.69 | 17.96 | 12.34 | 20.50 | 2.54 | 2.38 | 0.17 |
| G108-8 3183 | 1.46 | 9.05 | 12.48 | 22.53 | 13.48 | 7.13 | 6.36 |
| G108-8 3204 | 1.31 | 6.99 | 18.60 | 24.65 | 17.65 | 11.47 | 6.19 |
| G108-8 3212 | 0.20 | 1.59 | 7.35 | 14.62 | 13.03 | 4.13 | 8.90 |
| G108-8 3235 | 0.77 | 5.25 | 3.12 | 7.46 | 2.21 | 1.48 | 0.72 |
| G108-8 3268 | 0.54 | 3.47 | 1.83 | 5.58 | 2.11 | 0.77 | 1.35 |
| GD12 3823 | 3.75 | 9.24 | 6.37 | 10.87 | 1.64 | 1.46 | 0.17 |
| GD12 3826 | 16.73 | 23.20 | 17.99 | 23.70 | 0.49 | 0.36 | 0.13 |
| GD12 3831 | 15.41 | 21.78 | 15.86 | 22.11 | 0.33 | 0.03 | 0.30 |
| GD12 3833 | 13.91 | 27.47 | 16.53 | 30.02 | 2.55 | 1.42 | 1.13 |
| GD12 3834 | 14.23 | 21.67 | 14.91 | 21.91 | 0.24 | 0.17 | 0.07 |
| GD12 3847 | 0.31 | 3.04 | 1.68 | 10.95 | 7.91 | 2.04 | 5.87 |
| GD12 3855 | 0.26 | 2.44 | 0.93 | 7.46 | 5.02 | 0.80 | 4.22 |
| GD12 3859 | 0.40 | 3.29 | 1.13 | 7.03 | 3.74 | 0.97 | 2.77 |
| GD12 3894 | 0.86 | 6.14 | 3.60 | 13.83 | 7.70 | 3.42 | 4.27 |
| GD14 4078 | 4.85 | 12.25 | 5.98 | 14.03 | 1.78 | 1.12 | 0.66 |
| GD14 4081 | 0.63 | 5.21 | 1.31 | 8.13 | 2.92 | 1.06 | 1.86 |
| GD14 4082 | 0.24 | 2.10 | 1.34 | 9.52 | 7.42 | 1.70 | 5.71 |
| GD14 4084 | 0.46 | 3.45 | 1.60 | 10.16 | 6.71 | 1.86 | 4.84 |
| GD14 4095 | 0.38 | 3.88 | 1.60 | 9.76 | 5.87 | 2.03 | 3.84 |
| GD14 4096 | 0.48 | 4.01 | 1.38 | 8.69 | 4.68 | 1.49 | 3.18 |
| GD14 4103 | 0.39 | 3.35 | 0.97 | 7.35 | 4.00 | 0.91 | 3.09 |
| GD14 4113 | 0.56 | 4.39 | 1.13 | 7.61 | 3.22 | 0.83 | 2.39 |
| GD14 4115 | 0.77 | 4.67 | 3.25 | 10.40 | 5.74 | 3.11 | 2.63 |
| GD14 4116 | 0.52 | 5.14 | 1.62 | 11.43 | 6.30 | 1.70 | 4.59 |
| GD14 4117 | 0.42 | 2.58 | 3.69 | 9.71 | 7.13 | 3.72 | 3.41 |
| GD14 4126 | 0.48 | 4.26 | 2.03 | 12.49 | 8.23 | 2.38 | 5.84 |
| GD14 4134 | 0.49 | 4.33 | 1.43 | 8.58 | 4.25 | 1.48 | 2.77 |
| GD14 4136 | 0.48 | 4.50 | 1.67 | 11.96 | 7.45 | 1.73 | 5.72 |
Table 4.
Pore parameters of as-received and organic solvent-extracted shales from MIP analyses.
| Sample ID | As-Received | Organic Solvent-Extracted | Increase in Pore Volume (mm3/g) | |
|---|---|---|---|---|
| Pore Volume (mm3/g) | Porosity (%) | Pore Volume (mm3/g) | ||
| G108-8 2928 | 18.22 | 3.70 | 21.26 | 3.04 |
| G108-8 2944 | 20.94 | 5.50 | 26.94 | 6.00 |
| G108-8 2945 | 13.31 | 6.29 | 26.47 | 13.16 |
| G108-8 2946 | 22.08 | 5.44 | 23.42 | 1.34 |
| G108-8 2947 | 5.86 | 4.25 | 20.43 | 14.57 |
| G108-8 2949 | 16.92 | 5.84 | 25.36 | 8.44 |
| G108-8 2958 | 11.12 | 3.11 | 14.61 | 3.49 |
| G108-8 2964 | 13.50 | 5.08 | 22.50 | 9.00 |
| G108-8 2971 | 19.40 | 5.28 | 24.56 | 5.17 |
| G108-8 2973 | 22.12 | 7.54 | 34.50 | 12.38 |
| G108-8 3027 | 25.54 | 5.88 | 26.34 | 0.79 |
| G108-8 3050 | 11.27 | 3.73 | 16.15 | 4.88 |
| G108-8 3052 | 26.33 | 7.68 | 36.20 | 9.87 |
| G108-8 3059 | 7.41 | 2.35 | 12.36 | 4.95 |
| G108-8 3088 | 21.34 | 5.05 | 22.82 | 1.47 |
| G108-8 3104 | 9.54 | 5.49 | 22.43 | 12.88 |
| G108-8 3114 | 11.94 | 3.87 | 17.55 | 5.61 |
| G108-8 3127 | 2.38 | 2.78 | 13.76 | 11.38 |
| G108-8 3135 | 5.50 | 3.23 | 12.11 | 6.60 |
| G108-8 3143 | 9.82 | 5.19 | 20.12 | 10.30 |
| G108-8 3150 | 14.09 | 4.31 | 18.73 | 4.64 |
| G108-8 3161 | 15.01 | 4.14 | 18.03 | 3.02 |
| G108-8 3183 | 9.30 | 7.18 | 28.65 | 19.35 |
| G108-8 3204 | 18.67 | 7.86 | 34.00 | 15.32 |
| G108-8 3212 | 29.36 | 12.95 | 43.87 | 14.51 |
| G108-8 3235 | 15.17 | 7.11 | 28.76 | 13.59 |
| G108-8 3268 | 17.92 | 8.13 | 30.84 | 12.92 |
| GD12 3823 | 0.47 | 1.80 | 7.16 | 6.69 |
| GD12 3826 | 13.94 | 3.16 | 17.78 | 3.84 |
| GD12 3831 | 17.32 | 3.94 | 18.25 | 0.93 |
| GD12 3833 | 27.18 | 6.18 | 27.99 | 0.81 |
| GD12 3834 | 18.80 | 4.73 | 19.91 | 1.11 |
| GD12 3847 | 18.92 | 6.81 | 29.83 | 10.91 |
| GD12 3855 | 14.74 | 5.09 | 22.80 | 8.06 |
| GD12 3859 | 13.73 | 5.88 | 24.91 | 11.18 |
| GD12 3894 | 7.22 | 4.85 | 20.90 | 13.68 |
| GD14 4078 | 10.77 | 2.77 | 12.27 | 1.50 |
| GD14 4081 | 14.03 | 5.18 | 22.29 | 8.26 |
| GD14 4082 | 15.69 | 6.46 | 27.64 | 11.96 |
| GD14 4084 | 13.32 | 5.46 | 25.82 | 12.50 |
| GD14 4095 | 6.15 | 3.69 | 15.86 | 9.71 |
| GD14 4096 | 18.26 | 6.84 | 27.50 | 9.24 |
| GD14 4103 | 17.12 | 5.02 | 21.86 | 4.74 |
| GD14 4113 | 19.81 | 5.18 | 22.29 | 2.48 |
| GD14 4115 | 10.99 | 3.80 | 15.70 | 4.71 |
| GD14 4116 | 14.93 | 4.97 | 22.33 | 7.40 |
| GD14 4117 | 6.10 | 2.08 | 7.94 | 1.84 |
| GD14 4126 | 13.13 | 4.15 | 20.53 | 7.40 |
| GD14 4134 | 17.08 | 4.92 | 21.13 | 4.05 |
| GD14 4136 | 19.15 | 6.99 | 28.87 | 9.72 |
Table 5.
Adsorbed and free oil contents of Ek2 shales.
| Sample ID | Adsorbed Oil Content (mg HC/g Rock) | Free Oil Content (mg HC/g Rock) | Sample ID | Adsorbed Oil Content (mg HC/g Rock) | Free Oil Content (mg HC/g Rock) |
|---|---|---|---|---|---|
| G108-8 2928 | 3.17 | 1.16 | G108-8 3235 | 7.98 | 5.51 |
| G108-8 2944 | 6.59 | 2.29 | G108-8 3268 | 6.09 | 6.78 |
| G108-8 2945 | 8.25 | 2.29 | GD12 3823 | 0.97 | 1.76 |
| G108-8 2946 | 1.89 | 0.42 | GD12 3826 | 0.82 | 2.42 |
| G108-8 2947 | 10.85 | 3.47 | GD12 3831 | 0.31 | 0.71 |
| G108-8 2949 | 6.62 | 2.11 | GD12 3833 | 3.35 | 0.70 |
| G108-8 2958 | 6.00 | 3.30 | GD12 3834 | 0.67 | 0.24 |
| G108-8 2964 | 4.10 | 1.90 | GD12 3847 | 1.35 | 10.09 |
| G108-8 2971 | 4.97 | 2.19 | GD12 3855 | 4.04 | 6.03 |
| G108-8 2973 | 2.68 | 5.56 | GD12 3859 | 3.28 | 8.88 |
| G108-8 3027 | 0.87 | 0.33 | GD12 3894 | 5.08 | 10.20 |
| G108-8 3050 | 2.42 | 0.23 | GD14 4078 | 0.19 | 0.89 |
| G108-8 3052 | 5.87 | 2.22 | GD14 4081 | 3.00 | 7.61 |
| G108-8 3059 | 6.22 | 2.26 | GD14 4082 | 3.54 | 8.62 |
| G108-8 3088 | 0.72 | 0.27 | GD14 4084 | 1.30 | 15.79 |
| G108-8 3104 | 10.07 | 4.26 | GD14 4095 | 1.76 | 11.64 |
| G108-8 3114 | 3.13 | 0.48 | GD14 4096 | 3.00 | 9.21 |
| G108-8 3127 | 9.44 | 2.34 | GD14 4103 | 0.64 | 6.47 |
| G108-8 3135 | 6.92 | 3.78 | GD14 4113 | 0.06 | 4.18 |
| G108-8 3143 | 5.57 | 3.07 | GD14 4115 | 1.71 | 5.74 |
| G108-8 3150 | 2.70 | 1.90 | GD14 4116 | 3.21 | 6.95 |
| G108-8 3161 | 2.53 | 1.20 | GD14 4117 | 2.01 | 3.24 |
| G108-8 3183 | 11.90 | 4.86 | GD14 4126 | 3.40 | 6.34 |
| G108-8 3204 | 5.42 | 7.59 | GD14 4134 | 0.94 | 5.36 |
| G108-8 3212 | 7.73 | 13.52 | GD14 4136 | 6.44 | 11.04 |
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Ma, B.; Hu, Q.; Pu, X.; Yang, S.; Wang, X.; Han, W.; Wen, J. Occurrence Mechanism and Controlling Factors of Shale Oil from the Paleogene Kongdian Formation in Cangdong Sag, Bohai Bay Basin, East China. J. Mar. Sci. Eng. 2024, 12, 1557. https://doi.org/10.3390/jmse12091557
AMA Style
Ma B, Hu Q, Pu X, Yang S, Wang X, Han W, Wen J. Occurrence Mechanism and Controlling Factors of Shale Oil from the Paleogene Kongdian Formation in Cangdong Sag, Bohai Bay Basin, East China. Journal of Marine Science and Engineering. 2024; 12(9):1557. https://doi.org/10.3390/jmse12091557
Chicago/Turabian StyleMa, Binyu, Qinhong Hu, Xiugang Pu, Shengyu Yang, Xuyang Wang, Wenzhong Han, and Jiacheng Wen. 2024. "Occurrence Mechanism and Controlling Factors of Shale Oil from the Paleogene Kongdian Formation in Cangdong Sag, Bohai Bay Basin, East China" Journal of Marine Science and Engineering 12, no. 9: 1557. https://doi.org/10.3390/jmse12091557
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