Petroleum mobility in shale is closely correlated with the attributes of shale petroleum and pores; however, the relationship between these attributes is poorly understood. To characterize petroleum mobility in self-sourcing reservoirs, a suite of mature Eocene shales was selected and subjected to organic solvent extraction, and both the raw and solvent-treated samples were analyzed using pyrolysis, nitrogen adsorption, and x-ray diffraction. The results show that the pore surface area and pore volume of these shales are mainly controlled by their clay and quartz content rather than their organic matter (OM) content and are limited by the presence of carbonates. Correlations of soluble OM with pore surface area and volume after solvent extraction indicate that petroleum mobility of studied shales is initiated when the petroleum content reaches 0.70 wt. % of the rock and the pore diameter is over 12.1 nm. These thresholds are established in the studied area and should be similar for the self-sourcing reservoirs from similar sedimentary environments. This work proposes a method to reveal the thresholds of petroleum content and pore diameter for petroleum mobility in self-sourcing reservoirs, which is useful in the assessment of petroleum producibility and is of significance for unconventional petroleum exploration and exploitation.
Shales that make up self-sourcing reservoirs have been recognized extensively in recent years and are seen as a significant target for petroleum exploration (Ross and Bustin, 2008; Jarvie, 2012; Zou et al., 2013b). Because shale is a low-porosity and low-permeability reservoir rock (Valenza et al., 2013; Zou et al., 2013b), with pores being predominantly on the nanometer scale (Loucks et al., 2009, 2012; Milliken et al., 2013; Löhr et al., 2015; Mathia et al., 2016; Milliken and Curtis, 2016), the storage sites of petroleum in shale are mainly these nanopores. Previous studies have shown that petroleum occurrence in shale is both in the free and adsorbed states (Jarvie, 2012; Zou et al., 2013a), and the strength with which petroleum adheres to mineral grains varies greatly (Zhang et al., 2015; Zhu et al., 2016). In addition, different petroleum components differ in terms of their retention capacity in minerals (Zhang et al., 2015; Li et al., 2016). Therefore, free and adsorbed petroleum differ in terms of their mobility. These phenomena have led to many studies that assess petroleum producibility using different methods, such as oil saturation index (Jarvie, 2012), surface adsorption potential (Li et al., 2016), simulation of oil penetration into porous templates (Zou et al., 2015), and pore saturation index (Su et al., 2017). The goals of these studies were to obtain limiting parameters of petroleum mobility for petroleum exploration and exploitation. However, they only consider petroleum or pore attributes and have not correlated the attributes of shale petroleum with occurrence spaces (i.e., pore surfaces and pore voids). This work focuses on the correlation of petroleum content with pore surface area and volume to reveal thresholds of petroleum content and pore diameter for petroleum mobility in shale, thus serving unconventional petroleum exploration and exploitation.
Materials and Methods
A total of 27 mature shales buried at depths of 2948–3120 m (9672–10,236 ft) were recovered by coring from a single well of the Eocene-age Es3lower member of the Shahejie Formation in the Zhanhua Sag, Jiyang Depression, eastern China. The maturity of studied shales is indicated to be in the range of the early oil-generation window by reliable vitrinite reflectance from samples from nearby wells (Wang et al., 2015). The bulk shales were ground to less than 1 mm and divided into three aliquots. The first split was retained as raw sample material for measurements. A second aliquot was subjected to organic solvent extraction with a 9:1 (volume:volume) dichloromethane:methanol (DCM:MeOH) mixture in a Soxhlet apparatus for a minimum of 72 hr. The solvent extraction was ceased when the refluent distilled solvent was colorless. The third split was powdered and analyzed using x-ray diffraction (XRD). Both the raw and solvent-extracted samples were dried in an oven at 80°C for over 3 days. These samples were then separately measured for nitrogen (N2) adsorption and powdered to perform Rock-Eval pyrolysis. The sample used for solvent extraction and N2 adsorption measurement could not be further ground or powdered so that it could hold the original nanopore spaces within shale. A Rock-Eval 6 instrument was used for pyrolysis, and an X’Pert-MPD diffraction instrument was used for XRD. The measurement procedures used for these two methods followed those of Zhu et al. (2013), and contents of total organic carbon (TOC), free hydrocarbons (S1), thermally cracking hydrocarbons (S2), and mineral composition were collected. The N2 adsorption measurement is an effective method to probe nanopore spaces of shale (Webb and Orr, 1997; Groen et al., 2003; Clarkson et al., 2013). This measurement employed an ASAP 2020 to collect the data on adsorption volume and relative pressure (P/P0). The heating bag was set to 80°C, and the samples were degassed for more than 6 hr before data collection. Six points with P/P0 values ranging from 0.05 to 0.35 and a single point at P/P0 > 0.99 with their adsorption volumes were collected to determine the pore surface area (specific surface area [SSA] based on the Brunauer–Emmett–Teller equation [Brunauer et al., 1938], abbreviated as N2-BET SSA) and pore volume, respectively.
The mineralogical results (Figure 1) show that the shale is mainly composed of clay, quartz, and calcite, with small amounts of dolomite and pyrite and trace amounts of feldspar and siderite. Classifying the mineral phases into three main constituents, we found that the dominant mineral constituent is carbonates (calcite + dolomite + siderite), with an average content of 65.7%, and the other two constituents are detrital minerals (quartz + feldspar) and clay, which have average contents of 16.4% and 15.0%, respectively. More over, calcite or quartz accounts for over 90% of the carbonates or the detrital minerals, respectively.
Figure 1. Distribution of mineral compositions (A) and constituents (shown as green circles) (B) of shales. The box provides the 25th and 75th percentiles, with the median value represented by the black line. The red line in the box indicates the mean value.
By plotting the organic geochemical data from the raw samples with those of solvent-extracted samples (Figure 2), it can be seen that the correlations are positive with TOC and S2 but are relatively scattered in S1. In the raw samples, TOC ranged from 1.28 to 4.13 wt. % with an average of 2.73 wt. %, S1 ranged from 1.06 to 6.83 mg/g with an average of 2.52 mg/g, and S2 ranged from 4.59 to 28.64 mg/g with an average of 15.33 mg/g. After solvent extraction, the TOC, S1, and S2 are reduced, with average losses of 28.2%, 93.8%, and 41.2%, respectively. The removed content of TOC ranged from 0.14 to 1.50 wt. %, S1 ranged from 1.00 to 6.66 mg/g, and S2 ranged from 2.13 to 11.02 mg/g, with averages of 0.73 wt. %, 2.38 mg/g, and 5.63 mg/g, respectively.
Figure 2. (A–C) Crossplots of organic geochemical data (free hydrocarbons [S1], thermally cracking hydrocarbons [S2], and total organic carbon [TOC]) between raw and solvent-extracted shales. (D) Content of S1, S2, and TOC removed by solvent extraction. The box provides the 25th and 75th percentiles, with the median value represented by the black line. The red line in the box indicates the mean value.
Pore Surface Area, Pore Volume
In the raw samples, N2-BET SSA ranged from 1.0 to 3.7 m2/g with 2.5 m2/g on average, whereas the pore volume ranged from 0.0067 to 0.0266 cm3/g with an average of 0.0175 cm3/g. After organic solvent extraction, these two parameters generally increased, but some reduced values are noted; the N2-BET SSA ranged from 2.2 to 8.8 m2/g and was 4.7 m2/g on average, and the pore volume ranged from 0.0111 to 0.0377 cm3/g and was 0.0207 cm3/g on average (Figure 3). These results show that solvent extraction tends to increase the N2-BET SSA and the pore volume of shale, although there are a few decreases in these two parameters.
Figure 3. Comparisons of pore surface area (N2-BET SSA) and pore volume (Vp) between the raw and solvent-extracted shales. The down arrow indicates the decrease after solvent extraction.
Contributions of Shale Components to the Pores
Both before and after organic solvent extraction, pore volume and N2-BET SSA are positively correlated with clay and detrital mineral content but negatively correlated with carbonate content (Figure 4). Because solvent extraction does not destroy mineral components, these correlations suggest that the clay and detrital minerals contribute to or construct the shale pores, whereas the carbonates do not significantly contribute to the growth of pore surfaces and pore voids. Prior studies have suggested that clay makes up the “card-house” microstructure of shale pore systems (Bennett et al., 1991; Slatt and O’Brien, 2011), quartz and carbonates are rigid grains that resist burial compaction and may act as a rigid framework of pores (Loucks et al., 2012), and carbonates are chemically unstable and undergo dissolution, with the resulting cementation probably decreasing the pore surface areas and pore volumes (Gaines et al., 2012; Loucks et al., 2012). In our studied samples, the carbonates clearly occur as cement (Deng and Liang, 2012; Zhang et al., 2016), which further explains and confirms the negative correlations of pore volume and N2-BET SSA with carbonate content. Additionally, the samples contain small amounts of pyrite (2.9% on average). Calcite or quartz dominate the carbonates or detrital minerals, respectively (Figure 1). Therefore, clay and quartz predominantly contribute to the pore volume and N2-BET SSA of shale, and the pore volume and N2-BET SSA of shale are limited by calcite.
axyrzrtbfwexevefceaquczesfcbzzdzybFigure 4. Correlations of pore volume (Vp) and pore surface area (N2-BET SSA) with the mineral components.
Of the studied shale samples that were treated with organic solvents, most pore volumes and N2-BET SSAs increase, although some decreasing values were noted (Figure 3), with the changes in these values being controlled by soluble organic matter (OM) content (i.e., organic carbon [OC] content was removed by solvent extraction) (Figure 5A, B). Furthermore, the slopes of regression lines between pore volume and N2-BET SSA with the mineral components are much steeper in the extracted samples than those estimated from the raw samples (Figure 4), indicating that the solvent-extractable OM reduces the increase in pore surface area and pore volume. These characteristics suggest that the pore surfaces and pore voids are occupied by solvent-extractable OM, which is in agreement with the finding that the mineral pores and organic pores are commonly infilled by soluble OM and can be recovered after organic solvent extraction (Valenza et al., 2013; Löhr et al., 2015; Zargari et al., 2015). In the raw samples, the insoluble OC (OC in the extracted samples) shows overall positive trends with pore volume and N2-BET SSA (Figure 5C, D). After solvent extraction, the positive trends of insoluble OC with N2-BET SSA and pore volume are severely weakened and show considerable scatter. The N2-BET SSA shows much more scatter than the pore volume measurements when plotted against insoluble OC (>Figure 5C, D). Because insoluble OM accounts for more than 70% of TOC on average and ranges from 47% to 94% in the studied samples, it is conceivable that if the OM has a dominant contribution to the N2-BET SSA and pore volume of the studied shale (i.e., OM has abundant pores), the positive main trend between insoluble TOC and N2-BET SSA or pore volume can be maintained after soluble OM removal. However, the removal of soluble OM does not maintain the positive main trend in OM with pore surface areas and pore volumes (Figure 5C, D), which indicates that OM does not exert a primary control on the N2-BET SSA and pore volume. The ion-polished scanning electron microscope observation has not shown organic pores in shales from the same core (Dong et al., 2015; Wang et al., 2015). Thus, it can be concluded that the OM in these studied shales does not have abundant pores and is not the major contributor to pore surface area and volume.
Figure 5. Plot of organic carbon (OC) content versus pore surface area (N2-BET SSA) and pore volume. (A, B) The crossplots of soluble OC with differences in N2-BET SSA and pore volume between the organic solvent-extracted samples and the raw samples. (C, D) Crossplots of insoluble OC with N2-BET SSA and pore volume in raw and solvent-extracted samples; the primary axis and solid circles indicate raw samples, and the second axis and hollow circles indicate solvent-extracted samples.
Implications of the Changes in Pore Surface Area and Pore Volume after Organic Solvent Extraction
Organic geochemistry reveals that there exist positive correlations in OC and S2 between the raw and solvent-extracted samples (Figure 2) and that the soluble OM is positively correlated with S1 and total oil [total oil = (S1-whole rock − S1-extracted rock) + (S2-whole rock − S2-extracted rock)] (Jarvie, 2012) (Figure 6). In studies of shale oil, the soluble OM, S1, and total oil have all been used to represent petroleum (Baker, 1962; Jarvie, 2012; Han et al., 2015). Organic solvent extraction is a physical process that removes soluble OM in free and physically adsorbed states (Zhu et al., 2016). Therefore, the soluble OM measured in our experiments represents the petroleum that is free in pore voids and physically adsorbed on pore surfaces.
Figure 6. Correlations of soluble organic carbon (OC) with free hydrocarbons (S1) and total oil.
Whether the N2-BET SSAs and pore volumes increase or decrease after solvent extraction (Figure 3) is controlled by the petroleum content (Figure 5A, B). Because the petroleum occupies pore surfaces and voids within shale, the removal of petroleum clearly increases the pore surface area and volume. However, a few measured values via N2 adsorption decrease after petroleum removal, although most increased (Figures 3, 7). The decreasing values may be ascribed to the following reasons. First, the N2 adsorption method has measurement limitations and is only suitable for measuring pores within a certain size range (∼0.35–300 nm) (Webb and Orr, 1997; Groen et al., 2003; Clarkson et al., 2013). Some recovered spaces after petroleum removal (e.g., enlarged open pore spaces) may be outside the range of measurement limitations (Furmann et al., 2013; Wei et al., 2014), thus leading to the decreases in pore volume and increases in N2-BET SSA. Second, the pore space for petroleum occurrence may collapse after petroleum removal (Ding et al., 2013), which may “shrink” the pore surfaces and voids and decrease the N2-BET SSA and pore volume. Third, some insoluble microparticles wrapped by petroleum may be exposed and could be adsorbed on the surfaces within shale after petroleum removal, which can increase pore volume and decrease N2-BET SSA. As seen in Figure 7, after petroleum removal, a general positive correlation exists between the difference in N2-BET SSA and the difference in pore volume, showing a close relationship between the change in pore voids and the change in pore surfaces. Although there are a few decreasing values of N2-BET SSA and pore volume after solvent extraction, they are not observed in the same samples, except for sample T12 (Figures 3, 7), indicating that the deformation of shale pores after petroleum removal is finite in all samples. Therefore, the changes in N2-BET SSA and pore volume after solvent extraction are mainly ascribed to petroleum removal.
Figure 7. Crossplot between the difference (δ) in pore surface area (N2-BET SSA) with the difference in pore volume between solvent-extracted samples and raw samples.
Thresholds of Petroleum Mobility
The correlations of soluble OM with N2-BET SSA and pore volume after solvent extraction (Figure 8) appear to have two stages. In the first stage, the soluble OM is less than 0.70 wt. %, and the N2-BET SSA and pore volume are relatively stable with increasing soluble OM content. In the second stage, as the content of soluble OM increases to over 0.70 wt. %, the N2-BET SSA and pore volume increase sharply with increases in soluble OM content. Moreover, the shale pore surface area and pore volume are mainly controlled by minerals rather than OM (Figures 4, 5). Therefore, these two stages indicate that the petroleum occurrence on/in mineral pore surfaces and voids is different in the first stage from that in the second stage. Because petroleum generation is a process by which kerogen is transformed to hydrocarbons (Hedberg, 1964; McIver, 1967; Tissot et al., 1971; Laplante, 1974; Tissot and Welte, 1984 and references therein), petroleum adsorption on mineral surfaces and the infilling of pore voids thus proceeds from none to saturation. Consequently, because the petroleum content is not sufficient to saturate shale pores (i.e., there may exist unoccupied pore surfaces or voids), the petroleum does not fully cover the mineral surfaces; thus, the petroleum content does not increase with increasing pore surface area and pore volume during the first stage. However, when the petroleum content is progressively increased in the second stage, the petroleum is continuously enriched and saturates the shale pores; thus, the petroleum content increases with increasing pore surface area and pore volume. Because petroleum in shale has to overcome the adsorption by pore surfaces before it is free in pores, only if sufficient coverage of petroleum on pore surfaces in the first stage has formed will the excess petroleum in the second stage be free in pore voids. As a consequence, the inflection point at soluble OC = 0.70 wt. % between those two stages (Figure 8) represents the threshold value of petroleum content for the sufficient coverage of petroleum on pore surfaces and for petroleum mobility. Thus, a shift between these two stages reveals that petroleum mobility occurs when petroleum content reaches 0.70 wt. % of the rock.
Figure 8. Crossplots of petroleum content with pore surface area (N2-BET SSA) and pore volume after organic solvent extraction.
Because organic solvent extraction mobilizes petroleum and recovers shale pore systems (Figure 5A, B), and physically removes free oil or total oil (Baker, 1962; Jarvie, 2012; Han et al., 2015), there exists a close relationship between the recovered shale pores and petroleum mobility. Simulation experiments using synthetic porous templates have indicated that the lower size threshold of pore throats for oil penetration is approximately 20 nm under certain conditions (Zou et al., 2015). Based on the N2-BET SSA and pore volume, the average pore diameter can be calculated using 4Vp/N2-BET SSA to reveal the average characteristic of nanopore diameters within shale (Valenza et al., 2013). In bulk shales, the average pore diameter ranges from 21.3 to 38.1 nm, and the average value is 28.1 nm. After organic solvent extraction, the average pore diameters of the shales apparently decrease, except for sample T16 (Figure 9), and range from 12.1 to 26.0 nm with an average of 18.1 nm. Because the change in average pore diameter is caused by solvent extraction, the appearance of smaller pores is the result of petroleum removal. This suggests that the petroleum occurring in the pore zone (Figure 9) includes that which is free in pore voids and physically adsorbed on pore surfaces. Previous studies have mentioned that the effective molecular diameters of n-alkanes, cyclohexane, complex ring structures, and microgranular bitumen are 0.48, 0.54, 1–3, and 2.1–2.4 nm, respectively (Tissot and Welte, 1984; Wang et al., 1996). Thus, these petroleum molecules are capable of being mobilized through the recovered pores. However, the physically adsorbed petroleum is removed after solvent extraction, so the lower threshold of average pore diameter of the recovered pores (i.e., 12.1 nm) is smaller than the one when the physically adsorbed petroleum is retained in a sample. In other words, the lower threshold of pore diameter for petroleum mobility is larger than 12.1 nm, which suggests that the petroleum cannot be mobilized in pores with diameters smaller than 12.1 nm. As a consequence, comparison of average pore diameters between raw and extracted samples reveals that the lower threshold of pore diameter for petroleum mobility is over 12.1 nm.
Figure 9. Distribution of average pore diameters in raw and in solvent-extracted samples.
After revealing the thresholds of petroleum content and pore diameter for petroleum mobility, we combined these two parameters to optimize the conditions for petroleum mobility (Figure 10). Taken together, if both the petroleum content and pore diameter are greater than the lower thresholds for shale, the petroleum will likely be mobilized; otherwise, it is immobile. However, it should be noted that petroleum (e.g., viscosity, chemical composition, content) and mineral (e.g., SSA, mineral composition, compaction history) properties may vary in different sedimentary environments, which are closely related to the retention of petroleum in the rock (Zhang et al., 2015; Li et al., 2016; Zhu et al., 2016) and will influence the abovementioned thresholds. Despite the existence of these influencing factors, the proposed method to reveal the thresholds for petroleum mobility is not confined by the variations in petroleum and mineral properties, which can be used in different sedimentary environments. Thus, the threshold values in our study are representative of the studied area and should be similar to the self-sourcing reservoirs that have similar sedimentary environments; furthermore, the proposed method can be used in studies of petroleum mobility. Because the thresholds for petroleum mobility are key for unconventional petroleum exploration and exploitation, our work based on geological samples provides important insights for determining the quantity of mobile petroleum and provides technical parameters for petroleum mobility in self-sourcing reservoirs, which is of significance for the assessment of petroleum producibility and provides reference values that aid in petroleum exploration and exploitation.
Figure 10. Thresholds of petroleum content and pore diameter limiting the petroleum mobility of shale.
Mature shales were subjected to organic solvent extraction and the measurement of mineralogy, organic geochemical parameters, N2-BET SSA, and pore volume. Correlations of N2-BET SSA and pore volume with mineral components and TOC reveal that in these shales (1) the N2-BET SSAs and pore volumes of the studied samples are mainly controlled by clay and quartz content and limited by carbonate content and (2) the OM does not make a dominant contribution to the pore volume and pore surface area. Our data indicate that petroleum mobility in the studied shales is initiated when the petroleum content reaches 0.70 wt. % of the rock and the pore diameter is over 12.1 nm. These thresholds were established for the study area and should be similar to self-sourcing reservoirs that have a similar sedimentary environment. Our work proposes a method to reveal the thresholds for petroleum mobility in self-sourcing reservoirs, which is beneficial for assessing petroleum producibility and is of significance for unconventional petroleum exploration and exploitation.
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This work was financially supported by the National Natural Science Foundation of China (41672115, 41372130), the China Postdoctoral Science Foundation (2016M601650), and the National Science and Technology Major Project of China (2016ZX05006-001-003, 2016ZX05027-001-008, 2017ZX05049-004-007). We are grateful to anonymous reviewers and AAPG Editor Barry J. Katz for their constructive comments and suggestions that improved the quality of this paper. Special thanks go to Zhenmeng Sun and Xiancai Lu from Nanjing University for their assistance in the nitrogen adsorption measurement.
Supplementary data are available in an electronic version on the AAPG website (www.aapg.org/datashare) as Datashare 101.