1 Introduction
Carboniferous–Permian (C–P) coal-bearing strata is of high potential for petroleum generation, which has been discovered in several basins worldwide (e.g., Ordos Basin in China, Stellarton Sub-basins in Canada, and coal seam strata in Kansas of America) (
Collinson et al., 1994;
Ahmed et al., 2009;
D’Angelo et al., 2010;
Li et al., 2016,
2019a; Wang et al., 2016). Coaly source rocks occurred in the Bohai Bay Basin and Ordos Basin have been found to generate large amounts of hydrocarbons, with several large gas fields has been successfully developed in Ordos Basin (
Jin et al., 2009;
Tang et al., 2012;
Zhao et al., 2018;
Li et al., 2020). Even though gas exploration breakthroughs from the Bohai Bay Basin have been achieved, commercial production of oil and gas generated from the coaly strata has not been fully understood.
The evaluation of C–P coaly source rocks has received considerable attention in recent decades (
Li et al., 2016,
2019b). C–P coaly source rocks were considered to be deposited in a transitional environment, and consist of coal, mudstone, carbonaceous shale, and dark shale (
Collinson et al., 1994;
D’Angelo et al., 2010;
Figueiredo et al., 2010;
Zhao et al., 2015; Wang et al., 2016). C–P coal seams were believed as good source rocks providing abundant hydrocarbons (
Wang et al., 2016;
Zhao et al., 2018). The coaly source rocks have been assessed in terms of several aspects, including hydrocarbon generation history, maceral components, thermal simulation experiments, and oil-source relationships (
Figueiredo et al., 2010;
Tewari and Khan, 2015;
Wang et al., 2016;
Zhao et al., 2018). The total organic carbon (TOC) content of coal presented a wide variation between 20.5 wt% and 75.0 wt% (
Wang et al., 2016;
Zhao et al., 2018). The majority of coaly source rocks have higher hydrocarbon potentials implying good quality, whereas that of carbonaceous shales and dark shale ranges from low to good (
He et al., 2016;
Zhao et al., 2018). Type III to Type II
2 kerogen with the minority featuring Type II
1 are generally found in the the coaly source rocks (
Zhao et al., 2018). The differences in the organic matter abundance of coaly source rocks are revealed by observations of maceral components.
Many studies of coal petrology show that the coaly source rocks mainly comprise collodetrinite, collotelinite, corpogelinite, inertinite, and a small amount of liptinite (
Michelsen and Khorasani, 1990;
Stasiuk, 1994;
Tewari and Khan, 2015).
Jin et al. (2009) and
Zeng et al. (2013) revealed that a considerable amount of natural gas could be extracted from the C–P coaly source rocks, such as from well GBG1 of Jiyang Depression and well WL3 of Dongpu Sag in the Bohai Bay Basin. Furthermore, the occurrence of large amounts of hydrogen-rich collodetrinites and liptinite (e.g., cutinite, sporinite, and resinite) is expected to enhance coaly source rocks generating more hydrocarbons, especially in clarain, durain, and certain mudstones (
Tewari and Khan, 2015). More vitrinite and liptinite were found in coal deposited in the Argonne premium coal set and Cantabrian–Barruelian coal seams (
Hartgers et al., 1994;
Colmenero et al., 2008). Moreover, a high predominance of isomers with linear carbon skeletons speculated to be derived from microorganisms to vitrinite precursor sources was observed (
Hartgers et al., 1994).
In agreement with these findings, along with the large-scale generation of coal-derived gas, large estimates of condensate and crude oils have been determined in the Bohai Bay Basin (
Kędzior, 2009;
Zhao et al., 2018). For example, coal-derived petroleum reservoirs have been detected in well KG4 and well SU23 in the Bohai Bay Basin (
Ryder et al., 2012;
Zhao et al., 2018). In particular, with the recent major discovery of coaly-related condensate from wells YG1 and QG8 in the Bohai Bay Basin, coaly source rocks presenting better hydrocarbon potential are attracting wide attention (
Zhao et al., 2018).
Jin et al. (2009) and
Zhao et al. (2018) pointed out that coaly source rocks might have experienced two or three events of hydrocarbon generation since the Triassic, which could be caused by multiphase tectonic movements from the Indosinian to the Himalayan. Residual coaly source rocks buried deeper than 4000 m and experienced high thermal evolution. These source rocks provided lots of petroleum and gas with maturity ranging from 0.76 to 2.50% R
o (Chang et al., 2018). Although these coaly source rocks are extensively investigated, the differences in their hydrocarbon potential and the relationship between condensate and coaly source rocks remain unclear. C–P coaly source rocks can be further divided into five lithotypes of clarain, durain, carbonaceous shale, deltaic shale, and lagoonal shale according to their maceral components and depositional environments. Most coals were observed to be semi-clarain–semi-durain, which were divided into durain and clarain according to the types and contents of maceral components. The shales of the Shanxi and Taiyuan formations can be classified into deltaic shale deposited in delta plain and frontier environments and lagoonal shale formed in lagoon environments, respectively. However, the differences in the hydrocarbon potential of the five types of coaly source rocks have rarely been discussed. Moreover, there are no controlled parameters for clarifying the differences among coaly source rocks and coaly-related oils, which can account for the effect of similar maceral components of coaly source rocks. Therefore, the complexity of lithologies enhances the identification difficulty of the relative generation relationship from coaly source rock to coaly-related oils.
This study aimed to outline the organic geochemical differences among coaly source rocks (clarain, durain, and coaly shales of carbonaceous shale, deltaic shale, lagoonal shale) and coaly-related oils, and develop more accurate parameters to explore the evident discrepancies among the five types of coaly source rocks. New and effective parameters are expected to attain and clarify different lithologies of coaly source rocks. Therefore, the hydrocarbon generation processes and oils generated from five types of coaly source rocks were investigated through organic geochemical analysis and thermal simulation. This study provides new insights to judge the linkage between coaly-related oils and coaly source rocks. And the approach could be useful for studying source rocks deposited in similar environments worldwide.
2 Geological background
The Bohai Bay Basin formed above the North China Craton and developed from Mesozoic to Cenozoic (
Li et al., 2015;
Zhao et al., 2018). The Huanghua depression is located in the northwestern part of the Bohai Bay Basin and contains abundant petroleum resources (Fig. 1(a); Zhou et al., 2012. The succession of Upper Paleozoic contains the Benxi, Shanxi, Taiyuan, and Shihezi Formations (Fig. 1(c)), which developed thick (178–369 m), unconformable, siliciclastic-led deposits. Above the Middle Ordovician carbonates, the strata were formed in shallow-marine and paralic environments (Kim, 2001). The Shanxi and Taiyuan formations accumulated coaly source rocks in the paralic environments from late Carboniferous to early Permian (
Liu, 1990), and showed commercial coaly-related hydrocarbons (Fig. 1;
Lv and Chen, 2014;
Zhao et al., 2018). The coaly source rocks comprise of coal, carbonaceous mudstone and dark mudstone. As brightness and thickness decrease, the lithology of the coal samples changes from clarain to durain and deposited in the lagoon and delta environments. Carbonaceous mudstone was identified by high peat content and predominanted by argillaceous minerals and larger fossilized plant stems. The composition of the mudstone was controlled by its depositional environment, including salinity, hydrodynamic conditions, and organic matter input caused by the shift from lagoonal to prodeltaic environments. Accordingly, the mudstone can be divided into lagoonal shale and deltaic shale (
Xu and Jin, 2020). The coaly source rocks happened primary hydrocarbon generation during the mid-Triassic (T), which induced by regional tectonic settlement and terminated by uplift from the late T; A rift basin formed in east China during the Jurassic (J) to Cretaceous (K), and some coaly source rock generated hydrocarbons for the second time (early-secondary hydrocarbon generation); since the Eocene, a new rift basin developed on residual J–K strata, with some of the coaly source rocks buried deep beneath the sag areas of the rift generating oil and gas for a second (late-secondary hydrocarbon generation) or third time (tertiary hydrocarbon generation) (
Xu and Jin, 2020).
3 Materials and methods
3.1 Samples
A total of 36 coaly source rock samples were selected from wells CG2, CC1, GG16102, QG1601, QG8, and CL1601, as well as Caozhuang and Chazhuang coal mines in the Feicheng. Furthermore, five samples including clarain, durain, carbonaceous shale, lagoonal shale, and deltaic shale, were selected to conduct the thermal simulation experiment (Table 1). The oils and gas samples gathered from the thermal simulation experiments were analyzed for the biomarker analysis.
3.2 Analytical methods
3.2.1 Total organic carbon and Rock-Eval pyrolysis
Two hundred milligrams of the crushed samples (~200 mesh) were weighed to acidate with HCl at 60°C and wash with distilled water in a crucible. After the carbonate contents were removed, the washed subsamples were subsequently dried for 24 h at 50°C. TOC contents were measured with a LECO CS–230 analyzer. The Rock-Eval pyrolysis was analyzed with an OGE-II instrument with 60 to one hundred grams of each crushed sample. The crushed samples were placed in a helium atmosphere for heating. The heating procedure was set at a rate of 50°C/min and the temperature increased from 300°C to 600°C.
3.2.2 Maceral components analysis
Samples were polished and performed at the organic geochemistry laboratory of the China University of Petroleum (East China) following ISO procedures (ISO 7404-2, 2009). The component observation of organic petrology and determination of vitrinite reflectance were carried following standard procedures (ISO7404-3, ISO7404-5, 2009) under reflected light conditions of white and blue light excitation, following the ICCP System 1994 nomenclature (
ICCP, 1998,
2001;
Pickel et al., 2017). The samples were observed under an ultraviolet (UV) fluorescence microscope (Zeiss Axio Scope A1 POL) with magnifications at 200×, 500×, and 1000×.
3.2.3 Thermal simulation experiments
The thermal simulator can resist high temperatures and high pressures separately, up to 800°C and 120 MPa. The crushed samples (~100 mesh) are closed in the autoclave accompanying nitrogen or distilled water (adding as 25% of sample mass) and heated by a heater strip at a set heating rate. With a heating rate of 60°C/h, all coal samples were heated from 300°C to 650°C directly with every 50°C intervals. Every temperature point of a total of 6 points needs a 5 to 7 g of samples. The liquid products are dissolved through solvent dichloromethane (DCM) and analyzed by Gas chromatography-mass spectrometry (GC–MS) analyzer.
3.2.4 Gas chromatography-mass spectrometry (GC–MS) analysis
For GC–MS analysis, soxhlet extraction was used to treat the powdered samples for 72 h with dichloromethane. Asphaltenes solved in a mixture solution of hexane-DCM (80:1) were removed by centrifugal separation. The hydrocarbons and NSO compounds were separated with column chromatography (filled with silica gel and Al2O3). In which, the saturates were eluted with hexane, and the aromatics were extracted with DCM-hexane solution (2:1). The saturated and aromatic hydrocarbons were measured by a gas chromatograph coupled to an Agilent 7890 GC–MS. The fused silica column in the GC-MS analyzer was 30 m DB-5MS (i.d. 0.25 mm; 0.25 μm film thickness). The oven was heated from 70°C to 300°C at a rate of 3°C/min and lasted constant temperature for 30 min. The scan range of the mass-to-charge ratio was set from 50 to 650 with a total scan time of 0.7 s. Every compound was analyzed following the NIST library and the published data of mass spectra.
4 Results
4.1 Bulk geochemical parameters
Organic matter abundance showed a clear downward trend from coal to shale samples (Fig. 2). The total organic carbon content (TOC) of durain and clarain samples was higher than that of other samples, ranging from 50.6 wt% to 71 wt%. TOC values of carbonaceous shale ranged from 7.58 wt% to 24.80 wt%. Deltaic and lagoonal shales presented relatively lower TOC content (1.27–7.68 wt%; Fig. 2(a)). The S2 (0.90–236.57 mg/g)values of all samples showed roughly the same trend with TOC content (Table 1). Compared to the diagram of S1 versus TOC values, hydrocarbon potential (S1 + S2) and hydrogen index (HI) presented a transition area among five coaly source rocks (Fig. 2(b)). Clarain samples exhibited higher S1 + S2 (156.21–212.54 mg/g) and HI (TOC of 219.96–306.46 mg/g). Although durain samples also had high S1 + S2, their HI was low compared to carbonaceous shale. Lagoonal shale samples showed lower TOC and higher HI values, whereas deltaic shale samples exhibited the opposite trend (Figs. 2(a) and 2(b)). All Rock-Eval pyrolysis parameters exhibited a distinct difference in kerogen types from clarain to lagoonal shale samples. The vast majority of clarain samples falls under the type II2 area, except for one sample (type II1). The durain and carbonaceous shales corresponded to type II2 to type III, while deltaic and lagoonal shales were characterized by type III.
4.2 Organic petrology
Apparent differences presented in maceral components and contents among five coaly source rocks (Fig. 3). As shown in Table 2, coal samples were mainly composed of vitrinite. More than 80% of hydrogen-rich collodetrinite in clarain are present in the matrix as indicated by dark green fluorescence (Fig. 3(a)). Furthermore, sporinites and cutinites occur as bedding laminations within hydrogen-rich collodetrinite (Figs. 3(a) and 3(b)). In contrast, durain and carbonaceous shale contain more hydrogen-poor collotelinite and black corpogelinite with slight sporinites instead of hydrogen-rich collodetrinite (Figs. 3(c) and 3(d)). A significant decrease in vitrinite content was observed in deltaic and lagoonal shale samples (Figs. 3(e) and 3(f)). In addition, small amounts of cutinites and sporinites were presented in shales.
The type and content of maceral components exhibited some correlations with TOC content. TOC contents present a positive correlation with vitrinite content, and poor relationship with liptinite content (Fig. 4(a)). Statistics showed high contents of hydrogen-rich collodetrinite in the clarain (>45%) and durain (average 52.57%) samples, except for one sample (Fig. 4(b); Table 2). However, the vitrinite content of durain samples was extremely low, and TOC content was strongly associated with liptinite (Table 2). The contents of hydrogen-poor vitrinite and liptinite in carbonaceous shale show poor correlated to TOC content, which contents of liptinite ranging from 2.1% to 10.5% (Table 2). Despite the low content of maceral components, the deltaic and lagoonal shale samples exhibited an obviously increasing trend between hydrogen-poor vitrinite and TOC contents (Fig. 4(b)). Nevertheless, no relationship was between liptinite and TOC contents (Fig. 4(a)).
4.3 Hydrocarbon generation processes of coal and coaly shale
In the thermal simulation of the five types of source rocks, different hydrocarbon generation processes were observed during their evolution. Except for carbonaceous shale and lagoonal shale, the yield of liquid hydrocarbons peaked at 450°C. The yield of liquid hydrocarbons in carbonaceous shale began to peak at 400°C, whereas that in lagoonal shale peaked at approximately 525°C, showing a delay of more than 70°C (Fig. 5(a)). Before the peaking of liquid hydrocarbon generation, five types of source rocks exhibited significant differences in yield. Carbonaceous shale maintained a high yield until the peak at around 26.58 mg/g TOC. Before the temperature of 375°C, the durain had a higher yield than clarain and shales. For each sample, there was no clear difference in yield after the peak, with a decreasing trend till the end limit of the simulation.
Regarding the gas hydrocarbon generation process, all samples featured a similar increasing trend (Fig. 5(b)). After reaching the temperature of 400°C, striking differences began to appear, and clarain exhibited a significant increase in gas hydrocarbon generation, accounting for the highest gas yield. Deltaic and carbonaceous shales presented the lowest gas yield before 600°C. Finally, durain samples exhibited a sharp increase of gas hydrocarbon yield at 550°C and the yield approached that of the clarain sample (Fig. 5(b)).
4.4 Changes in saturated hydrocarbons and aromatic compounds during hydrocarbon generation
With increasing temperature, the five types of source rocks exhibited apparent differences in the evolution of saturated hydrocarbons and aromatic compounds (Fig. 6, Fig. 7, and Fig. 8). The clarain and durain samples showed relatively high and stable ratios of pristane and phytane (Pr/Ph), and other samples presented no obvious regularity (Fig. 7(a)). Similar characteristics were observed for the ratios of lower (∑nC21–) and higher normal alkanes (∑nC22+) in coaly source rocks, showing no strong discriminative power (Fig. 7(b)). Compared to the evolution of isoparaffin and normal alkanes, hopane and sterane series compound displayed distinct differences before reaching the temperature of 550°C (Figs. 7(c) and 6(d)). With increasing temperature, the carbonaceous shale, clarain, and durain samples exhibited increasing trends of Ts/(Ts+ Tm), Ga/C30 hopane, and C27 steranes/C29 steranes (Fig. 6). However, these parameters remained relatively stable in lagoonal and deltaic shales with slight fluctuations and values higher than those of other samples. The ratios of Ga/C30 hopane and Oleanane/C30 hopane in lagoonal shales were different from those of other samples (Figs. 6(c), 7(d) and 7(f)).
The saturated hydrocarbons, such as phenanthrene, fluorene, and naphthalene compounds, showed various evolution trends as increasing temperature (Figs. 6 and 7). Except for parameter MPI2, all samples can be identified according to the evolutionary character of the DBF/F ratio, DBT/F ratio, and MNR (Figs. 8(a), 7(b) and 7(d)). Lagoonal and carbonaceous shales exhibited higher values (>1.0) and a fluctuant trend of DBT/F ratio above the smooth trend of durain, deltaic shale, and clarain (Figs. 6 and 8(b)). Similar evolutional trends of DBF/F ratio and MNR were observed in all samples with a reversed order of parameters (Figs. 8(a) and 7(d)). After the temperature of 400°C, MPI2 values as increasing temperature decreased in lagoonal and deltaic shale and increased in coal and carbonaceous shale (Fig. 8(c)).
5 Discussion
5.1 Differences in hydrocarbon generation potential
Regarding C-P coaly source rocks deposited in a paralic environment, the hydrocarbon potential is closely related to types and contents of maceral components (e.g., hydrogen-rich collodetrinite, alginite, resinite, and sporinite;
Stasiuk, 1994;
Petersen et al., 2000;
Tewari and Khan, 2015). According to the results of TOC and Rock-Eval tests, clarain and durain have the highest potential to generate hydrocarbons, with values of S
1 + S
2 ranging from 236.57 mg/g to 140.92 mg/g (Fig. 2; Table 2). In contrast, lagoonal and deltaic shales have the lowest potential with values of S
1 + S
2 ranging from 3.46 mg/g to 0.90 mg/g. The hydrocarbon generation potential of carbonaceous shale lies between those of coals and dark shales with an average S
1 + S
2 of 45.33 mg/g. Observations of the maceral composition revealed that clarain contains more normal and H-rich vitrinites, showing a positive relationship with TOC content instead of liptinites of sporinite and cutinite (Figs. 3 and 4; Table 2). The durain contains more collotelinite and corpogelinite with a higher proportion of short-chain aliphatic and aromatic carbon compounds and liptinite with more long-chain aliphatic carbon compounds than the clarain (Fig. 3; Table 2). The liptinite is believed to agree well with hydrocarbon generation than the vitrinite (Fig. 4). The maceral compositions of coal samples mainly originated from terrigenous woody and herbaceous plants rather than algae (
Petersen et al., 2000;
Tewari and Khan, 2015).
The clarain deposited in a reducing low-stand swamp environment and accumulated more hydrogen-rich collodetrinite which is gelled with exinite of cutinite and sporinite (
Hartgers et al., 1994;
Tewari and Khan, 2015;
Li et al., 2019a, 2019
b). Due to strong biodegradation and gelatinization, more hydrogen-rich sporinite, resinite, and cutinite were cemented into collodetrinite (Figs. 3(a) and 3(b)). Therefore, the hydrogen-rich collodetrinite is considered to be the main contribution to the high hydrocarbon potential of the clarain. During a deposition in the weak reduction and hydrodynamic fluctuation environment, the durain contained more terrestrial detrital input (
Tewari and Khan, 2015). The collotelinite and corpogelinite in durain occurred as hydrogen-poor uniform gels due to simple gelatinization kinetics (Petersen et al., 2000;
Suwarna, 2006;
Li et al., 2019b). The hydrocarbon generation of the durain showed a decreasing trend (Fig. 2). The carbonaceous shale was formed in more oxygen environments (e.g. shallow water swamps or upland moors) with plentiful terrigenous plants input (
Greb and Martino, 2005;
Li et al., 2019a, 2019
b), comprising argillaceous minerals and coaly debris characterized by hydrogen-poor vitrinite. These conditions explain the low petroleum potential of the carbonaceous shale. The lagoonal shale developed in the lagoonal environment of the Taiyuan Formation and accumulated hydrogen-poor vitrinite and little bituminous organic matter, showing the lowest hydrocarbon potential (Fig. 3;
Li et al., 2019a). Under the influence of marine regression, more vitrinite, sporinite, and cutinite were accumulated in the deltaic shale than lagoonal shale during deposition of the Shanxi Formation, which is indicated by higher hydrocarbon-rich macerals (Fig. 3). Terrigenous organic matter, such liptinite, hydrogen-rich, and hydrogen-poor vitrinite, controlled the hydrocarbon generation of five types of coaly source rocks.
5.2 Implications for distinguishing lithologies of five types of coaly source rocks
Although saturated and aromatic fractions were the main components of organic matter in the coaly source rocks, the proportion of different compounds varied significantly, which was revealed by biomarker analysis at every temperature.
The relative contents of different isoprenoid, sterane, and terpane compounds were used to classify the marine and lacustrine environments. The evaporitic, deltaic, and carbonate environments were further identified from marine with above parameters. For instance, pristane/phytane ratios and short-chain versus long-chain normal alkanes (∑nC
21–/∑nC
22+) were used to identify the coal and shales deposits in swamps and paleolakes, respectively (
Mello et al., 1988;
Hughes et al., 1995). However, the evolution of above parameters presented minor differences among coal, carbonaceous shale, and dark shale from a paralic environment (Figs. 7(a) and 7(b)). In the thermal simulation, discrepancies were observed in the evolution of Ts/(Ts+ Tm), Ga/17α(H)21β(H)-C
30 hopane, 18α(H)-oleanane/17α(H)21β(H)-C
30 hopane, and 17β(H)21α(H)-C
30 morane/17α(H)21β(H)-C
30 hopane between coal, carbonaceous shale, and dark shales. These discrepancies are considered a good indicator for differentiating coal/carbonaceous shale and dark shales. Dark shales were characterized by high ratios of Ts/(Ts+ Tm) (>0.20), Ga/17α(H)21β(H)-C
30 hopane (>0.15), and 18α(H)-oleanane/17α(H)21β(H)-C
30 hopane (>0.05), and low ratios of 17β(H)21α(H)-C
30 morane/17α(H)21β(H)-C
30 hopane (<0.25), in contrast to those of coal and carbonaceous shale (Fig. 9).
Aromatic series compounds bear useful implications for the depositional environments, source input, and maturity of organic matter in the clarain, durain, lagoonal shale, and deltaic shale (
Luo et al., 2001;
Wei et al., 2001;
Li et al., 2001). The naphthalene, phenanthrene, and fluorene series of the aromatic fraction presented different characteristics within coaly source rocks (Fig. 8).
The abundant DBT accumulated in old organic-rich deposits is thought of as a consequence of a catalytic reaction between biphenyl ring systems and surface-adsorbed sulfur on carbonaceous material (
Asif et al., 2009;
Asif, 2010). DBFs trended to accumulate in source rocks deposited in fresh water and terrigenous oils and coals (
Li et al., 2004;
Li et al., 2013). The parameters of DBT/P ratio and Pr/Ph ratios in crude oils were useful for identifying the sedimentary environment and different lithotypes (
Hughes et al., 1995). However, the application of this plot was found to be unsuitable for source rocks deposited in paralic and lacustrine/swamp environments (
Radke et al., 2000). Due to variable sedimentary environments and similar source of organic matter, the discrimination for different lithologies of coaly source rocks was difficult to be identified. As mentioned in the literature review, the concentrations of naphthalene and methyl-substituted naphthalene series compounds were closely related to terrigenous organic matter input (
Radke and Willsch, 1994). Further investigation on the Permian coal of the southern Sydney Basin revealed that coal/coaly shales possess lower MNR and DBT/P ratio, and similar TeMNR compared to fine-grained sediments (
Ahmed et al., 2009).
Integrating the information of the sedimentary environment and source input, and results of the thermal simulation experiment, five types of C–P coaly source rocks could be well distinguished by several parameters of the aromatic fraction (e.g., TeMNR, MNR, DBT/F ratio, DBF/F ratio). In terms of TeMNR versus MNR, the carbonaceous shale is characterized by low TeMNR (<0.40) and high MNR (>1.80), and a depositional zone close to the lagoonal shale facies. In contrast, the durain is characterized by higher TeMNR (>0.56) and lower MNR (<1.80) (Fig. 10(a)). Lagoonal shale, deltaic shale, and clarain have similar TeMNR values and lie between carbonaceous shale and durain with moderate TeMNR and MNR. In different lithologies, the MNR varied in the descending order of lagoonal shale>deltaic shale>clarain (Fig. 10(a)). Significant differences were found between naphthalene and fluorene series compounds. The clarain and durain have high DBF/F ratios (>0.68) and low DBT/F ratios (<1.28) (Fig. 10(b)). The distributions of DBT/F ratios in deltaic shale and coal were similar, but the DBF/F ratio of deltaic shale was lower (<0.65). Both carbonaceous shale and lagoonal shale exhibited high ratios of DBT/F ratios, and that of carbonaceous shale was higher (Fig. 10(b)). Overall, the cross plots of TeMNR vs. MNR and DBT/F ratios vs. DBF/F ratios serve as suitable indicators for distinguishing different lithologies for five types of coaly source rocks.
Large amounts of coaly-related petroleum reservoirs have been revealed around the world (
Collinson et al., 1994;
Wang et al., 2016;
Zhao et al., 2018). Crude oil from younger Paleogene source rocks can be easily identified and quantified. However, the hydrocarbon potential of carbonaceous shale, lagoonal shale, and deltaic shale is underestimated, due to the lack of accurate methods for confirming the relationship between oil and coaly source rocks. This study indicates that the aromatic fraction of TeMNR, MNR, DBT/F ratios, and DBF/F ratios can well distinguish the characteristics of five types of coaly source rocks. These findings suggest that the estimation of crude oil and condensate can be determined by analyzing the source and evolution of different coaly source rocks. Our findings provide deeper insight into the hydrocarbon potential and coal–source for the associated rocks. This approach could be useful for exploring similar coaly source rocks in similar regions worldwide.
6 Conclusions
C–P coaly source rocks have significant hydrocarbon potential in the descending order of clarain, durain, carbonaceous shale, deltaic shale, and lagoonal shale. The clarain, durain, and carbonaceous shale were characterized by higher yield and the earlier peak of liquid hydrocarbon and more gas hydrocarbon than lagoonal and deltaic shales. Our results indicated that coaly source rock could provide significant hydrocarbon resources for the Bohai Bay Basin.
Although coaly source rocks accumulated abundant terrigenous organic matter, the high hydrocarbon potential of clarain, durain, and carbonaceous shale was attributed to sporinite and cutinite of liptinite and hydrogen-rich collodetrinite. In contrast, the lower hydrocarbon potential of lagoonal and deltaic shales can be caused by low hydrogen-rich maceral components (e.g., less exinite and hydrogen-poor vitrinite).
The coaly shales trended to produce the different composition of saturated hydrocarbons during the thermal evolution process, which was characterized by the Ts/(Ts+ Tm), Ga/17α(H)21β(H)-C30 hopane, 18α(H)-oleanane/17α(H)21β(H)-C30 hopane, and 17β(H)21α(H)-C30 morane/17α(H)21β(H)-C30 hopane. Aromatic fraction, particularly parameters of fluorene and naphthalene, provided more beneficial information for differentiating coaly source rocks. Five lithologies of coaly source rocks can be identified from the TeMNR, MNR, DBT/F, and DBF/F. The discrimination supported by the fluorene and naphthalene compounds could be beneficial for revealing organic geochemical differences among coaly source rocks and coaly-related oils.
The prospect of coaly source rock potential provides a new direction of energy exploration for the most oil fields in the Bohai Bay Basin. A new perspective of using parameters of fluorene and naphthalene series compounds to identify the different lithotypes of coaly source takes new insight for source analysis between coaly-related oils and coaly source rocks deposited the similar environments worldwide.
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