Abstract
The extensive thinning and destruction of North China Craton (NCC) during the Early Cretaceous led to the development of numerous rift basins and petroleum systems. However, the specific relationship between NCC evolution and hydrocarbon generation and accumulation in these sedimentary basins is still unclear. In this study organic geochemistry and oil-source correlation analyses were conducted to investigate the hydrocarbons generation potential and migration pathway in the representative Fuxin Basin. Results demonstrate that the semi-deep lacustrine source rocks were developed in the Jiufotang Formation (K1jf) in the west and the upper Shahai Formation (K1sh) in the east, both of which are enriched with organic matter content and hydrocarbon generation potential of kerogen Types II to III. Based on the hierarchical cluster analysis of crude oils biomarker fingerprints, two crude oil types (A and B) were deduced. The Type A crude oil is characterized by high gammacerane, low pristane/phytane, relatively high C29 regular sterane and methylphenanthrene index, which is consistent with the K1jf biomarker characteristics in the west. Therefore, the Type A crude oil is likely generated from the K1jf source rock that accumulated in turbidite sand bodies of the K1jf and/or migrated to the K1sh reservoir through strike-slip faults. Type B crude oil is dominated by low gammacerane, moderate pristane/phytane, high C27 regular sterane and 1,2,5-trimethylnaphthalenes, which is in good agreement with the K1sh4 features. The basin simulation revealed that hydrocarbon generation of source rocks in the Jiufotang and Shahai formations was linked to a rapid subsidence of the basin, which was induced by intense extension with the NCC destruction during the Early Cretaceous. Subsequently, the rapid subduction of the Western Pacific plate during the earliest Late Cretaceous led to the development of extensive epigenetic fractures, enabling extensive hydrocarbon migration in the Fuxin Basin. This study sheds light on oil sources in sedimentary basins in an extensional setting and provides insights into the dynamic process of hydrocarbon generation and migration associated with NCC evolution.
Article highlights
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1.
The upper Jiufotang and Shahai formations are the main source rock intervals of the Fuxin Basin.
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2.
Early Cretaceous NCC destruction promoted hydrocarbon generation in the Fuxin Basin.
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3.
Late Cretaceous subduction of the Western Pacific plate triggered hydrocarbon migration.
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1 Introduction
Meso-Cenozoic rift basins in China are considered the primary sedimentary basins with their significant hydrocarbon generation and production (Guo et al. 2012; Huang et al. 2013; Hu et al. 2022; Kang 2014; Song et al. 2019; Wang et al. 2019). During the Early Cretaceous, the lithosphere of North China Craton (NCC) was subjected to extensive thinning and destruction owing to the subduction and retreat of the Western Pacific plate (Zhu et al. 2011, 2020; Zhu and Xu 2019). This dynamic process triggered the formation of numerous rift basins in the NCC (Fig. 1a) (Li and Wang 2018; Zhu et al. 2020; Ma and Xu 2021), which received abundant contribution of coal and hydrocarbon resources (Li et al. 2020; Xu et al. 2020; Xie et al. 2021a). Nevertheless, the specific relationship between hydrocarbon generation and migration in these Cretaceous rift basins and the evolution of the NCC remains partly unraveled. The Fuxin area, located in the northern margin of the NCC, experienced the most significant the strongest crustal detachment and lithospheric thinning during the Late Mesozoic (Fig. 1a; Jia et al. 2021; Sun et al. 2022). The subsidence of the Fuxin Basin during the Early Cretaceous (ca. 130–100 Ma; Jia et al. 2021) shows a clear temporal and spatial correlation with the intensity of NCC destruction (peak stage at 125 Ma; Zhu et al. 2012) and magmatic activity (peak in 125 Ma; Wu et al. 2005; Zhu et al. 2012). Toward the earliest Late Cretaceous, the subduction of the Western Pacific plate caused rapid uplifting and exhumation of the Fuxin area (Zhu et al. 2020; Ma and Xu 2021). Therefore, the Fuxin Basin was subjected to several tectonic activities and thus represents typical example to explore the relationship between hydrocarbon accumulation and NCC evolution.
Recent drilling activities in the Fuxin Basin revealed thick oil-bearing intervals (Li et al. 1985; Xiao et al. 2017; Xie et al. 2021a). The thick lacustrine mudstones of the Jiufotang (K1jf) and Shahai (K1sh) formations have been identified as hybrid intervals of promising source rocks and shale gas reservoirs (Chen et al. 2018a; Xie et al. 2021a; Xu et al. 2022). During the Early Cretaceous, fan delta and underwater fan sand bodies were extensively developed in the Fuxin Basin (Li et al. 1985; Jia et al. 2021), serving as favorable reservoirs for oil migration and accumulation (Li et al. 1985). Therefore, the Fuxin Basin is considered a reliable prospect for hydrocarbon potential and future exploration and production activities (Li et al. 1985). However, the detachment tectonism associated with NCC evolution has impacted the basin framework, sedimentary filling, organic matter (OM) enrichment, and thermal evolution of the Fuxin Basin (Jia et al. 2021; Sun et al. 2022). These tectonics have resulted in a multi-source petroleum system in the Fuxin Basin (Li et al. 1985; Jia et al. 2021; Xie et al. 2021a), making it challenging to determine the oil sources. Therefore, investigating hydrocarbon generation and migration in the Fuxin Basin holds significant importance for hydrocarbon exploration and unveils the development stages of resources during the NCC evolution.
In this study, implementing an integrated approache of organic geochemistry and oil-source correlation are conducted to investigate the hydrocarbon generation and migration within the Fuxin Basin, and to explore the impact of the NCC evolution through basin simulation. The main objectives of this study are (1) to assess OM abundance, kerogen types, hydrocarbon generating potential, and generation history of source rocks within the Fuxin Basin; (2) to reveal the process of hydrocarbon migration from source rock layers to reservoirs through oil-source correlation; and (3) to clarify the effects of the Cretaceous NCC evolution on hydrocarbon generation and migration in the Fuxin Basin.
2 Geologic background
The Fuxin Basin is located in western Liaoning within the eastern Yanshan orogenic belt of the NCC (Fig. 1a; Jiang and Sha 2006; Liang et al. 2017). During the Early Cretaceous, paleo-Pacific plate subduction resulted in a regional lithospheric thinning in NCC (Li et al. 2018). This lithospheric thinning triggered a major shift from a compressional system to an extensional system (Shen et al. 2011; Zhu et al. 2011). Under this active tectonism, nearly 100 NE–NNE trending rift basins, including the Fuxin Basin, were developed in Northeast China during the Late Jurassic to Early Cretaceous (Fig. 1a; Jiang and Sha 2006; Liang et al. 2017). The Fuxin Basin is an extensional fault system trending NNE–NE and covers an area of ca.1500 km2 (Fig. 1b; Jiang and Sha 2006; Liang et al. 2017). The basin-fill process was mainly controlled by the Songling and Lüshan major faults, defining its western and eastern margins, respectively (Fig. 1; Wang et al. 1998; Xu et al. 2020). The Fuxin Basin was further influenced by three second-order structural belts, the western step fault zone, central half-graben zone, and eastern step-fault zone (Fig. 2). Moreover, seven successive third-order structural units formed due to active uplift and subsidence tectonics of the basement rocks (Fig. 1b; Wang et al. 1998).
Interpreted seismic cross sections through the boreholes of FY2 and the DY1 in the Fuxin Basin. Abbreviations: K1y, Yixian Formation; K1jf1, lower Jiufotang Formation; K1jf2, upper Jiufotang Formation; K1sh1, lower Shahai Formation; K1sh2, upper Shahai Formation; K1f, Fuxin Formation; K1s, Sunjiawan Formation
The Fuxin Basin was successively filled by the Lower Cretaceous strata, which include the Yixian (K1y), Jiufotang (K1jf), Shahai (K1sh), Fuxin (K1f) and Sunjiawan (K1s) formations (Fig. 3; Wang et al. 1998; Jia et al. 2021). The lithologies and sedimentary facies of the Jiufotang and Shahai formations are characterized by several oil shows. The lower Jiufotang Formation consists of shallow lacustrine gray mudstone in the western part of the basin that changed laterally into thick semi-deep lacustrine black mudstone toward the basin depocenter (Fig. 3). Conversely, subaqueous fan deposits are widely developed toward the east (Li et al. 1985; Jia et al. 2021, 2023). During the deposition of the upper Jiufotang Formation, slump delta deposits were dominant in the western part of the basin (Fig. 3). The lithologic composition is dominated also by medium-coarse sandstone and conglomerate with black lacustrine mudstone interbeds, which contain some oil shows of varying qualities (Fig. 4a).
Lithologies, sedimentary facies, and oil–bearing grades of each borehole in the Fuxin Basin. a Borehole FY2 (I–III, K1jf; IV–VI, K1sh): I, dark–grey mudstone; II, fine conglomerate, oil spot; III, calcite vein filled in mudstone fracture, oil immersed; IV, conglomerate, oil spot; V, dark–grey mudstone; VI, conglomerate, oil spot. b Borehole DY1 (I–III, K1sh): I, fault breccia, oil spot; II, dark–grey mudstone; III, fine conglomerate, oil rich (oil saturated). Stratigraphic symbols are the same as in Fig. 2
During the deposition of the lower Shahai Formation, significant flows of fan delta into a shallow lake and offshore sub-lacustrine fan deposits were common (Fig. 3; Wang et al. 2019; Li et al. 2020). The interval is also characterized by coarse clastic sediments intercalated with thin mudstones (Fig. 4v). The top part of the lower Shahai Formation is characterized by a slump fan depositional system developed in the western part of the basin (Figs. 3 and 4a), comprising conglomerates intercalated with dark mudstones. However, the lower Shahai Formation in the east is composed of sub-lacustrine fan and lake bay sediments (Fig. 3). The lake bay deposits consist of coal seams, carbonaceous mudstones, and mudstones (Fig. 4b; Xie et al. 2021a). During the deposition of the upper Shahai Formation, significant subsidence of the Fuxin Basin resulted in substantial lake expansion, which triggered gravity flows in the eastern parts of the basin (Fig. 3; Li et al. 1985; Jia et al. 2021; Xie et al. 2021a). Consequently, a deepening water column promoted the deposition of thick black mudstones in the upper Shahai Formation (Fig. 4i and ii). During the end deposition of the upper Shahai Formation, a phase of basin compression was prevalent and fan delta deposits began to accumulate (Fig. 3; Jia et al. 2021; Xie et al. 2021a).
During the deposition of the Fuxin Formation, the lake-basin scale rapidly shrank, and the basin was dominated by a fan delta system (Fig. 3). The Fuxin Formation consists of conglomeratic sandstone and siltstone, interbedded with lacustrine and swampy dark gray mudstone, carbonaceous mudstone, and coal seams (Xu et al. 2020).
3 Material and methods
The studied samples were collected from borehole FY2 in the west and borehole DY1 in the east of the Fuxin Basin (Figs. 2 and 3), except for one crude oil sample from borehole FD1 (Fig. 1b). Borehole FY2 and DY1 all observed different degrees of oil shows (Fig. 4) which are categorized into five grades: fluorescence, oil trace, oil spot, oil immersed, and oil rich (oil saturated, Fig. 4a). Oil spot and oil immersed are the most common grades within clastic sediments of the Jiufotang Formation (Fig. 4II and III), whereas the oil rich (oil saturated) grade is abundant in some brown coarse-grained sandstones (Fig. 4a). The oil-bearing intervals of the Shahai Formation are found within the lower Shahai Formation of the borehole FY2 (Fig. 4a), and in the upper Shahai Formation of the borehole DY1 (Fig. 4b). In the lower Shahai Formation of the borehole FY2, brown conglomerates observe oil spot and oil immersed grades (Fig. 4VI), whereas dark brown conglomerates in the upper Shahai Formation of the borehole DY1 are saturated with oil (Fig. 4iii).
A total of 158 mudstone rock samples were collected from boreholes FY2 and DY1 (Table 1), of which 84 samples had already been published based on their total organic carbon (TOC), Rock–Eval pyrolysis, vitrinite reflectance, and saturated hydrocarbon biomarkers (Xie et al. 2021a). Therefore, 74 rock samples from boreholes FY2 were specifically measured for their TOC content and Rock–Eval pyrolysis, and out of those, 24 mudstone samples were chosen for maceral analysis. Additionally, six oil samples and 15 carefully selected source rock samples from boreholes FY2 and FD1 were analyzed for biomarkers (Tables 2 and 3).
The TOC analysis was performed using a Leco-CS230 instrument. Before analysis, the powder samples underwent pretreatment with the HCl acid (5%) to eliminate inorganic carbon fractions. Pyrolysis was conducted by the Rock–Eval-6 instrument, and S1, S2, S3 and Tmax were measured. For detailed methods, the reader can refer to Xie et al. (2021a). To prepare pellets for organic petrography, the whole rocks were cut and polished. Further details of pellet preparation along with the composition of organic matter can be found in (ISO 7404–2, 2009). Reflected and fluorescent light investigations of the polished blocks were carried out using a Leica microscope that is equipped with oil immersion objectives. UV fluorescence light investigations used two filters with excitation energies of 515 and 55 nm. In this study, the classification and nomenclature of macerals followed the ICCP System (ICCP 1998, 2001; Pickel et al. 2017).
For biomarker analysis, samples were extracted using a mixture of CH2Cl2 and CH3OH (93:7, v:v) for 72 h. Crude oil and extracted OM were separated by column chromatography to obtain the saturated and aromatic fractions. The gas chromatograph (GC) analysis of saturated fractions utilized the Agilent 7890 GC. The gas chromatography mass spectrometry (GC–MS) analysis of saturated fractions was conducted using the Thermo-Trace GC Ultra-DSQ II equipped with a 60 m HP-5MS elastic quartz capillary column (i.d.0.25 mm; 0.25 μm film thickness). For detailed methods refer to Xie et al. (2021a). The aromatic hydrocarbon was measured using the same instrument as saturated hydrocarbon analysis, but with different temperature programing. The initial oven temperature was 100 °C and maintained isothermally for 5 min, then it was raised to 320 °C at a constant rate of 3 °C/min, which stayed isothermal at this temperature for 20 min.
The models of the burial history and thermal maturity of the boreholes FY-2 in the western parts of the basin and DY-1 in the eastern parts of the basin were reconstructed using the BasinMod of Platte River Associates, Inc. (USA). Model input, including the age, thickness, erosion, lithology, TOC, HI, vitrinite reflectance, and heat flow are applied to construct the burial and generation history curves. Detailed data is shown in Online Appendix 1–2. The heat flow variations in the eastern and western parts of the basin are different, with a heat flow of 52.1–103.27 mW/m2 in the western part and 52.1–111.11 mW/m2 in the eastern part (Jiang et al. 2019).
4 Result
4.1 Bulk geochemistry
The TOC content of the Jiufotang Formation is considerably varied, ranging from 0.1 to 3.5 wt% (Fig. 5; Table 1). The upper Jiufotang Formation shows higher TOC values (avg. 2.0 wt%) compared to the lower Jiufotang Formation (avg. 1.0 wt%) (Fig. 5a). In the lower Shahai Formation, the TOC content exhibits significant variability, ranging from as low as 0.2 wt% to as high as 60.6 wt%. The lower Shahai Formation in the west has TOC values in the range of 0.6–5.2 wt% (avg. 2.8 wt%) compared to coeval coal seams in the east that show the highest TOC values (7.3–60.6 wt%, avg. 28.7 wt%) (Fig. 5b). The TOC values in the upper Shahai Formation are nearly similar between the western (avg. 2.2 wt%) and eastern parts of in the basin (avg. 2.7 wt%).
Geochemical parameters of studied boreholes FY2 (a) and DY1 b in the Fuxin Basin (vitrinite reflectance data from Jia et al. (2021))
The S1 + S2 values of the lower Jiufotang Formation (0.1–4.0 mg HC/g rock, avg. 1.5 mg HC/g rock) are lower than those of the upper Jiufotang Formation (0.6–18.7 mg HC/g rock, avg. 5.6 mg HC/g rock) (Fig. 5a; Table 1). In the west, the S1 + S2 values of the lower Shahai Formation vary between 0.7 and 23.9 mg HC/g rock (Fig. 5a), while their coeval coal seams in the east display significantly higher values (17.0–133.5 mg HC/g rock) (Fig. 5b). In the west, the S1 + S2 values of the upper Shahai Formation (0.1–25.6 mg HC/g rock) are slightly higher than those in the east (0.8–16.1 mg HC/g rock).
The HI values in the lower Jiufotang Formation are relatively low (16–203 mg HC/g TOC) compared to the higher values in the upper Jiufotang Formation (80–509 mg HC/g TOC) (Fig. 5; Table 1). In the west, average HI values of the lower Shahai Formation are high (128–702 mg HC/g TOC, avg. 382 mg HC/g TOC) as opposed to lower values in the east (31–194 mg HC/g TOC, avg. 74 mg HC/g TOC). In the upper Shahai Formation, HI values of the measured samples are slightly similar between the west (avg. 204 mg HC/g TOC) and the east (avg. 214 mg HC/g TOC).
The coeval Tmax values in the east are higher than those in the west (Fig. 5; Table 1). The average Tmax values of the lower and upper Jiufotang Formation, lower and upper Shahai Formation in the west are 451 ℃, 446 ℃, 437 ℃, and 452 ℃, respectively. Notably, abnormally high Tmax values (up to 605 ℃) occur at the layer of dolerite intrusion (132–251 m; Fig. 5a). The average Tmax values of the lower and upper Shahai Formation in the east are 484 ℃ and 443 ℃, respectively.
4.2 Organic petrography
The maceral composition of mudstones in the Jiufotang Formation of borehole FY2 is rich in liptinite, primarily dominated by lamalginite (Fig. 6a and b). The lamalginite exhibits a sheet-like shape and emits a yellow fluorescence (Fig. 6b). The fusinites are also prevalent in the mudstone beds of the Jiufotang Formation (Fig. 6c). Similar maceral compositions are observed within the mudstones of the lower Shahai Formation (Fig. 6d–f). Abundant lamalginite is distributed as isolated flakes with a greenish-yellow fluorescence in the mudstones from the lower Shahai Formation (Fig. 6d). Significant occurrence of bituminite with a yellow fluorescence is also observed (Fig. 6e). The fusinites are recorded as a bulk block in the mudstone beds of the lower Shahai Formation (Fig. 6f). The maceral composition of the mudstones from the upper Shahai Formation comprises abundant liptinite macerals, including alginate and sporinite (Fig. 6g–i). The alginate is predominated by telalginite and lamalginite (Fig. 6g and h). The sporinite is also reported, showing hollow and clear edges with a yellow-green fluorescence (Fig. 6i).
Representative maceral photomicrographs of Borehole FY2: a 1248.45 m, lamalginite; b 1278.54 m, lamalginite; c 1278.54 m, fusinite; d 834.45 m, bituminite; e 834.45 m, vitrinite; f 874.45 m, fusinite; g 548.30 m, lamalginite; h 530.00 m, telalginite; i 435.10 m, sporinite, lamalginite. Photomicrographs a–d were taken from the upper K1jf samples, d–f represent the lower K1sh, while g–i were taken from the upper K1sh
4.3 Molecular geochemistry
4.3.1 Saturate biomarkers
The distribution of saturate biomarkers in source rocks and crude oils from the Jiufotang Formation is similar, with both characterized by a high gammacerane content (Fig. 7a and b). Regular steranes distribution in the Jiufotang Formation shows the predominance of C29 regular steranes (38–53%, avg. 46%), followed by C27 (23–38%, avg. 29%) and C28 (21–28%, avg. 26%, Fig. 7a; Table 2), which is similar to the distribution of observed in the crude oils from the Jiufotang Formation (average C29 is 52%, C27: 25%; C28: 23%, Fig. 7b; Table 3). Both the source rock intervals and crude oils of the Jiufotang Formation are characterized by a high 3-methyl–24-ethylcholestane content (peak 4 in Fig. 7a and b) versus a low content of 4-methyl–24-ethylcholestane (peak 2 in Fig. 7a and b) and dinosterane (peak 1 in Fig. 7a and b).
Gas chromatograms, m/z 191, m/z 217 and m/z 231 mass chromatograms of saturated hydrocarbon for representative source rock and crude oil samples. Note, Peak 4: 3-methyl–24-ethylcholestane, Peak 2: 4-methyl–24-ethylcholestane; Peak 1: dinosterane
The distribution of saturate biomarkers in the source rocks of the lower Shahai Formation is different from the crude oil recovered from the coeval reservoir, although both contain high gammacerane contents (Fig. 7c–e). Source rocks of the lower Shahai Formation in the west are characterized by the low pristane/phytane (Pr/Ph) (avg. 0.78) and C27 regular sterane contents (avg. 27%) compared to coeval source rocks from the east (Pr/Ph avg. 1.48 and C27 avg. 39%, Fig. 7c and d; Table 2). The distribution of the 4-methyl–24-ethylcholestane, 3-methyl–24-ethylcholestane, and dinosterane of the crude oils from the lower Shahai Formation is more consistent with the source rocks and crude oils from the Jiufotang Formation rather than that of the source rocks from the lower Shahai Formation (Fig. 7a–e; Table 2).
The source rocks and crude oils of the upper Shahai Formation are characterized by a low content of gammacerane (Fig. 7f–h). The source rocks in the west are dominated by high Pr/Ph ratios and C29 regular sterane contents, while the source rocks and crude oils in the east are characterized by the predominance of C27 diasteranes and regular sterane (Fig. 7f–h). The distribution of 4-methyl-24-ethylcholestane, 3-methyl-24-ethylcholestane, and dinosterane in source rocks and crude oils of the upper Shahai Formation (Fig. 7f–h).
4.3.2 Aromatic biomarkers
The distribution of aromatic biomarkers in source rocks and crude oils from the Jiufotang Formation exhibits slight differences (Fig. 8a and b). Source rocks show relatively high concentrations of phenanthrene (P), 1-methylphenanthrene (MP), and 9-MP versus low contents of 2-MP and 3-MP compared to crude oils. As a result, the methylphenanthrene index (MPI-1) of source rocks (avg. 0.59) is lower than that of crude oils (avg. 0.91; Tables 2 and 3). For the trimethylnaphthalenes (TMN) and tetramethylnaphthalenes (TeMN) of source rocks and crude oils, the 1,3,6-TMN and 1,3,6,7-TeMN show the highest peaks in the m/z170 and m/z 184 mass chromatograms (MC), respectively (Fig. 8a and b). Moderately triaromatic dinosteranes are detected in most samples of the studied intervals (Fig. 8).
M/z 78 + 192, m/z 170 + 184 and m/z 245 mass chromatograms of aromatic hydrocarbon for representative source rock and crude oil samples. Note, Peak 7: C29 triaromatic steroids; peak 8: 4-methyl–24-ethyltriaromatic steroids (C29); peak 9: 3-methyl–24-ethyltriaromatic steroids; peak 11: 4-methyltriaromatic steroids (C27); peak 12: 3-methyltriaromatic steroids (C27); peak 13: 3-methyl–24-methyltriaromatic steroids (C28) (after Huang et al. 2016)
The aromatic biomarkers attest to distinct differences between the source rocks and crude oils from the lower Shahai Formation (Fig. 8c–e). In the east, the MPI-1 of the source rocks in the lower Shahai Formation (avg. 1.05) is much higher than that of source rocks (avg. 0.4) and crude oils (avg. 0.72) in the west (Table 3). The source rocks in the west are characterized by the highest 1,3,6-TMN in the m/z170 (Fig. 8c), while the source rocks in the east are dominated by the highest dibenzothiophene (DBT) in m/z184 MC (Fig. 8d). Coeval crude oils from the lower Shahai Formation have high contents of 1,3,6,7-TeMN (Fig. 8e), which is very similar to that of crude oils from the Jiufotang Formation (Fig. 8b). The triaromatic dinosteranes are not detected in the samples from the east (Fig. 8d).
In the upper Shahai Formation, the distribution of aromatic biomarkers is consistent in source rocks and crude oils (Fig. 8f–h). The MPI-1 of source rocks (avg. 0.26) in the west is much lower than that of source rocks (avg. 0.47) and crude oils (avg. 0.51) in the east (Table 3). Unlike the samples from other intervals, the TMN and TeMN of the upper Shahai Formation are characterized by the highest peaks of 1,2,5-TMN and coeluting 1,2,5,6- and 1,2,3,5-TeMN in the m/z170 and m/z 184 MC, respectively (Fig. 8e and f).
4.4 Burial and generation history
During the evolution of the Fuxin Basin, the Lower Cretaceous strata underwent deep burial diagenesis. The maximum burial depth in the west (3300 m; Fig. 9a) is significantly shallower than that in the east (4600 m; Fig. 9b). Moreover, the western part of the basin was subjected to earlier uplifting (ca. 107 Ma) compared to the eastern part (ca. 100 Ma) (Fig. 9). In the west, source rocks initiated the processes of the (0.7% Ro), peak (1.0% Ro), and late stages of oil generation (1.3% Ro) at 112 Ma, 108 Ma, and 107 Ma, respectively (Fig. 9b). Conversely, the corresponding stages in the east occurred notable are obviously earlier (117 Ma, 111 Ma, and 107 Ma; Fig. 9b) than those in the western part.
5 Discussion
5.1 Hydrocarbon generation of the Fuxin Basin
5.1.1 Source rock evaluation
The source rocks of the lower Jiufotang Formation in the Fuxin Basin are characterized by the least OM richness (avg. 1.0 wt%) and poor hydrocarbon generation potential (S1 + S2) (avg. 1.5 mg HC/g rock) (Fig. 10; Table 1). In contrast, the source rocks from the upper Jiufotang Formation in the west are dominated by good OM richness with average TOC values of 1.97 wt% and fair to good hydrocarbon generation potential (avg. 5.6 mg HC/g rock) (Tissot and Welte 1984), with some source rocks having very good potential to generate hydrocarbons (S1 + S2 up to 18.8 mg HC/g rock) (Table 1; Peters and Cassa 1994). The lower Shahai Formation exhibits excellent hydrocarbon generation potential in the west (Fig. 10). However, most samples of the lower Shahai Formation in the east have poor to fair hydrocarbon potential, except for two coal-bearing seams that show excellent generation potential (Peters and Cassa 1994). The upper Shahai Formation source rocks are dominated by poor to good hydrocarbon generation potential in the west with five intervals encountering very good to excellent hydrocarbon potential with S1 + S2 values up to 25.6 mg HC/g rock (Table 1). The upper Shahai Formation in the east is characterized by poor to very good hydrocarbon potential with average values of 6.7 mg HC/g rock (Table 1).
Hydrocarbon potential of source rocks from the Jiufotang and Shahai formations in the boreholes FY2 (a) and DY-1 b (according to Peters and Cassa (1994))
The lower Jiufotang Formation is dominated by significantly low HI values (avg. 102 mg HC/g TOC), suggesting a prevalent kerogen Type III (perhydrous) of terrestrial organic matter (Peters and Cassa 1994; Carvajal-Ortiz and Gentzis 2015) (Table 1). The HI of the upper Jiufotang Formation in the west can be divided into two groups (Fig. 11). The lower intervals are characterized by low HI values (< 200 mg HC/g TOC) compared to the upper intervals with higher values (> 300 up to 509 mg HC/g TOC), implying kerogen Types III and II, respectively (Fig. 11) (Peters and Cassa 1994). Additionally, the abundant lamalginite in the upper intervals is also consistent with oil-prone kerogen type II (Fig. 6a and b) (Pickel et al. 2017; Xie et al. 2021b). Except for the certain occurrence of kerogen Type III of the lower Shahai Formation in the west, the kerogen is dominated by Types II and I with high HI values up to 702 mg HC/g TOC (Fig. 11). On the contrary, the lower Shahai Formation in the east is dominated by the lowest HI values throughout the Fuxin Basin (avg. 74 mg HC/g TOC), suggesting kerogen Types III to IV (Fig. 11). These differences in kerogen types can be attributed to terrestrial export efficiency (Mansour and Wagreich 2022), whereby the greater supply of terrigenous OM took place in the east compared to the west (Fig. 6f). These results are further supported by organic petrographic investigations, where liptinite macerals are prevalent in the west as opposed to vitrinite from carbonaceous mudstone and coal seams that is dominated in the east (Fig. 6d and e). The HI values of the upper Shahai Formation in the west are highly variable (2–488 mg HC/g TOC), indicating kerogen Type IV of inert OM to Types III, III/II, and II of gas to oil-prone OM, respectively (Fig. 11). Similar kerogen types are indicated for coeval intervals to the east, based on low to moderate HI values that are in the range of 54–334 mg HC/g TOC, suggesting predominance of kerogen Types III to III/II with minor samples of kerogen Type II (Fig. 11). In addition, the oil-prone maceral of lamalginite, telalginite and sporinite are prevalent in some intervals of the upper Shahai Formation (Fig. 6g–I), reinforcing the occurrence of Type II kerogen (Pickel et al. 2017; Xie et al. 2022).
The Jiufotang Formation in the west is dominated by high Tmax values (avg. 448 ℃; Fig. 11), which are in the peak stage of the oil window. The Ro values of the lower (0.99–1.06%) and upper Jiufotang Formation (0.88–0.98%) (Table 1), also indicate peak stages of hydrocarbon generation (Peters and Cassa 1994; Carvajal-Ortiz and Gentzis 2015), which are in agreement with the Tmax values. The deposits of the lower Shahai Formation experienced different stages of thermal maturity between the western and the eastern parts of the Fuxin Basin. In the east, the Tmax values are in the range of 457–519 °C in the east that are consistent with high Ro values (ca. 1.95%), indicating a postmature stage of dry gas window (Peters and Cassa 1994). In contrast, coeval intervals in the west are characterized by Tmax values of 432–443 °C, revealing early to peak stages of the oil window. The upper Shahai Formation in the west is dominated by low to moderate Tmax values of (avg. 436 °C), revealing an early stage of oil window (Fig. 11), except for two samples at the top are in the postmature stage of dry gas (Fig. 11). These samples are also characterized by abnormally high vitrinite reflectance (up to 2.32%; Fig. 5a), suggesting that the postmature stage is triggered by the thermal effect of the Cenozoic intrusive dolerite (Jia et al. 2021). Tmax values of the upper Shahai Formation in the east are considerably varied from low to high values with increasing burial depth in the borehole DY1 (Table 1), indicating early to late stages of the oil window (Fig. 11). This is in agreement with the gradual increase in Ro values with depth (0.62 to 1.11%) (Fig. 5b).
In summary, we deduced that the upper Jiufotang Formation in the west and the upper Shahai Formation in the east represent the primary source rocks for oil generation in the Fuxin Basin, based on the geochemical and organic petrographic investigations.
5.1.2 Hydrocarbon generation history
The burial, thermal, and hydrocarbon generation histories of source rocks in Fuxin Basin are different in the west and east due to active tectonism triggered by the Waziyu detachment fault in the east (Fig. 2) (Jia et al. 2021; Xu et al. 2022). In the west, the subsidence burial continued throughout the Jiufotang Formation (Jia et al. 2021). After significant basin filling, the maximum burial depth of the Jiufotang Formation reached up to 3300 m in the west (Fig. 9a), recording a maximum paleotemperature regime of ca. 160 ℃ (Jia et al. 2021). The source rocks from the Jiufotang Formation in the west reached the peak stage of oil generation, despite the tectonic uplifting that occurred in the west of the basin from the end deposition of the Fuxin Formation (ca. 107 Ma) (Fig. 9a). The Shahai Formation in the west underwent relatively shallow burial depths (ca. 2000 m; Fig. 9a). As a result, source rocks in the lower Shahai Formation had just entered the peak stage of oil generation, while the source rocks from the upper Shahai Formation did not reach the threshold of hydrocarbon generation (Fig. 9a).
In the east of the basin, a higher geothermal gradient and burial depth existed compared to the west (Fig. 9b). Due to high burial depth and paleogeothermal temperature gradient, the Jiufotang strata in the east entered the stage of dry gas generation during the end of burial (Figs. 9 and 11). With the rapid subsidence burial, the source rocks of the lower Shahai Formation underwent short-term oil generation and entered the stage of gas generation (Fig. 9). The source rocks of the upper Shahai Formation entered the peak stage of oil generation at ca. 117 Ma, and their maximum maturity reached as evidenced by high Ro values (1.1%) (Fig. 9b). Although the eastern part the basin was subsequently uplifted during the late deposition of the Sunjiawan Formation (100 Ma), the hydrocarbons generation took place due to higher paleogeothermal temperatures (Fig. 9b).
5.2 Hydrocarbon migration of the Fuxin Basin
Oil-source correlation analysis of a sedimentary basin with a multi-source petroleum system can detect the source and migration of hydrocarbon (Huang et al. 2016; Chen et al. 2018b; Safaei-Farouji et al. 2021; Wu et al. 2021; Zhu et al. 2021a, b). In this study, oil-source correlations through biomarker analysis were carried out to determine the hydrocarbon migration of the Fuxin Basin.
5.2.1 Hierarchial cluster analysis of the crude oils
Integrating biomarker parameters along with their relationships with each other and cross plots of ratios lead to robust and yet reliable interpretations (Peters et al. 2005; Wang et al. 2016; Wu et al. 2021). However, hierarchical cluster analysis (HCA) of multiple biomarker parameters can contain more information and has more advantages than a simple comparison of cross plots, so it is widely applied to oil-source correlation (Fu et al. 2019; Xiao et al. 2019; Safaei-Farouji et al. 2021). In total, 20 biomarker parameters, including Pr/Ph ratio, odd-over-even predominance (OEP), gammacerane index (GI), (C27 + C28)/C29 regular sterane, dinosterane index (DSI), 4-methylsterane index (4MSI), MPI-1 and triaromatic dinosteroids hydrocarbon index (TDSI), etc., were implemented for the HCA analysis using within-groups linkage method (Table 3).
The results of the HCA analysis categorized all crude oils from the Fuxin Basin into two main groups, namely Type A and Type B (Fig. 12). Type A consists of four crude oils from the Jiufotang and lower Shahai formations of the borehole FY2 (Fig. 12), which are characterized by high gammacerane, low Pr/Ph, relatively high C29 regular sterane and MPI-1 (Figs. 7 and 8). On the other hand, Type B is composed of two crude oils from the upper Shahai Formation of the boreholes DY1 and FD1 in the east (Fig. 12), which are featured by low gammacerane, moderate Pr/Ph, high C27 regular sterane and 1,2,5-trimethylnaphthalenes (Figs. 7 and 8). Based on these findings, we investigated the genetic relationship between the deduced two types of crude oils and the encountered source rocks in the Jiufotang and Shahai formations in the following subsection.
Results of hierarchial cluster analysis of the crude oils using the biomarkers parameter
5.2.2 Oil-source correlations
The most significant difference between Type A and Type B crude oils lies in the content of gammacerane (Figs. 7, 8 and 13a). In general, high values of the gammacerane index (GI) are indicative of saline and stratified water column (Sinninghe Damsté et al. 1995; Song et al. 2019, 2021). High GI values in the Jiufotang (avg. 0.61) and lower Shahai formations (avg. 0.22) indicate saline water column and/or enhanced water column stratification during the deposition of source rocks (Fig. 13a). Type A crude oil is also characterized by high GI values (avg. 0.39), consistent with the source rocks from the Jiufotang (avg. 0.61) and lower Shahai formations (avg. 0.22) (Fig. 13a). In contrast, the upper Shahai Formation is characterized by low GI values (avg. 0.10), indicating a freshwater environment during the deposition (Fig. 13a; Table 2) (Xie et al. 2021a; Bai et al. 2022). Similarly, Type B crude oil also has the lowest GI values (avg. 0.07), suggesting its source from the upper Shahai Formation source rocks (Fig. 13a). However, source rocks in the upper Shahai Formation in the west are still in the early stage of the oil window (Fig. 11), and have not yet generated abundant hydrocarbons (Fig. 9a). Conversely, the source rocks in the upper Shahai Formation in the east are in the peak stage of the oil window (Figs. 9a and 11). Therefore, Type B crude oil was more likely derived from the upper Shahai Formation source rocks in the east of the basin.
a Cross–plots of Pr/Ph and gammacerane index in boreholes FY2 and DY1, respectively. b Ternary diagram of regular steranes from borehole FY2 to the west and borehole DY1 to the east; c Plots of the Log (1,2,7-TMN/1,3,7-TMN) versus Log (1,2,5-TMN/1,3,6-TMN) in boreholes FY2 and DY1, respectively; d Conversion formula between methylphenantherene index (MPI-1) and Tmax of the K1jf and K1sh in Fuxin Basin. Stratigraphic symbols are the same as in Fig. 2
Additionally, the ternary diagram of regular steranes suggests a mixed OM source with an overwhelming contribution of terrestrial plants during the deposition of source rocks as well as Type A crude oil from the Jiufotang and lower Shahai formations (Fig. 13b). However, the source rock and Type B crude oil from the upper Shahai Formation in the east observed the highest C27 contents, followed by C29 and C28 steranes, suggesting a significant contribution of lake planktonic and bacterial material (Figs. 7g, h and 13b). This change in the OM source is largely related to lake expansion and/or an increase in the lake level during the deposition of the upper Shahai Formation. At this time, the continuous tectonic subsidence resulted in a semi-deep lake environment, promoting algal blooms (Fig. 3). Furthermore, the source rocks from the Jiufotang and lower Shahai formations along with Type A crude oil from borehole FY2 have high contents of 1,3,6-TMN (Figs. 8a–e and 13c), while the source rocks and Type B crude oil from the upper Shahai Formation in the east are rich in 1,2,5-TMN (Fig. 8g–h and 13c). Therefore, our results from the regular steranes distribution and the TMN provide further emphasis on the source of crude oils, reinforcing that Type B crude oil was derived from the source rocks in the upper Shahai Formation in the east. Whereas Type A crude oil was generated from the Jiufotang and lower Shahai formations in the west.
Despite the source of Type A crude oil remains partially debatable due to significant similarities in OM sources and depositional environment between the Jiufotang and lower Shahai formations in the west (Fig. 13a and b), such crude oil is most likely generated from the Jiufotang Formation source rocks intervals. This argument is supported by the fact that Type A crude oil and Jiufotang Formation source rock have similar maturity levels and 3-methyl–24-ethylcholestane contents compared to the lower Shahai Formation source rocks (Fig. 8a–e). We established a conversion relationship between the MPI-1 and Tmax in the Jiufotang and Shahai formations (Fig. 13d). Calculated Tmax values of Type A crude oil in borehole FY2 are in the range of 455–471 ℃ (avg. 460 ℃, Table 3), which is close to average Tmax values of the Jiufotang Formation (448 ℃) compared to the much higher difference than that of the lower Shahai Formation (438 ℃, Table 1). In addition, the source rocks in the Jiufotang Formation and Type A crude oil are featured by high 3-methyl-24-ethylcholestane contents (peak 4 in Fig. 8a, b and e) versus low contents of 4-methyl-24-ethylcholestane (peak 2 in Fig. 8a, b and e) and dinosterane (peak 1 in Fig. 8a, b and e). On the contrary, the source rocks of the lower Shahai Formation exhibit the lowest content of 3-methyl-24-ethylcholestane and relatively high concentrations of 4-methyl-24-ethylcholestane and dinosterane (Fig. 8c and d). Therefore, Type A crude oil is most likely generated from the source rocks of the Jiufotang Formation.
5.2.3 Geological analysis of the oil-source correlation results
The oil-source correlation and related geological data were comprehensively analyzed to determine their reliability. Type A crude oil is predominantly stored in the reservoir units of the upper Jiufotang and lower Shahai formations in the western part of the Fuxin Basin (Fig. 4a). The oil-source correlation results suggests that these crude oils originated from the source rocks of Jiufotang Formation in the west, especially the upper intervals, which then migrated to the reservoirs of the lower Shahai Formation through epigenetic active faults (Fig. 4a). These faults were widely developed within the Fuxin Basin in response to the tectonic activity of the Waziyu detachment fault (Zhang et al. 2012; Jia et al. 2021). The epigenetic active faults are generally supposed to be the migration pathway of Type A crude oil (Teng et al. 2019; Su et al. 2021).
On the other hand, the upper Shahai Formation source rocks of boreholes DY1 and FD1 in the east are suggested to be the source of Type B crude oil (Fig. 12). These intervals generated Type B crude oil at the peak stage of the oil window due to higher geothermal gradient and burial depth in the basin (Fig. 9) (Jia et al. 2021). This was followed by enhanced oil migration and storage into sand bodies of subaqueous fan that shows high porosity and permeability in the upper Shahai Formation (Fig. 3) (Li et al. 1985). In addition, a considerable amount of oil spots was reported in zones of fault breccia (Fig. 4i), indicating that these faults may serve as another migration pathway of crude oil. The crude oil that migrated to the upper Shahai Formation reservoir through these faults is more likely to originate from the mature upper Shahai Formation source rocks than postmature lower Shahai Formation source rocks (Fig. 11).
5.3 Dynamic processes of hydrocarbon generation and migration
During the Early Cretaceous, the NCC was undergoing the most significant destruction, accompanied by intense magmatic and extensional activities (Liu et al. 2013; Zhu et al. 2021b). This strong extensional activity has led to the formation of the metamorphic core complex (MCC) and extensional domes, as well as the development of numerous rift basins, including the Fuxin Basin (Fig. 1a) (Zhu et al. 2020, 2021b). The Fuxin Basin area, located in the northern margin of the NCC (Fig. 1a), experienced significant depositional history and evolution controlled by multiple extensional tectonism related to the thinning and destruction of the NCC during the Early Cretaceous, such as Yiwulüshan MCC, Waziyu detachment fault (Fig. 2) (Jia et al. 2021; Sun et al. 2022). The timing of detachment tectonism is related to the MCC development (40Ar/39Ar, 132–98 Ma) (Zhang et al. 2012; Lin et al. 2013; Liang et al. 2022), consistent with the volcano-sedimentary records in the Fuxin Basin (ca. 130–100 Ma; Jia et al. 2021). The transition between the Yixian volcanic eruption and the Jiufotang sedimentary filling (~ 124 Ma) corresponds to the peak of the NCC destruction (~ 125 Ma; Zhu and Xu 2019). Subsequently, the rapid uplift and cooling of the Yiwulüshan MCC (125–110 Ma) controlled the maximum subsidence of the Fuxin Basin (Fig. 9) (Lin et al. 2013). During this period, excellent lacustrine source rocks were widely deposited in the Jiufotang and upper Shahai formations of the Fuxin Basin (Fig. 14a) (Jia et al. 2021; Xie et al. 2021a). With increasing the sedimentary burial, the temperature regime gradually increases, and thus these source rocks gradually entered different stages of the oil window (Fig. 9). However, significant hydrocarbon generation in the east began at 117 Ma (~ 0.7% Ro, upper Shahai Formation) and was earlier than that in the west (112 Ma, Jiufotang Formation) (Fig. 9). This difference was related to thicker sedimentary fill in the east than that of the west caused by the Waziyu detachment tectonism (Fig. 14a). Furthermore, the shear heating associated with the rapid uplift and exhumation of the MCC further enhanced the geothermal gradient in the east (Fig. 14a). Therefore, the Yiwulüshan MCC and Waziyu detachment fault, related to the thinning and destruction of the NCC during the Early Cretaceous, played a significant role in promoting the development of high-quality source rocks and affecting the hydrocarbon generation history of the Fuxin Basin.
A model illustrating the modes of generation and migration of the hydrocarbons in the Fuxin Basin during the Cretaceous evolution in the northern margin of North China Craton. The grid of this profile is based on the seismic profile from Fig. 2
The basin simulation results reveal that the Fuxin Basin experienced significant uplifting during the end of the Early Cretaceous and earliest Late Cretaceous (Fig. 9). This uplift and exhumation process of the Fuxin area could be related to the compression, caused by the subduction of the Western Pacific plate during the earliest Late Cretaceous (Zhu and Xu 2019). This compressive event terminated the Early Cretaceous peak destruction and associated, intense extension. Simultaneously, a series of lower Cretaceous rift basins in the Craton began to reverse, uplift and die out (Zhang et al. 2019; Zhu et al. 2021a, b). The rapid uplift of the Fuxin Basin during the Late Cretaceous induced some fault activity and the formation of massive fractures, promoting the apparent migration of large-scale hydrocarbon fluids (Fig. 14b). Direct evidence of hydrocarbon migration is observed in the flowing or remaining oils stored in fractures of various strata from the Jiufotang to the Sunjiawan formations (ca. 124–100 Ma; Fig. 4). To sum up, the thinning and destruction of the NCC during the Early Cretaceous promoted the formation of the Fuxin Basin and its hydrocarbon generation. On the other hand, the rapid subduction of the Western Pacific plate during the earliest Late Cretaceous reformed the major structural elements of the Fuxin Basin, leading to large-scale hydrocarbon migration (Fig. 14b).
6 Conclusions
In this study, the Lower Cretaceous extensional fault basin in the Fuxin area of NE China was investigated. The development and formation of the Fuxin Basin were found to be closely associated with the Cretaceous evolution of the NCC, which had a significant impact on the processes of hydrocarbon generation and migration, previously unexplored in the Fuxin Basin. The following conclusions were developed.
-
(1)
The intervals of the upper Jiufotang Formation in the west and the upper Shahai Formation in the east contain good source rocks in the Fuxin Basin. The upper Jiufotang Formation source rocks with kerogen types II to III (perhydrous) are dominated by good hydrocarbon potential. Whereas very good hydrocarbon generation potential was detected in the upper Shahai Formation source rocks with kerogen types II to III. All source rocks have entered the peak stage of hydrocarbon generation.
-
(2)
Crude oils produced from the reservoirs of Jiufotang and lower Shahai Formations of borehole FY2 in the west are characterized by high GI, MPI-1, and (C27 + C28)/C29 regular sterane ratios. These crude oils derived from the upper Jiufotang Formation source rocks were migrated to the lower Shahai Formation reservoir through epigenetic active faults. In contrast, crude oils in the upper Shahai Formation reservoir of boreholes DY1 and FD1 are dominated by low gammacerane and MPI-1 compared to relatively high (C27 + C28)/C29 regular sterane ratios in the east. These crude oils are inferred to originate from the source rocks in the upper Shahai Formation.
-
(3)
The thinning and destruction of the NCC during the Early Cretaceous promoted the formation and evolution of the Fuxin Basin, leading to the development of excellent source rocks in lacustrine environments. The coeval extensional tectonism related to the NCC destruction resulted in different hydrocarbon generation histories between the west and the east in the Fuxin Basin. The subduction of the Western Pacific plate during the Late Cretaceous caused the rapid uplifting of the Fuxin area, which triggered the development of numerous epigenetic fractures crossing various strata. We infer that such a dynamic evolutionary process has promoted the hydrocarbon migration of the Fuxin Basin.
Data availability
No dataset was generated or analyzed during this study.
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Acknowledgements
We express our sincere gratitude to Changsheng Miao, Jianyi Qin, and Yanjia Wu for their valuable assistance in the basic geological survey and sedimentology. This work was supported by the National Natural Science Foundation of China (42372138), the Project of China Geological Survey (Grant No. DD20221807), and the Basic Scientific Research Fund of the Ministry of Science and Technology of China (Grant No. J2304).
Funding
This study was supported by the National Natural Science Foundation of China (42372138), the Project of China Geological Survey (Grant No. DD20221807), and the Basic Scientific Research Fund of the Ministry of Science and Technology of China (Grant No. J2304).
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WX: Writing-Original draft preparation, Editing. JJ: Supervision, Guidance, Editing. AM: Editing. XW: Guidance of basic geology and investigation.
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Xie, W., Jia, J., Mansour, A. et al. Hydrocarbon generation and migration in the Fuxin Basin during the Cretaceous evolution of the North China Craton, NE China. Geomech. Geophys. Geo-energ. Geo-resour. 9, 148 (2023). https://doi.org/10.1007/s40948-023-00687-0
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DOI: https://doi.org/10.1007/s40948-023-00687-0