Multi-stage primary and secondary hydrocarbon migration and accumulation in lacustrine Jurassic petroleum systems in the northern Qaidam Basin, NW China

Marine and Petroleum Geology 62 (2015) 90e101

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Research paper

Multi-stage primary and secondary hydrocarbon migration and accumulation in lacustrine Jurassic petroleum systems in the northern Qaidam Basin, NW China Tingting Wang a, Shaoyong Yang b, Shengsheng Duan b, Haitao Chen c, Haizhen Liu c, Jian Cao a, * a b c

State Key Laboratory for Mineral Deposits Research, Department of Earth Sciences, Nanjing University, Nanjing 210023, China Department of Exploration Enterprise, PetroChina Qinghai Oilfield Company, Dunhuang 736202, China Research Institute of Exploration and Development, PetroChina Qinghai Oilfield Company, Dunhuang 736202, China

a r t i c l e i n f o

a b s t r a c t

Article history: Received 14 November 2014 Received in revised form 27 January 2015 Accepted 31 January 2015 Available online 7 February 2015

To improve the understanding on lacustrine Jurassic petroleum migration and accumulation in the northern Qaidam Basin (NW China), we conduct an integrated analysis of the petrography and geochemistry of oil-bearing fluid inclusion, including inclusion petrography, homogenization temperature combined with reservoir burial and thermal history, and reservoir sequential extraction. Results show that during the first stage of late Oligocene to early Miocene, the deep Paleogene reservoir was first charged by oils sourced from Middle Jurassic rocks (petroleum inclusion). This charge was accompanied by some oil alteration. During the second stage of early to middle Miocene, the deep Paleogene reservoir was charged by Lower-Jurassic-sourced oils (intergranular free oil) and this charging event is different from the first one in that it witnessed little hydrocarbon alteration. During the third stage in the Pliocene, widespread gas sourced from Lower and Middle Jurassic rocks occurred in both the deep Paleogene and shallow Neogene reservoirs and primary oil accumulations in deep Paleogene reservoirs migrated vertically to shallow Neogene reservoirs along faults, and formed secondary accumulations. Little alteration took place, favorable for the remigration. Thus, the lacustrine Lower and Middle Jurassic petroleum systems in the northern Qaidam Basin represent multi-stage primary and secondary hydrocarbon accumulations and mixing of hydrocarbons was very common. © 2015 Elsevier Ltd. All rights reserved.

Keywords: Secondary hydrocarbon accumulation Oil-bearing fluid inclusion Reservoir sequential extraction Hydrocarbon remigration Lacustrine Jurassic Qaidam Basin

1. Introduction The Qaidam Basin of northwestern China is a large superimposed petroliferous basin that contains three major petroleum systems: PaleogeneeNeogene saline lacustrine oil in the southwestern basin (Hanson et al., 2001; Zhu et al., 2004; Feng et al., 2013); Jurassic fresh lacustrine and paludal oil and gas in the northern basin (Zhang et al., 2005; Cao et al., 2008a, b, 2012); and Quaternary biogenic gas in the eastern basin (Wei et al., 2005; Ma et al., 2008; Zhang et al., 2014). Of these three systems, the Jurassic system has a long exploration history, and has been an important research area, as this system represents a critical part of the Middle-Asia Jurassic coal-type hydrocarbon realm system (Ritts et al., 1999; Dai, 2007). Hydrocarbon accumulations with the

* Corresponding author. Tel.: þ86 25 83686719; fax: þ86 25 83686016. E-mail address: [email protected] (J. Cao). http://dx.doi.org/10.1016/j.marpetgeo.2015.01.015 0264-8172/© 2015 Elsevier Ltd. All rights reserved.

same origin have been widely found in the neighboring Tarim, Junggar, and Turpan basins (Zhao et al., 1996; Dai, 2007; Katz, 2001; Li et al., 2009; Xiao et al., 2009). Previous studies have indicated that there are two dominant source sequences for this Jurassic petroleum system, i.e., the Lower and Middle Jurassic, which can generate both oil and gas (Dang et al., 2003; Wang et al., 2004; Zhang et al., 2005). This means that there are two sub-petroleum systems and reservoirs are believed to have been likely charged by mixed oils and gas, which is typical for superimposed petroliferous basins (Bojesen et al., 1999; Tang et al., 2000; Tian et al., 2007, 2008; Yuan et al., 2011). Thus, understanding the complex hydrocarbon migration and accumulation processes is significant for regional exploration. However, the accumulation history has not been sufficiently investigated. Only some preliminary oil- and gas-correlation and fluid inclusion studies, mainly based on geochemistry have been conducted, with little focus on specific processes (Gao and Chen, 2000; Su et al., 2003; Bao et al., 2013). For example, Gao and

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Chen (2000) used fluid inclusion geochemistry to determine the time and stages of hydrocarbon reservoir filling, but they did not combine these results with petrographic studies and geological setting to reconstruct the process of hydrocarbon migration and accumulation. In this paper, we attempt to reconstruct and model the hydrocarbon migration and accumulation processes using an integrated analysis of petrography and geochemistry of oil-bearing fluid inclusions as this has been suggested to be an effective method of investigating complex, multiple-stage hydrocarbon migration and accumulation histories (Karlsen et al., 1993; Schwark et al., 1997; Tian et al., 2008; Zhang et al., 2012; Xiang et al., 2015). 2. Geological setting 2.1. Tectonic setting, stratigraphy, and oil and gas occurrence The Qaidam Basin is located on the northern margin of the QinghaieTibet Plateau. It is the largest inland basin in the QinghaieTibet Plateau in western China (Fig. 1a and b), with an eastewest length of approximately 850 km, a northesouth width of approximately 150e300 km, and a total area of approximately 121  103 km2 (Xu et al., 2006; Lv et al., 2011). This is a Mesozoic and Cenozoic continental basin and has experienced multiplecycles and multiple tectonic stages evolution over a long period, which can be divided into two main formationetransformation cycles: the Mesozoic faulted basin and the Cenozoic strike-slip basin (Xu et al., 2006). Strata of Jurassic to Quaternary age are present (Fig. 2).

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In the studied Jurassic petroleum systems in the northern Qaidam Basin, the known oil and gas reserves occur mainly in PaleogeneeNeogene reservoirs, and were mostly derived from Jurassic coal-bearing mudstone sequences of Early and Middle Jurassic age, according to oil- and gas-source correlation studies (Gao and Chen, 2000; Su et al., 2003; Bao et al., 2013). These Lower and Middle Jurassic petroleum systems are complex, with multiple sets of sourceereservoirecap-rock combinations, and can be classified into two types (Hong et al., 2001; Zhang, 2004), namely the Paleogene combination and the Neogene combination (Fig. 2). Deeply buried reservoirs are principally developed in Oligocene sandstones and conglomerates, and Oligocene mudstones act as a cap rock. The shallower reservoirs are in Neogene sandstones, with Pliocene mudstones as a cap rock. As shown in Figure 1c, several depressions have developed in the northern Qaidam Basin. The southwestern part of the Nanbaxian area contains the Yibei sag, with Lower Jurassic source rocks. In the northeastern part of the area, the Saishiteng, Gaxi, Yuqia, and Gaqiu sags are found, and contain Middle Jurassic source rocks. Therefore, the Nanbaxian area is the most likely part of the northern Qaidam Basin to be charged by Jurassic mixed oils, and was therefore the study area chosen for this work. Oil test results show that the oil and gas in the Nanbaxian area accumulated in Paleocene, Miocene, and Pliocene reservoirs. The deeply buried Paleogene hydrocarbon accumulation system and shallower Neogene hydrocarbon accumulation system are separated by Oligocene mudstones. Wells X4 and X6 in Figure 1c have oil and gas reservoirs in both deep (E3) and shallow (N1 and N2)

Figure 1. The study area. (a) Location of the Qaidam Basin within China. (b) The three petroleum systems in the Qaidam Basin. The red rectangle indicates the study area shown in (c). (c) Structural units and the studied Nanbaxian oil and gas field in the northern Qaidam Basin. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)

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Figure 2. Generalized stratigraphy and sourceereservoirecap-rock combinations in the study area.

reservoirs, whereas the reservoirs of wells X3, X8, and X9 are mainly in the shallow system (N2), and wells X5 and X7 are mainly in the deep system (E3). 2.2. Source rocks Field observations and the results obtained from well drilling suggest that the accumulated oil and gas in the study area was

derived mainly from Lower and Middle Jurassic coal-bearing mudstones, which include dark gray mudstones, black carbonaceous mudstones, and coal measures (Dang et al., 2003; Wang et al., 2004). The Lower Jurassic coal measures have a thickness of around 30 m, but the carbonaceous mudstones are thinner. In contrast, the dark mudstones are relatively thick (up to several hundred meters). Thicker coals and carbonaceous mudstones are present in the Middle Jurassic source sequences, whereas the dark mudstones are

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thinner, in the range 50e100 m. However, the quality of the Middle Jurassic source rocks is better than that of the Lower Jurassic, particularly in the presence of a set of good-quality oil shales (Liu et al., 2007). Both the Lower and Middle Jurassic source rocks are rich in organic matter, with average total organic carbon (TOC) contents of about 4.0% and 5.0%, respectively (Cao et al., 2009). In terms of organic matter type, Lower and Middle Jurassic source rocks contain mainly types IIIeII and IIeI kerogens, respectively. In terms of the thermal evolution of organic matter, the Middle Jurassic source rocks are generally in the immature to mature stage of evolution, whereas the Lower Jurassic has a wide range of thermal maturity, from immature to highly mature, due to different parts of the strata having experienced different burial depths (Liu et al., 2007; Zhai et al., 2013). Therefore, it can be concluded that the Lower and Middle Jurassic source rocks can generate both oil and gas, but the latter tends to generate dominantly oil due to the relatively low maturity and oil-prone kerogen type (Fu et al., 2010). The source rock generation history, which is done by using BasinMod software (Wang et al., 2001) based on regional stratigraphic burial and thermal history data (Dang et al., 2003; Wang et al., 2004), indicates that in the northern Qaidam Basin the Middle Jurassic source rocks, but not the Lower Jurassic source rocks with higher maturity, first reached the peak of hydrocarbon generation and expulsion in the early Oligocene (E13); later the Lower Jurassic source rocks reached the oil generation peak (E23eN1) (Wang et al., 2004). This is due to the difference of bioprecursor and associated activation energy of source rocks. The bio-precursors of the Middle Jurassic source rocks are dominated by Botryococcus, which is a type of bio-precursor favorable for oil generation during early maturation with low activation energy (Zhou et al., 2002; Liu et al., 2007). In contrast, the Lower Jurassic source rocks mainly contain conventional aquatic algae, which have relatively higher activation energy and thus generate oil later than the Middle Jurassic source rocks. Taking all the above elements of source rock generation, the evolution of the source rock generation in different sags of the northern Qaidam Basin was summarized in Figure 3 (Dang et al., 2003; Wang et al., 2004). It is showed that the hydrocarbon generation is discrete even if the activation energy distribution is narrow; differences in burial depth across a basin or sub-basin should broaden the distribution. In addition, the Yibei and Saishiteng sags (Fig. 1c) are the representatives for the Lower and Middle Jurassic sources with big generation volume, respectively (Dang et al., 2003; Wang et al., 2004). In terms of biomarkers, based on hundreds of data, several diagnostic parameters have been suggested to distinguish between

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the Lower and Middle Jurassic source rocks, with little overlap, e.g., the tricyclic terpane C19/C20 ratios, abundance of C30 diahopane, Ts/ Tm value and regular sterane C27R/C29R ratios (Wang et al., 2004; Liu et al., 2007; Cao et al., 2008a; Xu et al., 2008; Bao et al., 2013). First, the tricyclic terpane C19/C20 ratios of the Lower Jurassic and Middle Jurassic rocks are greater than 1.0 and less than 1.0, respectively. This is an indication that the Lower Jurassic and Middle Jurassic rocks were deposited in paludal and lacustrine environments, respectively (Dang et al., 2003; Wang et al., 2004). Second, C30 diahopane is widely detected in the Lower Jurassic source rocks, but not in the Middle Jurassic source rocks, suggesting that this compound is commonly related to the catalysis of clay minerals in coal sequences (Pan et al., 2005), which is characteristic of the Lower Jurassic source rocks (Dang et al., 2003; Wang et al., 2004). Third, the Ts/Tm value of the Lower Jurassic and Middle Jurassic rocks are greater than 3.0 and less than 1.0, respectively. The reason for this large discrepancy is similar to the abundance of C30 diahopane above. Fourth, the regular sterane C27R/C29R ratios of the Lower and Middle Jurassic rocks are less than 0.8 and greater than 1.0, respectively. This means that the Middle Jurassic source rocks contain more aquatic algae and fewer higher plants than the Lower Jurassic rocks in terms of organic maceral composition (Zhou et al., 2002; Liu et al., 2007; Cao et al., 2009). 3. Samples and methods Twenty-three core samples from seven wells were collected for use in an integrated petrologic and geochemical study, incorporating two sets of reservoirs (deeply buried Paleogene and shallowly buried Neogene reservoirs; Table 1). All samples were observed under a microscope to determine the fluid inclusion petrographic characteristics. Subsequently, we completed homogenization temperature measurements of oil-bearing fluid inclusions, which, in combination with the reservoir stratigraphic burial and thermal evolution history, were used to characterize the stages and timing of hydrocarbon charging. This complex process of hydrocarbon charging was further investigated using reservoir sequential extraction. Finally, based on this suite of analytical results and interpretations, together with information on the geological background, the hydrocarbon charging process was reconstructed and a model was developed. Petrographic analysis was carried out on thin sections using a Nikon ECLIPSE LV100NPOL microscope under incident-light, reflected-light, and fluorescent-light modes. The light source used was a 100 W mercury lamp, and photomicrographs were obtained using a Nikon DS-Ri1 digital micrography and imaging system. For

Figure 3. Generalized source rock generation history of different sags in the northern Qaidam Basin (Dang et al., 2003; Wang et al., 2004).

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Table 1 General sample information and results of homogenization temperature (Th) measurements of saline inclusions coeval with petroleum inclusions. Number

Sample

Well

Depth (m)

Formation

Lithology

Th ( C)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

X3-1* X3-2 X4-1 X5-1 X6-1* X6-2*,# X6-3 X6-4 X6-5 X6-6 X6-7 X6-8 X6-9* X6-10 X6-11 X7-1 X7-2 X8-1 X9-1 X9-2* X9-3 X9-4* X9-5

X3

2300.5 2301.9 1815.3 2836.6 1190.9 2839.3 2845.2 2855.3 2987.3 3026.7 3030.9 3033.9 2989.0 3052.9 3408.5 2898.9 2910.3 1550.0 824.3 1216.7 1211.4 1589.3 1533.9

E23 E23 N1 E13 N12 E13 E13 E13 E13 E13 E13 E13 E13 E13 E1þ2 E13 E13 N12 N12 N12 N12 N1 N1

Siltstone Siltstone Sandy conglomerate Siltstone Fine-grained sandstone Siltstone Siltstone Siltstone Medium-to-coarse-grained sandstone Coarse-grained sandstone Sandy conglomerate Sandy conglomerate Fine-grained sandstone Fine-to-medium-grained sandstone Fine-to-medium-grained sandstone Fine-grained sandstone Fine-grained sandstone Fine-to-medium-grained sandstone Siltstone Medium-grained sandstone Sandy siltstone Medium-grained sandstone Medium-grained sandstone

55e121 / / / 76e93 55e115 / / / / / / 50e112 / / / / / / 50e92 / 58e80 /

X4 X5 X6

X7 X8 X9

Note: All samples were petrographically observed in detail. “*”: Samples for the analysis of homogenization temperature (Th) measurements of saline inclusions coeval with petroleum inclusions. “#”: Samples for the analysis of reservoir sequential extraction. “/”: No analytical Th data.

the identification and characterization of petroleum inclusions, the liquid petroleum inclusions are brown or dark brown under transmitted light and display yellow-greenish fluorescence when excited by blue light. In contrast, the gaseous petroleum inclusions are colorless under both transmitted and fluorescent lights. Homogenization temperature measurements were obtained using a microscope-mounted LNKAM THMS-Q 600 heatingefreezing stage. Heatingefreezing stage calibration was carried out using synthetic fluid inclusion standards supplied by FLUID INC. The heating and freezing rates were set to 10  C/min during the initial runs, but reduced to 1  C/min when close to phase transformation. The precision of temperature measurements was about 1  C. The reservoir stratigraphic burial and thermal evolution history is reconstructed by using BasinMod software (Wang et al., 2001) based on actual parameters, such as stratigraphic depth, borehole temperatures, inclusion homogenization temperatures and vitrinite reflectance. Reservoir sequential extraction analysis with separation of free hydrocarbons in pores and inclusion hydrocarbons followed the experimental procedure of Xiang et al. (2015). Briefly, the sample was first crushed into small pieces (1e2 cm) and then several pieces were randomly selected and immersed in dichloromethane (DCM) in flasks for 48 h. The extract obtained in this step is defined as ‘‘free oil’’ or ‘‘mobile oil’’ and is considered to represent the currently reservoired oils. Then, the rest pieces were further crushed and sieved to obtain 0.10e0.30 mm size fraction. After a full cleaning of residual external organic matter, the grains were ground (dry) to powder to liberate oil from oil-bearing fluid inclusions, and then Soxhlet-extracted (DCM:MeOH; 48 h) to obtain the included oil. The reservoir extraction fractions of these two types of hydrocarbon were further analyzed by gas chromatographic (GC) and mass spectrometric (GCeMS) analysis. The GC analysis was performed using a HP6890 GC fitted with an SE-54 elastic silica capillary column. The GC oven temperature was initially held at 80  C for 3 min, increased from 80 to 310  C at 3  C/ min, and then held at 310  C for 20 min with 1 ml/min helium. The GCeMS analysis was carried out using an Agilent 5973 interfaced to

a HP6890 GC fitted with a 30 m  0.25 mm HP-5 column. The inlet temperature of GCeMS analysis was 300  C with 0.8 ml/min helium. The GC oven temperature was initially held at 80  C for 3 min, increased from 60 to 230  C at 3  C/min, from 230 to 310  C at 2  C/min, and finally held at 310  C for 18 min. The mass spectrometer was operated at 70 eV electron energy conditions with an ion source temperature of 230e250  C. The temperature of the transmission line was 250  C using a photomultiplier voltage of 350 V. The effluent of the column was monitored in MID (multiple ion detection) mode.

4. Results and discussion 4.1. Petrography Petrographic observations show that the features of intergranular free oils from the two sets of petroleum accumulation systems (i.e., Paleogene and Neogene) are generally similar. Most free oils occur in primary residual intergranular pores and cracks, are brown in color under plane-polarized light, and display yellow-greenish fluorescence when excited by blue light. In addition, another type of intergranular free oil was identified especially in deep Paleogene reservoirs, with a generally brown to dark red color under planepolarized light and little fluorescence (Fig. 4a and b), indicating the presence of heavy hydrocarbons. This implies that the oils may have experienced alteration, such as biodegradation. In contrast to the intergranular free hydrocarbons, the petroleum inclusions in the two sets of reservoirs (Paleogene and Neogene) show remarkable differences. In the Paleogene samples, inclusions mainly occur in the secondary quartz overgrowths and crack-infilling cements, mostly as liquid and gaseous hydrocarbons, respectively. In contrast, in the Neogene samples, inclusions are dominantly gas and are hosted in secondary quartz overgrowths. This observation implies that gaseous hydrocarbons may have become charged in the reservoir relatively late, and the late gas inclusions are present in both deep- and shallow-buried reservoirs.

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Figure 4. Photomicrographs showing reservoir intergranular free oils and inclusion oils from the Nanbaxian area. (a) and (b) Sample X3-1. (c) and (d) Sample X6-6. (e), (f), (g), and (h) Sample X8-1. The photomicrographs in the left and right columns were captured under transmitted and fluorescent lights, respectively. See Table 1 and Figure 1 for the basic information of the samples.

The types of petroleum inclusion in the reservoir sandstones are complex, and generally include mono-phase gaseous inclusions, mono-phase liquid inclusions, and two-phase fluid inclusions of various shapes. This reflects reservoir charging by multiple types of hydrocarbons.

For mono-phase gaseous inclusions, there are generally two forms. One type is beaded in cracks in quartz grains coeval with other types of petroleum and saline inclusions (Fig. 4c and d). This type mostly occurs in the Paleogene samples. As the beads intersect the cracks, we deduce that the gas charging and associated

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formation of gaseous inclusions occurred relatively late. The other type of mono-phase gaseous inclusion was found in secondary quartz overgrowths in Neogene rocks (Fig. 4e and f), implying that the gas charging events are post-Neogene. For the mono-phase liquid inclusions, there are also two types, mainly distinguished by their fluorescence colors, although both were brown or dark brown under transmitted light. One type displays yellow-greenish fluorescence, which is slightly weaker than that of free oil (Fig. 4g and h), implying that the inclusion oils and free oils may represent hydrocarbons with different origins (e.g., different sources and/or maturities). As these inclusions occur in cracks in quartz grains in the pseudosecondary form, it can be deduced that these inclusions occurred prior to gas charging. The other type of mono-phase liquid inclusions displays yellow fluorescence and was found in secondary quartz overgrowths. Both characteristics are different from those of the first type of monophase liquid inclusions, suggesting that there are at least two stages of oil charging with different origins (e.g., different sources and/or maturities). With respect to the two-phase (gas/liquid) petroleum inclusions, gas bubbles are colorless under both transmitted and fluorescent lights (Fig. 4g and h). These gases were dissolved in oil during reservoir charging. In summary, there are obvious differences between intergranular free oils and inclusion oils. The fluorescence of free oils is slightly stronger than that of inclusion oils. Combined with the different occurrence of these free and inclusion oils as outlined above (Fig. 4), this implies that the oils were formed in at least two stages, although the different fluorescence colors of oils may not directly indicate different maturity/origin (Pironon and Pradier, 1992; George et al., 2001). This understanding is also supported by the following discussion of inclusion homogenization temperatures and reservoir sequential extraction (see Sections 4.2 And 4.3). Combined with the existence of gaseous inclusions and biodegraded reservoir organic matter, it can be preliminarily concluded that the reservoirs in this study experienced at least two stages of oil charging and one stage of gas charging, and there may have been some oil alteration during the reservoir charging.

4.2. Inclusion homogenization temperatures and timing of hydrocarbon charging Based on the petrographic results, a multi-stage oil and gas charging process was preliminarily identified in two sets of reservoir combinations; i.e., the deeply buried Paleogene and shallowly buried Neogene reservoirs. Further insights are provided by inclusion homogenization temperature (Th) measurements. As shown in Figure 5, the Paleogene samples (X3-1, X6-2, and X6-9) generally record three Th ranges, 50e60, 70e80, and 100e120  C. The first two values represent saline inclusions coeval with the oil inclusions, while the last one represents saline inclusions coeval with gas inclusions. In contrast, the Th values of the Neogene samples (X6-1, X9-2, and X9-4) are comparatively concentrated and have a generally continuous distribution, peaking between 60 and 80  C, which includes saline inclusions coeval with both oil and gas inclusions. The Th values display a relatively narrow distribution because the accumulation is generally late within a short interval. However, according to the inclusion petrography, the distribution contains multiple stages, although showing a seeming continuum. The deep Paleogene reservoirs underwent three stages of hydrocarbon charging (two of oil and one of gas), whereas the shallow Neogene reservoirs have mostly experienced one stage (superimposed oil and gas charging). To determine the hydrocarbon charge timing, well X6, which contains both deep and shallow reservoirs, was selected to reconstruct the reservoir burial and thermal evolution histories (Fig. 6). The first stage of hydrocarbon (oil) charging in the deeply buried Paleogene reservoir occurred during the late Oligocene to early Miocene. The second hydrocarbon (oil) charging episode took place during the early to middle Miocene. The third hydrocarbon (gas) charging event took place during the Pliocene. The hydrocarbon filling events in the shallow Neogene reservoirs lasted relatively longer during the late Pliocene compared with that in the deeper Paleogene reservoirs, and involved both oil and gas charging. This event was roughly coeval with the third gas charging stage of the deep Paleogene reservoirs. Therefore, there are discrete hydrocarbon-charging events in the area. The reason for this is because the discrete hydrocarbon generation from different source

Figure 5. Histograms showing the distribution of inclusion homogenization temperatures (Th) in the Nanbaxian area.

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Figure 6. Reconstructed stratigraphic burial and thermal history in the Nanbaxian area based on well X6. The colored bars represent the timing of the main stages of hydrocarbon charging. The location of well X6 is within the structural highs (Fig. 1c) and thus source rock units are not drilled. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)

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sequences developed in different sags and associated hydrocarbon charges (Fig. 6). Using the source rock generation history (Fig. 3), the sources of these three hydrocarbon charges can be inferred. The first oil charging stage in the deeply buried Paleogene reservoirs during the Oligocene to early Miocene represents oil generation in and expulsion from Middle Jurassic source rocks in the sags (especially the representative Saishiteng sag based on oil-source correlation and its biggest hydrocarbon generation potential within the several sags; Wang et al., 2004; Cao et al., 2008a, b; Bao et al., 2013). The second oil charging stage in the deeply buried Paleogene reservoirs during the early Miocene corresponds to oil generation in and expulsion from Lower Jurassic source rocks (especially the representative Yibei sag; Wang et al., 2004). Then, the Lower and Middle Jurassic source rocks began to generate gas from the late Miocene, corresponding to the last stage of gas charging in the deeply buried Paleogene during the Pliocene. This gas also charged the shallowly buried Neogene reservoirs and likely accompanied by remigration of primary oil accumulations in the deeply buried Paleogene reservoirs because not only gas inclusions but also oil inclusions were observed. Since the Pliocene, little oil generation and expulsion and associated primary oil accumulations can take place due to high maturity of source rock in the Saishiteng and Yibei sags (Fig. 3), and thus the oils in the Neogene reservoir are most likely the remigration of primary oil accumulations in the deep Paleogene reservoirs.

Figure 7. Chromatograms from sample X6-2. (a) Gas chromatogram, (b) m/z 191, and (c) m/z 217 mass chromatograms of free oil. (d) Gas chromatogram, (e) m/z 191, and (f) m/z 217 mass chromatograms of inclusion oil. See Table 1 and Figure 1 for the basic information of the samples.

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4.3. Reservoir sequential extraction Analytical results from the reservoir sequential extraction indicate that the free and inclusion oils have different molecular characteristics (Fig. 7; Table 2). Considering the diagnostic parameters that can distinguish between the Lower and Middle Jurassic source rocks (see Section 2.2), some parameters of the free and inclusion oils are suggestive of the Lower Jurassic source, but others indicate the Middle Jurassic source, and some parameters are intermediate between Lower and Middle Jurassic end-member values of rocks and associated oils (Wang et al., 2004; Liu et al., 2007; Cao et al., 2008a; Xu et al., 2008; Bao et al., 2013). This implies that both free and inclusion oils received contributions from Lower and Middle Jurassic rocks and that there was a common oil mixing, further supporting the conclusions derived from the inclusion petrography and Th (see Sections 4.1 and 4.2). This can be exemplified by the four representative oil-source correlation parameters (see Section 2.2 for end member values). (1) The tricyclic terpane C19/C20 ratios of the free and inclusion oils are 1.00 and 0.30, corresponding to Lower and Middle Jurassic source rocks, respectively. (2) C30 diahopane was detected in both free oil and inclusion oil, suggesting that both free and inclusion oils contain components derived from the Lower Jurassic source rocks. (3) The Ts/Tm value of the free and inclusion oils is 3.45 and 1.22, indicative of Lower Jurassic and Middle Jurassic sources, respectively. (4) The regular sterane C27R/C29R values of the free and inclusion oils are 0.74 and 1.10, suggestive of Lower Jurassic and Middle Jurassic source rocks, respectively. This result is the same as for tricyclic terpanes. In summary, in terms of oil sources, the free and inclusion oils may be derived mainly from Lower Jurassic and Middle Jurassic source rocks, respectively, although oil mixing also occurred commonly.

Table 2 Molecular geochemical parameters of free and inclusion oils from sample X6-2. See Table 1 and Figure 1 for the basic information of the samples. Parameter

Free oil

Inclusion oil

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22

C23 1.09 0.13 0.11 0.76 0.19 3.94 C21 1.00 0.49 1.85 0.67 3.45 0.36 0.92 0 0 35 18 47 0.61 0.38

C16、C18 0.25 0.59 0.14 1.23 0.71 17.98 C21 0.30 0.61 1.12 0.43 1.22 0.15 0.56 0.45 0.10 41 22 37 0.46 0.42

1, Peak (maximum concentration) of n-alkanes; 2, OEP; 3, Pr/nC17; 4, Ph/nC18; 5, Pr/ Ph; 6, (Tricyclic þ tetracyclic) terpanes/pentacyclic terpanes; 7, Tricyclic terpanes/ tetracyclic terpanes; 8, Peak carbon of tricyclic terpanes; 9, Tricyclic terpane C19/C20; 10, Tricyclic terpane C20/C21; 11, Tricyclic terpane C21/C23; 12, C24 tetracyclic terpane/(C24 tetracyclic terpane þ C26 tricyclic terpane); 13, Ts/Tm; 14, Gammacerane/ C30 hopane; 15, C31 hopane22S/(22S þ 22R); 16, C29-25-norhopane/C30 hopane; 17, b-carotene/C30 hopane; 18, %C27aaa20R regular sterane; 19, %C28aaa20R regular sterane; 20, %C29aaa20R regular sterane; 21, Regular sterane C2920S/20(S þ R); 22, Regular sterane C29bb/C29(aa þ bb).

With respect to oil maturity, the indicative ratios of C2920S/ 20(S þ R) steranes and C29bb/C29(aa þ bb) steranes are 0.61 and 0.38 for free oil and 0.46 and 0.42 for inclusion oil (Peters and Moldowan, 1993) (Table 2). This, combined with the microscopic observation (see section 4.1), implies that the free oil has higher values in general than the inclusion oil and the slightly higher value of C29bb/C29 (aa þ bb) steranes in the inclusion oil than in the free oil may be ascribed to migration fractionation (Seifert and Moldowan, 1978, 1986). Small amounts of unresolved complex mixture (UCM) and partial presence of n-alkanes are visible in the inclusion oil (Fig. 7d). In particular, the nC16 and nC18 with memorably high relative concentrations may be influenced by contamination (Sherman et al., 2007; Jin et al., 2014). However, this is unlikely in this study. Simultaneous analysis on the free oil displays that the peak of n-alkanes is nC21 rather than nC16 or nC18. The dramatically high concentrations of tricyclic terpanes relative to hopanes and peculiar distribution pattern of tricyclic terpanes (e.g., C21 > C23 > C20 in the inclusion oil) are unusual in contaminants (Jones et al., 1988). Combined with the 25-norhopanes detected in the m/z 177 mass chromatograms, the UCM in the inclusion oil implies that this oil was subjected to biodegradation (Peters et al., 2005). In contrast, the free oil contains no significant amounts of UCM or 25norhopanes, suggesting that it did not experience obvious degradation. This differs from the inclusion oil. 4.4. Multiple-stage hydrocarbon migration and accumulation model In summary, by comprehensively integrating the above results the complex hydrocarbon (oil) migration and accumulation processes in the study area can be determined. Reservoirs in the study area were filled by two stages of oil charging followed by late-stage gas charging. The inclusion oil, derived mainly from the Middle Jurassic source rocks, underwent significant biodegradation and was then mixed with Lower Jurassic undegraded oil. The nonfluorescent hydrocarbons in the intergranular pores, visible under the microscope, are probably degraded oils sourced from the Middle Jurassic rocks. The later-charged free oils in the reservoir, derived mainly from the Lower Jurassic source rocks, are, in general, more mature than the inclusion oils. Subsequent gas charging and oil remigration and dysmigration took place, as shown by the large number of gaseous inclusions and two-phase inclusions observed under the microscope. Based on the above results, combined with information on the geological setting, it is likely to summarize the multiple-stage hydrocarbon migration and accumulation process in the study area and to develop a migration and accumulation model (Fig. 8). During the first stage, from the end of the Oligocene to the early Miocene, the basin changed from strike-slip to compression (Gao et al., 2003). In the Middle Jurassic sags (e.g., the representative Saishiteng sag; Wang et al., 2004; Cao et al., 2008b; Xu et al., 2008; Bao et al., 2013), hydrocarbon generation and expulsion began in the middle Oligocene (Wang et al., 2004, Fig. 3). Expelled oils migrated along basement-cutting faults and accumulated in Paleogene reservoirs of structural highs (e.g., the Nanbaxian area in this study). Oil reservoirs were formed at the end of the Oligocene. During this period, the reservoir is shallowly buried (<1500 m) and the reservoir temperature is lower than 80  C (Fig. 6). This, combined with the activity of reservoir water (Dang et al., 2003; Wang et al., 2004), is favorable for the biodegradation (Connan, 1984; Cai et al., 1996; Li et al., 2010; Tian et al., 2012), as evidenced by dark brown free oils under microscope (Fig. 4a and b) and UCM and 25-norhopanes in molecular geochemistry (Fig. 7d).

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Figure 8. Model showing the multiple-stage filling history of mixed-Jurassic-sourced hydrocarbon migration and accumulation.

During the second stage, in the early to middle Miocene, Himalayan movement was active (Xue and Yang, 2002). Lower Jurassic source rocks in the representative Yibei sag generated and expelled hydrocarbons actively since the late Oligocene (Wang et al., 2004, Fig. 3). Oil migrated along faults and accumulated in favorable areas, mixed with the earlier Middle Jurassic-sourced oil, as discussed above. The mixed oils were present mostly in intergranular pores and cracks of the Paleogene reservoirs. As the cap rocks formed a better seal and diagenesis was basically completed during burial (Yu et al., 2001), this crude oil was better preserved and underwent little biodegradation, as evidenced by little UCM and 25-norhopanes in molecular geochemistry (Fig. 7a). During the third stage in the Pliocene, the tectonics of the study area was strongly altered by continuous Himalayan movement (Xue and Yang, 2002). Natural gas began to be generated from both the Lower and Middle Jurassic (Wang et al., 2004, Fig. 3). Under the influence of these Cenozoic tectonic events, enormous detachment faults were formed, which acted as migration pathways for deeply sourced natural gas and connected the primary oil accumulations in the deeply buried Paleogene reservoirs. As a consequence, natural gas accumulated in both the deep Paleogene and shallow Neogene reservoirs, and oil remigrated from the deeply buried

Paleogene reservoirs to the shallow Neogene reservoirs (Su et al., 2003; Li et al., 2006). This event witnessed little oil alteration as few altered hydrocarbons were observed under microscope and UCM and 25-norhopanes were detected in oils and reservoir extracts. This is favorable for the hydrocarbon remigration. In summary, the study region is a case of primary and secondary hydrocarbon accumulations; this is typical in western China's superimposed basins due to the cutting of faults through different reservoir intervals (Pan et al., 2003; Tian et al., 2008; Xiang et al., 2015). In this study, as shown in Figure 8, the well-developed faults cutting through the deep Paleogene and shallow Neogene reservoirs provide good conditions for the possible hydrocarbon remigration/dysmigration, which in one of the representatives of primary and secondary hydrocarbon accumulations. During the third critical event of hydrocarbon charge in the Pliocene, continuous Himalayan movement resulted in the activation of faults (Xue and Yang, 2002). Thus, the remigration and/or dysmigration are likely. This can be supported by the results in this study. Inclusion petrographic observation indicates that both oil and gas inclusions are present in deep Paleogene and shallow Neogene reservoirs and more abundant oil inclusions are present in deep reservoirs. This is typical for oil remigration/dysmigration, as oil inclusions are hard

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to be formed under such conditions due to relatively low charging intensity and rapid charging speed (George et al., 2007; Xiang et al., 2015). In contrast, for the gas charge, there is little difference because it is primary for both the deep and shallow reservoirs. Based on the inclusion Th results, the deep Paleogene reservoir underwent three stages of hydrocarbon charging, while the shallow Neogene reservoir mostly experienced one stage. The one stage in the shallow reservoir includes both oil and gas charges, and thus the oil charge is most likely the remigration and/or dysmigration of primary oil accumulations in the deep Paleogene reservoir as the source rocks have entered gas window during this stage. This hydrocarbon remigration would impact the inclusion Th distribution as having relatively less values and being overlapped with the Th values of gas inclusions (Fig. 5). In addition, under this condition, the Th value would no longer be tied to source rock generation and should be interpreted in the context of geological context. Based on the above results and discussion, the complex primary and secondary hydrocarbon accumulations were finally completed (Fig. 8). According to this model, the secondary shallowly buried, and well-preserved deeply buried reservoirs, may both constitute future exploration targets with promising prospects. 5. Conclusions (1) The Jurassic petroleum systems, which include Lower and Middle Jurassic rocks, in the northern Qaidam Basin experienced multiple-stage and mixed hydrocarbon charging events. Abundant intergranular free oil and petroleum inclusions with various fluorescence colors were observed in two sets of reservoirs, deeply buried Paleogene and shallowly buried Neogene reservoirs. The Th values of saline inclusions coeval with petroleum inclusions fall into several intervals. The molecular compositions of the inclusion and intergranular free oils differ. (2) The complex hydrocarbon migration and accumulation processes in the study area can be divided into three main stages. During the first stage, from the late Oligocene to early Miocene, oils sourced from Middle Jurassic rocks migrated from hydrocarbon-generating sags along basement-cutting faults and accumulated in structural highs. Some of these oils were dysmigrated or remigrated as a result of unfavorable sealing conditions. The second stage took place during the early to middle Miocene, when the Lower Jurassic source rocks started to expel hydrocarbons. These hydrocarbons migrated through the same pathway systems as the earlier Middle Jurassic-sourced oils, and mixed with the earlier accumulated oils. The third stage was during the Pliocene. Gas sourced from both Lower and Middle Jurassic rocks widely charged deeply and shallowly buried reservoirs. Simultaneously, the primary accumulations in the deeply buried Paleogene reservoirs remigrated vertically to shallowly buried Neogene reservoirs along faults, forming secondary accumulations. (3) The study area represents a case of complex primaryesecondary superimposed hydrocarbon migration and accumulation. Secondary hydrocarbon accumulations in shallowly buried Neogene reservoirs formed by vertical migration, and well-preserved deeply buried Paleogene reservoirs, are promising future exploration targets. Acknowledgments We would like to thank Journal Associate Editor Dr. Hui Tian, and reviewers Dr. Barry Katz and Prof. Changchun Pan for their

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