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Geochemical Characteristics and Hydrocarbon Expulsion of Lacustrine Marlstones in the Shulu Sag, Bohai Bay Basin, Eastern China: Assessment of Tight Oil Resources

  • Zhipeng HuoEmail author
  • Xuan TangEmail author
  • Qingkuan Meng
  • Jinchuan Zhang
  • Changrong Li
  • Xiaofei Yu
  • Xue Yang
Original Paper
  • 37 Downloads

Abstract

In recent years, tight oil exploration has made significant progress in the lower part of Shahejie Formation (\( {\text{Es}}_{3} ^{{\text{L}}} \)) in the Shulu Sag, Bohai Bay Basin, Eastern China, which shows good exploration prospects for tight oil. However, accurate evaluation of tight oil resource potential is influenced by a lack of studies and an incomplete understanding of hydrocarbon expulsion from marlstone source rocks. This study investigated the geological and geochemical characteristics of marlstone source rocks, their hydrocarbon generation and expulsion, and the tight oil resource. Results show that the marlstone source rocks were deposited in a reducing to weakly oxidizing lacustrine environment with low-middle salinity, distributed widely in the central and southern troughs, with the maximum thickness greater than 700 m. The marlstone source rocks have relatively high organic matter abundance (0.06–7.97% of total organic carbon content with an average value of 1.51%), are dominated by type II and I kerogen, and are at the immature to mature stage (0.3% < vitrinite reflectance (VR) < 0.8%), which reveals fair–good source rocks for the marlstones. The threshold and peak of hydrocarbon expulsion for marlstone source rocks are at 0.51% VR and 0.6% VR, respectively. The amounts of generation and expulsion from marlstone source rocks are 19.72 × 108 t and 8.53 × 108 t, respectively, with an expulsion efficiency of 43%. The total tight oil resource in place is 10.9 × 108 (5.8 × 108 t within the carbonate rudstone reservoir and 5.1 × 108 t within the marlstone reservoir), indicating a significant tight oil potential and promising exploration prospect in the Shulu Sag, Bohai Bay Basin, Eastern China.

Keywords

Marlstone source rocks Geochemical characteristics Hydrocarbon generation and expulsion Tight oil Shulu Sag 

Introduction

Tight oil is defined as the oil resource accumulated in tight sandstone or carbonate reservoirs via expulsion and short migration from adjacent source rocks (National Energy Board 2011; Zhou and Yang 2012; Zou et al. 2013a). Tight oil has become a new hot spot after shale gas in global unconventional hydrocarbon exploration and development (Pollastro et al. 2008; Kuhn et al. 2012; Jia et al. 2012). Unlike tight oil in marine deposits in North America, tight oil in China is mainly developed in continental lacustrine strata that have greater thickness but smaller area (Jia et al. 2012; Katz and Lin 2014).

The Bohai Bay Basin, the largest petroliferous basin in China (Jiang et al. 2016a, b), has rich tight oil resources (Jia et al. 2012; Zhao et al. 2014a, b). Lacustrine carbonate rocks were widely deposited in the Eocene and are generally regarded as potential targets for tight oil exploration in the Bohai Bay Basin (Jiang et al. 2007), in which the Shulu Sag is an important area rich in tight oil in carbonate rocks (Zhao et al. 2014a, b, 2015; Tian et al. 2017; Li et al. 2017). Tight oil is continuously being discovered in the marlstone and rudstone reservoirs in the lower part of member 3 of the Eocene Shahejie Formation (\( {\text{Es}}_{3} ^{{\text{L}}} \)). By the end of 2014, 29 wells have been drilled into the \( {\text{Es}}_{3} ^{{\text{L}}} \) marlstones and show a good oil and gas presence (Zhao et al. 2015). The exploration of tight oil began from the JG11 well in 1988; however, the stable oil yield lasted only a short time after fracturing owing to the limitations of geological understanding and industrial technology (Zhao et al. 2015). Since 2012, as geological understanding for tight marlstone and rudstone gradually increased and development technology increasingly improved, tight oil attracted more attention from geologists and garnered enthusiasm as a prospective hydrocarbon to explore in the Shulu Sag (Zhao et al. 2014a, 2015; Tian et al. 2017). In recent years, three exploratory wells (ST1H, ST2X, and ST3) have been drilled successively and these have achieved commercial oil flows: for example, ST1H reached 243.6 t/d after fracturing testing and a stable oil yield of 12 t/d. Therefore, lacustrine tight oil has become an important exploration target because of the good exploration potential at the PetroChina Huabei Oilfield (Zhao et al. 2014b).

Source rock is a key factor controlling the formation of tight oil resources (Zou et al. 2013b; Hu et al. 2016). Marlstones with rich organic matter (OM) are the source rocks for tight oil: Their sedimentary environment, thickness and distribution, and geochemical features have been studied for many years (Jiang et al. 2007; Li 2010; Wang 2014; Zhao et al. 2014a, b; Zheng et al. 2015; Li et al. 2017; Tang et al. 2018). However, previous investigations of marlstone source rocks were still not sufficient for full characterization. The geochemical characteristics of marlstone source rocks were considered using only a single parameter when a comprehensive evaluation using multiple indicators would be more reliable. In addition, the hydrocarbon generation and expulsion characteristics of marlstone source rocks are rarely studied.

Researchers have proposed many methods, including thermal simulating experiment, chemical dynamic methods, and numerical simulation, to study the hydrocarbon generation and expulsion characteristics of source rocks (Cooles et al. 1986; Magara 1986; Lafargue et al. 1990; Xu, et al. 1995; Baskin 1997; Chen and Cha 2005; Qin 2005). However, these methods have some disadvantages: (1) They need many parameters and are complicated, and the results often are greatly different from actual geological conditions (Zhang 2005); (2) most of them ignore the cumulative contribution of immature and low-mature oil owing to the theory of traditional hydrocarbon generation threshold.

Therefore, this study focused on the detailed geological and geochemical characteristics of marlstone source rocks in the Shulu Sag via multiple parameters, including the sedimentary environment, distribution, abundance, and type and thermal maturity of OM. Moreover, the hydrocarbon generation and expulsion characteristics, including generation and expulsion intensity, efficiency, and quantities, were systematically evaluated by a modified generation and expulsion model based on the source rock characteristics (Zhou and Pang 2002; Pang et al. 2005). Finally, these results were employed to evaluate tight oil resources in the tight marlstone and rudstone reservoirs in the Shulu Sag.

Geological Setting

The Shulu Sag, with an area of approximately 700 km2, is located in the southwestern corner of the Jizhong Depression in the Bohai Bay Basin, Eastern China (Fig. 1). It is a Cenozoic NNE trending half-graben whose western, northeastern, and eastern boundaries are the Ningjin uplift, Hengshui fault, and Xinhe boundary fault, respectively (Fig. 1c) (Zhao et al. 2014a; Tang et al. 2018). Two west–east-trending faults (Taijiazhuang and Jingqiu faults) divide the sag into the northern, middle, and southern parts (Zhao et al. 2014b; Tian et al. 2017). The tectonic unit consisted of two uplifts (Taijiazhuang and Jingqiu paleo-structure), three troughs (northern, central, and southern trough), and the western slope (Fig. 1c). The central and southern troughs are the focus in this study. The formation and evolution of the Shulu Sag was controlled by the tectonic activities in the Jizhong Depression (Zhao et al. 2014a, b; Li et al. 2017).
Figure 1

Structural characteristics of the Shulu Sag, Bohai Bay Basin.

(Modified from Tang et al. 2018)

In the Eocene, the Shulu Sag began rifting owing to the influence of basement tilting and intensive faulting (Qiu et al. 2006; Tang et al. 2018). The Cenozoic lacustrine deposits unconformably overlie Cambrian–Ordovician and Permian–Carboniferous basements and consist of five formations, namely, in ascending order: Shahejie (Es), Dongying (Ed), Guantao (Ng), Minghuazhen (Nm), and Pinyuan (Np) (Fig. 1d) (Li et al. 2017). The Shahejie Formation can be further subdivided into three members—\( {\text{Es}}_{1} \), \( {\text{Es}}_{2} \), and \( {\text{Es}}_{3} \)—from top to bottom; these are the main source rocks and oil-bearing strata. \( {\text{Es}}_{3} \), with a thickness of 0–2200 m, is composed mainly of two units: the upper part (\( {\text{Es}}_{3} ^{{\text{U}}} \)) and the lower part (\( {\text{Es}}_{3} ^{{\text{L}}} \)) (Li et al. 2017). The \( {\text{Es}}_{3} ^{{\text{L}}} \) is the focus of this study, and its thickness in the central trough (depositional center) can reach 1600 m (Tian et al. 2017). The \( {\text{Es}}_{3} ^{{\text{L}}} \) starts with coarse-grained gray and light gray carbonate rudstone, fining upward into fine-grained dark gray marlstone with thin-interlayered mudstone and siltstone (Li et al. 2017; Tang et al. 2018) (Figs. 1d, 2). For tight oil, organic-rich marlstones are the source rocks; both marlstones and carbonate rudstones are reservoirs; and tight marlstones are the main caprocks (Wang 2014; Zhao et al. 2014a; Li et al. 2017). This results in the formation of multiple source–reservoir–caprock assemblages (Fig. 2). The upper fine-grained cap rock is vital to preserve hydrocarbons.
Figure 2

Source–reservoir–caprock assemblages of the Paleogene Shahejie Formation in the Shulu Sag, Bohai Bay Basin

Data and Methods

Data

In this study, more than 400 samples from five exploratory wells were collected and tested to analyze source rocks (Supplementary Table 1). Two wells (J116X and JG13) were drilled through the bottom of the marlstones (\( {\text{Es}}_{3} ^{{\text{L}}} \)), and the other three wells (ST1H, ST2X, and JG11) were drilled into the lower portion of the marlstones. The lithologies of the samples mainly comprise marlstones with some calcareous mudstones. Additionally, abundant geochemical and reservoir data, such as chloroform bitumen “A,” vitrinite reflectance (VR), organic elements, macerals, gas chromatography of saturated hydrocarbon, and porosity and permeability, were collected from the Research Institute of Exploration and Development, PetroChina Huabei Oilfield Company.

Methods

Laboratory Methods

Geochemical tests used in this study include Rock–Eval pyrolysis, total organic carbon (TOC) content, VR, bitumen extraction, gas chromatography (GC), and gas chromatography–mass spectrometry (GC–MS). Rock–Eval pyrolysis was conducted using a Rock–Eval II instrument. The measured parameters include free hydrocarbon (S1) volatilizing from a sample at 300 °C, residual hydrocarbon generation potential (S2) of kerogen, which arises during progressive heating from 300 to 600 °C, and the temperature of maximum pyrolysis yield (Tmax) (Espitalié et al. 1977; Tissot and Welte 1984; Peters 1986) (Supplementary Table 1). The TOC was determined using a TL851-5A carbon and sulfur analyzer. The sample particles were weighed before the carbonates were dissolved by hydrochloric acid. After rinsing and drying, the decarbonated samples were reweighed and then combusted. The TOC in weight percentage was calculated by comparing the unknown samples to a standard value. The VR was measured using an oil immersion lens and a Leica MPV Compact II reflected light microscope fitted with a microphotometer. The VR for each sample was calculated by averaging the histogram of the 80–100 reliable data (Waples 1985; Lee 1997).

The bitumen content was determined via extraction from source rock samples with conventional Soxhlet extraction methods lasting for 72 h. In addition, some bitumen samples were further analyzed through GC and GC–MS to determine the biomarkers. The GC was performed using a Hewlett Packard 5890 II chromatograph equipped with a flame ionization detector (FID) (Supplementary Table 2) and the GC–MS with an Agilent GC6890 Plus/MS5973 network system quadrupole instrument (Supplementary Table 3). Extracted bitumen was analyzed using a HP-5MS quartz capillary column (30 m × 0.25 mm × 0.25 mm). The heating program was set as follows. The instrument was first kept at an initial constant temperature of 50 °C for 1 min. It was then heated to 105 °C at a rate of 20 °C/min for 5 min, which subsequently increased to 320 °C at a rate of 3 °C/min, maintaining for 20 min. Helium was used as the carrier gas at a constant flow rate of 1 ml/min.

Hydrocarbon Generation and Expulsion Conceptual Model

The conceptual model of generated and expelled hydrocarbon was proposed by Pang et al. (2005) to estimate the quantities of hydrocarbon generation and expulsion. We used and improved this model by restoring the original hydrocarbon generation potential according to mass balance (Fig. 3).
Figure 3

Conceptual model of hydrocarbon generation and expulsion of source rocks.

(Modified from Pang et al. 2005)

The [(S1 + S2)/TOC] × 100 ratio was called the hydrocarbon generation potential index (GPI), which represents the total potential of generated hydrocarbons (Zhou and Pang 2002; Pang et al. 2005). With increasing burial and thermal evolution for source rocks, the generated hydrocarbons first experience retention (including water solution and adsorption) and subsequently discharge in quantity (mostly in the free phase) from source rocks when the amounts of generated hydrocarbon outnumber the maximum retention capacity of the source rocks (Pepper 1992; Pang et al. 2005). The VR or depth at which hydrocarbons started expelling is called as the hydrocarbon expulsion threshold (Zhou and Pang 2002; Pang et al. 2005). The GPI reaches its maximum value at the hydrocarbon expulsion threshold (Fig. 3). Before hydrocarbon expulsion, the GPI is defined as the original hydrocarbon generation potential index (GPIo) (Fig. 3). In that case, the GPIo reveals both the hydrocarbon generation and retention potential of source rocks. However, the remaining hydrocarbon generation potential index (GPIr) refers to the decreased hydrocarbon generation potential after hydrocarbon expulsion (Fig. 3), and it must be restored to GPIo.

The GPIo was restored based on the mass balance. The organic carbon (or TOC) in a source rock includes ineffective and effective carbon. The part of organic carbon or TOC that cannot generate hydrocarbons is called ineffective carbon: Its absolute mass remains unchanged both before and after hydrocarbon expulsion (Cooles et al. 1986; Qin 2005; Hu et al. 2016). Following the above principle, the GPIo can be restored by Eqs. 1 and 2:
$$k = \frac{{1 - 0.83{\text{GPI}}_{\text{r}} /1000}}{{1 - 0.83{\text{GPI}}^{0} /1000}}$$
(1)
$${\text{GPI}}_{\text{o}} = k \cdot {\text{GPI}}^{0}$$
(2)
where k is a restored coefficient, dimensionless; 0.83 is the average carbon content in hydrocarbons (Burnham 1989); GPIr is the residual hydrocarbon generation potential index, mg HC/g TOC; GPIo is the original hydrocarbon generation potential index, mg HC/g TOC; and GPI0 is the hydrocarbon generation potential index at hydrocarbon expulsion threshold, mg HC/g TOC.
The difference between the GPIo and the GPIr is called the hydrocarbon expulsion ratio (qe): It represents the hydrocarbon expulsion quantity per unit of organic carbon (Fig. 4) and can be calculated using Eq. 3. The hydrocarbon expulsion efficiency (Pef) is the ratio of hydrocarbon expulsion to generation, as shown in Eq. 4. The hydrocarbon expulsion velocity (Ve) refers to the variations in hydrocarbon expulsion ratios with a 0.1% increase in VR, and it can be obtained from Eq. 5.
$$q_{\text{e}} ({\text{VR}}) = {\text{GPI}}_{\text{o}} ({\text{VR}}) - {\text{GPI}}_{\text{r}} ({\text{VR}})$$
(3)
$$P_{\text{ef}} = \frac{{q_{\text{e}} ({\text{VR}})}}{{{\text{GPI}}_{\text{o}} ({\text{VR}})}} \times 100$$
(4)
$$V_{\text{e}} = \frac{{\Delta q_{\text{e}} ({\text{VR}})}}{{\Delta {\text{VR}}}}$$
(5)
where qe is the hydrocarbon expulsion ratio, mg HC/g TOC; Pef is the hydrocarbon expulsion efficiency, %; and Ve is the hydrocarbon expulsion velocity, (mg HC/g TOC)/(0.1% VR).
Figure 4

Gas chromatograms, gas chromatograms–mass chromatograms of saturated hydrocarbons of marlstone source rocks in the Shulu Sag: (ac) ST1H, 4280 m, marlstone; C27DS = C27 diasteranes; C27RS = C27 regular steranes; C28RS = C28 regular steranes; C29RS = C29 regular steranes

Hydrocarbon generation and expulsion intensity (Ig and Ie) is defined as the amounts of hydrocarbon generation and expulsion per area in the same source rock layer. Once we established an envelope curve of data points of [(S1 + S2)/TOC] × 100 in Figure 3, the hydrocarbon generation and expulsion ratios (qg and qe), intensities (Ig and Ie), and amounts (Qg and Qe) could be calculated using Eqs. 3 and 69, respectively.
$$I_{\text{g}} = \int\limits_{{{\text{VR}}_{1} }}^{\text{VR}} {10q_{\text{g}} ({\text{VR}}) \cdot H \cdot \rho \cdot {\text{TOC}} \cdot {\text{d}}({\text{VR}})}$$
(6)
$$I_{\text{e}} = \int\limits_{{{\text{VR}}_{2} }}^{\text{VR}} {10q_{\text{e}} ({\text{VR}}) \cdot H \cdot \rho \cdot {\text{TOC}} \cdot {\text{d}}({\text{VR}})}$$
(7)
$$Q_{\text{g}} = \int\limits_{{{\text{VR}}_{1} }}^{\text{VR}} {10^{5} q_{\text{g}} ({\text{VR}}) \cdot H \cdot A \cdot \rho \cdot {\text{TOC}} \cdot {\text{d}}({\text{VR}})}$$
(8)
$$Q_{\text{e}} = \int\limits_{{{\text{VR}}_{2} }}^{\text{VR}} {10^{5} q_{\text{e}} ({\text{VR}}) \cdot H \cdot A \cdot \rho \cdot {\text{TOC}} \cdot {\text{d}}({\text{VR}})}$$
(9)
where Ig is the hydrocarbon generation intensity (t/km2), Ie is the hydrocarbon expulsion intensity (t/km2), qg is the hydrocarbon generation ratio (mg HC/g TOC), Qg is the hydrocarbon generation quantity (t), Qe is the hydrocarbon expulsion quantity (t), VR is the vitrinite reflectance (%), VR1 is the hydrocarbon generation threshold (%), VR2 is the hydrocarbon expulsion threshold (%), H is the thickness (m) of source rocks, TOC is the total organic carbon content (%), ρ is the bulk density (g/cm3) of source rocks, and A is the area (m2) of source rocks.

Results and Discussion

Geological Characteristics of Marlstone Source Rocks

Sedimentary Environment

In the Eocene, the Shulu Sag started rifting with basement tilting and intensive faulting (Qiu et al. 2006; Wang 2014). The sag experienced continental marlstone and carbonate rudstone deposition within lacustrine and fan delta environments during the period of \( {\text{Es}}_{3} ^{{\text{L}}} \) deposition (Jiang et al. 2007; Wang 2014; Zheng et al. 2015; Tang et al. 2018). At the beginning stage of \( {\text{Es}}_{3} ^{{\text{L}}} \), the sag rapidly rifted and the extent of the lake dramatically expanded, and a large quantity of coarse-grained sediments eroded from Paleozoic carbonates were brought into lake by floods, which resulted in thick rudstones with thin interlayers of mudstone and calcareous sandstone. Hereafter, the water level rose and the lake had the widest range, then the tectonics stabilized, and a thick layer of fine-grained organic-rich marlstones with thin interlayers of mudstones, rudstones, and siltstones was developed (Zheng et al. 2015; Tang et al. 2018). Organic-rich marlstones from deep lacustrine to semi-deep lacustrine deposits are the main source rocks. The water became saline gradually from the north to the south in the sag, and the water circulation was poor in the central and southern parts; thus, most deposits were calcareous mudstone and sandstone, and marlstone and rudstone developed in the central and southern troughs (Liang et al. 2007; Zhao et al. 2014a; Tian et al. 2017). Thus, the central and southern troughs are the focus in this study.

Figure 4 shows GC and GC–MS scans of saturated hydrocarbons of marlstone source rocks. Pristane/phytane (Pr/Ph) is an indicator for identifying the depositional conditions where high Pr/Ph values (> 3) show pure oxidizing sedimentary environments, values < 3 represent the gradual decrease in oxygen content, and ratios < 1 reveal reducing and saline environments (Peters et al. 2005; Obermajer et al. 2010). The Pr/Ph ratios of marlstones range from 0.37 to 2.00 with an average value of 0.99 (more than half of Pr/Ph ratios are less than 1.00) in the Shulu Sag, which indicates mainly medium salinity and reducing environments with weakly reducing weak oxidizing conditions. Like Pr/Ph, the lower Pr/nC17 ratio (0.26–1.37) and Ph/nC18 ratio (0.26–1.30) also represent reducing to weakly oxidizing environments (Fig. 5). The terrigenous/aquatic ratios (TAR) ((nC27 + nC29 + nC31)/(nC15 + nC17 + nC19)) of n-alkane are 0.14–4.25 and the values of ΣC21 − /ΣC22 + are 0.05–0.43, respectively, which show that terrestrial OM is far more abundant than marine OM (Supplementary Table 2). Gammacerane is a key index for a stratified water column and hypersaline conditions (Sinninghe Damste et al. 1995; Peters et al. 2005). The gammacerane/C31-hopane ratios, from 0.08 to 0.94, are relatively low (Supplementary Table 3), revealing that the salinity was low-middle during the marlstone deposition.
Figure 5

Discrimination of reducing and oxidation of sedimentary environments of marlstones in the Shulu Sag, Bohai Bay Basin

Distribution and Thickness

The evaluations of source rock from wells underrepresent source rock distribution and thickness because all the wells are located in the western slope and two uplifts (Fig. 1c). Therefore, the distribution and thickness of marlstone source rocks were studied in this work based on a comprehensive analysis using well data, structural contour, seismic interpretation, sedimentary facies, and published reports.

The depocenters were located in the southern trough, and especially in the central trough in the Shulu Sag (Zhao et al. 2014a; Tian et al. 2017), which controlled the thickness and distribution of marlstone source rocks in the Shulu Sag. The thicknesses of marlstone source rocks are generally 100–600 m, and the maximum thicknesses in the central and southern troughs are greater than 700 m and 300 m, respectively (Fig. 6). The source rocks become thinner from the troughs to uplifts and the western slope, disappearing in the margin of the western slope. Overall, the area of organic-rich (TOC > 1%) and thick (greater than 100) marlstone source rocks is greater than 300 km2 (Figs. 6, 8).
Figure 6

Thickness distribution of marlstone source rocks in the Shulu Sag, Bohai Bay Basin

Geochemical Characteristics of Marlstone Source Rocks

OM Abundance

The OM abundance of marlstone source rocks was evaluated using TOC, hydrocarbon generation potential (S1 + S2), pyrolysis yields (S2), and chloroform bitumen “A” content (Tissot and Welte 1984; Bordenave et al. 1993; Peters et al. 2005) (Supplementary Table 1). The TOC of marlstone source rocks is between 0.06 and 7.97% with an average value of 1.51%, with 83.75% of 480 samples exceeding 0.6% (lower limit of fair source rocks) and 71.88% exceeding 1.0% (lower limit of good source rocks) in the Shulu Sag (Fig. 7a and b). The S1 + S2 values of marlstone source rocks range from 0.04 mg HC/g rock to 60.83 mg HC/g rock and the average value is 7.99 mg HC/g rock, with 80.00% and 54.58% of 480 samples exceeding 2 mg HC/g rock and 6 mg HC/g rock, respectively (Fig. 7a and c). The chloroform bitumen “A” of source rocks range from 104 to 3499 ppm and average 1639 ppm, and 92.57% and 75.68% of 148 samples exceed 500 ppm and 1000 ppm, respectively (Fig. 7b and c). These OM abundance values demonstrate that most marlstones are good source rocks based on the evaluation standards in Table 1 (SY/T 5735–1995). In addition, S2 is also used to evaluate OM abundance of source rocks (Bordenave et al. 1993; Peters and Cassa 1994). S2 values oscillate from 0.03 mg HC/g rock to 57.08 mg HC/g rock and average 7.17 mg HC/g rock in the Shulu Sag. Although the S2 evaluation standard for source rocks by Peters and Cassa (1994) is different from that in SY/T 5735–1995 (Table 1), the S2 values indicate that most marlstones have the generative potential of good source rocks, which is in accordance with their TOC content (Fig. 7d).
Figure 7

Organic matter (OM) abundance of marlstone source rocks in the Shulu Sag, Bohai Bay Basin

Table 1

Evaluation standard for organic matter abundance of source rocks (SY/T 5735-1995)

Type of source rocks

Organic geochemistry evaluation indexes

TOC (%)

S1 + S2 (mg HC/g rock)

Chloroform bitumen “A” (ppm)

Excellent

> 2.0

> 20

> 2000

Good

> 1.0

> 6.0

> 1000

Fair

1.0–0.6

2.0–6.0

500–1000

Poor

0.6–0.4

0.5–2

100–500

None

< 0.4

< 0.5

< 100

The TOC distribution of marlstone source rocks was evaluated referring to structural depth contours, seismic inversion, and sedimentary facies (Fig. 8). The TOC is generally greater than 0.4%, indicating that the effective source rocks are widely distributed and continuous in the whole Shulu Sag. The maximum values of TOC in the central and southern troughs are higher than 2.8% and 1.8%, respectively, showing an obvious gradual decreasing trend from the troughs to the uplifts and slope. More than 70% area of the Shulu Sag develops good–excellent (1.0% ≤ TOC < 3%) source rocks.
Figure 8

TOC distribution of marlstone source rocks in the Shulu Sag, Bohai Bay Basin

OM Types

OM (or Kerogen) is generally classified as three types: type I, type II, and type III (Tissot and Welte 1984; Hunt 1996), and was determined by using organic elemental analyses, Rock–Eval pyrolysis data, and organic maceral analyses.

Kerogen types were confirmed based on elemental carbon (C), hydrogen (H), and oxygen (O) and their ratios (Van Krevelen 1961; Durand and Monin 1980; Tissot and Welte 1984). The H/C ratios are between 0.62 and 1.48, and O/C ratios are from 0.04 to 0.20 (Fig. 9a). The kerogens are dominated by type II and type I, with a few type III samples (Fig. 9a).
Figure 9

OM types of marlstone source rocks in the Shulu Sag, Bohai Bay Basin

The cross-plot of hydrogen index (HI) vs. maximum temperature (Tmax) was frequently used to determine OM types (Tissot and Welte 1984; Hakimi et al. 2013). The HI values range from 186.7 mg HC/g TOC to 842.9 mg HC/g TOC, and most are from 200 mg HC/g TOC to 700 mg HC/g TOC. The Tmax values are mainly from 430 to 450 °C (Fig. 9b). These results show that the samples can be categorized mainly as type II and type I kerogen, with some type III kerogen, which agrees with results obtained from organic element.

OM types could be classified by the optical properties of OM (Tissot and Welte 1984; Hunt 1996). Macerals analysis showed that the sapropelitic group is the dominant maceral component, generally with a content higher than 70% (Fig. 9c). Thus, OM is composed mainly of type II and type I kerogen, which is the same as results of organic element and pyrolysis as well as the previous study (Zhao et al. 2014b; Li et al. 2017; Tang et al. 2018). It is noted that core samples are from wells on structural highs or slopes in this study; source rocks in deeper troughs should have better OM type (oil-prone), which helps in the formation of tight oil reservoirs.

Thermal Maturity of OM

In this study, the OM maturity of marlstone source rocks was studied using the VR, pyrolysis Tmax, sterane isomerization (20S/(20R + 20S)C29 and ββ/(αα + ββ)C29), the odd/even predominance ratio (OEP), and the carbon preference index (CPI) of n-alkanes (Machkenzie 1984; Tissot and Welte 1984; Bordenave et al. 1993; Peters et al. 2005).

The critical values of VR for immature, low (or early) mature, mature, high mature, and over mature stages are < 0.5%, 0.5–0.7%, 0.7–1.3%, 1.3–2.0%, and > 2.0%, respectively (Tissot and Welte 1984; Tissot et al. 1987). For Tmax, the range values of maturity (oil window) and high maturity (gas/condensate) are at 430–455 °C and 455–470 °C, respectively (Bordenave et al. 1993). The VR values span from 0.30 to 0.82% (Fig. 10a), and the Tmax values are 426–454 °C (Fig. 10b); thus, the marlstone source rocks were in the immature–mature stage and they have generated a large quantity of oil. The VR values have gradually increasing trend from the western slope to the eastern troughs (from 0.3% to more than 0.8% and from immaturity to maturity stage) (Fig. 11). In the central and southern troughs, marlstone source rocks should have higher maturity and are all at the mature and oil mass generation (oil window) stage (VR > 0.8%).
Figure 10

OM maturity of marlstone source rocks in the Shulu Sag, Bohai Bay Basin

Figure 11

VR distribution of marlstone source rocks in the Shulu Sag, Bohai Bay Basin

Sterane isomerization parameter ββ/(αα + ββ)C29 and 20S/(20R + 20S)C29, and CPI and OEP could be obtained from GC–MS and GC, respectively (Machkenzie 1984; Peters et al. 2005). The ββ/(αα + ββ)C29 and 20S/(20R + 20S)C29 of 40 samples are in the range of 15.0–54.9% and 16.0–58.2%, respectively (Fig. 10c). The CPI values of these samples vary from 0.68 to 1.35 and the OEP values vary from 0.88 to 1.59 (Fig. 10d). These values indicate that the majority of source rocks are early mature–mature within the oil window. The OM maturity shown by these results is slightly higher than those of VR and Tmax, which is perhaps because that a part of hydrocarbons from rock extraction is derived from deeper and higher mature source rocks, in particular source rocks in the troughs.

Hydrocarbon Generation and Expulsion Characteristics of Marlstone Source Rocks

Hydrocarbon Generation and Expulsion Model

A hydrocarbon generation and expulsion model of marlstone source rocks was established based on TOC, rock pyrolysis parameters, burial depth, and VR (Fig. 12) In this study, the actual measured VR was used for the 32 samples in Figure 10a, and the VR was calculated using the fitting equation for VR and depth for those samples without actual measured values.
Figure 12

Quantitative model of hydrocarbon generation and expulsion of marlstone source rocks in the Shulu Sag, Bohai Bay Basin

A VR value of 0.5% is commonly considered as the threshold of substantial hydrocarbon generation in muddy source rocks (Tissot and Welte 1984; Tissot et al. 1987). However, for some continental sedimentary rocks, in particular, saline lacustrine source rocks, higher content of soluble organic matter, bacteria, and algae (lipid) could generate immature or low-mature oil (Bazhenova and Arefiev 1990; Wang et al. 1995; Qin et al. 1997; Huang et al. 2003). The marlstones in the Shulu Sag were deposited in a certain saline lake and have relatively higher bacteria and algae seen from the high C27 steranes (Fig. 4c). In addition, the marlstones with lower maturity contain more soluble organic matter—chloroform bitumen “A” (Fig. 7b and c). These reasons are perhaps why the marlstones expulsed hydrocarbons in an earlier period with 0.37% VR in the Shulu Sag. Marlstones from saline lakes could generate more immature and low-mature oil, such as lipid-like extractable organic matter, than those of mudstones (Palacas 1984; Tannenbaum and Aizenshtat 1985; Orr 1986), and pyrolysis experiments have proved that carbonate rocks have greater hydrocarbon conversion rates than mudstones (Hu et al. 2004; Qin 2005; Tao 2008; Liu et al. 2010). However, the residual hydrocarbons in carbonate rocks are much lower than mudstones (Gehman 1962; Wu 1986; Qin 2005). Therefore, it is easier to expulse hydrocarbons earlier from marlstones (carbonate rocks) than from mudstones (Huo et al. 2019). In the Shulu Sag, the thresholds of hydrocarbon generation and expulsion for marlstone source rocks were at lower VR values, 0.37% VR and 0.51% VR, respectively (Fig. 12a). The hydrocarbon expulsion velocity was the largest at the hydrocarbon expulsion peak, which was a bit greater than the hydrocarbon expulsion threshold, corresponding to 0.60% VR (Fig. 12c). When the hydrocarbon generation and expulsion thresholds were reached, the hydrocarbon generation and expulsion ratios increased rapidly but the degree of increase gradually reduced, in particular, during the late stage (Fig. 12c). The maximum velocity of hydrocarbon expulsion is up to 247 mg HC/g TOC/0.1% VR at 0.6% VR. The variation trend of hydrocarbon expulsion efficiency is similar to hydrocarbon generation and expulsion ratios (Fig. 12d). With increasing thermal evolution (from 0.5% VR to 0.9% VR), the hydrocarbon expulsion efficiency increased from 0 to 59%. On the contrary, the hydrocarbon retention efficiency decreased gradually to 41% (Fig. 12d).

Hydrocarbon Generation and Expulsion Intensity and Amount

The comprehensive variations in OM abundance, thermal maturation, and thickness of marlstone source rocks (Figs. 6, 7, 8, 9, 10, 11, and 12) control the hydrocarbon generation and expulsion intensities that were calculated using Eqs. 6 and 7 (Figs. 13, 14).
Figure 13

Recent cumulative hydrocarbon generation intensity of marlstone source rocks in the Shulu Sag, Bohai Bay Basin

Figure 14

Recent cumulative hydrocarbon expulsion intensity of marlstone source rocks in the Shulu Sag, Bohai Bay Basin

Previous studies revealed that after the marlstones of the \( {\text{Es}}_{3} ^{{\text{L}}} \) were deposited, the Shulu Sag experienced a fault depression period in the Paleogene and a depression period in the Neogene without significant tectonic uplift, resulting in a continuous subsidence of the marlstone layer (Fig. 15) (Qiu et al. 2006; Li 2010; Wang 2014; Tang et al. 2018). As the thermal evolution increased, marlstones began to generate oil, expulsing massive volumes after the Guantao period at a depth corresponding to 2800 m and threshold value of 101 °C, and continue to do so to this day (Liang et al. 2001; Li 2010; Wang 2014).
Figure 15

Burial and thermal history of marlstone source rocks in the Shulu Sag, Bohai Bay Basin (Modified from Li 2010): Ek = the Kongdian Formation; \( {\text{Es}}_{4} \) = the fourth member of Shahejie Formation; \( {\text{Es}}_{3} \) = the third member of Shahejie Formation; \( {\text{Es}}_{2} \) = the second member of Shahejie Formation; \( {\text{Es}}_{1} \) = the first member of Shahejie Formation; Ed = the Dongying Formation; Ng = the Guantao Formation; Nm = the Minghuazhen Formation; Q = Quaternary (Pingyuan Formation)

Source rocks with better OM type, larger hydrocarbon generation potential, and higher thermal evolution have higher hydrocarbon expulsion extensity and efficiency (Pepper and Corvi 1995; Ritter 2003; Pang et al. 2005). High-quality and mature marlstone source rocks are mostly developed in the central and southern troughs, which agrees with the depocenter and controls the hydrocarbon generation and expulsion centers. The highest hydrocarbon generation intensities for marlstone source rocks in the central and southern troughs are greater than 3600 × 104 t/km2 and 1200 × 104 t/km2, respectively (Fig. 13). Due to the low maturity, the marlstone source rocks have not yet expelled hydrocarbons in the western part (or margin) of the western slope. All other marlstone source rocks in the Shulu Sag have reached the expulsion threshold. The hydrocarbon expulsion intensity decreases rapidly from troughs to uplifts and slope, which is consistent with the variation in the hydrocarbon generation intensity. The maximum intensity of hydrocarbon expulsion for marlstone source rocks in the central and southern troughs is greater than 2000 × 104 t/km2 and 600 × 104 t/km2, respectively (Fig. 14).

The cumulative amounts of generated and expelled hydrocarbon could be determined by multiplying the hydrocarbon generation and expulsion intensity by the area of source rocks (Peng et al. 2016; Hu et al. 2016) using Eqs. 8 and 9. Currently, the total amounts of hydrocarbon generation and expulsion from marlstone source rocks are 19.72 × 108 t and 8.53 × 108 t, respectively, which suggest the hydrocarbon expulsion efficiency is 43%. Therefore, 57% of generated hydrocarbons remain in marlstone source rocks, which indicates that the potential of expelled and retained hydrocarbons are both enormous for marlstone source rocks. The VR values range from 0.5 to 0.9% in most areas in the Shulu Sag; thus, source rocks are dominated by oil generation (in the oil window), which is favorable to the formation and enrichment of tight oil in marlstone and rudstone reservoirs.

Tight Oil Resource Assessment

The hydrocarbon expulsion center impacts the formation and distribution of conventional oil and gas (Jiang et al. 2018). Unconventional near-source tight oil only experiences short secondary migration, or primary migration (Jia et al. 2012; Zou et al. 2013a, b); thus, the accumulation and distribution of tight oil are remarkably controlled by the hydrocarbon expulsion intensity or center (Hu et al. 2016; Peng et al. 2016).

Oil–source correlations indicated that the organic-rich marlstones are the oil source of tight oil (Wang et al. 2014; Li et al. 2017). Reservoir rocks mainly contain marlstones and carbonate rudstones. The rudstone layers are generally the adjacent organic-rich marlstone layers, providing good conditions for tight oil accumulation which forms the accumulation models of tight oil with self-source and self-reservoir in marlstone reservoir and with a near-source in the rudstone reservoir, respectively (Zhao et al. 2014a, 2015; Tian et al. 2017). The tight oil is widely distributed in the entire \( {\text{Es}}_{3} ^{{\text{L}}} \) layer vertically and continuous areas horizontally. Therefore, high-quality marlstone source rock is a key factor that controls the enrichment and distribution of tight oil in the Shulu Sag.

Based on the evaluation criterion for tight reservoir proposed by Jia et al. (2012), a tight reservoir is defined as one with a porosity value less than 12% and permeability value less than 1.0 × 10−3 µm. The marlstone and rudstone represent typical low-permeability (123 of 178 samples are less than 1.0 × 10−3 µm) and low-porosity (178 samples are all less than 12%) tight reservoirs (Fig. 16). The parent rocks of carbonate rudstones are the tight carbonate rocks in the lower Paleozoic Cambrian–Ordovician (Jiang et al. 2007; Tian et al. 2017; Tang 2018), and marlstones are mainly mixed deposits from terrigenous clastics and endogenous carbonates and experienced severe compaction in the early diagenetic stage (Liang et al. 2007; Jiang et al. 2007; Wang et al. 2014). Therefore, both types of reservoir have become tight before hydrocarbon accumulation. However, abundant micro-fractures are developed in marlstones and rudstones and they enhance the porosity and permeability of tight reservoirs (Zhao et al. 2014a, b; Wang 2014; Tian et al. 2017). These fractured reservoirs have higher oil saturations and form local “sweet spots” (Katz and Lin 2014).
Figure 16

Porosity–permeability analysis of marlstone source rocks in the Shulu Sag, Bohai Bay Basin

According to the above analysis, tight oils are composed of two parts: self-source oils in marlstone reservoirs and near-source oils in the rudstone reservoirs. We investigate the tight rudstone oil potential by the genetic method and marlstone oil potential by the volumetric method, similar to the assessment of tight sand oil and shale oil resources. The accumulation coefficient is a key parameter to evaluate correctly the tight rudstone oil potential and is influenced by the distance of the hydrocarbon migration, the order between the tight period of the reservoir and the hydrocarbon accumulation period (Zhu et al. 2007; Hu et al. 2016; Peng et al. 2016). The smaller the distance, and the earlier the formation of the tight reservoir, the greater the accumulation coefficient. The rudstone reservoirs are adjacent to marlstone source rocks, indicating a short migration pathway for hydrocarbons. In addition, the timing of becoming tight for the rudstone reservoirs was earlier than the hydrocarbon accumulation period. Therefore, the accumulation coefficient of rudstone tight oil should be greater than that of conventional oil. Studies showed than the accumulation coefficient of tight carbonate oil with short migration pathway and earlier densification is 29.6% in the Junggar Basin (Wang et al. 2014; Hu et al. 2016). Therefore, we adopt 29.6% as the accumulation coefficient of the tight rudstone oil in the Shulu Sag because of similar accumulation characteristics. The amount of tight rudstone oil from marlstone source rocks is approximately 5.8 × 108 t.

Tight marlstone oil can be regarded as the residual oil in marlstone source rocks like shale oil. When assessing the in-place resources by volumetric method, thickness, area, oil content, and maturation are key parameters, as shown in Eq. 10, in which it is the most critical to accurately determine the oil content (Zhang et al. 2012; Zou et al. 2013b; Xue et al. 2016).
$$Q = Sh\rho q$$
(10)
where Q is the quantity of resources in place, kg; S is the distribution area of marlstone, m2; h is the thickness of gas shale, m; ρ is the density of marlstone, 2.7 t/m3; and q is the original residual hydrocarbon content represented by original chloroform bitumen “A” content, mg HC/g rock.
The oil content is commonly represented by the content of chloroform bitumen “A” or pyrolysis “S1” hydrocarbon (Jarvie 2012; Xue et al. 2016). In this study, chloroform bitumen “A” was used to determine the oil content. In fact, the light hydrocarbons in S1 and “A” evaporate easily and are lost during core recovery, sample storage, and handling before testing. The evaluation of shale oil resources by using the present S1 or “A” values will underestimate resource potential. Therefore, it is necessary to restore the light hydrocarbon loss to obtain original oil content before resource evaluation (Jarvie 2012; Jiang et al. 2016a, b; Xue et al. 2016; Chen et al. 2018). Xue et al. (2016) conducted evaporative loss calibration using Rock–Eval and kerogen kinetics and indicated that the loss recovery coefficients of S1 and “A” amounts were 4.2 and 1.2, respectively, in which they thought 1.2 of “A” was more reasonable and 4.2 of S1 was larger than the actual value. Thus, we used the chloroform bitumen “A” and 1.2, its loss recovery coefficient, to obtain the original oil content in the Shulu Sag (Fig. 17). The in-place resource of tight marlstone oil is approximately 5.1 × 108 t. The total amount of tight rudstone and marlstone oil is 10.9 × 108 t, which indicates a large exploration potential for tight oil in the Shulu Sag.
Figure 17

Retained hydrocarbon model of marlstone source rocks in the Shulu Sag, Bohai Bay Basin

Conclusions

  1. 1.

    The \( {\text{Es}}_{3} ^{{\text{L}}} \), composed of marlstone and carbonate rudstone, developed mainly in lacustrine and fan deltas in the Shulu Sag, where a reducing to weakly oxidizing sedimentary environment and low-middle salinity existed. The depocenters are located in the central and southern troughs, where the maximum thicknesses of the marlstone source rocks are greater than 700 m and 300 m, respectively, rapidly thinning from the troughs to uplifts and the western slope. The area of organic-rich source rocks greater than 200 m is approximately 200 km2.

     
  2. 2.

    The marlstone source rocks have relatively high OM abundance (TOC ranges from 0.06 to 7.97%, averages 1.51%), predominated type II and type I kerogen, and are immature to mature with 0.3–0.8% VR. The overall evaluation showed that the marlstones in the Shulu Sag are fair–good source rocks, which have significant potential for hydrocarbon generation under moderate to high thermal evolution.

     
  3. 3.

    The threshold and peak of hydrocarbon expulsion for marlstone source rocks are at 0.51% VR and 0.6% VR, respectively. The greatest intensity of hydrocarbon expulsion for marlstone source rocks in the central and southern troughs is greater than 2000 × 104 t/km2 and 600 × 104 t/km2, respectively. The quantities of hydrocarbon generation and expulsion from marlstone source rocks are 19.72 × 108 t and 8.53 × 108 t, respectively, and the comprehensive hydrocarbon expulsion efficiency is 43%.

     
  4. 4.

    Tight oil reservoirs are developed both the carbonate rudstone and marlstone tight formations. The in-place resources within the carbonate rudstone and marlstone reservoirs are 5.8 × 108 t and 5.1 × 108 t, respectively, with a sum of 10.9 × 108 t, indicating that there is large tight oil potential in the \( {\text{Es}}_{3} ^{{\text{L}}} \) in the Shulu Sag.

     

Notes

Acknowledgments

This work was supported by the Special grant of China Postdoctoral Science Foundation (2018T110124), Open Project of Key Laboratory of Tectonics and Petroleum Resources of Ministry of Education, China University of Geosciences, Wuhan (TPR-2016-06), University-Enterprise Cooperation Project of the PetroChina Huabei Oilfield Company (2014-0018963-HBYT-0003277). We also thank the Research Institute of Exploration and Development of PetroChina Huabei Oilfield Company for offering geochemical data of source rocks.

Supplementary material

11053_2019_9580_MOESM1_ESM.pdf (909 kb)
Supplementary material 1 (PDF 908 kb)

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Copyright information

© International Association for Mathematical Geosciences 2019

Authors and Affiliations

  1. 1.School of Energy ResourcesChina University of GeosciencesBeijingChina
  2. 2.Key Laboratory of Strategy Evaluation for Shale Gas of Ministry of Land and ResourcesChina University of GeosciencesBeijingChina
  3. 3.CNPC Logging Liaohe BranchPanjinChina
  4. 4.State Key Laboratory of Petroleum Resources and ProspectingChina University of PetroleumBeijingChina

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