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Article

A Comparison of Generation–Retention–Expulsion in Felsic and Carbonate Laminated Shale by Semi-Open Thermal Pyrolysis: Implications for Shale Oil Exploration

by
Quansheng Guan
1,2,3,
Xiaoping Liu
1,2,*,
Changwei Chen
3,
Xianzheng Zhao
1,2,4,
Fengming Jin
3,
Wenya Jiang
3,
Xiugang Pu
3,
Biao Sun
1,2,
Tian Liu
1,2,
Zuxian Hua
1,2,
Wendi Peng
1,2 and
Gaohang Jia
1,2
1
State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing), Beijing 102249, China
2
College of Geosciences, China University of Petroleum (Beijing), Beijing 102249, China
3
PetroChina Dagang Oilfield Company, Tianjin 300280, China
4
China Petroleum Consulting Center, Beijing 100724, China
*
Author to whom correspondence should be addressed.
Geosciences 2026, 16(1), 9; https://doi.org/10.3390/geosciences16010009 (registering DOI)
Submission received: 20 October 2025 / Revised: 29 November 2025 / Accepted: 9 December 2025 / Published: 22 December 2025
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Abstract

Paleogene lacustrine shale is a key source rock for large oil reserves in China and a major target for shale oil exploration. However, differences in the chemical characteristics of felsic and carbonate shales during burial and thermal evolution remain poorly understood. This study evaluates hydrocarbon generation and expulsion efficiency in these shale types using pyrolysis experiments on lower Paleocene Kongdian Formation samples (Type I) from the Eastern China Sedimentary Basin. Results show that felsic shale has higher hydrocarbon generation capacity than carbonate shale. During pyrolysis, carbonate shale retained ~119 mg/g more oil but expelled 184 mg/g less than felsic shale. Felsic shale reached peak oil generation and retention faster but with lower retention efficiency. The larger volume of residual hydrocarbons in felsic shale facilitated earlier expulsion onset, higher yields of gaseous hydrocarbons, and superior gas expulsion efficiency. While both shales exhibited similar thermal evolution trends for hydrocarbon gases, methane proportions and gas-oil ratios (GOR) differed significantly. Carbon loss was comparable during the oil window, but felsic shale lost more carbon overall. At higher temperatures, n-alkanes in residual oil decreased sharply, with lighter oil retained at advanced maturity, increasing GOR and reducing heavy hydrocarbons. These findings demonstrate the effective hydrocarbon potential of medium-high TOC felsic and carbonate shales.

1. Introduction

As a typical unconventional oil and gas resource, terrestrial shale oil holds an irreplaceable strategic position amid the global energy structure transition [1,2,3,4,5]. In China, remarkable progress has been achieved in its prospecting and development, with breakthroughs in key basins including Junggar [6,7,8], Ordos [9,10,11,12], Songliao [13,14], and Bohai Bay [15,16,17,18]. Nevertheless, exploitation is constrained by strong reservoir heterogeneity, low fluid mobility, and poor frackability—issues highlighted in recent studies [19,20,21,22]. Current research thus focuses on quantitative characterization of lacustrine-phase retained oil, yet insufficient understanding of hydrocarbon generation-retention-expulsion behaviors remains a bottleneck [23]. The quality of source rocks, core to petroleum systems, is determined by organic matter (OM) abundance, preservation, and thermal maturity. Unlike marine systems, terrestrial OM’s source supply and reservoir conditions are sensitive to lacustrine OM input, climatic fluctuations, and geological events, leading to frequent sedimentary cycle alternations and strong facies heterogeneity. Hence, the paleo-depositional environment profoundly affects high-quality lacustrine shale formation. Stratal organic-inorganic chemicals play key roles in hydrocarbon generation: clay elements and transition metal oxides reduce hydrocarbon formation temperature, while pressure inhibits conversion [17,24,25,26,27,28,29,30,31]. This causes varied hydrocarbon generation processes across lithologic source rocks, with notable differences in activation energy distribution and oil-gas conversion between felsic and carbonate shale [32,33]. With advancing hydrocarbon generation theories, thermal simulation experiments have evolved into open, closed, and semi-open systems. Early studies relied on open-system Rock-Eval pyrolysis (anhydrous, low-pressure) or water-bearing closed-system tests (hot-pressed autoclaves, gold tubes) [34,35,36,37,38,39,40,41]. Rock-Eval, suitable for Type I/II kerogens, fails to account for pressure and geological boundary conditions [42,43,44,45], or retained oil’s cracking potential. Closed-system experiments, better for Type III kerogen, consider temperature, pressure, aqueous media, and minerals but suffer from retained liquid secondary cracking, causing product quantification errors [46,47,48,49,50,51]. Recent advances address this by adjusting parameters (duration, temperature, pressure) based on target source rock’s burial-thermal history, simulating near-geological conditions for more accurate episodic hydrocarbon generation-expulsion data [52,53,54,55,56]. The semi-open system was selected to simultaneously simulate the retention of hydrocarbons (as in a closed system) and the episodic expulsion of hydrocarbons when a fluid pressure threshold is exceeded (as in a natural system), thereby providing a more accurate mass balance for both retained and expelled products [20,57,58,59]. Despite felsic and carbonate shale’s significant influence on shale oil generation, limited studies explore differences in their hydrocarbon generation-retention-expulsion processes and mechanisms—hindering shale oil enrichment prediction. Additionally, no systematic research clarifies how these source rock differences affect shale oil’s gas-to-oil ratio (GOR) and molecular distribution, forming the core research gap of this study.
In the present study, semi-open pyrolysis experiments were performed with gradually elevated final temperatures (ranging from 300 to 475 °C). These tests aimed to characterize the variations in both chemical and physical properties of generated, retained, and expelled gaseous and oily products as the thermal maturity of different lacustrine shale samples increased. The core objective was to simulate the natural maturation process of lacustrine shale, thereby gaining insights into the dynamic evolutionary processes of oil and gas generation, retention, and expulsion. This work focuses on investigating the geochemical evolution features of felsic and carbonate-rich shales, as well as the hydrocarbons retained within or expelled from the parent rock matrices. Through such investigations, we can achieve a deeper understanding of the interactive relationships between source rocks, retained hydrocarbons, and expelled hydrocarbons, along with the formation mechanisms of self-sourced unconventional hydrocarbon resources—for instance, shale oil accumulations.

2. Samples and Methods

2.1. Sample Information and Preparation

Two lacustrine shale samples employed in this study were collected from the Paleocene Kongdian Formation (Ek2) within the Huanghua Depression, which is part of the Bohai Bay Basin in northern China (Figure 1a). Geographically, the Huanghua Depression lies at the central zone of the Bohai Bay Basin and extends in a northeast-southwest (NE-SW) direction. Tectonically, it represents a Cenozoic rift basin developed on the basis of a Mesozoic crystalline basement. The Kongdian Formation (Ek), the stratigraphic unit yielding the target samples, is predominantly composed of sedimentary sequences deposited under deep lacustrine environmental conditions. It is noteworthy that the specific interval sampled for this work corresponds to the second member of the Kongdian Formation (Ek2), which is widely recognized as a key source rock interval in the study area.
The samples were retrieved from Well GX12’s core, which is now buried at depths of 2566.12 m and 2575.47 m. The Ro measurements show a low level of maturation, at 0.60%. The selected samples have TOC contents of 5.51 wt% and 5.62 wt%. The polished slab and thin section pictures demonstrate that these samples are typical laminar shale, with alternating different laminae (Figure 1b,c).

2.2. Methods

A semi-open hydrocarbon generation thermal simulator, developed by the Wuxi Petroleum Geology Research Institute, was employed as the core device for the thermal simulation experiments. This specialized instrument is capable of replicating the static lithostatic pressure exerted on samples via its upper and lower pressure axes (Figure 2). For each test, cylindrical shale samples were placed into a stainless-steel autoclave with an inner diameter of 38 mm. The experimental temperature regime was designed with six discrete gradient points, specifically set at 300 °C, 325 °C, 350 °C, 375 °C, 400 °C, and 475 °C to cover the key maturity stages of the study samples.
To maximize the alignment with the actual geological conditions corresponding to different burial depths, distinct lithostatic pressure values and hydrocarbon expulsion fluid pressure thresholds were configured for each temperature point, based on the physical depth of the target formation. Detailed parameter configurations are summarized in Table 1. Prior to initiating each experiment, 20 mL of distilled water was injected into the autoclave. The system was then heated to the preset temperature at a constant heating rate of 2 °C per minute. During the 72-h isothermal heating period, once the actual fluid pressure exceeded the preconfigured hydrocarbon expulsion threshold, the system’s hydrocarbon discharge valve would automatically open. The generated hydrocarbons were subsequently transferred to a gas-liquid separation tank, where continuous sub-zero cooling facilitated the separation, storage, and collection of gaseous and liquid components. A cold trap was employed throughout the simulation to capture condensate oil entrained in the expelled gas. Upon completion of the experiment at each temperature point, methylene chloride was used to rinse the autoclave and pipeline inner walls, ensuring complete collection of light oil fractions. The condensate oil and light oil were combined to form the “expelled oil” for that specific thermal simulation stage. After the experiment, dichloromethane extraction was performed on each rock sample, with the extracted product defined as the “retained oil” corresponding to the respective temperature point. The collected gaseous and liquid hydrocarbon products were then subjected to group component analysis and gas chromatography-mass spectrometry (GC-MS) analysis to characterize their geochemical properties.
Gas component analysis in this study was conducted using an Agilent 7890B gas chromatograph, coupled with a gas sampling bag injection approach. This analytical setup enables the simultaneous determination of C1–C5 hydrocarbon gases, along with non-hydrocarbon components including CO, CO2, H2, N2, and O2, in a single injection run. The column oven temperature program was optimized as follows: an initial hold at 30 °C for 10 min, followed by ramping to 180 °C at 10 °C per minute, and a final isothermal hold at 180 °C for 20–30 min to ensure complete elution of all target components.
For oil sample pretreatment prior to analysis, approximately 20 mg of n-hexane was added to the collected oil products from each thermal simulation. The mixture was then allowed to stand for 24 h to precipitate asphaltenes, which were subsequently removed. The remaining deasphalted oil was loaded onto an alumina separation column and sequentially eluted using three solvent systems: pure n-hexane, dichloromethane/n-hexane (1:2, v/v), and dichloromethane/methanol (93:7, v/v). These solvents selectively extracted saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbon fractions, respectively.
Saturated hydrocarbon fractions were analyzed using an Agilent 7890B/5977B gas chromatography-mass spectrometry (GC-MS) system, equipped with an HP-5MS capillary column (30 m × 0.25 mm × 0.25 μm). The GC temperature program was set as follows: initial temperature of 50 °C (held for 1 min), increased to 100 °C at 20 °C per minute, then ramped to 315 °C at 3 °C per minute, and maintained at 315 °C for 16 min.
The mass spectrometer was operated with a quadrupole analyzer maintained at 150 °C and an electron impact (EI) ion source at 230 °C with an ionization energy of 70 eV. A combined scanning mode was adopted, incorporating both full-scan (mass range: 50–550 amu) and selected ion monitoring (SIM) functions. The key characteristic ions monitored in SIM mode included m/z 85, 123, 191, and 217. Relative quantification of target compounds was achieved via manual integration of the m/z 191 mass chromatogram derived from the SIM signal, where peak areas of relevant compounds were measured and used to calculate the required geochemical parameters.

3. Results

3.1. TOC and Rock–Eval Data

Table 2 presents the total organic carbon (TOC) content and Rock-Eval analytical results of solid residues obtained through post-thermal pyrolysis. As the pyrolysis temperature increases, there is a systematic decrease in TOC, hydrogen index (HI), S1, and S2 values. Specifically, the TOC content decreases from 5.51 wt% and 5.62 wt% to 1.07 wt% and 1.40 wt%, while the HI decreases from 596 and 728 to 4 and 12 mg HC/g TOC. Similarly, the S1 + S2 values decrease from 11.09 and 31.63 to 0.25 and 0.36 mg HC/g TOC, respectively. These results indicate that the hydrocarbon potential of the two samples gradually declines as thermal evolution increases.

3.2. Amount of Generated, Expelled and Retained Hydrocarbon

Table 3 summarizes the experimental results derived from the thermal simulation tests on the shale samples. With the gradual increase of simulated temperature, the oil hydrocarbon generation rate exhibited three distinct evolutionary stages, which are detailed as follows: The first stage corresponds to a slow-growth phase of oil generation (Ro: 0.78–0.91%), representing the early maturation period prior to the onset of peak oil production. The second stage is characterized by a dramatic surge in oil generation rate (Ro: 0.91–1.34%), coinciding with the thermal evolution peak of the source rocks. The maximum oil generation rates during this stage were recorded at 1.05% and 1.34% Ro, respectively. Notably, the retained oil yield reached its experimental maximum at these two Ro values (1.05% and 1.34%), whereas the most significant growth rates for total oil, total hydrocarbons, and retained oil were observed between 0.91% and 1.05% Ro. The third stage involves a rapid decline in oil generation efficiency (Ro: 1.34–2.52%). Specifically, the retained oil yield began to decrease after reaching its peak at 1.05% and 1.34% Ro. A key observation is that the retained oil reaches its generation peak earlier than expelled oil, total oil, and total hydrocarbons, as illustrated in Figure 3a–c.
In summary, the gaseous products generated from the source rock hydrocarbon generation and expulsion simulation experiments consist of both hydrocarbon gases and inorganic gas components, with CO2 and H2 being the primary inorganic species. As presented in Table 4, the total gas yield shows a consistent upward trend with the elevation of simulated temperature. Notably, the gas generation rate maintained a continuous growth pattern throughout the high-to-overmaturity stage of thermal evolution (Figure 3d). A comparative analysis of retained oil, expelled oil, and total oil yields uncovered a striking correspondence: the temperature point at which expelled oil yield exhibits the most rapid growth closely matches the threshold temperature where retained oil yield begins to decline. Furthermore, the variation trends of total oil yield and retained oil yield are highly consistent, indicating a strong positive correlation between these two parameters (Figure 3f–h).

3.3. Fraction and Molecular Composition of Generated Hydrocarbon

As the temperature increases, the relative contents of saturated hydrocarbons and aromatic hydrocarbons in the retained oil fraction exhibit a consistent variation pattern: an initial rise followed by a subsequent decline. Their peak relative abundances are both observed within the temperature interval of 325–350 °C. In contrast, non-hydrocarbons and asphaltenes display an opposing trend, with their relative contents first decreasing and then increasing; this transition typically occurs around the 350–375 °C temperature range. Saturated hydrocarbons, aromatic hydrocarbons, non-hydrocarbons, and asphaltenes together account for a major proportion of the total oil in the retained oil samples. Notably, the variation characteristics of each of these fractions are highly analogous between the two sets of shale samples tested in this study (Figure 4).
In the original shale sample, the carbon chain length of saturated hydrocarbons spanned from nC11 to nC33. Of note, the carbon number distribution exhibited two prominent peaks at C21 and C17, respectively. The odd-even predominance (OEP) value of these n-alkanes reflected a distinct odd-carbon number preference. Detailed experimental data for these parameters are compiled in Table 5, while Figure 5 presents the chromatographic profiles illustrating the compositional variations of saturated hydrocarbons across different temperature stages of the thermal simulation.
For the retained oil collected from the simulation tests, the n-alkane components covered a carbon chain range of C14 to C36. The ∑nC21−/∑nC22+ ratio—an indicator of carbon number distribution—revealed that low-carbon-number alkanes were the dominant fraction in the retained oil. This observation implies that lighter hydrocarbon components possess a higher retention potential within the shale matrix during thermal maturation.

4. Discussion

4.1. Hydrocarbon Generation Potentials from Felsic and Carbonate Laminated Shale

Based on pyrolysis experiments, it was found that the carbon loss of both samples reached 30% at temperatures up to 300 °C. At 325 °C, approximately 45% of the original total organic carbon (TOC) was lost, and at 400 °C, around 80% of the initial TOC was lost (Figure 6). The maximum carbon loss for felsic shale during heating was observed to be 80.2 wt% at 400 °C, after significant oil expulsion. Similarly, at 400 °C, carbonate shale experienced a loss of 72.8% of the original TOC. Differential carbon loss between felsic shale and carbonate shale occurred primarily between 350–400 °C, exhibiting a similar trend for both shale types. The trend of hydrogen index reduction aligns with the carbon loss curve (Figure 7). Carbon loss from felsic shale peaked at approximately 475 °C, reaching 80.6% (Figure 6), which exceeds the 75.1% carbon loss of carbonate shale. The substantial change in TOC is further supported by our observations for felsic shale, which indicate a loss of up to 80% of the original organic matter. As a result, the evaluation system for felsic shale should differ from that for carbonate shale rocks, given the increased reduction in TOC through maturation. Moreover, the total hydrocarbon products derived from felsic shale surpass those of carbonate shale (Figure 7). When compared to felsic shale source rocks, carbonate shale source rocks lose significantly less TOC during maturation. This shows that certain low-TOC, extremely developed felsic shale source rocks could be effective if oil is expelled. However, distinguishing present low TOC felsic shale source rocks from original low TOC carbonate rocks, which have experienced organic carbon loss during oil expulsion, remains a challenge.

4.2. Hydrocarbon Retention-Expulsion from Felsic and Carbonate Laminated Shale

Oil retention efficiency (ORE) was determined by calculating the fraction of retained oil in relation to all created hydrocarbons, which included expulsion hydrocarbons, and oil left in the sample after the experiment.
Preliminary assessment results indicate that the felsic shale expelled merely 10% of its total generated oil when the temperature was below 325 °C; this oil expulsion ratio (ORE) then surged to 45.6% at 375 °C. Beyond this temperature, ORE gradually decreased due to intense thermal cracking, a process that converts liquid oil into gaseous hydrocarbons. In comparison, the carbonate shale exhibited a lower ORE within the main oil-generating interval. At 350 °C, roughly 28.5% of the oil produced by the carbonate shale was expelled, whereas the felsic shale achieved a much higher expulsion ratio of 44.0% at the same temperature (Figure 8a). With respect to gas expulsion efficiency (GEE), this parameter increases with rising temperature but at disparate rates between the two shale types. A notable burst of gas expulsion was observed in felsic shale: GEE jumped from approximately 10% at 350 °C to nearly 50% at 400 °C, and its overall GEE remained substantially higher than that of carbonate shale throughout the experiment (Figure 8b). Petroleum expulsion efficiency (PEE) is defined as the ratio of total expelled hydrocarbons (expelled oil plus gas) to total generated hydrocarbons. As temperature increased, PEE displayed a “slow-fast-slow” growth pattern (Figure 8c). Within the oil window (Ro: 0.5–1.2%), the felsic shale maintained higher PEE values than the carbonate shale. In contrast, oil retention efficiency (ORE) showed a consistent downward trend with the elevation of thermal maturity (Figure 8d). For carbonate shale’s higher oil retention, combined with pore structure data and Wang et al.’s (2024) findings, it mainly results from two factors: strong adsorption of polar hydrocarbons by OM with high aromaticity, and occlusion of liquid hydrocarbons in disconnected nano-pores (5–50 nm) due to poor pore network connectivity. Regarding felsic shale’s earlier expulsion and higher GOR, our analysis links this to clay minerals (illite-smectite mixed layers) that exert a catalytic effect, accelerating kerogen cracking into light hydrocarbons and gas. Additionally, felsic shale’s higher brittleness and well-connected pore networks (observed via FIB-SEM) lower expulsion thresholds, enabling earlier hydrocarbon discharge.
Heating both felsic shale and carbonate shale resulted in equal methane outputs, with temperature predominantly influencing the dryness index [C1/∑(C1–5)]. In the felsic shale, the dryness index first decreased until peaking at 0.40 at 400 °C.
This downward trend was associated with the formation of bitumen, a process that drove the dryness index up to 0.64 when the temperature reached 475 °C. In contrast, the dryness index of carbonate shale exhibited a slight decline from 0.45 (at 400 °C) before peaking at 0.72 at 550 °C. These results indicate that thermal maturity plays a pivotal role in determining the dryness index of both shale types (Figure 9a). The methane (CH4) enrichment characteristic, reflected by the C1/C2 ratio, showed a consistent variation pattern with the dryness index in both shales (Figure 9b). Wet gas indices—including the C2/C3, C3/C4, and C4/C5 ratios—displayed analogous trends across the two shale samples. Specifically, these ratios remained relatively stable at low values below 400 °C, followed by a noticeable increase at higher temperature conditions (Figure 9c–e). Additionally, for the felsic shale, the isobutane/n-butane (iC4/nC4) and isopentane/n-pentane (iC5/nC5) ratios showed a steady upward trend with rising temperature. However, at the same temperature points, these ratios were consistently lower than those measured in the carbonate shale.

4.3. Molecular Variation of Retained Hydrocarbon with Thermal Maturity

Figure 10 presents histograms illustrating the n-alkane distribution characteristics in the retained oil of felsic and carbonate shale samples. Generally, the carbon number distribution of these alkanes exhibits a typical bell-shaped profile. By adjusting the envelope curves of the histograms to better fit the n-alkane carbon number variations, a clear peak shift phenomenon was observed: as the heating temperature increased from 300 °C to 475 °C, the dominant peak of the alkane distribution moved from the C20+ range to C17. Notably, when the sample temperature reached 375 °C, the bell-shaped distribution of n-alkanes transitioned back to a bimodal pattern, with a prominent unimodal component centered at C17. For samples heated above 375 °C, high-molecular-weight alkanes (C30+) were almost completely absent. The distribution characteristics at 375 °C revealed an enrichment of low-molecular-weight n-alkanes, which are presumably derived from the hydrocarbon generation products of shales heated within the 300–350 °C range. The retained oil fractions consistently contained substantial amounts of small-molecular-mass n-alkanes. Furthermore, a transition from unimodal to bimodal n-alkane distribution was observed when the temperature exceeded 350 °C. As thermal maturity increased, the average molecular mass of the retained oil showed a gradual decreasing trend. Based on these comprehensive observations, it can be concluded that the variation patterns of residual oil molecular mass in the two shale types are relatively consistent during the thermal maturation process.

4.4. Variation of GOR During Pyrolysis

The volumetric gas-to-oil ratio (GOR), expressed in cubic meters per ton (m3/t), served as a key parameter to assess the internal dynamic changes of the shale system during the heating process. Throughout the experiment, the yields of generated oil and gas were continuously monitored, and the GOR value was computed by dividing the volume of discharged hydrocarbon gas by that of discharged oil. Figure 11 illustrates how the GOR varies with the progressive increase of thermal maturity.
As thermal maturity increases, GOR also exhibits an upward trend. In this study, the behavior of GOR remains relatively constant until approximately the mid-point of the oil window (around 1.0%Ro) (Figure 11). Subsequently, as the peak oil generation phase is reached (around 1.0%Ro), secondary cracking becomes dominant, leading to the generation of more mobile light oil and hydrocarbon gas. This, in turn, contributes to an increase in GOR (Figure 11) and enhances the fluidity of the oil. These findings align with previous study. The presence of lighter oil components and a higher GOR enhances shale oil fluidity and production potential. Following this phase, the residual oil is quickly consumed, and the responses are predominantly influenced by wet gas breaking and coking, resulting in reduced production. Based on the data, it is clear that felsic shale has a larger GOR than carbonate shale at identical degrees of thermal maturity. As a result, the production of shale oil from felsic shale exceeds that of carbonate shale.

5. Conclusions

This is the first study to quantitatively compare hydrocarbon generation-retention-expulsion dynamics, and the resulting GOR and molecular compositions, between felsic and carbonate lacustrine shales, utilizing a geologically realistic semi-open pyrolysis system.
Throughout the pyrolysis process, notable differences in hydrocarbon distribution were observed between the two shale types. The retained oil yield of carbonate shale exceeded that of felsic shale by approximately 119 mg/g, whereas its expelled oil amount was 184 mg/g lower than the latter. Felsic shale exhibited earlier peaks in both oil generation and retention compared to carbonate shale, though it had a lower oil retention efficiency. Despite this, the higher residual hydrocarbon content in felsic shale facilitated earlier oil expulsion, enhanced gaseous hydrocarbon formation, and achieved substantially higher gas expulsion efficiency than carbonate shale. Although the hydrocarbon gases produced by both shales followed analogous thermal evolution trends, significant disparities existed in methane relative content and gas-to-oil ratio (GOR) between the two samples. Within the oil window (Ro: 0.5–1.2%), the carbon isotopic trends of the two source rocks were highly similar; however, felsic shale experienced more pronounced carbon loss than carbonate shale. With increasing thermal maturity, the molecular weight of n-alkanes in the retained oil showed a more distinct decreasing trend. Moreover, compared to low-maturity stages, lighter oil components were more prone to retention at higher maturity levels. This phenomenon contributed to a marked increase in GOR, with retained hydrocarbons characterized by a higher abundance of light hydrocarbon fractions. The results of this study confirm that lithology exerts a significant control on the processes of hydrocarbon generation, retention, and expulsion. Consequently, it highlights the necessity of investigating and clarifying the unique properties of different source rocks, which is crucial for establishing hydrocarbon exploration models and assessing shale oil development potential.

Author Contributions

Conceptualization, Q.G., X.L. and B.S.; methodology, Q.G., X.L., B.S., C.C., Z.H. and X.Z.; software, Q.G. and B.S.; validation, Q.G., X.Z., F.J., W.J. and X.P.; formal analysis, Q.G. and B.S.; investigation, C.C., X.Z., F.J., W.J. and X.P.; resources, C.C., X.Z., F.J., W.J. and X.P.; data curation, Q.G.; writing—original draft preparation, Q.G.; writing—review and editing, Q.G., X.L.; visualization, T.L., Z.H., W.P. and G.J.; supervision, Q.G. and X.L.; project administration, X.L., C.C. and X.Z.; funding acquisition, X.L. All authors have read and agreed to the published version of the manuscript.

Funding

This work was financially supported by the National Natural Science Foundation of China (Grant No. 42072150 and Grant No. 42572167) and we thank the sponsors of these projects.

Data Availability Statement

Data is contained within the article.

Acknowledgments

We thank the contribution of all authors and petroChina Dagang Oilfield Company for providing samples, data access and fundings (Science and Technology Project of China National Petroleum Corporation: “Research and Experiment on Optimization Technology for Continental Shale Oil Development”, Project No.: 2023ZZ15YJ03; National Science and Technology Major Project for New type Oil and Gas Exploration and Development: Regularities of Shale Oil Enrichment and High Productivity and Domains for Reserve Growth, Project No.: 2024ZD1400105).

Conflicts of Interest

Author Changwei Chen, Fengming Jin, Wenya Jiang and Xiugang Pu were employed by the company PetroChina Dagang Oilfield Company. Author Xianzheng Zhao was employed by the company China Petroleum Consulting Center. The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

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Figure 1. (a). Stratigraphic column of the Paleogene strata in the Huanghua Depression; (b). Scanned polished slabs of the sample in this study, showing laminae; (c). thin section image of the sample, showing organic-rich and organic-lean laminae.
Figure 1. (a). Stratigraphic column of the Paleogene strata in the Huanghua Depression; (b). Scanned polished slabs of the sample in this study, showing laminae; (c). thin section image of the sample, showing organic-rich and organic-lean laminae.
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Figure 2. Structures of thermal simulation experimental devices of Semi-open systems.
Figure 2. Structures of thermal simulation experimental devices of Semi-open systems.
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Figure 3. Relationship between the yields of hydrocarbon products and temperature, Ro of the Felsic shale and Carbonate shale samples.
Figure 3. Relationship between the yields of hydrocarbon products and temperature, Ro of the Felsic shale and Carbonate shale samples.
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Figure 4. Relative percentages of group components of expelled oil and retained oi in thermal simulation of the Felsic shale and Carbonate shale samples.
Figure 4. Relative percentages of group components of expelled oil and retained oi in thermal simulation of the Felsic shale and Carbonate shale samples.
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Figure 5. Variation of normal paraffin parameters of retained oil in thermal simulation of the Felsic shale and Carbonate shale samples.
Figure 5. Variation of normal paraffin parameters of retained oil in thermal simulation of the Felsic shale and Carbonate shale samples.
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Figure 6. Carbon-loss during pyrolysis experiments of the Felsic shale and Carbonate shale samples.
Figure 6. Carbon-loss during pyrolysis experiments of the Felsic shale and Carbonate shale samples.
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Figure 7. HI reduction and total hydrocarbon products during pyrolysis experiments of the Felsic shale and Carbonate shale samples.
Figure 7. HI reduction and total hydrocarbon products during pyrolysis experiments of the Felsic shale and Carbonate shale samples.
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Figure 8. Variations in Oil Expulsion Efficiency (OEE: Expelled Oil/Total Oil Generated), Gas Expulsion Efficiency (GEE), Petroleum Expulsion Efficiency (PEE: ((Expelled Oil + Expelled Gas)/Total Hydrocarbon Products Generated)), and Oil Retention Efficiency (ORE) with Rising Temperature.
Figure 8. Variations in Oil Expulsion Efficiency (OEE: Expelled Oil/Total Oil Generated), Gas Expulsion Efficiency (GEE), Petroleum Expulsion Efficiency (PEE: ((Expelled Oil + Expelled Gas)/Total Hydrocarbon Products Generated)), and Oil Retention Efficiency (ORE) with Rising Temperature.
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Figure 9. Changes of gas chemical compositions during pyrolysis experiments.
Figure 9. Changes of gas chemical compositions during pyrolysis experiments.
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Figure 10. N-alkane distribution of retained hydrocarbon in samples from pyrolysis-gas chromatography.
Figure 10. N-alkane distribution of retained hydrocarbon in samples from pyrolysis-gas chromatography.
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Figure 11. Evolution of the GORI and GORE during pyrolysis.
Figure 11. Evolution of the GORI and GORE during pyrolysis.
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Table 1. Boundary conditions of pyrolysis experiments.
Table 1. Boundary conditions of pyrolysis experiments.
Sample StyleTemperature, °CDepth, mFormation Pressure, MpaLithostatic
Pressure, Mpa
Felsic shaleOS25653175
30025753175
32531163788
35034493994
375365145109
400453849117
475600060144
Carbonate shaleOS25753175
30025753175
32531163788
35034493994
375365145109
400453849117
475600060144
Table 2. Organic geochemical characteristics of the Felsic shale and Carbonate shale samples.
Table 2. Organic geochemical characteristics of the Felsic shale and Carbonate shale samples.
Sample StyleTemperature, °CTOC, %S1, mg/gS2, mg/gHI, mg/g
Felsic shale3005.510.4810.61596
3253.022.1119.88659
3502.583.5213.98542
3751.753.243.74213
4001.090.570.3432
4751.070.210.044
Carbonate shale3005.621.2430.39728
3253.361.9721.97654
3503.033.9815.54513
3752.564.886.35248
4001.530.770.7851
4751.400.190.1712
Table 3. Chemical composition of gases produced from the pyrolysis experiments of the Felsic shale and Carbonate shale samples.
Table 3. Chemical composition of gases produced from the pyrolysis experiments of the Felsic shale and Carbonate shale samples.
Sample StyleTemperature,
°C		Expelled Oil, mgHC/gTOCRetained Oil, mgHC/gTOCTotal Oil, mgHC/gTOCH2, m3/gTOCCO2, m3/gTOCHydrocarbon Gas, m3/gTOCTotal Gas, m3/gTOCTotal
Hydrocarbon Products, mgHC/gTOC
Felsic shale3001711813412231114149
3253823327112722229300
350375371746200278106852
3753512445954263175175770
400255593144293303450764
475220112314479570585816
Carbonate shale300920521454133217
32522205226112189236
35012227539716512531427
37519149068124015630711
400190462362642131183419
47519081985188213204402
Table 4. The gas products from the pyrolysis experiments of the Felsic shale and Carbonate shale samples.
Table 4. The gas products from the pyrolysis experiments of the Felsic shale and Carbonate shale samples.
Sample StyleTemperature,
°C		C1,
mol%		C2H6,
mol%		C2H4,
mol%		C3H8,
mol%		C3H6,
mol%		iC4,
mol%		nC4,
mol%		C4H8,
mol%		iC5,
mol%		nC5,
mol%		H2,
mol%		CO2,
mol%
Felsic shale3004.541.010.001.250.030.160.470.000.130.471.9390.00
3258.202.620.001.960.030.290.840.020.210.681.5583.59
35013.915.570.004.070.000.641.930.000.481.330.7871.28
37513.825.870.004.540.040.582.330.030.461.370.5270.46
40016.479.080.007.970.090.944.020.050.681.920.4458.34
47535.4713.410.005.780.000.470.320.000.000.070.8943.59
Carbonate shale3003.340.500.000.450.000.080.170.000.060.171.0694.18
3253.940.970.000.690.000.110.300.000.080.230.9292.77
3507.582.190.001.530.020.230.720.000.160.490.7286.36
37510.853.370.002.400.010.331.140.000.230.620.3580.68
40014.987.030.005.630.040.712.770.020.491.290.4266.62
47520.665.650.002.250.000.190.090.000.000.031.0570.08
Table 5. Saturated hydrocarbon chromatographic parameters of the Felsic shale and Carbonate shale samples.
Table 5. Saturated hydrocarbon chromatographic parameters of the Felsic shale and Carbonate shale samples.
Sample StyleTemperature,
°C		Saturated
Hydrocarbons,
%		Aromatic
Hydrocarbons,
%		Non-
Hydrocarbons,
%		Asphaltenes,
%		Maximum Peak∑C21−/
∑C22+		OEPPr/nC17Ph/nC18
Felsic shale30025.3418.6247.184.76C211.161.290.351.53
32529.7921.0039.877.32C211.031.360.160.74
35023.7617.6046.859.81C211.181.250.080.15
37531.7713.4846.836.56C171.491.030.070.10
40019.5531.2737.747.54C171.431.030.050.09
475----C171.430.990.080.08
Carbonate shale30019.039.3842.6221.37C211.391.070.140.62
32518.967.4549.4819.36C221.921.010.140.51
35023.5413.2033.8324.54C210.921.060.140.26
37539.719.9417.9732.13C211.721.090.040.07
40048.0513.2122.8415.76C212.241.050.140.04
47521.7814.1518.5644.81C211.371.060.060.08
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Guan, Q.; Liu, X.; Chen, C.; Zhao, X.; Jin, F.; Jiang, W.; Pu, X.; Sun, B.; Liu, T.; Hua, Z.; et al. A Comparison of Generation–Retention–Expulsion in Felsic and Carbonate Laminated Shale by Semi-Open Thermal Pyrolysis: Implications for Shale Oil Exploration. Geosciences 2026, 16, 9. https://doi.org/10.3390/geosciences16010009

AMA Style

Guan Q, Liu X, Chen C, Zhao X, Jin F, Jiang W, Pu X, Sun B, Liu T, Hua Z, et al. A Comparison of Generation–Retention–Expulsion in Felsic and Carbonate Laminated Shale by Semi-Open Thermal Pyrolysis: Implications for Shale Oil Exploration. Geosciences. 2026; 16(1):9. https://doi.org/10.3390/geosciences16010009

Chicago/Turabian Style

Guan, Quansheng, Xiaoping Liu, Changwei Chen, Xianzheng Zhao, Fengming Jin, Wenya Jiang, Xiugang Pu, Biao Sun, Tian Liu, Zuxian Hua, and et al. 2026. "A Comparison of Generation–Retention–Expulsion in Felsic and Carbonate Laminated Shale by Semi-Open Thermal Pyrolysis: Implications for Shale Oil Exploration" Geosciences 16, no. 1: 9. https://doi.org/10.3390/geosciences16010009

APA Style

Guan, Q., Liu, X., Chen, C., Zhao, X., Jin, F., Jiang, W., Pu, X., Sun, B., Liu, T., Hua, Z., Peng, W., & Jia, G. (2026). A Comparison of Generation–Retention–Expulsion in Felsic and Carbonate Laminated Shale by Semi-Open Thermal Pyrolysis: Implications for Shale Oil Exploration. Geosciences, 16(1), 9. https://doi.org/10.3390/geosciences16010009

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