Search Results (180)

As exploration expands into deep and unconventional petroleum systems, light oil and condensate have become key targets for reserve growth and production enhancement. This study employs the gold tube pyrolysis of kerogens from Cretaceous Qingshankou shale to investigate the role of hydrocarbon (HC) expulsion in light oil and condensate generation during thermal maturation. The results show that HC expulsion significantly reduces overall HC yields and alters their chemical composition. Specifically, compared with immature kerogen, n-hexane-extracted mature kerogen (EasyR_o = 0.96%) exhibited reductions of 60%, 57%, and 50% in C₁₅₊ compounds, C_6–14 HCs, and C_1–5 gases, respectively. Moreover, the generation window of C_6–14 HCs (a proxy for light oil) is narrowed and shifted toward lower maturity. Kinetic parameters were further used to establish two separate evolutionary models for methane, wet gas, light oil, and heavy oil. Based on these models, the shale oil resource potential of the first member of the Qingshankou Formation, the Qijia–Gulong Sag, is estimated to be (6.95–8.80) × 10⁶ ton/km² for the no-HC-expulsion scenario and (3.63–3.85) × 10⁶ ton/km² for the significant-HC-expulsion scenario (HEE = 84.35%). These results provide a valuable reference for assessing the light oil and condensate potential of high-maturity Qingshankou shale in the Songliao Basin. Full article

Refracturing is an important stimulation technique for improving the productivity of mature shale gas wells. However, for low-productivity horizontal wells, the controlling effects of production history and pre-refracturing energy replenishment on fracture re-initiation and repropagation remain insufficiently quantified. This study focuses on mature wells in the H Block of the Fuling shale gas field. The Jiaoshiba area in the Fuling shale gas field, located on the eastern margin of the Sichuan Basin, is characterized by organic-rich marine shales of the Wufeng–Longmaxi Formation, where gas enrichment is jointly controlled by the Jiaoshiba anticline, fault distribution, and favorable preservation conditions. A three-dimensional geological model was constructed using seismic interpretation, well logging, core analysis, ant-tracking fracture attributes, and field fracturing data. A one-way coupled finite-element workflow was then applied to simulate the evolution of pore pressure and in situ stress during primary production, water-injection energy replenishment, and refracturing. The model was calibrated against historical bottomhole flowing pressure data, with a pressure-response matching accuracy greater than 85%. The results show that a lower initial production (4 × 10⁴ m³/d) allocation can mitigate reservoir pressure depletion and maintain a more favorable stress environment for fracture branching during refracturing. Compared with refracturing after 10 or 20 years of production, refracturing after 5 years produced a stronger post-treatment response in the simulated cases. For water-injection energy replenishment, an injection rate of 700 m³/d restored reservoir pressure and regulated the local stress field more effectively than 500 m³/d, whereas increasing the rate to 1000 m³/d provided only limited additional pressure recovery. Overall, under the simulated reservoir conditions, a technically favorable parameter combination for the target well is an initial production allocation of 4 × 10⁴ m³/d, refracturing after approximately 5 years of production, and one year of pre-refracturing water-injection energy replenishment at about 700 m³/d. These findings provide a reference for refracturing timing and pre-treatment energy-replenishment design in depleted shale gas reservoirs. Full article

Mature shale gas areas commonly retain substantial remaining resources after long-term depletion, but their redevelopment potential is governed by pressure redistribution, present-day stress evolution, natural-fracture stability, and target accessibility. Taking the HuangJinBa YS108 shale gas area as an example, this study proposes an integrated redevelopment zoning workflow that couples geological conditions, geomechanical constraints, and fracture-slip risk. Two types of remaining targets are identified: inter-well remaining resources and wellbore-control blind-spot resources. A geological-condition evaluation index (GCEI) is then constructed using remaining gas content, effective reservoir thickness, and remaining pressure. The zoning results are further constrained by the Anderson stress-regime index, horizontal stress difference, maximum horizontal stress orientation, and a Mohr–Coulomb-based natural-fracture-slip-risk index. Results indicate that L113 and L112 are the main depleted layers, whereas L114, L111, and the Wufeng Formation retain further redevelopment potential. Favorable zones are mainly distributed around platforms H24, H1, H3, H23, H13, and eastern H20. Long-term depletion reduces the minimum horizontal stress in densely developed areas and generally improves fracture stability, although local fracture intersections still present elevated slip risk. The final zoning provides a practical basis for redevelopment decision-making: platforms H24, H1, H3, H23, H13, and eastern H20 can be prioritized for near-term screening; inter-well targets should be developed using conservative infill strategies with controlled fracture length; and wellbore-control blind-spot targets can be stimulated more intensively under controllable fracture-slip risk. Full article

This study presents experimental adsorption–desorption data of CH₄ and CO₂ on shale samples from the Cesar-Ranchería Basin, Colombia, a region with limited characterization of gas–rock interactions under reservoir-relevant conditions. The work addresses the behavior of early-mature shales, contributing to the understanding of gas retention mechanisms in tropical basins. Adsorption–desorption isotherms were obtained using a high-pressure manometric system at 50 °C and 80 °C, with pressures up to 3 MPa, and were fitted using the Langmuir model. The results show a consistently higher adsorption capacity for CO₂ compared to CH₄ across all conditions, along with a clear decrease in adsorption capacity with increasing temperature, confirming the exothermic nature of the process. No hysteresis was observed, indicating fully reversible adsorption dominated by physisorption mechanisms. The integration of adsorption data with mineralogical, BET surface area, and geochemical characterization provides insight into the factors controlling gas retention in early-mature shales. The results highlight the combined influence of surface area, organic matter, and clay mineralogy on adsorption performance, and demonstrate that CO₂ exhibits a stronger affinity for the shale matrix under all tested conditions. These findings contribute experimental evidence of gas adsorption behavior in an underexplored basin and provide a reference framework for evaluating gas storage potential in similar geological settings. Full article

Organic-rich shales in China’s deep-water shelf environments possess significant shale gas resource potential. To investigate the reservoir development characteristics of deep-water shelf shale, 143 shale samples were collected from the low-maturity Xiamaling Formation in the Zhangjiakou area and the high to over-mature Wufeng–Longmaxi Formations in the southeastern margin of the Sichuan Basin. Basic analytical methods, including X-ray diffraction (XRD), total organic carbon (TOC) analysis, rock pyrolysis, and solid bitumen reflectance measurements, were employed alongside advanced reservoir characterization techniques such as field-emission scanning electron microscopy (FE-SEM), low-pressure CO₂/N₂ physisorption, mercury intrusion porosimetry (MIP), and focused ion beam scanning electron microscopy (FIB-SEM). This study focuses on the petrographical, geochemical, and microscopic pore structure characteristics of these marine shales. The results indicate that the mineral composition of deep-water shelf sedimentary shale is dominated by quartz, clay minerals, feldspar, calcite, dolomite, apatite, and pyrite, with quartz being the most abundant. The Xiamaling Formation shales, at low maturity, are relatively rich in siliceous components, while the high to over-mature Wufeng and Longmaxi Formation shales are richer in carbonate components. The kerogen type of organic matter in the Xiamaling Formation is primarily Types II₁ and II₂, whereas the Wufeng–Longmaxi shales are predominantly Types I and II₁. TOC content is highest in the Wufeng Formation, followed by the Longmaxi Formation, with the Xiamaling Formation exhibiting the lowest TOC levels. Pore development in the Wufeng and Longmaxi shales is significantly superior to that in the Xiamaling shales. Overall, the Wufeng and Longmaxi Formations demonstrate more favorable pore characteristics and hydrocarbon generation potential compared to the Xiamaling Formation. The Wufeng and Longmaxi Formations’ shales will be the key targets for shale gas exploration in the future. The findings of this study contribute to the understanding and development of theories of marine shale gas accumulation in China and hold both theoretical and practical significance for the efficient and rational exploitation of shale oil and gas resources. Full article

This study is a systematical investigation of the fundamental geological conditions for shale gas in the Wufeng–Longmaxi formations in western Hubei, China, using drilling core data, with Well Xiandi-2 serving as the key well for core observation and experimental testing, integrated with outcrop profiles and regional provincial-level shale gas block data. The analysis encompasses petrology, organic geochemistry, mineral composition, physical properties, pore types, and gas content. Through a comprehensive comparison with established shale gas production fields in the Sichuan Basin, the shale gas resource potential of the study area is evaluated, and favorable zones for shale gas exploration are delineated. The results indicate that the study area contains a continuous organic-rich shale interval with a 18.84 m net thickness, 2.3% average total organic carbon, 65–89% brittle mineral content, 2.36% average porosity, and thermal maturity within the gas window. Systematic comparison with the Jiaoshiba and Changning fields confirms comparable geological attributes, including organic matter abundance, reservoir porosity, and brittle mineralogy. Given this comparability, areas with burial depths shallower than 1500 m on the northwestern margin of the Xuefeng Uplift are interpreted to retain moderate shale gas resource potential. Three favorable zones are delineated as priority targets: the synclines on both sides of the Longtan normal fault and the Lianghekou Syncline. These findings provide practical exploration value: the identified favorable zones offer immediate drilling targets, the analytical workflow is transferable to other structurally complex blocks on the basin margin, and the potential of shallow-buried sequences expands exploration beyond the core Sichuan Basin into previously overlooked transitional zones. Full article

Considerable debate remains regarding the mechanisms responsible for the reduction in organic matter (OM) pores in post-mature shales. To address this issue, complementary techniques including scanning electron microscopy (SEM), total organic carbon (TOC) analysis, and helium porosity measurement were employed to characterize the microstructure and porosity of post-mature shales from the Qiongzhusi Formation in the southwestern Upper Yangtze region, China. The results show that OM pores in these shales are poorly developed and exhibit highly irregular morphologies. Notably, the degree of OM pore development is negatively correlated with TOC. Interestingly, in samples with TOC < 2.5 wt.%, well-preserved spongy migrated OM is still observable under SEM. The average porosity of Qiongzhusi mudstones is 1.8%; siltstone samples with TOC < 2 wt.% yield an average porosity of 3.5%, whereas samples with TOC > 4 wt.% have an average porosity of only 1.9%. These findings do not support the hypothesis that graphitization causes the significant destruction of OM pores in post-mature shales. Instead, we propose that compaction has been the dominant factor controlling OM pore destruction. Accordingly, we introduce a “depth window” for the development of high-quality shale gas reservoirs: Beyond a certain maximum paleoburial depth, compaction leads to extensive OM pore destruction and a marked decline in reservoir quality. This study advances our understanding of pore evolution in post-mature shales and provides practical guidance for shale gas exploration. Full article

At present, more than 50% of the horizontal wells in Changning block have entered the middle and late stage of low gas production, and the gas is difficult to produce with liquid. For such gas wells with a complex wellbore structure, multiple wellbore flow patterns and complex pressure distribution, the corresponding gas–liquid distribution characteristics and liquid carrying capacity are not yet mature. Therefore, based on the establishment of a large-scale experimental simulation device for air–water two-phase flow in horizontal wells with a horizontal section–inclined section–vertical section, this paper studies the gas–liquid distribution characteristics and liquid carrying capacity of shale gas horizontal wells through gas–liquid two-phase flow experiments. The variation and distribution characteristics of gas–liquid two-phase flow pattern in horizontal wellbore are mastered. When the gas flow rate in the horizontal section is less than 20 m³/h, and the gas flow rate in the vertical section and the deflecting section is less than 30 m³/h, churn flow occurs and effusion occurs. It is found that the deflecting section of each well section is the most difficult to carry liquid, and the horizontal section is the easiest to carry liquid. When the critical carrying liquid is in the horizontal section, the vertical tube accumulates liquid, and the oblique section accumulates liquid simultaneously. This result is not only crucial to improve the production of gas wells in Changning block but also provide guidance for the production of shale gas horizontal wells in the middle and late low gas production stages. Full article

An integrated analysis incorporating total organic carbon (TOC) content measurement, X-ray diffraction (XRD), scanning electron microscopy (SEM), and gas adsorption experiments was performed on core samples from Well FY1-4 of the upper-fourth Shahejie Formation (Es₄) in the Minfeng Sag. To address the lack of systematic research on the pore and fractal characteristics of organic-rich low-maturity shales in the Minfeng Sag (against the preponderance of studies on high-maturity shales), this study characterized the lithofacies, reservoir space and pore fractal features of the target low-maturity shale interval and clarified the sedimentary controls on lithofacies and key factors regulating pore fractal heterogeneity. The results reveal that the shale in the Es₄ of the study area exhibits low thermal maturity, with six distinct lithofacies identified. Organic-rich laminated calcareous shale lithofacies (RL-1) and organic-rich laminated calcareous/argillaceous mixed shale lithofacies (RL-2) represent the most favorable lithofacies, which are dominated by large mesopores and macropores. Their reservoir spaces were primarily composed of intergranular pores, intragranular pores, and organic pores, whereas the other lithofacies are dominated by small mesopores. The pore surface fractal dimension (D) was calculated using the Frenkel–Halsey–Hill (FHH) model based on low-temperature N₂ adsorption (LTNA) data. The meso-macropore system shows higher heterogeneity than the micropore system (D₂ > D₁). Both D₁ and D₂ exhibit a weak negative correlation with TOC and carbonate content and a positive correlation with clay content. In the initial depositional stage of the Es₄, the arid climate, weak terrigenous input, shallow lake depth, and high salinity resulted in the strongly reducing saline depositional environment with relatively low organic matter enrichment. As the climate became progressively humid in the middle and late stages, hydrodynamic conditions intensified, leading to a lithofacies transition from mixed shales to argillaceous calcareous shales. Increased TOC and carbonate contents reduce the pore fractal dimension of shale. Smaller fractal dimensions directly indicate a simple pore structure and regular pore surface in the shale oil reservoir of the Minfeng Sag, where reservoir space is dominated by large pores such as intercrystalline pores and dissolved pores. Such pore characteristics are more favorable for the enrichment of shale oil. Full article

The marine shale of the Longmaxi Formation is the main layer for shale gas exploration and development in the Sichuan Basin. That said, the pore structure in the Longmaxi shale is strongly heterogeneous, and how these pores form and are preserved remains unclear—which limits our understanding of what makes a good reservoir and holds back efficient shale gas development. To investigate the coupling relationship between hydrocarbon generation and pore evolution in marine shale, medium-maturity shale from the Longmaxi Formation in NE Sichuan was collected for thermal maturation experiments. Shale samples and pyrolysis products from different evolutionary stages were obtained for a series of analyses, including gas composition and pore structure. The influence of organic hydrocarbon generation and inorganic diagenesis on the development of shale nanopores was revealed, and a pore evolution model for marine shale was established. The results show the following: (1) The hydrocarbon generation process of medium-maturity marine shale consists of three stages. The maximum methane yield is 362.58 mL/g. (2) As the thermal maturity increases, the quartz content shows a gradual increase, while the content of clay minerals, feldspar, and carbonate minerals decreases. (3) As the thermal maturity increases, pore evolution is observed in four stages: “slow decrease,” “rapid increase,” “relatively stable,” and “slow decrease.” The first stage is characterized by pore reduction dominated by intense compaction. The second stage is dominated by pore expansion driven by mineral transformation and dissolution. The third stage is the pore preservation stage, during which continuous natural gas generation occurs. The fourth stage is characterized by pore reduction, mainly driven by weak compaction. This study has enriched the theoretical understanding of the dynamic evolution of shale pores, providing a theoretical basis for the research on the formation and enrichment mechanism of shale gas and the exploration practice of shale gas reservoirs. Full article

This study investigates the heterogeneity of pore structures in lacustrine shale gas reservoirs, with a specific focus on shales from the Lower Cretaceous Shahezi Formation in the Lishu Fault Sag of the Songliao Basin. By integrating multi-scale characterization techniques—including high-pressure mercury intrusion, N₂/CO₂ adsorption, and nuclear magnetic resonance (NMR)—we examined the pore networks across five identified lithofacies: organic-rich clayey shale, organic-rich mixed shale, organic-rich siliceous shale, organic clayey shale, and organic mixed shale. The results indicate that mesopores (2–50 nm) constitute the dominant fraction of pore volume (31.7%–56.6%), followed by micropores (<2 nm) and macropores (>10 μm). Notable lithofacies-dependent variations were observed: organic-rich clayey shale exhibits abundant organic pores, clay interlayer pores, and intragranular dissolution pores with favorable connectivity; organic-rich siliceous shale is mainly dominated by inorganic pores with limited organic porosity; mixed shales are characterized by clay mineral contraction fractures and intergranular pores. The key controlling factors are mineral composition and organic matter abundance: clay content shows a positive correlation with pore volume and surface area in organic-rich clayey shale, but a negative correlation in organic mixed shale. Brittle minerals (quartz and feldspar) generally reduce porosity through compaction. Total organic carbon (TOC) displays a weak positive correlation with mesopore volume, while thermal maturity (Ro = 1.2%–1.73%) exerts influences that vary by lithofacies. In contrast to marine shales—which are dominated by high-maturity (Ro > 2.0%) organic pores and quartz-supported frameworks—terrestrial shales primarily rely on inorganic pores derived from clay minerals (e.g., illite). This study clarifies the relationships among lithofacies, pore structure, and controlling factors, thereby providing a basis for evaluating the gas potential of terrestrial shales. Full article

Better understanding the controlling factors of shale oil quality including density and viscosity plays a key role in exploring these unconventional pay zones efficiently and profitably. The shale oil extracted from the middle Permian Lucaogou Formation (P₂l) of Santanghu Basin becomes denser and more viscous from the Tiaohu Sag to Malang Sag. It has been proven that oil quality is negatively correlated with saturated hydrocarbon content and positively correlated with aromatic/resin content. However, the underlying controls at the molecular levels are not yet clear. In order to reveal the fundamental controls, shale oil samples with varying density and viscosity were collected from these two sags, and molecular compositions of these samples were analyzed by using gas chromatography–mass spectrometry (GC–MS) for the saturated and aromatic hydrocarbons and electrospray ionization (ESI) Fourier transform ion cyclotron resonance mass spectrometry (FT–ICR MS) for heteroatom hydrocarbons in resin fraction. Thereafter, correlation analysis was performed between oil density and viscosity and geochemical parameters associated with saturated, aromatic and NSO-containing compounds. The experimental results indicate that the oil thermal maturity levels play a major role, since both density and viscosity present significant negative correlations (correlation coefficient > 0.5) with the maturity parameters of n-alkanes, terpanes, steranes and triaromatic steranes. Organic facies also play a partial role as indicated by the significant positive correlations between density and viscosity and the parameters of tricyclic terpanes, dibenzothiophene/phenanthrene, and methylated phenanthrenes. In resin fraction, density presents better correlations with acid compounds, including O_x (x = 5–9), N₁O_x (x = 0–2) and N₂O₃ species, and viscosity shows better correlations with basic N-containing compounds (N₁O₁, N₁O₃, and N₂O₁ species) and S-containing compounds (N₁S₁ and O₁S₁ species). This indicates that the cross-linking by acid oxygen-containing compounds and the intramolecular and intermolecular forces induced by basic N-containing compounds and sulfur-containing compounds play an important role in directing the P₂l shale oil quality. Moreover, the ratios of specific species with low-to-high double bond equivalents (DBEs) and the homologues with low molecular weight to high molecular weight both present significant negative correlations with density and saturated and aromatic maturity parameters. This highlights the effects of bond cleavage, cyclization and aromatization reactions with elevated thermal maturity in enhancing oil quality in the targeted pay zones. Most P₂l shale oil sources were deposited under the reducing lacustrine setting, containing mainly Type I/II kerogens. Shale oils from Tiaohu Sag are more matured than those from Malang Sag, which is supposed to be responsible for the better oil quality in Tiaohu Sag. This study provides the supporting evidence for regulating shale oil quality in the Santanghu Basin at the molecular levels, and should be helpful in identifying the sweet spots of shale oil plays in this area. Full article

Deep shale gas reservoirs in the southern Sichuan Basin (Weiyuan area) exhibit strong heterogeneity and complex pore-fracture networks. Traditional reservoir evaluation methods struggle to accurately capture their microscale pore characteristics and fracability, thereby restricting efficient development and precise sweet spot prediction. Therefore, integrating digital core technology with geological analysis is essential to systematically quantify key reservoir parameters, including microscale pore structure, mineral composition, and brittleness characteristics. To clarify the controlling factors of high-quality deep shale gas reservoirs in the Weiyuan area and assess their exploration and development potential, we performed digital core analysis at micron to nanometer scales. Three-dimensional digital core models of representative deep shale gas wells were constructed. Integrating mineral composition, geochemical characteristics, and pore space features, we discuss the geological conditions for deep shale gas accumulation and the fracability of horizontal wells, and we delineate favorable shale reservoir zones. The results show that digital core technology enables quantitative and visual characterization of each sublayer of the Longmaxi Formation shale reservoir, including mineral types, laminae types, pore-throat structures, and organic matter distribution. From the Long 11-1 sublayer to the Long 11-4 sublayer, the pore-throat radius, total pore volume, total throat volume, connected pore-throat percentage, and coordination number all gradually decrease. In the eastern Weiyuan area, the siliceous components in deep shale gas reservoirs at the base of the Longmaxi Formation are primarily of both biogenic and terrigenous origin. Due to local variations in the sedimentary environment, terrigenous input contributes significantly to the total siliceous content in this region. Although the Long 11-1 sublayer of the Longmaxi Formation is lithologically classified as mud shale, its particle size and mineral composition more closely resemble those of clayey siltstone or argillaceous sandstone, suggesting considerable potential for reservoir space development. Typical wells in the eastern Weiyuan area exhibit distinct lithological characteristics, including coarser grain sizes, stronger hydrodynamic conditions during deposition, and abundant terrigenous clastic supply. The rigid framework formed by silt- to sand-sized particles effectively mitigates compaction, thereby facilitating the preservation of intergranular pores and microfractures. High organic matter abundance, appropriate thermal maturity, and a considerable thickness of high-quality shale ensured sufficient hydrocarbon supply. The main types of natural fractures are intergranular and grain-edge fractures formed by differences in sedimentary grain size, and bedding-parallel fractures generated by hydrocarbon generation overpressure. Based on reservoir mineral composition, pore characteristics, areal porosity, and pore size distribution identified via digital core analysis, the bottom 0–3 m of the Long 11-1 sublayer is determined to be the optimal target interval. By delineating the microscopic characteristics of the shale reservoir and predicting rock mechanical parameters, a fracability evaluation index was established from digital core simulations. This guides the selection of target layers in deep shale gas reservoirs and optimizes hydraulic fracturing design. Full article

Permeability is affected by nanopores and pore structure, and anisotropic permeability is the result of shale lamination, orientation, and stratification of minerals. To understand the reasons for permeability anisotropy, the pore networks of over-mature shale has been studied. The mineral compositions, petrophysical properties, and pore structures of the Lower Cambrian Niutitang Formation shales were analyzed using subcritical gas adsorption, field-emission scanning electron microscopic, and X-ray micro-computed tomographic methods. Quartz, clay minerals, and carbonate are the dominant minerals in the shales. The bedding-parallel and bedding-perpendicular permeabilities are 1.25–46.21 × 10⁻² and 1.38–6.62 × 10⁻² mD, respectively. The anisotropy of permeability, which is the ratio between the bedding-parallel and bedding-perpendicular permeability, is 0.21–26.87. The micropore and Barrett–Joyner–Halenda pore volumes are 0.54–3.62 and 0.05–0.69 mL/100 g, respectively. The bedding-parallel permeability is correlated positively with the micropore and Barrett–Joyner–Halenda pore volumes. Thin-section observations indicate the shales exhibit a bedding-parallel alignment of phyllosilicate minerals and planar deformation bands. The scanning electron microscopy shows deformation of the lamination and parallel alignment of the clay minerals due to compaction or differential compaction over coarser-grained quartz grains. The scanning electron microscopy images and subcritical gas adsorption data indicate that the pore fracture system is parallel to bedding and formed after diagenesis. Furthermore, X-ray micro-computed tomographic analysis shows that the micro-fractures are also preferentially oriented, parallel to bedding. Full article

Unconventional shale resources remain crucial to energy security. In situ conversion technology (ICP) offers a promising pathway for exploiting low–maturity shale, yet the distinct roles of kerogen and bitumen during thermal conversion are not fully understood. This study investigates the decomposition behavior of kerogen and extracted bitumen from the Shahejie Formation through gold–tube pyrolysis experiments at 50 MPa and heating rates of 2 °C/h and 20 °C/h. The results show that the yield curves of C₁, C₂–C₅, and C₆–C₁₄ generated from kerogen and bitumen exhibited similar trends. In contrast to the C₁₅₊ fraction from kerogen, which initially increased and then decreased, the yield of C₁₅₊ from bitumen began to decline from the onset of cracking. Additionally, the CO₂ generated from the kerogen continued to increase until the end of pyrolysis, whereas the CO₂ from the bitumen reached its maximum at an EasyRo of approximately 1.8%. The kinetic results show that bitumen has a higher activation energy for gas generation than kerogen, while kerogen has a higher activation energy for oil generation than bitumen. A heating program of 1 °C/day rate, 324 d duration, and a final temperature of 360 °C was applied to predict oil and gas generation during ICP. Below 326 °C, the proportion of C₁ and C₂–C₅ contributed by kerogen increased and exceeded 90%. Although kerogen’s contribution ratio of C₆–C₁₄ exhibited fluctuating variation characteristics, it remained above 50% across most of the intervals. The gas–to–oil ratio increased rapidly above 299 °C and reached 375 m³/m³ by the end of heating. Full article