Search Results (51)

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

The Songliao Basin is an important Meso-Cenozoic terrestrial petroliferous basin in China. The hydrocarbon source rocks of the Upper Cretaceous Qingshankou Formation in the Central Depression possess favorable oil-generating conditions and huge hydrocarbon resource potential. This paper systematically analyzes the geochemical characteristics and simulates the thermal evolution history of Upper Cretaceous source rocks in the study area. The results show that the total organic carbon (TOC) content of Qingshankou Formation source rocks reaches up to 4.6925%. Organic matter is predominantly Type I and Type II₁, representing high-quality hydrocarbon source rocks. Thermal history simulation reveals two evolutionary stages: rapid temperature rise from the Early Cretaceous to the Late Cretaceous, and gradual cooling from the Late Cretaceous to the present day. Continuous temperature increase occurred during the depositional period of the Qingshankou to Mingshui Formations, with the maximum paleotemperature up to 180 °C. Paleotemperature has gradually decreased since the late depositional stage of the Mingshui Formation. The average TOC content of the 1st Member of Qingshankou Formation is 3.88%, classified as high-quality source rock. It reached the hydrocarbon generation threshold at approximately 82 Ma and is currently at the high-mature stage. The average TOC content of the 2nd and 3rd Members is 1.31%, also high-quality source rock. These strata entered the hydrocarbon generation threshold at about 80 Ma with relatively low vitrinite reflectance (Ro), belonging to the medium-mature and high-mature stage. Since the deposition of the Qingshankou Formation, the major hydrocarbon generation period of Cretaceous source rocks in the Central Depression ranged from 75 Ma to 80 Ma. The maximum oil generation rate is 28 mg/(g·TOC·Ma), and the cumulative oil generation capacity peaks at 220 mg/(g·TOC). The maximum gas generation rate reaches 5.5 mg/(g·TOC·Ma), with a maximum cumulative gas yield of 40 mg/(g·TOC). Full article

Lacustrine shales are globally important both as archives of paleoenvironmental change and as unconventional hydrocarbon reservoirs. The first Member of the Upper Cretaceous Qingshankou Formation in the Songliao Basin, NE China, represents a prominent interval of high-quality petroleum source rocks. Despite their significance, the factors governing organic matter accumulation and pore evolution in these lacustrine deposits remain inadequately constrained, especially with respect to the interplay between paleoenvironmental conditions and porosity development. This research explores the geochemical, mineralogical, and pore structure features of lacustrine shales and mudstones from this formation. The samples analyzed display TOC contents between 0.62 and 3.13 wt%, with Rock-Eval pyrolysis results (T_max avg. 439 °C) reflecting thermal maturity spanning the early to peak oil window. Mineralogically, the samples are dominated by quartz (avg. 28 wt%) and clay minerals (avg. 51 wt%), with feldspar as a minor component (avg. 14 wt%). Geochemical proxies suggest deposition under arid to semi-arid climatic conditions, characterized by minimal chemical weathering, elevated paleo-salinity (Sr/Ba avg. 0.89; 100 × Mg/Al avg. 14.94), and predominantly suboxic to oxic bottom-water conditions (U/Th avg. 0.38; Ni/Co avg. 1.77). Organic matter enrichment is primarily driven by high paleoproductivity (Cu/Al avg. 3.77 × 10⁻⁴) and stratified water columns, while detrital input (Zr/Al ratio) is unfavorable for organic matter accumulation. Pore structure analysis reveals micropore volumes averaging 0.0053 cm³/g and meso- and macropore volumes averaging 0.0233 cm³/g. The contents of quartz and clay minerals exhibit no substantial correlation with pore volume, likely due to secondary quartz overgrowth and mechanical compaction. Similarly, the weak negative correlation between TOC and pore volume is attributed to the poorly developed pore networks within kerogen. This study provides new insights into the depositional and diagenetic controls on organic matter accumulation and pore development in the lacustrine Qingshankou Formation, with implications for paleoenvironmental reconstruction and unconventional hydrocarbon exploration in analogous lacustrine basins worldwide. Full article

Lithofacies characterization of organic-rich shales constitutes the essential foundation for sweet spot evaluation in lacustrine shale oil systems. This study targets the first member of the Upper Cretaceous Qingshankou Formation (K₂qn¹) in the southern Songliao Basin. Based on systematic core description of 908 m of core from eight cored wells, combined with 123 total organic carbon (TOC) measurements, 47 whole-rock X-ray diffraction (XRD) analyses, 29 major- and trace-element analyses, and six maceral identification datasets (≥500 organic particles counted per sample), together with conventional well log data from 75 wells (measured vitrinite reflectance $R_o$ = 0.34%–1.38%, mean = 0.94%), we establish an integrated lithofacies classification scheme incorporating the TOC as a classification parameter and develop a log-based lithofacies identification workflow. Eight lithofacies are recognized within K₂qn¹ across the study area, of which three are organic-rich. The high-TOC clay-rich mudstone-grade laminated shale deposited in a deep lake setting (LF-A; mean TOC = 3.18%, clay minerals ≥50%, formed under saline and strongly anoxic-euxinic conditions; mean paleosalinity = 8.06‰, V/(V + Ni) = 0.75–0.97) and the high-to-moderate-TOC felsic mudstone-grade laminated shale deposited in a semi-deep lake setting (LF-B; mean TOC = 2.18%, felsic minerals ≥50%, formed under brackish-to-saline anoxic conditions; mean paleosalinity = 5.10‰, V/(V + Ni) = 0.70–0.84) constitute the dominant organic-rich lithofacies. From Y1 to Y3, the cumulative thickness of organic-rich lithofacies expands from approximately 10 m to approximately 25 m. Areally, the mean TOC increases systematically from 1.65% in the southern delta-front zone to 2.74% in the northern deep lake center, reflecting an enrichment pattern governed primarily by paleoproductivity and modulated jointly by preservation conditions and terrigenous dilution. The log-based identification workflow, established by integrating a modified ΔlogR method with multiple linear regression, achieves a TOC prediction coefficient of determination of $R^2=0.86$ in the calibration well and lithofacies identification accuracies ranging from 64.6% to 94.0% in validation wells, with the highest performance observed in the delta-front facies zone. These results provide quantitative constraints for the genetic interpretation and log-based identification of organic-rich lacustrine shales. Full article

The Qingshankou Formation (K₂qn) represents a key interval for lacustrine shale oil accumulation in the Songliao Basin. However, the spatial heterogeneity of organic-rich shales and their controlling mechanisms remain poorly constrained. Here, we investigate the Qijia–Gulong and Sanzhao sags by integrating drilling, well-log, geochemical, and mineralogical data to systematically evaluate source rock characteristics and their dominant controls. Based on well-log data from 442 wells, total organic carbon (TOC) was continuously predicted using an improved ΔlogR method. In addition, mineral compositions and lithofacies distributions were quantitatively characterized for representative wells in the eastern and western sags by combining X-ray diffraction (XRD) data with a deep residual shrinkage network (DRSN) model. The results reveal a dual depocenter pattern within K₂qn across the study area. The Qijia–Gulong Sag is characterized by thicker mudstone successions (30–600 m), higher sedimentation rates, and stronger stratigraphic continuity, whereas the Sanzhao Sag exhibits comparatively thinner deposits (30–300 m). Significant differences are also observed in organic matter type and thermal maturity: the Qijia–Gulong Sag is dominated by Type II₁ kerogen with higher maturity (R_o = 1.0%–1.5%), while the Sanzhao Sag mainly contains Type I kerogen with relatively lower maturity (R_o = 0.8%–1.3%). Despite this, TOC values in the Sanzhao Sag are markedly higher than those in the Qijia–Gulong Sag, with average values of 3.34% and 2.19%, respectively. These differences reflect the coupled control of palaeoenvironmental conditions and terrigenous input on organic matter enrichment. Elevated salinity and enhanced water-column stratification in the Sanzhao Sag promoted the development of reducing conditions favorable for organic matter preservation, resulting in higher TOC contents. In contrast, although the Qijia–Gulong Sag experienced high sedimentation rates and developed thick shale sequences, strong terrigenous input and dilution effects limited organic matter enrichment, while simultaneously leading to higher thermal maturity. Consequently, two distinct enrichment modes are identified in the study area: a “high-salinity stratification–efficient preservation” mode and a “high maturity–thick shale development” mode, which together govern the spatial heterogeneity of shale oil resources. Full article

Fracability serves as the dominant factor governing the recoverable conditions of shale oil reservoirs. Based on logging data from the Cretaceous Qingshankou Formation in the central Daqing Placanticline, China, combined with core experimental data, correlation analysis, and the analytic hierarchy process (AHP) for weight calculation of fracability evaluation indices, this study establishes a fracability parameter interpretation model for the area. The calculation results are highly consistent with test and analytical data, featuring high accuracy and satisfying fracability evaluation demands. The results show that the Cretaceous Qingshankou Formation in the study area is characterized by a low–medium Young’s modulus, high Poisson’s ratio, high brittleness index, low stress difference, and a normal faulting stress regime. For the first member of the Qingshankou Formation, Young’s modulus ranges from 6.7 to 21.4 GPa, Poisson’s ratio from 0.26 to 0.41, brittleness index from 34.1 to 58.4%, stress difference from 1.67 to 2.41 MPa, and fracability index from 0.26 to 0.79. Class II fracability dominates the central region horizontally, with a small amount of Class I in the southeastern and western parts. Regarding the reservoirs in the second and third members of the Qingshankou Formation, Young’s modulus is 9.6–19.5 GPa, Poisson’s ratio is 0.31–0.39, the brittleness index is 39.5–50.3%, the stress difference is 1.76–2.28 MPa, and the fracability index is 0.39–0.77. Both Class I and II are well developed: Class I is mainly distributed horizontally in the western, southern and northeastern regions, while Class II shows a curvilinear zonal distribution in the central area. Full article

While CO₂ huff-n-puff (CO₂ HnP) is a promising technique for shale oil recovery, the characteristics and controlling factors of microscopically movable oil in lacustrine argillaceous-rich shales remain poorly understood. Shale samples from the Qingshankou Formation in the Songliao Basin were collected, and a series of experiments, including low-pressure N₂ adsorption, mercury injection porosimetry, and nuclear magnetic resonance, were conducted. High-pressure and high-temperature CO₂ HnP experiments were then conducted to investigate the effects of cycle number, soaking time and changes in pore structure on movable oil distribution. The shales exhibit multi-scale pores and lamellar fractures containing substantial residual oil (41.33–52.16% saturation). CO₂ HnP effectively mobilizes oil from macropores (50–1000 nm) and fractures (>1000 nm), with a limited effect in micro–mesopores (<50 nm). Three CO₂ HnP cycles were optimal for movable oil extraction. Extending the soaking time increased movable oil by ~4%, primarily from macropores and fractures (5.59–6.05%), with minimal improvement in smaller pores. A combination of CO₂ flooding followed by CO₂ HnP increased total movable oil by 4.83–7.26%, significantly enhancing recovery from micropores (7.26%) and macropores (9.21%). This study clarifies the pore size distribution and mobilization constraints of movable oil in argillaceous-rich shales. The integrated CO₂ flooding and HnP strategy proves to be highly effective, especially for movable oil in micro–mesopores. This study is the first to investigate pore-scale movable oil in lacustrine argillaceous-rich shales during CO₂ huff-n-puff under in situ reservoir conditions, and could provide critical insights for optimizing shale oil recovery in the Songliao Basin and similar lacustrine reservoirs. Full article

The Qingshankou Formation shales in the southeastern uplift of the Songliao Basin provide an ideal archive for constraining the controls of paleoenvironment on organic matter enrichment. Taking the shale succession at the Niaohexiang section of Binxian as the study object, we combined field sampling with TOC measurements, whole-rock X-ray diffraction, and major, trace, and rare earth element analyses. The strata are dominated by black shale and dark gray mudstone, with mineral assemblages composed mainly of clay, felsic, and carbonate minerals; argillaceous shale exceeds 60%. Normal alkanes display a post-peak distribution with C₂₇ as the dominant peak, low Pr/Ph ratios, and gammacerane index values of 0.18–0.26. Regular steranes are generally V-shaped, whereas some samples show high C₂₉ sterane contents and a reversed L-shaped pattern. Major elements are dominated by SiO₂ and Al₂O₃, trace elements such as Sr and Ba are relatively enriched, and rare earth elements show light REE enrichment with a pronounced negative Eu anomaly. These signatures indicate an upper-crustal felsic provenance and a continental island arc tectonic setting. Organic matter contents are low and derived mainly from terrestrial higher plants with minor aquatic input. Paleoenvironmental reconstruction suggests deposition in a freshwater to slightly brackish, semi-arid, anoxic-reducing shallow lacustrine setting with relatively low productivity, whereas dolostone formed under more saline, arid, and more productive conditions. Climatic fluctuations, salinity variations, and alternating redox states jointly controlled organic matter enrichment, and late-stage lacustrine salinization and anoxia associated with dolostone horizons enhanced organic matter preservation. Full article

The development and utilization of unconventional shale oil and gas have enhanced the resilience of global energy security. Hydraulic fracturing is the primary method for enhancing unconventional shale oil and gas extraction. Previous studies have predominantly employed homogenized geomechanical models to simulate fracture propagation in rock masses. However, bedding planes and inhomogeneous mineral distributions introduce mechanical anisotropy in shale, rendering conventional homogenized models insufficient for accurately representing hydraulic fracturing in real reservoirs. For this, millimeter-scale indentation testing was employed to systematically quantify the depth-dependent distribution of mechanical parameters across varying bedding orientations, using fragmented shale samples obtained from the Qingshankou Formation of the Songliao Basin, northern China. Then, hydraulic fracturing simulations were performed using the mechanical properties derived from the indentation tests. The key findings include: (1) The elastic modulus of the Qingshankou Formation shale reservoir exhibits significant anisotropic properties in both the depth and bedding orientations. The elastic modulus measured parallel to bedding (10.23–65.08 GPa) is 28% higher than that measured perpendicular to bedding (9.60–47.24 GPa) due to shale bedding anisotropy. The mineralogical composition predominantly governs the depth-dependent anisotropy, with an elevated brittle mineral content increasing the elastic modulus and a higher clay content reducing it. (2) The simulation results reveal that the depth-dependent anisotropy of elastic modulus induces asymmetric hydraulic fracture propagation, with the fractures preferentially extending along the orientations exhibiting a higher elastic modulus. This behavior arises due to the enhanced brittleness and reduced deformation resistance of high-modulus rocks, facilitating fracture advancement. The study offers critical insights for hydraulic fracturing design and operational implementation in bedded shale reservoirs. Full article

Hydrocarbon resource potential evaluation represents the primary and core component of whole petroleum system studies. However, compared with the substantial progress achieved in understanding hydrocarbon generation mechanisms, quantitative assessments of hydrocarbon generation amounts from source rocks in the Songliao Basin remain relatively limited. Given that the genetic method is capable of comprehensively reflecting both the intrinsic hydrocarbon generation potential and conversion efficiency of source rocks and is supported by robust geological principles, this study was conducted within a genetic framework. Stratigraphic data and lithological descriptions from more than 2000 wells in the northern Songliao Basin, logging data from 387 wells, and measured basic geochemical data from 201 wells were integrated. Combined with the ΔlogR method, original hydrocarbon generation potential restoration techniques, and results from thermal simulation experiments, the planar distributions of key geochemical parameters of the first member of the Qingshankou Formation were systematically characterized. On this basis, the hydrocarbon generation potential and total hydrocarbon generation amounts of different structural units within the Songliao Basin were quantitatively evaluated. The results indicate that the cumulative hydrocarbon generation of the first member of the Qingshankou Formation reached approximately 506.55 × 10⁸ t. Among the structural units, the Qijia–Gulong Sag contributed 266.13 × 10⁸ t, the Sanzhao Sag 132.71 × 10⁸ t, the Longhupao Terrace 66.81 × 10⁸ t, and the Daqing Placanticline 40.90 × 10⁸ t. These results demonstrate significant heterogeneity in hydrocarbon generation capacity among different structural units, with the Qijia–Gulong Sag identified as the most important hydrocarbon generation center in the study area. This study provides a critical quantitative foundation for whole petroleum system research in the northern Songliao Basin. It not only supplies essential data support for subsequent resource apportionment of conventional and shale hydrocarbons but also offers important constraints for analyses of reservoir-type distribution and hydrocarbon accumulation mechanisms. Full article

The First Member of the Cretaceous Qingshankou Formation (K₂qn¹) in the Gulong Sag, Songliao Basin, contains vast shale oil resources conventionally interpreted as deposits of suspension settling in a quiescent, anoxic deep-lacustrine environment. However, this static “deep-lake” model fails to account for the strong lithofacies heterogeneity and high-energy sedimentary records observed in recently acquired core data. This study reconstructs the sedimentary dynamics of the K₂qn¹ shale through high-resolution core description, thin-section petrography, and flow-loop hydrodynamic simulations. We identify abundant sedimentary structures diagnostic of high-energy combined flows, including Hummocky Cross-Stratification (HCS), Swaley Cross-Stratification (SCS), erosional scour surfaces, and large-scale tabular intraclasts (up to 40 mm). Hydrodynamic simulations, utilizing an “equivalent substitution” method, demonstrate that the Minimum Vertical Suspension Velocity (V_mf) required to transport these large intraclasts exceeds 1.0 m/s. This threshold is 1 to 5 orders of magnitude higher than theoretical values derived from classical settling equations, confirming that the paleolake bottom was frequently perturbed by high-velocity storm-driven currents. Consequently, we propose an “Intermittent High-Energy Deposition Model,” wherein background suspension settling was punctuated by episodic storm events. We argue that these high-energy events facilitated organic matter enrichment through a “Transport-Burial Pump” mechanism, which operated in concert with the chemical stratification associated with the Oceanic Anoxic Event 2 (OAE2) to enable rapid physical burial and sealing of organic matter. These findings challenge the traditional fine-grained sedimentological paradigm and suggest that storm-reworked intervals—characterized by enhanced brittleness and hydrodynamic winnowing—constitute the primary “sweet spots” for lacustrine shale oil exploration. Full article

The characteristics of shale oil reservoirs, such as low porosity, ultra-low permeability, and complex pore structure, are key factors affecting effective pore space and fluid migration. This study focuses on medium-to-high maturity mud shale in the Qing-1 Member of the Qingshankou Formation in the Gulong Sag. Using methods such as XRD, organic geochemical testing, and multi-scale pore characterization (FE-SEM, low-temperature CO₂–N₂ adsorption, high-pressure mercury intrusion, and CT scanning), the lithofacies and pore structure were comprehensively characterized, and their controlling factors were analyzed. The results indicate: (1) The mineral composition is dominated by felsic and clay minerals. Based on a three-level classification standard of “mineral composition–sedimentary structure–organic matter abundance”, seven subfacies were identified, with the dominant lithofacies being Felsic–Clayey Mixed Shale and Felsic-bearing Clay Shale. (2) The reservoir space consists of inorganic pores, organic pores, microfractures, and a small amount of other auxiliary pores, exhibiting “bimodal” pore size characteristics. Micro–mesopores dominate adsorption, while macropores/microfractures control free oil seepage; mesopores contribute the most to pore volume. (3) In terms of oil-bearing potential, Felsic–Clayey Mixed Shale shows prominent movable oil potential (average OSI: 133.08 mg/g; S₁ > 2 mg/g, OSI > 100 mg/g). (4) CT-based 3D stick-and-ball models indicate that Felsic–Clayey Mixed Shale has the best connectivity (connectivity rate: 30.63%), with throat radii mostly ranging from 1–15 μm and pore radii from 2–20 μm. (5) Pore development is synergistically controlled by total organic carbon (TOC, with an optimal range of approximately 1–2.5%), clay/felsic mineral ratio, and bedding/structural fractures. The formation of the pore system is the result of dynamic coupling of organic–inorganic interactions during diagenetic evolution: intergranular pores of clay minerals and microfractures jointly contribute to specific surface area and pore volume, while bedding fractures connect nanopore clusters to enhance seepage capacity. This study improves the integrated understanding of dominant lithofacies, pore structure, and oil-bearing potential in the Qing-1 Member of the Gulong Sag, providing a basis for sweet spot evaluation and development optimization. Full article

The Qingshankou Formation shale in the Changling Sag of the Songliao Basin represents a typical lacustrine pure-shale reservoir, characterized by high organic matter abundance, high maturity, high clay mineral content, and strong heterogeneity. To elucidate the pore structure and heterogeneity of this shale, a comprehensive suite of analytical techniques—including X-ray diffraction (XRD), scanning electron microscopy (SEM), high-pressure mercury intrusion porosimetry (MICP), and low-temperature nitrogen adsorption—was employed to investigate its pore types and fractal characteristics systematically. On this basis, lithofacies classification and FHH fractal modeling were conducted to quantitatively assess the complexity of pore–throat structures and their influence on reservoir properties. The results indicate that shale-dominated lithofacies (Types A–C) exhibit higher surface fractal dimensions (D₁ = 2.51–2.58) and structural fractal dimensions (D₂ = 2.73–2.81), corresponding to low porosity, low permeability, and high displacement pressure. In contrast, carbonate- and clastic-dominated lithofacies (Types D–G) display lower fractal dimensions, suggesting more regular pore–throat structures and better connectivity. Overall, both D₁ and D₂ show negative correlations with porosity and permeability but positive correlations with displacement pressure, and are negatively correlated with TOC content, reflecting the intrinsic coupling among pore–throat complexity, reservoir capacity, and organic matter abundance. These findings reveal that the Qingshankou shale reservoir has undergone a geometric evolutionary pathway of “shale compaction → siltstone transition → carbonate porosity reconstruction.” The fractal dimensions effectively characterize the reservoir heterogeneity and pore–throat connectivity, providing a new theoretical basis for the quantitative characterization, classification, and potential prediction of continental shale oil reservoirs. Full article

Pore systems in continental shales are controlled by lithofacies and show strong heterogeneity, which challenges shale oil development. The Qingshankou Formation in the Songliao Basin is a major shale oil play in China. Previous studies have focused on macroscopic reservoir properties, with limited analysis of pore differences among lithofacies. This study integrates mineralogy, organic geochemistry, and multi-scale pore structure characterization to examine four typical lithofacies: argillaceous, siliceous, calcareous, and mixed shales. Results show that pore evolution in the Qingshankou Formation can be divided into five stages: immature (Ro < 0.6%), low maturity (0.6% < Ro ≤ 0.8%), middle maturity (0.8% < Ro ≤ 1.0%), high maturity (1.0% < Ro ≤ 1.2%), and over maturity (Ro > 1.2%). The overall pattern follows a “three declines and two increases” trend. Due to differences in mineral composition and organic matter (OM), each lithofacies displays dis-tinct pore characteristics, which further influence oil-bearing potential and mobility. Siliceous shale, rich in felsic minerals, exhibits well-preserved pores and a developed micro-fracture network, providing the largest pore volume and average diameter. This facilitates the storage and flow of free oil, making it the preferred exploration target. Argillaceous shale, characterized by abundant clay minerals and OM, supports micropore development and offers the highest specific surface area (SSA). This yields significant adsorbed oil potential, highlighting its value as a secondary exploration target. This study clarifies the lithofacial controls on pore development in continental shales, providing a scientific basis for predicting favorable intervals and optimizing exploration strategies in the Qingshankou Formation and analogous basins. Full article

Overpressure systems in the Qingshankou Formation of the Gulong Sag have a significant impact on unconventional shale oil accumulation, but their distribution and genesis are unknown. This study uses a comparative analysis of three primary pressure prediction methods—the equivalent depth method, the Eaton method, and the Bowers method—to investigate the genetic mechanisms of overpressure and their controlling factors. The study clarifies the link between overpressure and hydrocarbon distribution. The key findings are as follows. (1) The Eaton method is identified as the best approach for estimating current formation pore pressure. The Qingshankou Formation exhibits mild overpressure development, with a maximum pressure coefficient of 1.44. (2) Hydrocarbon-generating overpressure, driven by source rock maturation, is confirmed as the dominant mechanism through integrated acoustic velocity–density cross plots and logging analysis. (3) Tectonic-sedimentary factors, such as burial depth, source rock thickness, sand-mud ratio, and faults, collectively control the spatial variability of overpressure. (4) The distribution of the Gulong shale oil and the Fuyu tight oil is influenced by overpressure, with the northwestern part of the sag and the adjacent sand bodies being the respectively favorable areas. These results lay the groundwork for accurately reconstructing paleopressure and better understanding the hydrocarbon accumulation potential of shale oil and Fuyu tight oil. They also provide guidance on the exploration and development of unconventional resources. Full article