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20 pages, 12723 KB

Open AccessArticle

Effect of Hydrocarbon Expulsion on Light Oil/Condensate Generation During Artificial Maturation of Qingshankou Shale Kerogen from the Songliao Basin

by Wei Jin, Jinlong Li, Qiuli Huo, Deyong Shao, Yuyin Xue and Yusheng Wang

Processes 2026, 14(15), 2429; https://doi.org/10.3390/pr14152429 - 28 Jul 2026

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Abstract

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) [...] Read more.

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

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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23 pages, 5590 KB

Open AccessArticle

Thermal Evolution and Hydrocarbon Generation History of Upper Cretaceous Qingshankou Formation in Central Depression of Songliao Basin

by Yusheng Wang, Qiuli Huo, Fei Dai, Hening Xu, Junping Cui and Wei Jin

Processes 2026, 14(15), 2396; https://doi.org/10.3390/pr14152396 - 24 Jul 2026

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Abstract

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 [...] Read more.

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

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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27 pages, 7738 KB

Open AccessArticle

Quantitative Characterization of Connectivity in Fracture–Cave Carbonate Reservoirs Under Main Fault Constraints Based on the MFC-FVCP Model and Its Application to Remaining Oil Enrichment Prediction

by Xiao Zhang, Qi Chang, Zhen Wang, Xiaobo Peng and Shijie Zhu

Processes 2026, 14(14), 2236; https://doi.org/10.3390/pr14142236 - 8 Jul 2026

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Abstract

The fracture–cave carbonate reservoir in Unit S91 of the Tahe Oilfield is jointly controlled by strike-slip fault activity, karstification, and later-stage fracture development, resulting in reservoir spaces characterized by strong heterogeneity, strong discreteness, and multi-scale superimposition. The inter-well connectivity of this type of [...] Read more.

The fracture–cave carbonate reservoir in Unit S91 of the Tahe Oilfield is jointly controlled by strike-slip fault activity, karstification, and later-stage fracture development, resulting in reservoir spaces characterized by strong heterogeneity, strong discreteness, and multi-scale superimposition. The inter-well connectivity of this type of reservoir is not governed by the size of a single fracture–cave body or local fracture density, but rather by the spatial configuration among the main controlling fault, the associated fracture network, and the fracture–cave reservoir bodies. As the reservoir enters the middle–high-water-cut development stage, the production differential between dominant connecting channels and weakly connected fracture–cave bodies further enlarges, leading to marked heterogeneity in the remaining oil distribution. Integrating post-stack seismic data, fracture prediction, RGB attribute fusion, production performance, and numerical simulation data, this paper constructs a main fault-controlled fracture–vug coupling probability (MFC-FVCP) model under the constraint of the main controlling fault. Unlike conventional multi-attribute fusion methods that mainly enhance seismic anomaly visualization, the MFC-FVCP model transforms the main fault constraint, fracture connectivity, and fracture–cave reservoir-body effectiveness into a unified coupling probability. The model uses three core components—the main fault response field, the fracture attribute response field, and the fracture–cave reservoir body response field—to characterize the fault-control effect, fracture-network continuity, and effective reservoir-body response, respectively. By evaluating the coupling probability, the inter-well connectivity potential is assessed, the dominant connectivity areas where fractures and fracture–cave bodies synergistically develop under the constraint of the main controlling fault are identified, and potential remaining oil targets are clarified. The predicted connectivity pattern was further constrained by production performance, nitrogen injection response, and staged oil saturation simulation, which improves the reliability of remaining oil enrichment prediction. The results show that the T74 layer is the dominant development interval of fracture–cave reservoir bodies in Unit S91. These fracture–cave bodies are mainly distributed along the main controlling fault and associated fracture zones in beaded, chain-like, and banded patterns, exhibiting distinct fault-and-fracture control characteristics. Potential point A near well TK858XCH features both good reservoir physical properties and insufficient sweep efficiency, making it a key target for subsequent injection–production adjustment and remaining oil tapping. The MFC-FVCP model can incorporate static seismic responses, fracture–cave spatial structures, and dynamic development responses into a unified evaluation framework, providing a quantitative basis for characterizing inter-well connectivity and identifying remaining oil enrichment areas in fracture–cave carbonate reservoirs. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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20 pages, 14843 KB

Open AccessArticle

Development of a Shear-Responsive Gel for Lost Circulation Control Tailored to Enhance Drilling Rate of Penetration

by Shoushuai Huang, Zhigang Zhang, Jian Mao, Bin Li, Ruigang Yuan, Zhaomin Jiang and Shubin Liu

Processes 2026, 14(13), 2168; https://doi.org/10.3390/pr14132168 - 3 Jul 2026

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Abstract

Lost circulation of wellbore fluids within fissured zones constitutes a primary factor contributing to increased non-productive time (NPT) and restricted rate of penetration (ROP). Conventional gel-based lost circulation materials (LCMs) inherently suffer from a tradeoff between pumpability and in situ fracture retention, and [...] Read more.

Lost circulation of wellbore fluids within fissured zones constitutes a primary factor contributing to increased non-productive time (NPT) and restricted rate of penetration (ROP). Conventional gel-based lost circulation materials (LCMs) inherently suffer from a tradeoff between pumpability and in situ fracture retention, and they lack a design methodology quantitatively correlated with drilling engineering parameters. In this study, a shear-responsive gel with a dual physically crosslinked network—combining hydrophobic association and Fe³⁺-mediated ionic coordination—was prepared through a single-step water-based radical polymerization process, utilizing commercially available monomers. By systematically tuning the hydrophobic monomer and Fe³⁺ contents, the gel’s fracture-sealing efficacy, autogenous healing ability, and shear rheological characteristics were evaluated, establishing a quantitative correlation between the critical shear rate and drilling parameters. The empirical data demonstrate that with an increase in the hydrophobic monomer dosage from 0.4 wt% to 1.2 wt%, the critical shear rate decreases from 22.5 s⁻¹ to 8.6 s⁻¹, exhibiting an exponential decay relationship. The optimized formulation, G0.8F0.5, demonstrates a low initial viscosity of 245 mPa·s under high shear conditions, which surges to 6180 mPa·s at a shear rate of 14.2 s⁻¹, achieving a thickening factor of 29.4. Upon incubation at 80 °C for a duration of 12 h, the formulated gel restores 94.9% of its mechanical tensile strength and 96.3% of its fracture strain, whereas the Fe³⁺-free control sample fails to heal. In dynamic plugging tests using a 3 mm fracture plate, G0.8F0.5 achieves a breakthrough pressure of 12.8 MPa with a minimal fluid loss of 98 mL. The LCM forms a monolithic gel block positioned at the middle-to-rear section of the fracture, outperforming conventional gel counterparts. Drilling hydraulics simulations reveal that deploying this gel reduces the annular equivalent circulating density (ECD) by 0.06 g/cm³. Furthermore, under idealized conditions, this approach is calculated to enhance the ROP by approximately 26%. The proposed molecular design of a shear-responsive, dual physically crosslinked network provides a viable technical pathway for quantitatively tailoring the shear-responsive properties of while-drilling LCMs. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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18 pages, 8448 KB

Open AccessArticle

Numerical Simulation Study and Field Practice of Balanced Fracture Propagation Under Non-Uniform Perforation: A Case Study of Shale Oil in the Kong’er Member of the Cangdong Sag

by Yuan Pan, Xuewei Liu, Ping Guo, Jianbing Li, Liyong Yang, Tao Zhao, Quan Wang, Yingxi Zhang and Zheng Li

Processes 2026, 14(11), 1728; https://doi.org/10.3390/pr14111728 - 26 May 2026

Cited by 1 | Viewed by 317

Abstract

Multi-cluster perforation staged fracturing in horizontal wells has become an important means of completion stimulation for unconventional oil and gas reservoirs. However, the non-uniform propagation of multi-cluster hydraulic fractures remains one of the key challenges restricting efficient reservoir stimulation. In this study, based [...] Read more.

Multi-cluster perforation staged fracturing in horizontal wells has become an important means of completion stimulation for unconventional oil and gas reservoirs. However, the non-uniform propagation of multi-cluster hydraulic fractures remains one of the key challenges restricting efficient reservoir stimulation. In this study, based on the finite element method and considering factors such as frictional pressure drop along the wellbore for power-law fluid, perforation friction, and stress interference, a fracture propagation model with dynamic multi-stage flow distribution coupling formation, perforation, and wellbore flow was constructed. The effects of non-uniform perforation schemes, total number of perforations, and perforation non-uniformity coefficient on multi-cluster fracture propagation behavior were systematically investigated, and the characteristics of dynamic flow distribution were clarified. The results show that the order of fluid intake uniformity among different perforation schemes is as follows: spindle-shaped perforation, uniform perforation, and Tapered perforation. Reducing the number of perforations and decreasing the perforation non-uniformity coefficient can improve the uniformity of fracture propagation to a certain extent. The findings of this study can provide a theoretical basis and practical reference for efficient fracturing stimulation of shale oil in the Cangdong Sag. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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23 pages, 4764 KB

Open AccessArticle

A Study on Hydro-Thermo–Mechanical Coupled Numerical Simulation of Hydraulic Fracture Propagation Behaviour in Unconventional Oil and Gas Reservoirs

by Jun He, Yuyang Liu, Jianlin Lai, Haibing Lu, Tianyi Wang, Xun Gong and Yanjun Guo

Processes 2026, 14(10), 1617; https://doi.org/10.3390/pr14101617 - 16 May 2026

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Abstract

Unconventional oil and gas reservoirs naturally have low porosity and low permeability, which necessitate reservoir stimulation during production to achieve commercial exploitation. Therefore, to improve reservoir stimulation effectiveness, this study established a thermal–hydraulic–mechanical coupled numerical model suitable for hydraulic fracturing experiment scales based [...] Read more.

Unconventional oil and gas reservoirs naturally have low porosity and low permeability, which necessitate reservoir stimulation during production to achieve commercial exploitation. Therefore, to improve reservoir stimulation effectiveness, this study established a thermal–hydraulic–mechanical coupled numerical model suitable for hydraulic fracturing experiment scales based on rock mechanics, elasticity mechanics, damage mechanics, and flow mechanics theories, combined with maximum principal stress and Mohr–Coulomb damage criteria. The model was numerically solved within a finite element framework and used to simulate the reservoir hydraulic fracturing process. The results indicate that the propagation behavior of hydraulic fractures is controlled by reservoir rock mechanical properties, geostresses, reservoir temperatures, fracturing fluid viscosities, and injection rates. Among these, the increase in principal stress difference, reservoir temperature, fracturing fluid viscosity and injection rate promotes the propagation of hydraulic fractures along the direction of the maximum horizontal principal stress, whereas an increase in the rock’s elastic modulus reduces the propagation length of the hydraulic fractures. During fracturing, the fracturing fluid fractures the reservoir rock, significantly improving its porosity and permeability. This not only enhances the mobilization of unconventional oil and gas resources but also provides effective flow pathways for their migration, thereby ensuring the commercial viability of unconventional oil and gas resource extraction. Additionally, selecting a fracturing process that matches the geological characteristics of the study area during fracturing design is a prerequisite for improving the reservoir stimulation effect. The results of this study provide a reference for fracturing design and optimization. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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21 pages, 2563 KB

Open AccessArticle

A Wettability-Based Approach for Mitigating Permeability Damage Caused by Fine Migration in Unconsolidated Sandstone Reservoirs

by Zhenyu Wang, Wei Xiao, Tianxiang Cheng, Haitao Zhu and Shiming Wei

Processes 2026, 14(8), 1205; https://doi.org/10.3390/pr14081205 - 9 Apr 2026

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Abstract

Fine migration is widely recognized as a primary cause of production decline in unconsolidated sandstone reservoirs. Migrated fines may accumulate within pore throats and obstruct flow channels, or they may be transported into the wellbore with the produced fluids, leading to operational issues [...] Read more.

Fine migration is widely recognized as a primary cause of production decline in unconsolidated sandstone reservoirs. Migrated fines may accumulate within pore throats and obstruct flow channels, or they may be transported into the wellbore with the produced fluids, leading to operational issues such as wellbore plugging, pump sticking, and equipment abrasion. Despite extensive studies on fine migration, the role of particle wettability has received limited attention. In this study, the mineralogical composition of formation particles was first characterized using X-ray diffraction (XRD) and quantitative clay analysis. Surface modification experiments were then conducted to investigate the effect of hexadecylamine (HDA) on particle wettability and to determine the optimal reaction conditions. Surface characterization techniques were employed to elucidate the modification mechanism. Subsequently, sand-packed tube displacement experiments were performed to evaluate the influence of wettability alteration on fine migration behavior. The underlying mechanisms were further interpreted through interfacial thermodynamic analysis. Two potential field application schemes are proposed to facilitate practical implementation in oilfield operations. The results indicate that the water contact angle of formation particles increased from 0° to 150° when treated with 0.8 wt% HDA for 24 h. Surface characterization confirms that HDA molecules were physically adsorbed onto the particle surfaces. Displacement experiments demonstrate that the permeability reduction rate decreases significantly with increasing particle hydrophobicity. Thermodynamic analysis suggests that the work of adhesion on the modified particle surface was reduced by 93.3%, thereby weakening fluid–particle interfacial coupling and suppressing fine mobilization. This study provides a wettability-based approach for mitigating permeability damage caused by fine migration in unconsolidated sandstone reservoirs. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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20 pages, 7778 KB

Open AccessArticle

Reservoir Characteristics and Main Controlling Factors of Tight Sandstone in the First Sub-Member of the First Member of Shaximiao Formation in the Zhongjiang Block of Tianfu Gas Field, Sichuan Basin

by Xiaoli Zhang, Rongrong Zhao, Xiaojuan Wang, Lin Qiao, Hang Li, Xiaoting Pang, Hualing Ma, Xu Guan, Shuangling Chen and Jiang He

Processes 2026, 14(6), 994; https://doi.org/10.3390/pr14060994 - 20 Mar 2026

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Abstract

The Tianfu Gas Field in the Sichuan Basin is a core block for the large-scale, economic development of Jurassic tight gas in China. The first sub-member of the first member of the Shaximiao Formation in the Zhongjiang Block hosts typical low-porosity and low-permeability [...] Read more.

The Tianfu Gas Field in the Sichuan Basin is a core block for the large-scale, economic development of Jurassic tight gas in China. The first sub-member of the first member of the Shaximiao Formation in the Zhongjiang Block hosts typical low-porosity and low-permeability tight sandstone reservoirs. Based on detailed field geological surveys and core observations, this study employed multiple technical methods, including cast thin sections, scanning electron microscopy, computed tomography (CT) scanning, and nuclear magnetic resonance (NMR) to investigate sedimentary microfacies’ characteristics, analyze key reservoir properties (e.g., reservoir space types and pore structure), and clarify the main controlling factors of reservoir development. The results indicate the following: (1) The sedimentary period of the first sub-member of the first member of the Shaximiao formation (Es₁¹) was controlled by a subtropical humid climate, with widespread gray mudstones and bedding-parallel plant fossil fragments. The main sedimentary environment was a shallow-water delta front, where the underwater distributary channel microfacies was the dominant facies belt. (2) Reservoir lithology is dominated by lithic arkose and feldspathic litharenite, with low compositional and structural maturity. Residual primary intergranular pores are the dominant reservoir space type, followed by intragranular dissolved pores in feldspar and lithic fragments. (3) The pore structure is characterized by a small pore-throat radius, poor sorting, and strong heterogeneity. Reservoirs can be subdivided into three categories, with Types II and III being the main types developed in this block. (4) Underwater distributary channels of the shallow-water delta are the main occurrence of reservoir sand bodies. During the burial diagenetic stage, calcite and laumontite cementation and filling led to reservoir densification. Meanwhile, early-formed chlorite rim cement effectively protected primary pores by inhibiting grain compaction and quartz overgrowth. Superimposed with the dissolution and alteration of feldspar, lithic fragments, and other components by late acidic fluids, effective pores were further expanded. The synergistic coupling of these sand-controlling factors and the “densification–protection–alteration” diagenetic process jointly constitutes the formation mechanism of high-quality reservoirs. This mechanism can provide a reliable theoretical basis for the accurate prediction of reservoir “sweet spots” and the optimal selection of horizontal well targets in the Zhongjiang Block of the Tianfu Gas Field. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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20 pages, 4698 KB

Open AccessArticle

Controlling Mechanisms of Burial Karstification in Gypsum Moldic Vug Reservoirs of the 4-1 Sub-Member, Member 5 of the Majiagou Formation, Central Ordos Basin

by Jiang He, Hang Li, Lei Luo, Lin Qiao, Juzheng Li, Xiaolin Ma, Yuhan Zhang, Jian Yao, Sisi Jiang and Yaping Wang

Processes 2026, 14(2), 275; https://doi.org/10.3390/pr14020275 - 13 Jan 2026

Cited by 1 | Viewed by 444

Abstract

The moldic pore-vuggy reservoirs of the Ma5₄-Ma5₁ sub-member in the Majiagou Formation, central Ordos Basin, are key targets for deep natural gas exploration, yet the alteration mechanisms and controlling factors of burial-stage pressure-released water karstification remain unclear. Herein, an integrated [...] Read more.

The moldic pore-vuggy reservoirs of the Ma5₄-Ma5₁ sub-member in the Majiagou Formation, central Ordos Basin, are key targets for deep natural gas exploration, yet the alteration mechanisms and controlling factors of burial-stage pressure-released water karstification remain unclear. Herein, an integrated methodology encompassing core observation, thin-section analysis, and geochemical testing was adopted to systematically clarify the development characteristics and multi-factor coupling control mechanisms of this karst process. Results show that burial-stage pressure-released water karst is dominated by overprinting on pre-existing syndepositional and supergene pore networks, forming complex reservoir spaces via synergistic selective dissolution. The development of preferential dissolution zones is jointly controlled by differential compaction of the weathering crust, permeability heterogeneity of the overlying strata and weathered crust, and diagenetic fluid properties. After the supergene diagenetic stage, differential tectonic deformation and burial compaction induced overpressure in pore fluids, which drove acidic pressure-released water to migrate along high-permeability pathways such as the “sandstone windows” overlying the Ordovician weathering crust. These fluids preferentially dissolved high-permeability moldic pore-vuggy dolomites in paleo-karst platforms and steep slope zones, whereas tight micritic dolomites served as effective barriers. The acidic environment sustained by organic acids and H₂S in pressure-released water promoted carbonate dissolution, and carbon-oxygen isotopes as well as pyrite δ³⁴S values verify that the fluids were derived from mudstone compaction. This study reveals that the distribution of high-quality reservoirs is jointly determined by the synergistic preservation of moldic pore-vuggy systems in paleo-karst platforms and steep slopes and directional alteration of pressure-released water along preferential pathways, providing crucial geological guidance for the evaluation of deep carbonate reservoirs. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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22 pages, 5708 KB

Open AccessArticle

Influence of Organic and Inorganic Compositions on the Porosity of the Deep Qiongzhusi Shales on the Margin of the Deyang–Anyue Aulacogen, Sichuan Basin: Implications from the Shale Samples of Well Z204

by Wei Wu, Liang Xu, Chao Luo, Haitao Gao, Huan Liu, Xinyue Shi, Haifeng Gai and Peng Cheng

Processes 2025, 13(12), 3880; https://doi.org/10.3390/pr13123880 - 1 Dec 2025

Cited by 1 | Viewed by 654

Abstract

The deep Qiongzhusi (QZS) shales in the Deyang–Anyue Aulacogen, Sichuan Basin, are important shale gas targets in China. However, the differences in pore development of the shales in the marginal areas of the aulacogen and its main controlling factors remain unclear. In this [...] Read more.

The deep Qiongzhusi (QZS) shales in the Deyang–Anyue Aulacogen, Sichuan Basin, are important shale gas targets in China. However, the differences in pore development of the shales in the marginal areas of the aulacogen and its main controlling factors remain unclear. In this study, the organic and inorganic compositions, water-bearing characteristics, and porosities of the sublayer 7 (SL7) and sublayer 5 (SL5) deep QZS shales collected from Well Z204 were systematically investigated. The results indicate that, compared with the SL5 shales, the SL7 shales have higher total organic carbon (TOC) and clay mineral contents, lower brittle mineral contents, greater porosities, and water content and saturation. The TOC content of the deep QZS shale has a strong positive correlation with porosity, and a negative correlation with water saturation. Therefore, the TOC content is the main controlling factor for the development of effective porosity. The TOC content of the SL7 shale is higher than that of the SL5 shale, so the SL7 shale has a larger effective porosity. Therefore, the margin of the Deyang–Anyue Aulacogen is a new exploration area for the deep QZS shales, and the shale gas accumulate conditions of the SL7 shales are better than that of the SL5 shales, especially in the lower section of the SL7 shales. This new understanding provides an important geological basis for the next exploration of the Deyang–Anyue Aulacogen. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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16 pages, 7443 KB

Open AccessArticle

Study on the Organic Geochemical Characteristics of Jurassic Source Rocks from the Northern Tibetan Plateau Basin

by Yajun Shi, Li Xu, Xinmin Ma and Jiajia Guo

Processes 2025, 13(10), 3266; https://doi.org/10.3390/pr13103266 - 13 Oct 2025

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Abstract

The Northern Tibetan Plateau Basin is the most extensive and least explored Mesozoic marine basin in China and shows considerable potential for oil and gas exploration. This study systematically analyzed the abundance, type, hydrocarbon generation potential, and conversion rate of organic matter within [...] Read more.

The Northern Tibetan Plateau Basin is the most extensive and least explored Mesozoic marine basin in China and shows considerable potential for oil and gas exploration. This study systematically analyzed the abundance, type, hydrocarbon generation potential, and conversion rate of organic matter within three Jurassic drill core samples from the Biloucuo area of the Northern Tibetan Plateau Basin. The total organic carbon (TOC) content of these Jurassic source rocks was >4%, on average, permitting their classification as excellent source rocks. The average contents of sapropelinite, exinite, vitrinite, and inertinite in kerogen were 74%, 4%, 18%, and 4%, respectively. The H/C and O/C ratios of the kerogen mainly ranged from 0.8 to 1.3 and 0.06 to 0.11, respectively, indicative of type II₁ kerogen. The average S₁ + S₂ content was 15.0 mg/g rock, indicating a high hydrocarbon generation potential. On the basis of the relationship between the quantity of soluble hydrocarbons remaining in the strata and the S₂ and TOC contents, it can be inferred that the hydrocarbon generation conversion rate of these Jurassic source rocks was between 25% and 50%, and partial hydrocarbon expulsion has taken place. It is estimated that the maximum oil generation potential of the formation will reach 20 kg/t rock at a greater depth, which equates to good exploration potential. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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16 pages, 3614 KB

Open AccessArticle

Molecular Simulation Study on the Competitive Adsorption and Diffusion of CH₄ and CO₂ in Coal Nanopores with Different Pore Sizes

by Guangli Huang, Qinghua Zhang and Fujin Lin

Processes 2025, 13(9), 2990; https://doi.org/10.3390/pr13092990 - 19 Sep 2025

Cited by 3 | Viewed by 1650

Abstract

Coalbed methane (CBM), mainly composed of methane (CH₄) and carbon dioxide (CO₂), has attracted increasing attention due to its dual significance as a clean energy resource and its role in greenhouse gas management. This research systematically examines the adsorption, [...] Read more.

Coalbed methane (CBM), mainly composed of methane (CH₄) and carbon dioxide (CO₂), has attracted increasing attention due to its dual significance as a clean energy resource and its role in greenhouse gas management. This research systematically examines the adsorption, desorption, diffusion, and bubble evolution dynamics of methane (CH₄) and carbon dioxide (CO₂) in graphene nanopores with diameters of 4 nm, 6 nm, and 8 nm by molecular dynamics simulations. Radial distribution function (RDF) analyses reveal strong solvation of both gases by water, with CO₂ exhibiting slightly stronger interactions. Adsorption and desorption dynamics indicate that CO₂ molecules display shorter residence times on the graphene surface (0.044–0.057 ns) compared with CH₄ (0.055–0.062 ns), reflecting faster surface exchange. Gas-phase molecular number analysis demonstrates that CH₄ accumulates more significantly in the vapor phase, while CO₂ is more prone to adsorption and re-dissolution. Mean square displacement (MSD) results confirm enhanced molecular mobility in larger pores, with CH₄ showing greater overall diffusivity. Structural evolution of the 8 nm system highlights asymmetric bubble dynamics, where large bubbles merge with the upper adsorption layer to form a thicker layer, while smaller bubbles contribute to a thinner layer near the lower surface. CH₄ and CO₂ follow similar pathways, though CO₂ diffuses farther post-desorption due to its weaker surface retention. These results provide fundamental insights into confinement-dependent gas behavior in graphene systems, offering guidance for gas separation and storage applications. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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21 pages, 2133 KB

Open AccessArticle

The Supercritical Adsorption Potential Equation for Shale Gas and Its Application: A Case Study of Methane Adsorption in Danish Bornholm Shale

by Pei Xue, Quansheng Liang, Chao Gao, Jintao Yin, Cheng Huang and Yushan Ma

Processes 2025, 13(9), 2918; https://doi.org/10.3390/pr13092918 - 12 Sep 2025

Cited by 1 | Viewed by 849

Abstract

Since shale gas adsorption belongs to supercritical gas adsorption, the ideal gas adsorption potential equation is not suitable for calculating the adsorption potential of shale gas. In this study, the supercritical gas adsorption potential equation is proposed based on the assumption that the [...] Read more.

Since shale gas adsorption belongs to supercritical gas adsorption, the ideal gas adsorption potential equation is not suitable for calculating the adsorption potential of shale gas. In this study, the supercritical gas adsorption potential equation is proposed based on the assumption that the adsorbed phase is a real gas. The adsorbed phase pressure, as the parameter in the adsorption potential equation, was calculated using the Amankwah equation. For the unknown parameter K in the Amankwah equation, a method for determining the optimal value of K based on the consistency of the adsorption characteristic curve and the accuracy of the predicted isothermal adsorption curve is proposed, thus obtaining the adsorbed phase pressure. Simultaneously, based on a comparison of the ideal gas and supercritical gas adsorption potential, a simplified equation for the supercritical gas adsorption potential is proposed. In this paper, the isothermal adsorption curve of CH₄ adsorbed by Holm shale is used to carry out practical calculations. This study revealed that the optimal value of K for the CH₄ adsorption system in Holm shale is 2.9, with the adsorbed phase pressure ranging from 17.11 to 32.19 MPa within the temperature range of 300–373 K. The supercritical gas adsorption characteristic curves exhibited excellent consistency, and the average relative error of the predicted ascending segment of the excess adsorption isotherm at 373 K was merely 1.77%, thereby substantiating the rationality of the supercritical gas adsorption potential equation. The simplified equation for supercritical gas adsorption potential is straightforward in form, facilitating its widespread application and promotion. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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23 pages, 11598 KB

Open AccessArticle

Characteristics of Load-Bearing Rupture of Rock–Coal Assemblages with Different Height Ratios and Multivariate Energy Spatiotemporal Evolution Laws

by Bo Wang, Guilin Wu, Guorui Feng, Zhuocheng Yu and Yingshi Gu

Processes 2025, 13(8), 2588; https://doi.org/10.3390/pr13082588 - 15 Aug 2025

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Abstract

The destabilizing damage of rock structures in coal beds engineering is greatly influenced by the bearing rupture features and energy evolution laws of rock–coal assemblages with varying height ratios. In this study, we used PFC3D to create rock–coal assemblages with rock–coal height ratios [...] Read more.

The destabilizing damage of rock structures in coal beds engineering is greatly influenced by the bearing rupture features and energy evolution laws of rock–coal assemblages with varying height ratios. In this study, we used PFC3D to create rock–coal assemblages with rock–coal height ratios of 2:8, 4:6, 6:4, and 8:2. Uniaxial compression simulation was then performed, revealing the expansion properties and damage crack dispersion pattern at various bearing phases. The dispersion and migration law of cemented strain energy zoning; the size and location of the destructive energy level and its spatiotemporal evolution characteristics; and the impact of height ratio on the load-bearing characteristics, crack extension, and evolution of multiple energies (strain, destructive, and kinetic energies) were all clarified with the aid of a self-developed destructive energy and strain energy capture and tracking Fish program. The findings indicate that the assemblage’s elasticity modulus and compressive strength slightly increase as the height ratio increases, that the assemblage’s cracks begin in the coal body, and that the number of crack bands inside the coal body increases as the height ratio increases. Also, the phenomenon of crack bands penetrating the rock through the interface between the coal and rock becomes increasingly apparent. The total number of cracks, including both tensile and shear cracks, decreases as the height ratio increases. Among these, tensile cracks are consistently more abundant than shear cracks, and the proportion between the two types remains relatively stable regardless of changes in the height ratio. The acoustic emission ringing counts of the assemblage were not synchronized with the development of bearing stress, and the ringing counts started to increase from the yield stage and reached a peak at the damage stage (0.8

σ_{c}

) after the peak of bearing stress. The larger the rock–coal height ratio, the smaller the peak and the earlier the timing of its appearance. The main body of strain energy accumulation was transferred from the coal body to the rock body when the height ratio exceeded 1.5. The peak values of the assemblage’s strain energy, destructive energy, and kinetic energy curves decreased as the height ratio increased, particularly the energy amplitude of the largest destructive energy event. In order to prevent and mitigate engineering disasters during deep mining of coal resources, the research findings could serve as a helpful reference for the destabilizing properties of rock–coal assemblages. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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19 pages, 7491 KB

Open AccessArticle

A Model and the Characteristics of Gas Generation of the Longmaxi Shale in the Sichuan Basin

by Xuewen Shi, Yi Li, Yuqiang Jiang, Ye Zhang, Wei Wu, Zhiping Zhang, Zhanlei Wang, Xingping Yin, Yonghong Fu and Yifan Gu

Processes 2025, 13(7), 2294; https://doi.org/10.3390/pr13072294 - 18 Jul 2025

Cited by 2 | Viewed by 1089

Abstract

Currently, the Longmaxi shale in the Sichuan Basin is the most successful stratum of shale gas production in China. However, because Longmaxi shale mostly has high over-maturity, a low-maturity sample cannot be obtained for gas generation thermal simulations, and as a result, a [...] Read more.

Currently, the Longmaxi shale in the Sichuan Basin is the most successful stratum of shale gas production in China. However, because Longmaxi shale mostly has high over-maturity, a low-maturity sample cannot be obtained for gas generation thermal simulations, and as a result, a gas generation model has not yet been established for it. Therefore, models of other shales are usually used to calculate the amount of gas generated from Longmaxi shale, but they may produce inaccurate results. In this study, a Longmaxi shale sample with an equivalent vitrinite reflectance calculated from Raman spectroscopy (EqVR_o) of 1.26% was obtained from Well Yucan 1 in the Chengkou area, northeast Sichuan Province. This Longmaxi shale may have the lowest maturity in nature. Pyrolysis simulations based on gold tubes were performed on this sample, and the gas generation line was obtained. The amount of gas generated during the low-maturity stage was compensated by referring to gas generation data obtained from Lower Silurian black shale in western Lithuania. Thus, a gas generation model of the Longmaxi shale was built. The model showed that the gas generation process of Longmaxi shale could be divided into three stages: (1) First, there is the quick generation stage (EqVR_o 0.5–3.0%), where hydrocarbon gases were generated quickly and constantly, and the generation rate was steady. A maximum of 458 mL/g TOC was reached at a maturity of 3.0% EqVR_o. (2) Second, there is the stable stage (EqVR_o 3.0–3.25%), where the amount of generated gas reached a plateau of 453–458 mL/g TOC. (3) Third, there is the rapid descent stage (EqVR_o > 3.25%), where the amount of generated gas started to decrease, and it was 393 mL/g TOC at an EqVR_o of 3.34%. This model allows us to more accurately calculate the amount of gas generated from the Longmaxi shale in the Sichuan Basin. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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21 pages, 2074 KB

Open AccessArticle

Influence of Clay Content on the Compaction and Permeability Characteristics of Sandstone Reservoirs

by Jin Pang, Tongtong Wu, Chunxi Zhou, Haotian Chen, Jiaao Gao and Xinan Yu

Processes 2025, 13(6), 1835; https://doi.org/10.3390/pr13061835 - 10 Jun 2025

Cited by 2 | Viewed by 2162

Abstract

Clay content is a critical geological parameter influencing the pore structure, compaction sensitivity, and flow capacity of sandstone reservoirs. In this study, representative Tertiary sandstones from a major sedimentary basin in western China were selected, covering natural and synthetic core samples with clay [...] Read more.

Clay content is a critical geological parameter influencing the pore structure, compaction sensitivity, and flow capacity of sandstone reservoirs. In this study, representative Tertiary sandstones from a major sedimentary basin in western China were selected, covering natural and synthetic core samples with clay contents ranging from 20% to 70%. Utilizing a self-developed apparatus capable of both static and dynamic compaction experiments, we systematically performed staged static loading and gas–water two-phase displacement tests. This enabled us to obtain comprehensive datasets on porosity, permeability, pressure response, and two-phase flow characteristics under various clay content, confining pressure, and gas drive rate conditions. Results demonstrate that high clay content leads to pronounced pore structure compaction and substantially greater permeability reductions compared to low-clay reservoirs, indicating heightened stress sensitivity. The synergy between gas drive rate and confining pressure regulates intralayer water production efficiency: initially, increased gas drive enhances mobile water production, but efficiency drops sharply at late stages due to pore contraction and increased bound water. As confining pressure increases, the mixed-flow region for two-phase flow shrinks, with water permeability decreasing sharply and gas permeability increasing, revealing the dynamic fluid transport and productivity decline mechanisms controlled by effective stress. The research deepens understanding of compaction–flow mechanisms in clay-rich sandstones, offering bases for evaluating reservoir stress sensitivity and supporting efficient, sustainable gas reservoir development, which increasingly helps offset global energy shortages. Full article

(This article belongs to the Special Issue Advances in Theory and Technology of Unconventional Oil and Gas Reservoirs)

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