The Cairo-Suez District (CSD), located in the northwestern sector of the Gulf of Suez rift, is characterized by significant structural complexity, including an intricate network of extensional faults and transfer zones. This study focuses on the Gebel El-Himeira and northern Gebel Ataqa areas, situated at the eastern part of the CSD. This research aims to clarify the internal architecture of these areas through detailed geological field mapping, structural data collection, and satellite imagery analysis. The primary objectives are to establish the geometry of the transfer zones, decipher their deformation history, and understand the influence of their evolution on syn-tectonic sedimentation. The structural analysis of the mapped areas reveals that the Gebel El-Himeira and northern Gebel Ataqa regions represent two prominent conjugate divergent transfer zones which formed between adjacent bounding faults that dip away from each other. The results indicate that the development of both transfer zones began during the Late Eocene and led to dissimilar geometries. This difference in geometry is attributed to the role of reactivated preexisting faults. The growth and propagation of these transfer zones exert significant control on syn-sedimentation processes. These findings provide valuable analogues for subsurface mapping and enhance the understanding of structural controls on hydrocarbon accumulation and migration pathways in similar rift-related basins.
{"title":"Fault interactions and role of preexisting structures on the geometry of conjugate transfer zones: Structural insights from Cairo-Suez District, Egypt","authors":"Ahmed Henaish , Sherif Kharbish , Moustafa Abdelhady , Fares Khedr","doi":"10.1016/j.marpetgeo.2025.107402","DOIUrl":"10.1016/j.marpetgeo.2025.107402","url":null,"abstract":"<div><div>The Cairo-Suez District (CSD), located in the northwestern sector of the Gulf of Suez rift, is characterized by significant structural complexity, including an intricate network of extensional faults and transfer zones. This study focuses on the Gebel El-Himeira and northern Gebel Ataqa areas, situated at the eastern part of the CSD. This research aims to clarify the internal architecture of these areas through detailed geological field mapping, structural data collection, and satellite imagery analysis. The primary objectives are to establish the geometry of the transfer zones, decipher their deformation history, and understand the influence of their evolution on syn-tectonic sedimentation. The structural analysis of the mapped areas reveals that the Gebel El-Himeira and northern Gebel Ataqa regions represent two prominent conjugate divergent transfer zones which formed between adjacent bounding faults that dip away from each other. The results indicate that the development of both transfer zones began during the Late Eocene and led to dissimilar geometries. This difference in geometry is attributed to the role of reactivated preexisting faults. The growth and propagation of these transfer zones exert significant control on syn-sedimentation processes. These findings provide valuable analogues for subsurface mapping and enhance the understanding of structural controls on hydrocarbon accumulation and migration pathways in similar rift-related basins.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107402"},"PeriodicalIF":3.7,"publicationDate":"2025-04-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143769092","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":2,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-04-02DOI: 10.1016/j.marpetgeo.2025.107399
Yousef Abedi , Hossein Mosaddegh , Mohammad Ali Kavoosi
The Santonian Ilam Formation, is one of the most important hydrocarbon reservoirs in the Abadan Plain, southwestern Iran. The aim of this study is to evaluate the diagenetic processes and products in a sequence stratigraphic framework by combining the results of core description, the study of microscopic thin sections and petrophysical diagrams from the perspective of facies, diagenetic features, and reconstruction of the depositional environments. Petrographic studies were performed on 235 thin sections from drill cuttings from four wells and about 124 m of core samples from two key wells across four oil fields in the study area. Facies analysis identified seven carbonate microfacies belonging to lagoon, shoal, and open marine facies belts. The findings indicate that the Ilam Formation was deposited in a homoclinal carbonate ramp platform. Sequence stratigraphic investigations led to the identification of two third-order depositional sequences. Diagenetic processes affecting include dissolution, recrystallization and dolomitization, mainly observed dominant in the late highstand systems tract of the lower Santonian depostional sequence. In the early TST and late HST stages, due to increased accommodation space, marine diagenetic processes such as micritization and cementation are more extensive. Due to the development of grain-supported microfacies, dissolution processes and the development of vuggy and moldic porosity are more prevalent. In the late TST stages, favorable conditions for low-energy environment microfacies and in the early HST stages, with the decline in relative sea level rise rate and reduced accommodation space, have expanded.
{"title":"Linking diagenesis to sequence stratigraphy: An integrated approach for understanding and predicting the reservoir quality distribution of the Ilam Formation (Santonian) in Abadan Plain, southwest of Iran","authors":"Yousef Abedi , Hossein Mosaddegh , Mohammad Ali Kavoosi","doi":"10.1016/j.marpetgeo.2025.107399","DOIUrl":"10.1016/j.marpetgeo.2025.107399","url":null,"abstract":"<div><div>The Santonian Ilam Formation, is one of the most important hydrocarbon reservoirs in the Abadan Plain, southwestern Iran. The aim of this study is to evaluate the diagenetic processes and products in a sequence stratigraphic framework by combining the results of core description, the study of microscopic thin sections and petrophysical diagrams from the perspective of facies, diagenetic features, and reconstruction of the depositional environments. Petrographic studies were performed on 235 thin sections from drill cuttings from four wells and about 124 m of core samples from two key wells across four oil fields in the study area. Facies analysis identified seven carbonate microfacies belonging to lagoon, shoal, and open marine facies belts. The findings indicate that the Ilam Formation was deposited in a homoclinal carbonate ramp platform. Sequence stratigraphic investigations led to the identification of two third-order depositional sequences. Diagenetic processes affecting include dissolution, recrystallization and dolomitization, mainly observed dominant in the late highstand systems tract of the lower Santonian depostional sequence. In the early TST and late HST stages, due to increased accommodation space, marine diagenetic processes such as micritization and cementation are more extensive. Due to the development of grain-supported microfacies, dissolution processes and the development of vuggy and moldic porosity are more prevalent. In the late TST stages, favorable conditions for low-energy environment microfacies and in the early HST stages, with the decline in relative sea level rise rate and reduced accommodation space, have expanded.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107399"},"PeriodicalIF":3.7,"publicationDate":"2025-04-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143785880","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":2,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-30DOI: 10.1016/j.marpetgeo.2025.107400
Hongrui Zhang , Jinbu Li , Wanglu Jia , Min Wang , Ping'an Peng
Developing an accurate assessment of the content of in-situ fluid in different states (adsorbed and free) within complex shale reservoirs is crucial for reserve evaluation and shale oil mobility. While various methods based on nuclear magnetic resonance (NMR) technology, such as the two-dimensional (2D) NMR Chart method, Heating method, and Centrifugal method, have been proposed and tested by researchers for evaluating the content of free and adsorbed oil/water in shale reservoirs, a comprehensive comparative analysis of these methods is lacking. Moreover, previous investigations have predominantly focused on NMR analysis of shale samples saturated with single-phase fluids (either oil or water), neglecting the significant impact of oil-water two-phase in-situ fluids on experimental outcomes. Therefore, this study employed 23 preserved initial shale core samples from the Paleogene Shahejie Formation in Bohai Bay Basin, eastern China, and conducted a series of NMR experiments for shale samples under initial, centrifugal, and heating conditions. The content of in-situ oil and water in different states was systematically evaluated using the three aforementioned methods. Key findings include: a. The free oil content evaluated using the Chart method and the Heating method were very similar, both significantly exceeding that obtained via the Centrifugal method, likely due to the ladder-like manner of fluid expulsion from the shale during the centrifugal process and the influence of oil-water two-phase interactions on the Centrifugal method. b. Direct evaluation of free and adsorbed water using the Chart method proved challenging for preserved samples, necessitating auxiliary pretreatment steps such as sample heating to determine appropriate T2 cutoff values. c. The Heating method demonstrated limitations, including incomplete release of free fluid at the threshold temperature and premature expulsion of some adsorbed fluid prior to reaching the threshold, resulting in a slight underestimation of free fluid and an overestimation of adsorbed fluid. Given these observations, it is recommended that a combined approach incorporating the Chart method with the Heating method be employed for a comprehensive evaluation of fluid content in tight shale reservoirs saturated with multiphase fluids. These findings contribute valuable insights for quantifying the content of in-situ free and adsorbed fluids in unconventional reservoirs.
{"title":"Quantification of free and adsorbed fluid content in shale oil reservoirs: Insights from preserved cores and different methods","authors":"Hongrui Zhang , Jinbu Li , Wanglu Jia , Min Wang , Ping'an Peng","doi":"10.1016/j.marpetgeo.2025.107400","DOIUrl":"10.1016/j.marpetgeo.2025.107400","url":null,"abstract":"<div><div>Developing an accurate assessment of the content of in-situ fluid in different states (adsorbed and free) within complex shale reservoirs is crucial for reserve evaluation and shale oil mobility. While various methods based on nuclear magnetic resonance (NMR) technology, such as the two-dimensional (2D) NMR Chart method, Heating method, and Centrifugal method, have been proposed and tested by researchers for evaluating the content of free and adsorbed oil/water in shale reservoirs, a comprehensive comparative analysis of these methods is lacking. Moreover, previous investigations have predominantly focused on NMR analysis of shale samples saturated with single-phase fluids (either oil or water), neglecting the significant impact of oil-water two-phase in-situ fluids on experimental outcomes. Therefore, this study employed 23 preserved initial shale core samples from the Paleogene Shahejie Formation in Bohai Bay Basin, eastern China, and conducted a series of NMR experiments for shale samples under initial, centrifugal, and heating conditions. The content of in-situ oil and water in different states was systematically evaluated using the three aforementioned methods. Key findings include: a. The free oil content evaluated using the Chart method and the Heating method were very similar, both significantly exceeding that obtained via the Centrifugal method, likely due to the ladder-like manner of fluid expulsion from the shale during the centrifugal process and the influence of oil-water two-phase interactions on the Centrifugal method. b. Direct evaluation of free and adsorbed water using the Chart method proved challenging for preserved samples, necessitating auxiliary pretreatment steps such as sample heating to determine appropriate T<sub>2</sub> cutoff values. c. The Heating method demonstrated limitations, including incomplete release of free fluid at the threshold temperature and premature expulsion of some adsorbed fluid prior to reaching the threshold, resulting in a slight underestimation of free fluid and an overestimation of adsorbed fluid. Given these observations, it is recommended that a combined approach incorporating the Chart method with the Heating method be employed for a comprehensive evaluation of fluid content in tight shale reservoirs saturated with multiphase fluids. These findings contribute valuable insights for quantifying the content of in-situ free and adsorbed fluids in unconventional reservoirs.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107400"},"PeriodicalIF":3.7,"publicationDate":"2025-03-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143747145","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":2,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-28DOI: 10.1016/j.marpetgeo.2025.107396
Mohamed M. Awad, D. Nicolas Espinoza
Caprock sealing capacity is essential for carbon geological storage in saline aquifers and depleted oil and gas formations. Clay-rich caprocks and fault gouge are expected to hold buoyant CO2 in the storage formation by capillary forces. However, all direct capillary sealing capacity measurements of clay-rich rocks to CO2 were so far limited to pressures below ∼20 MPa and/or temperatures below 50 °C, typically lower than target storage conditions. This paper presents new results of brine absolute permeability, capillary CO2 breakthrough pressure, and post-breakthrough CO2 permeability for resedimented kaolinite clay plugs at fluid pressures greater than 41 MPa, temperatures of 60 °C and 80 °C, and mean effective stress of ∼6.8 MPa. The results show that breakthrough pressure (PCO2 - Pw) is always positive and remains in the interval between ∼ 1.4 MPa and 2.8 MPa within the range of pressure and temperature explored. Moreover, average post-breakthrough CO2 relative permeability is ∼5 %. An additional test with a clay mixture representative of a shale from the North Sea, at similar pressure-temperature conditions held a differential pressure, i.e., no breakthrough, over three months with a maximum difference PCO2 - Pw = 5.71 MPa. Results and analysis support the water-wet properties of clays at high pressure and temperature and the resulting capillary sealing capacity to CO2. These results support expectations that clay-rich caprocks are satisfactory seals for holding buoyant CO2 via capillary forces. Results also suggest that if the sealing capacity is surpassed, clay-rich caprocks can limit advective flow because of their low CO2 relative permeability and potential for resealing through snap-off.
{"title":"Brine-saturated kaolinite mudrocks preserve capillary sealing to CO2 at high pressure and temperature","authors":"Mohamed M. Awad, D. Nicolas Espinoza","doi":"10.1016/j.marpetgeo.2025.107396","DOIUrl":"10.1016/j.marpetgeo.2025.107396","url":null,"abstract":"<div><div>Caprock sealing capacity is essential for carbon geological storage in saline aquifers and depleted oil and gas formations. Clay-rich caprocks and fault gouge are expected to hold buoyant CO<sub>2</sub> in the storage formation by capillary forces. However, all direct capillary sealing capacity measurements of clay-rich rocks to CO<sub>2</sub> were so far limited to pressures below ∼20 MPa and/or temperatures below 50 °C, typically lower than target storage conditions. This paper presents new results of brine absolute permeability, capillary CO<sub>2</sub> breakthrough pressure, and post-breakthrough CO<sub>2</sub> permeability for resedimented kaolinite clay plugs at fluid pressures greater than 41 MPa, temperatures of 60 °C and 80 °C, and mean effective stress of ∼6.8 MPa. The results show that breakthrough pressure (P<sub>CO</sub><sub>2</sub> - P<sub>w</sub>) is always positive and remains in the interval between ∼ 1.4 MPa and 2.8 MPa within the range of pressure and temperature explored. Moreover, average post-breakthrough CO<sub>2</sub> relative permeability is ∼5 %. An additional test with a clay mixture representative of a shale from the North Sea, at similar pressure-temperature conditions held a differential pressure, i.e., no breakthrough, over three months with a maximum difference P<sub>CO</sub><sub>2</sub> - P<sub>w</sub> = 5.71 MPa. Results and analysis support the water-wet properties of clays at high pressure and temperature and the resulting capillary sealing capacity to CO<sub>2</sub>. These results support expectations that clay-rich caprocks are satisfactory seals for holding buoyant CO<sub>2</sub> via capillary forces. Results also suggest that if the sealing capacity is surpassed, clay-rich caprocks can limit advective flow because of their low CO<sub>2</sub> relative permeability and potential for resealing through snap-off.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107396"},"PeriodicalIF":3.7,"publicationDate":"2025-03-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143776729","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":2,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Field studies of sedimentary successions complemented by petrographic analyses allow distinctions among sub-environments, even in the case of subtle differences in geometry, structure, and composition. In three apparently uniform sections of the coarse-grained siliciclastic K2b unit of Upper Cretaceous age exposed in the southern central Alborz Mountains (northern Iran), careful observations of texture, fabric, composition, and bed thickness have allowed the identification of eight petrofacies, twelve low-rank facies associations, and six high-rank facies associations. The coarse grain size of the K2b unit, the radial paleocurrent pattern indicated by grain orientation, along with the presence of hummocky and swaley cross-stratification, glaucony, Skolithos ichnofacies, and Hedbergellidae planktonic foraminifera suggest a fan-delta prograding onto a shallow shelf. Conglomerate layers, erosion surfaces, plane beds, and oriented grains point to diverse depositional mechanisms, including cohesive debris flows, hyperconcentrated flows, and turbidity currents. Sediment-gravity flows in the K2b unit, generated along the southern margin of the Proto-south Caspian basin, testify to both relative sea-level fall and tectonic uplift in mountainous source areas.
{"title":"Facies analysis of gravity-flow deposits from the Upper Cretaceous of the Alborz Mountains (northern Iran)","authors":"Hedieh Abbasian , Mahboubeh Hosseini-Barzi , Abbas Sadeghi , Abdolhossein Amini , Eduardo Garzanti","doi":"10.1016/j.marpetgeo.2025.107395","DOIUrl":"10.1016/j.marpetgeo.2025.107395","url":null,"abstract":"<div><div>Field studies of sedimentary successions complemented by petrographic analyses allow distinctions among sub-environments, even in the case of subtle differences in geometry, structure, and composition. In three apparently uniform sections of the coarse-grained siliciclastic K2b unit of Upper Cretaceous age exposed in the southern central Alborz Mountains (northern Iran), careful observations of texture, fabric, composition, and bed thickness have allowed the identification of eight petrofacies, twelve low-rank facies associations, and six high-rank facies associations. The coarse grain size of the K2b unit, the radial paleocurrent pattern indicated by grain orientation, along with the presence of hummocky and swaley cross-stratification, glaucony, Skolithos ichnofacies, and <em>Hedbergellidae</em> planktonic foraminifera suggest a fan-delta prograding onto a shallow shelf. Conglomerate layers, erosion surfaces, plane beds, and oriented grains point to diverse depositional mechanisms, including cohesive debris flows, hyperconcentrated flows, and turbidity currents. Sediment-gravity flows in the K2b unit, generated along the southern margin of the Proto-south Caspian basin, testify to both relative sea-level fall and tectonic uplift in mountainous source areas.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107395"},"PeriodicalIF":3.7,"publicationDate":"2025-03-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143734754","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":2,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-26DOI: 10.1016/j.marpetgeo.2025.107394
Wei-Chung Han , Liwen Chen , Wu-Cheng Chi , Hsieh-Tang Chiang , Song-Chuen Chen , Char-Shine Liu , Chuen-Tien Shyu
Ubiquitous bottom simulating reflections (BSRs) on seismic profiles indicate the presence of gas hydrates and free gases in both the active and passive margins offshore SW Taiwan. Detailed seafloor temperature measurements and modeling were conducted in offshore SW Taiwan gas hydrate provinces to investigate the thermal structure under dynamic gas hydrate systems. We performed seismic analysis, direct temperature measurements, and BSR-based thermal modeling to understand the seafloor thermal structures and subsurface fluid flow systems. First, seismic interpretation was applied to understand the BSR distribution and structural features in the gas hydrate provinces along the convergent plate boundary offshore SW Taiwan. Then, we compiled the 159 in-situ temperature measurements in marine sediments, and a regional heat flow map was proposed. After that, we use the sub-bottom depths of the widespread BSRs to derive seafloor thermal structures offshore SW Taiwan. Finally, by comparing the measured and BSR-based temperature fields, several interesting geological processes affecting the seafloor thermal structures are revealed. The distinct heating effects near the lower slope of the accretionary prism indicate active fluid flow along the thrust and décollement systems. In the upper slope, the seafloor thermal structure shows an overall low with local higher heat flow near the diapiric structures, implying that the diapirs may serve as active fluid conduits. Although few large-scale fault systems exist in the passive South China Sea (SCS) Slope, the upward fluid migration along normal faults, dipping strata, and gas chimneys contribute to intense local-scale seafloor heating. Apparent thermal nonequilibrium observed near the deformation front reveals a recent mass transport deposit (MTD) event with a volume of ∼0.8 km3. Our results present the geologically controlled seafloor thermal structures under the dynamic gas hydrate systems, which may give insights into the subsurface fluid flow, gas hydrate systems, and submarine geohazards.
{"title":"Seafloor thermal structures controlled by recent slope failure and fluid flow: An example from offshore SW Taiwan","authors":"Wei-Chung Han , Liwen Chen , Wu-Cheng Chi , Hsieh-Tang Chiang , Song-Chuen Chen , Char-Shine Liu , Chuen-Tien Shyu","doi":"10.1016/j.marpetgeo.2025.107394","DOIUrl":"10.1016/j.marpetgeo.2025.107394","url":null,"abstract":"<div><div>Ubiquitous bottom simulating reflections (BSRs) on seismic profiles indicate the presence of gas hydrates and free gases in both the active and passive margins offshore SW Taiwan. Detailed seafloor temperature measurements and modeling were conducted in offshore SW Taiwan gas hydrate provinces to investigate the thermal structure under dynamic gas hydrate systems. We performed seismic analysis, direct temperature measurements, and BSR-based thermal modeling to understand the seafloor thermal structures and subsurface fluid flow systems. First, seismic interpretation was applied to understand the BSR distribution and structural features in the gas hydrate provinces along the convergent plate boundary offshore SW Taiwan. Then, we compiled the 159 <em>in-situ</em> temperature measurements in marine sediments, and a regional heat flow map was proposed. After that, we use the sub-bottom depths of the widespread BSRs to derive seafloor thermal structures offshore SW Taiwan. Finally, by comparing the measured and BSR-based temperature fields, several interesting geological processes affecting the seafloor thermal structures are revealed. The distinct heating effects near the lower slope of the accretionary prism indicate active fluid flow along the thrust and décollement systems. In the upper slope, the seafloor thermal structure shows an overall low with local higher heat flow near the diapiric structures, implying that the diapirs may serve as active fluid conduits. Although few large-scale fault systems exist in the passive South China Sea (SCS) Slope, the upward fluid migration along normal faults, dipping strata, and gas chimneys contribute to intense local-scale seafloor heating. Apparent thermal nonequilibrium observed near the deformation front reveals a recent mass transport deposit (MTD) event with a volume of ∼0.8 km<sup>3</sup>. Our results present the geologically controlled seafloor thermal structures under the dynamic gas hydrate systems, which may give insights into the subsurface fluid flow, gas hydrate systems, and submarine geohazards.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107394"},"PeriodicalIF":3.7,"publicationDate":"2025-03-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143734755","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":2,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-25DOI: 10.1016/j.marpetgeo.2025.107393
Peng Li , Zhiqiang Fan , Liang Zhao , Chunlong Yang , Kun He , Dayong Wang
Hydraulic fracturing in hydrate-bearing formation enhances reservoir permeability, thereby promoting gas production, but simultaneously compromises the mechanical strength integrity of the solid skeleton, amplifying risks of reservoir deformation, seafloor subsidence, and sand production. Despite these challenges, the interplay between hydraulic fracturing and such risks remains inadequately quantified, resulting in underestimation of exploitation risks. In this study, we developed a fully coupled thermal-hydraulic-mechanical-chemical model that incorporates sand production dynamics, validated against experimental data and numerical benchmarks. Using the Shenhu hydrate reservoir as a case study, we evaluated the effects of hydraulic fracturing (characterized by a fracture length of 5 m, a fracture permeability of 1 D, and a damage zone permeability of 50 mD) on long-term gas production, formation deformation, and sand production behaviors. Our analysis reveals that hydraulic fracturing increases cumulative gas production by 57 %, reaching 2.34 × 106 m3 after 1000 days. However, it also triggers significant mechanical degradation: the volumetric strain in the damaged zone exceeds 2.5 %, which exacerbates formation collapse, inducing an additional 7 cm of seafloor subsidence, for a total of 21 cm and intensifying sand production to 903 m3, 2.4 times higher than production without fracturing. Further increases in fracture length beyond 5 m or fracture permeability above 0.1 D yield diminishing returns in gas production but exacerbates sand production. Enhancing the damaged zone's permeability from 25 mD to 75 mD increases gas production by 20 %, but also raises sand production by 49 % and seafloor subsidence by 4 cm.
{"title":"Underestimated risks for application of hydraulic fracturing into hydrate exploitation: In the perspective of formation deformation and sand production","authors":"Peng Li , Zhiqiang Fan , Liang Zhao , Chunlong Yang , Kun He , Dayong Wang","doi":"10.1016/j.marpetgeo.2025.107393","DOIUrl":"10.1016/j.marpetgeo.2025.107393","url":null,"abstract":"<div><div>Hydraulic fracturing in hydrate-bearing formation enhances reservoir permeability, thereby promoting gas production, but simultaneously compromises the mechanical strength integrity of the solid skeleton, amplifying risks of reservoir deformation, seafloor subsidence, and sand production. Despite these challenges, the interplay between hydraulic fracturing and such risks remains inadequately quantified, resulting in underestimation of exploitation risks. In this study, we developed a fully coupled thermal-hydraulic-mechanical-chemical model that incorporates sand production dynamics, validated against experimental data and numerical benchmarks. Using the Shenhu hydrate reservoir as a case study, we evaluated the effects of hydraulic fracturing (characterized by a fracture length of 5 m, a fracture permeability of 1 D, and a damage zone permeability of 50 mD) on long-term gas production, formation deformation, and sand production behaviors. Our analysis reveals that hydraulic fracturing increases cumulative gas production by 57 %, reaching 2.34 × 10<sup>6</sup> m<sup>3</sup> after 1000 days. However, it also triggers significant mechanical degradation: the volumetric strain in the damaged zone exceeds 2.5 %, which exacerbates formation collapse, inducing an additional 7 cm of seafloor subsidence, for a total of 21 cm and intensifying sand production to 903 m<sup>3</sup>, 2.4 times higher than production without fracturing. Further increases in fracture length beyond 5 m or fracture permeability above 0.1 D yield diminishing returns in gas production but exacerbates sand production. Enhancing the damaged zone's permeability from 25 mD to 75 mD increases gas production by 20 %, but also raises sand production by 49 % and seafloor subsidence by 4 cm.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107393"},"PeriodicalIF":3.7,"publicationDate":"2025-03-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143725657","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":2,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-24DOI: 10.1016/j.marpetgeo.2025.107392
Yishu Li , Guangdi Liu , Zezhang Song , Mingliang Sun , Xingwang Tian , Dailing Yang , Lianqiang Zhu
Hydrocarbon reservoirs in ancient and deeply buried formations typically exhibit complex evolutionary histories. After experiencing high temperatures, pressures, and multiple types of secondary modifications, the geological information carried by hydrocarbons is superimposed and difficult to interpret. Methane carbon isotopes (δ13C) in the Sinian natural gas in the central Sichuan Basin are heavier than those of the reservoir solid pyrobitumen (SB) and are considered an ‘anomalous’ fractionation. Therefore, based on the abundant δ13C data of the source rock, SB, and natural gas, this study aimed to interpret the geological significance recorded by the ‘anomalous’ fractionation combined with the analysis of geological elements and the evolution process of the gas reservoir. The results showed that the combined contributions of multiple source rocks lead to differences in the original δ13C of crude oil in paleo-oil reservoirs. Among them, the slope of the paleo-uplift was closer to the Deyang–Anyue rift trough, where the δ13C of the main Cambrian source rocks was negatively biased, making the δ13C of the paleo-oil reservoirs more negative. During the late thermal evolution, deasphalting was caused by gas produced from oil cracking under high temperatures and pressures. In contrast, the adsorption of clay minerals and gas intrusion due to kerogen degradation in the source rocks had little effect on deasphalting. The δ13C values of the bulk SB precipitated by deasphalting were light and similar to those of the contemporaneous oil. However, the cracked gas with substantial negative δ13C produced in the early phase completely escaped as the reservoir pressure increased; the traps concentrated only the late cracked gas, which was isotopically heavier than all the SB produced in the different stages. This study provides new insights into the evolution of isotopic fractionation in ancient oil and gas systems involving oil cracking and phase transformation.
{"title":"Implications of carbon isotope fractionation of natural gas, pyrobitumen, and source rock on Sinian gas reservoirs evolution, central Sichuan Basin","authors":"Yishu Li , Guangdi Liu , Zezhang Song , Mingliang Sun , Xingwang Tian , Dailing Yang , Lianqiang Zhu","doi":"10.1016/j.marpetgeo.2025.107392","DOIUrl":"10.1016/j.marpetgeo.2025.107392","url":null,"abstract":"<div><div>Hydrocarbon reservoirs in ancient and deeply buried formations typically exhibit complex evolutionary histories. After experiencing high temperatures, pressures, and multiple types of secondary modifications, the geological information carried by hydrocarbons is superimposed and difficult to interpret. Methane carbon isotopes (δ<sup>13</sup>C) in the Sinian natural gas in the central Sichuan Basin are heavier than those of the reservoir solid pyrobitumen (SB) and are considered an ‘anomalous’ fractionation. Therefore, based on the abundant δ<sup>13</sup>C data of the source rock, SB, and natural gas, this study aimed to interpret the geological significance recorded by the ‘anomalous’ fractionation combined with the analysis of geological elements and the evolution process of the gas reservoir. The results showed that the combined contributions of multiple source rocks lead to differences in the original δ<sup>13</sup>C of crude oil in paleo-oil reservoirs. Among them, the slope of the paleo-uplift was closer to the Deyang–Anyue rift trough, where the δ<sup>13</sup>C of the main Cambrian source rocks was negatively biased, making the δ<sup>13</sup>C of the paleo-oil reservoirs more negative. During the late thermal evolution, deasphalting was caused by gas produced from oil cracking under high temperatures and pressures. In contrast, the adsorption of clay minerals and gas intrusion due to kerogen degradation in the source rocks had little effect on deasphalting. The δ<sup>13</sup>C values of the bulk SB precipitated by deasphalting were light and similar to those of the contemporaneous oil. However, the cracked gas with substantial negative δ<sup>13</sup>C produced in the early phase completely escaped as the reservoir pressure increased; the traps concentrated only the late cracked gas, which was isotopically heavier than all the SB produced in the different stages. This study provides new insights into the evolution of isotopic fractionation in ancient oil and gas systems involving oil cracking and phase transformation.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107392"},"PeriodicalIF":3.7,"publicationDate":"2025-03-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143704765","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":2,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-21DOI: 10.1016/j.marpetgeo.2025.107388
Zhenyu Sun , Jian Chen , Wanglu Jia , Qiang Wang , Jie Xu , Xin Li , Jianghu Yang , Ping'an Peng
Thermochemical sulfate reduction (TSR) is an intense redox reaction that significantly alters the original hydrocarbons in deep reservoirs. Previous studies have shown that light hydrocarbons (LHs) could be generated as important products in certain stages of TSR. However, the geochemical characteristics of these TSR-derived LHs remain poorly investigated, and their differences from those of LHs generated by thermal cracking (TC-derived LHs) are unclear. A TSR simulation designed to generate LHs without the influence of TC can solve this problem. In this study, three TSR series were conducted using n-octadecane, n-dodecylbenzene, and heavy oil as initial hydrocarbon reactants in sealed gold tubes. The yield, molecular composition, and carbon isotopic characteristics of the generated LHs were systematically analyzed. Results indicated that the yield of TSR-derived light oils was considerable (243.90–326.48 mg/g HCs), broadly equivalent to that in TC. However, the generation process of TSR-derived LHs was significantly brought forward and occurred at lower maturities relative to TC. In terms of molecular composition, TSR facilitated the formation of n-alkanes and aromatics, while suppressing the generation of branched alkanes and cycloalkanes. This resulted in the compositional characteristics of TSR-derived LHs being distinct from those of TC-derived LHs. Additionally, TSR-derived LHs became increasingly enriched in 13C as TSR progressed. The observed enrichment (3.7 ‰–6.2 ‰) was greater than that in TC-derived LHs (<3 ‰) but smaller than that in TSR-altered LHs, most of which were destroyed by TSR alteration (3–22 ‰). Most geochemical parameters of TSR-derived LHs did not provide reliable information on biological inputs, depositional environment, maturity, or later alteration. As a result, these parameters should be used cautiously in deep reservoirs where TSR is likely to occur. Moreover, the composition of the initial hydrocarbons influenced the generation of TSR-derived LHs. The long-chain paraffin group from the initial hydrocarbons breaks off and gradually evolves into LHs during the later stages of TSR, whereas the occurrence of aromatic rings leads to the earlier generation of aromatic-rich LHs. TSR-derived light oils represent a new hydrocarbon resource in deep basins, although they are less economical than TSR-unaltered oils. This study enhances our understanding of the generation, evolution, and typical geochemical characteristics of TSR-derived LHs, and offers valuable insights for evaluating light oil resources in deep basins.
{"title":"Geochemical characteristics of light hydrocarbons generated in thermochemical sulfate reduction: Results from three series of simulation experiments","authors":"Zhenyu Sun , Jian Chen , Wanglu Jia , Qiang Wang , Jie Xu , Xin Li , Jianghu Yang , Ping'an Peng","doi":"10.1016/j.marpetgeo.2025.107388","DOIUrl":"10.1016/j.marpetgeo.2025.107388","url":null,"abstract":"<div><div>Thermochemical sulfate reduction (TSR) is an intense redox reaction that significantly alters the original hydrocarbons in deep reservoirs. Previous studies have shown that light hydrocarbons (LHs) could be generated as important products in certain stages of TSR. However, the geochemical characteristics of these TSR-derived LHs remain poorly investigated, and their differences from those of LHs generated by thermal cracking (TC-derived LHs) are unclear. A TSR simulation designed to generate LHs without the influence of TC can solve this problem. In this study, three TSR series were conducted using <em>n</em>-octadecane, <em>n</em>-dodecylbenzene, and heavy oil as initial hydrocarbon reactants in sealed gold tubes. The yield, molecular composition, and carbon isotopic characteristics of the generated LHs were systematically analyzed. Results indicated that the yield of TSR-derived light oils was considerable (243.90–326.48 mg/g HCs), broadly equivalent to that in TC. However, the generation process of TSR-derived LHs was significantly brought forward and occurred at lower maturities relative to TC. In terms of molecular composition, TSR facilitated the formation of <em>n</em>-alkanes and aromatics, while suppressing the generation of branched alkanes and cycloalkanes. This resulted in the compositional characteristics of TSR-derived LHs being distinct from those of TC-derived LHs. Additionally, TSR-derived LHs became increasingly enriched in <sup>13</sup>C as TSR progressed. The observed enrichment (3.7 ‰–6.2 ‰) was greater than that in TC-derived LHs (<3 ‰) but smaller than that in TSR-altered LHs, most of which were destroyed by TSR alteration (3–22 ‰). Most geochemical parameters of TSR-derived LHs did not provide reliable information on biological inputs, depositional environment, maturity, or later alteration. As a result, these parameters should be used cautiously in deep reservoirs where TSR is likely to occur. Moreover, the composition of the initial hydrocarbons influenced the generation of TSR-derived LHs. The long-chain paraffin group from the initial hydrocarbons breaks off and gradually evolves into LHs during the later stages of TSR, whereas the occurrence of aromatic rings leads to the earlier generation of aromatic-rich LHs. TSR-derived light oils represent a new hydrocarbon resource in deep basins, although they are less economical than TSR-unaltered oils. This study enhances our understanding of the generation, evolution, and typical geochemical characteristics of TSR-derived LHs, and offers valuable insights for evaluating light oil resources in deep basins.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107388"},"PeriodicalIF":3.7,"publicationDate":"2025-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143704766","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":2,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-20DOI: 10.1016/j.marpetgeo.2025.107391
David A. Ferrill , Kevin J. Smart , Adam J. Cawood , Daniel J. Lehrmann , Giovanni Zanoni , R. Ryan King
The Wolfcampian Alta Formation represents 1700 m of deep-water siliciclastic deposits exposed in the Marfa Basin, the southwestern sub-basin of the Permian Basin complex of west Texas. These exposures are important outcrop analogs for the highly productive Wolfcamp Shale oil and gas reservoir of the Delaware and Midland Basins because they are of similar age, lithologies, and depositional environments. We present preliminary field data from outcrops of the Alta Formation in the southeast part of the Chinati Mountains, including lithostratigraphy, fracture characterization, and mineralogical analyses. Mesostructural deformation fabrics are dominated by up to four systematic sets of bed-perpendicular opening- mode fractures but also include rare bed-parallel opening-mode veins (beef), and occasional normal faults and thrust faults. Opening-mode fractures are generally bed-restricted and are interpreted to record a complex history reflecting changing extension direction at the time of fracturing in these sandstone and shale strata. Fracture dimensions mapped in a sandstone bedding pavement exposure show that length (parallel to bedding) to height (perpendicular to bedding) ratios for opening-mode fractures range from 0.13 to 38.56, with an average aspect ratio for all mapped opening-mode fractures of 4.84. Scanline surveys of a systematic NE-striking opening-mode fracture set show that fracture spacing is strongly correlated with mineralogy in both sandstone and shale lithologies, with a strong positive correlation for fracture spacing vs. clay content, and very strong negative correlations for fracture spacing vs. quartz, quartz + feldspar, and brittleness index. Bed thickness vs. fracture spacing data from scanlines show marked differences between sandstone and shale beds, with a very strong positive correlation for sandstone beds, a weak negative correlation for shale beds, and a very weak positive correlation – i.e. no correlation – for combined data. These results suggest that composition exerts a first-order control on opening-mode fracture abundance, and that bed thickness is likely a subordinate, or less important, controlling factor. These relationships can potentially be leveraged for mineralogy-based subsurface fracture prediction in comparable siliciclastic deposits.
{"title":"Fracturing in basinal siliciclastic deposits of the Wolfcampian Alta Formation, Marfa Basin, west Texas","authors":"David A. Ferrill , Kevin J. Smart , Adam J. Cawood , Daniel J. Lehrmann , Giovanni Zanoni , R. Ryan King","doi":"10.1016/j.marpetgeo.2025.107391","DOIUrl":"10.1016/j.marpetgeo.2025.107391","url":null,"abstract":"<div><div>The Wolfcampian Alta Formation represents 1700 m of deep-water siliciclastic deposits exposed in the Marfa Basin, the southwestern sub-basin of the Permian Basin complex of west Texas. These exposures are important outcrop analogs for the highly productive Wolfcamp Shale oil and gas reservoir of the Delaware and Midland Basins because they are of similar age, lithologies, and depositional environments. We present preliminary field data from outcrops of the Alta Formation in the southeast part of the Chinati Mountains, including lithostratigraphy, fracture characterization, and mineralogical analyses. Mesostructural deformation fabrics are dominated by up to four systematic sets of bed-perpendicular opening- mode fractures but also include rare bed-parallel opening-mode veins (beef), and occasional normal faults and thrust faults. Opening-mode fractures are generally bed-restricted and are interpreted to record a complex history reflecting changing extension direction at the time of fracturing in these sandstone and shale strata. Fracture dimensions mapped in a sandstone bedding pavement exposure show that length (parallel to bedding) to height (perpendicular to bedding) ratios for opening-mode fractures range from 0.13 to 38.56, with an average aspect ratio for all mapped opening-mode fractures of 4.84. Scanline surveys of a systematic NE-striking opening-mode fracture set show that fracture spacing is strongly correlated with mineralogy in both sandstone and shale lithologies, with a strong positive correlation for fracture spacing vs. clay content, and very strong negative correlations for fracture spacing vs. quartz, quartz + feldspar, and brittleness index. Bed thickness vs. fracture spacing data from scanlines show marked differences between sandstone and shale beds, with a very strong positive correlation for sandstone beds, a weak negative correlation for shale beds, and a very weak positive correlation – i.e. no correlation – for combined data. These results suggest that composition exerts a first-order control on opening-mode fracture abundance, and that bed thickness is likely a subordinate, or less important, controlling factor. These relationships can potentially be leveraged for mineralogy-based subsurface fracture prediction in comparable siliciclastic deposits.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107391"},"PeriodicalIF":3.7,"publicationDate":"2025-03-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143740011","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":2,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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