Pub Date : 2025-04-04DOI: 10.1016/j.marpetgeo.2025.107406
Marco Antonellini , Leonardo Del Sole , Pauline Nella Mollema
We apply outcrop-based structural and in-situ petrophysical properties measurements for the construction of flow and mass transport calibrated numerical models in a porous sandstone aquifer. The hydraulic conductivity in this aquifer is influenced by the presence of deformation bands and related carbonate nodules. These heterogeneities are shown to decrease the hydraulic conductivity of the host rock by 2–3 orders of magnitude. The result obtained is robust, given that the models were calibrated with hydrologic field data. Our upscaling methodology for hydraulic conductivity allows inclusion of outcrop-scale structures and diagenetic features by means of inversion of the advective velocity for conservative particles. This approach can be used for easily implementing field data in aquifers or other geofluids reservoir simulators. Our experiments show that the use of an equivalent isotropic hydraulic conductivity approach fails to correctly account for mass transport in porous sandstone aquifers and we recommend implementing, as much as possible, the local heterogeneities and anisotropies in hydraulic conductivity within the model to be able to have a more realistic and conservative estimate of advection and dispersion. Our findings should be helpful to those scientists dealing with geofluids modeling and groundwater pollution.
{"title":"Effects of outcrop-scale structural and diagenetic heterogeneities on flow and mass transport in a porous sandstone aquifer","authors":"Marco Antonellini , Leonardo Del Sole , Pauline Nella Mollema","doi":"10.1016/j.marpetgeo.2025.107406","DOIUrl":"10.1016/j.marpetgeo.2025.107406","url":null,"abstract":"<div><div>We apply outcrop-based structural and <em>in-situ</em> petrophysical properties measurements for the construction of flow and mass transport calibrated numerical models in a porous sandstone aquifer. The hydraulic conductivity in this aquifer is influenced by the presence of deformation bands and related carbonate nodules. These heterogeneities are shown to decrease the hydraulic conductivity of the host rock by 2–3 orders of magnitude. The result obtained is robust, given that the models were calibrated with hydrologic field data. Our upscaling methodology for hydraulic conductivity allows inclusion of outcrop-scale structures and diagenetic features by means of inversion of the advective velocity for conservative particles. This approach can be used for easily implementing field data in aquifers or other geofluids reservoir simulators. Our experiments show that the use of an equivalent isotropic hydraulic conductivity approach fails to correctly account for mass transport in porous sandstone aquifers and we recommend implementing, as much as possible, the local heterogeneities and anisotropies in hydraulic conductivity within the model to be able to have a more realistic and conservative estimate of advection and dispersion. Our findings should be helpful to those scientists dealing with geofluids modeling and groundwater pollution.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107406"},"PeriodicalIF":3.7,"publicationDate":"2025-04-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143791773","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}
Pub Date : 2025-04-02DOI: 10.1016/j.marpetgeo.2025.107397
Liangtao Ma , Weisheng He , Xianwen Zhang , Yunfeng Gao , Zongjun Wang , Rongsheng He , Linjie Yin
Studying the static connectivity of reservoir is essential to predict the lateral connectivity of sandbodies and devise field development strategies. Critical elements of static connectivity include geometry, stacking pattern, and the distribution of sandstone bodies. The meandering river reservoir in the lower member of the Minghuazhen (Nm) Formation is intersected and superimposed by multi-stage channel sandbody, resulting in a complex sandbody architecture. However, in the early phase of oilfield development with limited well data and sparse well spacing, there is a lack of comprehensive characterization of the strongly heterogeneous distribution pattern of channel sandbody and an incomplete understanding of sandbody connectivity, which complicates the optimization of well placement. We conducts a precise analysis of sandbody connectivity at different levels in seismic scale for Lm733 sandbody of the V oil group in the lower section of the Nm Formation, based on a comprehensive utilization of geological data in oilfield and guided by sequence stratigraphy and seismic sedimentology applying stratigraphic proportional slicing and sandbody edge detection technique. The results indicate that Lm733 sandbody can be classified into two composite channel sandbodies, respectively distributed in the early sequence (SQ1) and late sequence (SQ2). Based on the diverse seismic reflection characteristics, varying thicknesses, and plane distribution features of the interbed, the connectivity between two composite channel sandbodies for SQ1 and SQ2 could be classified into three categories (Type-Ⅰ, Ⅱ, and Ⅲ). According to the seismic attribute variation, including amplitude, waveform, and frequency at the internal boundaries of composite sandbodies, the internal connectivity of composite sandbody in SQ2 can be classified into three categories (Type-1,2, and 3), in conjunction with the existing injection-production well pattern. In this manner, predicting the characterization of sandbody connectivity at various levels in composite channel sandbody at seismic scale can aid in adjusting oilfield development plans.
{"title":"Qualitative characterization of sandbody connectivity for meandering river composite channel sandbody at seismic scale with large well spacing","authors":"Liangtao Ma , Weisheng He , Xianwen Zhang , Yunfeng Gao , Zongjun Wang , Rongsheng He , Linjie Yin","doi":"10.1016/j.marpetgeo.2025.107397","DOIUrl":"10.1016/j.marpetgeo.2025.107397","url":null,"abstract":"<div><div>Studying the static connectivity of reservoir is essential to predict the lateral connectivity of sandbodies and devise field development strategies. Critical elements of static connectivity include geometry, <em>stacking pattern</em>, and the distribution of sandstone bodies. The meandering river reservoir in the lower member of the Minghuazhen (Nm) Formation is intersected and superimposed by multi-stage channel sandbody, resulting in a complex sandbody architecture. However, in the early phase of oilfield development with limited well data and sparse well spacing, there is a lack of comprehensive characterization of the strongly heterogeneous distribution pattern of channel sandbody and an incomplete understanding of sandbody connectivity, which complicates the optimization of well placement. We conducts a precise analysis of sandbody connectivity at different levels in seismic scale for Lm733 sandbody of the V oil group in the lower section of the Nm Formation, based on a comprehensive utilization of geological data in oilfield and guided by sequence stratigraphy and seismic sedimentology applying stratigraphic proportional slicing and sandbody edge detection technique. The results indicate that Lm733 sandbody can be classified into two composite channel sandbodies, respectively distributed in the early sequence (SQ1) and late sequence (SQ2). Based on the diverse seismic reflection characteristics, varying thicknesses, and plane distribution features of the interbed, the connectivity between two composite channel sandbodies for SQ1 and SQ2 could be classified into three categories (Type-Ⅰ, Ⅱ, and Ⅲ). According to the seismic attribute variation, including amplitude, waveform, and frequency at the internal boundaries of composite sandbodies, the internal connectivity of composite sandbody in SQ2 can be classified into three categories (Type-1,2, and 3), in conjunction with the existing injection-production well pattern. In this manner, predicting the characterization of sandbody connectivity at various levels in composite channel sandbody at seismic scale can aid in adjusting oilfield development plans.</div></div>","PeriodicalId":18189,"journal":{"name":"Marine and Petroleum Geology","volume":"177 ","pages":"Article 107397"},"PeriodicalIF":3.7,"publicationDate":"2025-04-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143791664","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}
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}
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