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Integrated field characterization and static hydrocarbon reserve estimation of the Penobscot Field, Nova Scotia, Canada 加拿大新斯科舍省Penobscot油田综合油田特征及静态油气储量估算
IF 3.6
Energy Geoscience Pub Date : 2025-08-06 DOI: 10.1016/j.engeos.2025.100448
Ahmed Eleslambouly , Tarek Khalifa , Omar Aldhanhani , Mursal Zeynalli , Ahmed Abdelmaksoud
{"title":"Integrated field characterization and static hydrocarbon reserve estimation of the Penobscot Field, Nova Scotia, Canada","authors":"Ahmed Eleslambouly ,&nbsp;Tarek Khalifa ,&nbsp;Omar Aldhanhani ,&nbsp;Mursal Zeynalli ,&nbsp;Ahmed Abdelmaksoud","doi":"10.1016/j.engeos.2025.100448","DOIUrl":"10.1016/j.engeos.2025.100448","url":null,"abstract":"<div><div>The Penobscot Field, located within the Scotian Basin offshore Nova Scotia, Canada, represents an underexplored hydrocarbon field with potential for future development. Previous studies have been confined to specific reservoir intervals without integrating multiple stratigraphic levels, and a comprehensive static reservoir characterization and volumetric assessment of the Penobscot Field has yet to be undertaken, constraining its full development evaluation. This study presents a comprehensive characterization of the field by integrating geological, geophysical, and petrophysical datasets, leading to static hydrocarbon reserve estimation. The workflow involves seismic interpretation, structural modeling, petrophysical evaluation, and static volumetric calculations. Seismic analysis revealed a structurally complex setting dominated by normal and inverted faults, with reservoir intervals primarily within the Missisauga Formation, which is subdivided into upper, middle, and lower units. Petrophysical evaluation from well logs and core data identified key reservoir properties, including porosity ranging from 12 % to 28 %, permeability spanning from 1 to 1000 mD, and variable water saturations. Stochastic modeling of facies and petrophysical attributes provided insights into lateral and vertical heterogeneity. The Penobscot Field's original oil-in-place ranges from 41.6 × 10<sup>6</sup> m<sup>3</sup> to 109.7 × 10<sup>6</sup> m<sup>3</sup>, with the Middle Missisauga sands presenting the highest reservoir potential. Fault seal analysis indicated predominantly sealing behavior in the shallow sections and semi-permeable conditions at greater depths, suggesting potential lateral migration pathways. The results underscore the field's hydrocarbon potential while emphasizing the significance of structural complexity, facies distribution, and petrophysical variability in reservoir quality, as well as its potential for future development or utilization of similar sand reservoirs for CO<sub>2</sub> storage utilization. This work provides the first fully integrated static reservoir model of the Penobscot Field, offering critical insights for delineating the hydrocarbon reservoirs potential and future production strategies in the Scotian Basin.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100448"},"PeriodicalIF":3.6,"publicationDate":"2025-08-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144830215","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
引用次数: 0
Hydrocarbon source rock potential of the Late Cretaceous sediments in the Asaga–Ohafia Axis, Afikpo Basin, Nigeria: Insights from facies and kerogen analyses 尼日利亚Afikpo盆地Asaga-Ohafia轴晚白垩世沉积物烃源岩潜力:来自相和干酪根分析的见解
IF 3.6
Energy Geoscience Pub Date : 2025-08-06 DOI: 10.1016/j.engeos.2025.100447
Samuel Okechukwu Onyekuru , Timothy Chibuike Anyanwu , Kenneth Okechukwu Nwosu , Ifeyinwa Juliana Ofoh , Francis Begianpuye Akiang , Obinna Chigoziem Akakuru , Onyema Uchenna Achukwu–Ononye , Kalu Kalu Ibe , Godwin Okumagbe Aigbadon
{"title":"Hydrocarbon source rock potential of the Late Cretaceous sediments in the Asaga–Ohafia Axis, Afikpo Basin, Nigeria: Insights from facies and kerogen analyses","authors":"Samuel Okechukwu Onyekuru ,&nbsp;Timothy Chibuike Anyanwu ,&nbsp;Kenneth Okechukwu Nwosu ,&nbsp;Ifeyinwa Juliana Ofoh ,&nbsp;Francis Begianpuye Akiang ,&nbsp;Obinna Chigoziem Akakuru ,&nbsp;Onyema Uchenna Achukwu–Ononye ,&nbsp;Kalu Kalu Ibe ,&nbsp;Godwin Okumagbe Aigbadon","doi":"10.1016/j.engeos.2025.100447","DOIUrl":"10.1016/j.engeos.2025.100447","url":null,"abstract":"<div><div>This study investigated the hydrocarbon source rock potential of the Late Cretaceous Mamu and Nkporo formations in the Asaga–Ohafia Axis, Afikpo Basin, southeastern Nigeria, using integrated facies analysis, organic geochemical and palynofacies data. Five lithofacies were identified: dark grey shale, oolitic limestone, heterolithic mudstone/sandstone, laminated bioturbated sandstone, and calcareous mudstone, indicating estuarine, deltaic, and shallow marine depositional environments. Total organic carbon (<em>TOC</em>) contents range from 1.47 to 2.40 wt%, which reflects moderate to good organic richness. For the Mamu Formation, kerogen composition is dominated by Type II/III, composed of 30 %–50 % amorphous organic matter (<em>AOM</em>), 5 %–10 % liptinite, 30 %–50 % vitrinite, and 10 %–20 % inertinite. Spore coloration and Thermal Alteration Index (<em>TAI</em>: 3–3+) suggest thermal maturity within the oil window (<em>R</em><sub>o</sub>: 0.80 %–1.50 %). In contrast, the Nkporo Formation shows comparable kerogen composition (20 %–45 % <em>AOM</em>, 0–20 % liptinite, and 40 %–65 % vitrinite) but lower maturity (<em>TAI</em>: 2–2+; <em>R</em><sub>o</sub>: 0.45 %–0.80 %). Rock–Eval pyrolysis further supports these findings. The Mamu Formation displays higher Hydrogen Index, favorable <em>T</em><sub>max</sub>, and Production Index values, confirming its maturity and oil and gas–prone potential. Palynological assemblages, including marine dinoflagellate cysts (Mamu Formation) and freshwater algae/fungal spores (Nkporo Formation), align with the inferred depositional settings. Thus, the Mamu Formation is the more prolific source rock, characterized by superior organic quality and thermal maturity.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100447"},"PeriodicalIF":3.6,"publicationDate":"2025-08-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144827549","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
引用次数: 0
Exploring the geochemical, petrographic, and palynological signatures: An analysis of the Mungaroo Formation source rock potential in the Exmouth Plateau, Northern Carnarvon Basin, Australia 地球化学、岩石学和孢粉学特征的探索:澳大利亚北部Carnarvon盆地Exmouth高原Mungaroo组烃源岩潜力分析
IF 3.6
Energy Geoscience Pub Date : 2025-08-05 DOI: 10.1016/j.engeos.2025.100446
Ummi Fayyadhah Binti Haji Talipudin , Mohamed Ragab Shalaby , Amajida Roslim , Md Aminul Islam
{"title":"Exploring the geochemical, petrographic, and palynological signatures: An analysis of the Mungaroo Formation source rock potential in the Exmouth Plateau, Northern Carnarvon Basin, Australia","authors":"Ummi Fayyadhah Binti Haji Talipudin ,&nbsp;Mohamed Ragab Shalaby ,&nbsp;Amajida Roslim ,&nbsp;Md Aminul Islam","doi":"10.1016/j.engeos.2025.100446","DOIUrl":"10.1016/j.engeos.2025.100446","url":null,"abstract":"<div><div>The Late Triassic Mungaroo Formation of the Exmouth Plateau was investigated through an integrated, stratigraphically and geographically extensive study to characterize its source rock potential and depositional controls. Geochemical, petrographic, and palynological analyses reveal highly variable organic richness across the formation, with total organic carbon (<em>TOC</em>) content values ranging from very low in sand-dominated intervals to notably high in coal-bearing mudstones. The Mungaroo Formation exhibits diverse organic composition, with <em>TOC</em> content ranging from 0.63 % to 54.18 %, demonstrating that while certain intervals contain significant organic richness, others are notably lean in organic content. Petrographic analyses reveal the presence of dinoflagellates, liptodetrinite, sporinite, and cutinite, suggesting transitional settings with varying marine influence. Thermal maturity assessments indicate a range of maturity levels, with vitrinite reflectance (<em>R</em><sub>o</sub>) values ranging from 0.45 % to 1.39 %, reflecting thermal maturity of immature to post-mature stage. Rock-Eval pyrolysis parameters support these observations, highlighting varying stages of hydrocarbon generation. Biomarker characteristics further confirm the mixed organic origin and complex paleo-depositional environments within the Mungaroo Formation. The presence of both marine and terrigenous biomarkers underscores the depositional history of the region, with Pristane/Phytane ratios (Pr/Ph) indicating oxidizing environments typically associated with terrigenous plants’ input. Palynological data indicates strong terrigenous influence within both the wells Mercury-1 and Jupiter-1, characterized by proximal delta-plain environments.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100446"},"PeriodicalIF":3.6,"publicationDate":"2025-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144826388","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
引用次数: 0
Mitigating clay swelling and permeability loss in thermal EOR with a quaternary ammonium clay stabilizer under high-temperature low-salinity conditions 在高温低矿化度条件下,用季铵粘土稳定剂减轻热采收率中粘土膨胀和渗透率损失
IF 3.6
Energy Geoscience Pub Date : 2025-07-26 DOI: 10.1016/j.engeos.2025.100444
Aisha Labak, Peyman Pourafshary
{"title":"Mitigating clay swelling and permeability loss in thermal EOR with a quaternary ammonium clay stabilizer under high-temperature low-salinity conditions","authors":"Aisha Labak,&nbsp;Peyman Pourafshary","doi":"10.1016/j.engeos.2025.100444","DOIUrl":"10.1016/j.engeos.2025.100444","url":null,"abstract":"<div><div>Clay swelling and fines migration pose significant challenges to thermally enhanced oil recovery (EOR) operations, particularly in clay-rich formations. This study systematically investigates clay swelling behavior and permeability impairment under high-temperature, low-salinity (HTLS) conditions and evaluates various inhibition methods to mitigate formation damage. To ensure realistic analysis, data and materials from a field with similar issues in Kazakhstan were used. Static/dynamic swelling tests demonstrated that a quaternary ammonium-based inhibitor consistently provided superior clay stabilization through effective ion exchange and surface charge modification mechanisms. In distilled water at 100 °C, inhibitor-treated samples maintained 48.89 % of their original permeability, while untreated samples exhibited severe damage, retaining only 17.05 %. Additionally, this chemical inhibitor significantly lowered the critical salt concentration (CSC), effectively stabilizing clay at 4920 ppm salinity compared to 7380 ppm required without treatment. Scanning electron microscopy (SEM) imaging corroborated these results, revealing that inhibitor-treated clay maintains a compact and coherent structure, in stark contrast to the pronounced swelling, delamination, and structural deterioration observed in untreated clay samples. Nevertheless, this quaternary ammonium-based clay stabilizer presents a robust and promising solution for reducing clay swelling-induced damage, sustaining reservoir permeability, and improving thermal EOR performance in swelling-prone formations.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100444"},"PeriodicalIF":3.6,"publicationDate":"2025-07-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144738431","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
引用次数: 0
Exploring interconnected indicators of energy transition: A global perspective 探索能源转型的相互关联指标:全球视角
IF 3.6
Energy Geoscience Pub Date : 2025-07-26 DOI: 10.1016/j.engeos.2025.100445
Abroon Qazi
{"title":"Exploring interconnected indicators of energy transition: A global perspective","authors":"Abroon Qazi","doi":"10.1016/j.engeos.2025.100445","DOIUrl":"10.1016/j.engeos.2025.100445","url":null,"abstract":"<div><div>This study aims to evaluate the relative importance of the pillars and indicators within the Energy Transition Index (ETI) and their influence on overall ETI performance. Using a dataset from the World Economic Forum's 2024 ETI report, which covers 120 countries, this research applies Bayesian Belief Networks (BBNs), a probabilistic graphical modeling technique suited for analyzing complex interdependencies among variables. Two models are developed: one connecting the ETI to its eight pillars, and another linking it to 22 selected indicators. Findings reveal that the finance and investment pillar has the strongest positive association with ETI scores, whereas innovation is the area with the highest concentration of low-performing countries. Additionally, strong synergies are observed across digital infrastructure readiness and education quality, highlighting opportunities for multi-dimensional policy interventions. The study provides actionable insights for policymakers, such as prioritizing financial instruments, strengthening regulatory frameworks, and enhancing educational and digital infrastructure to accelerate progress in energy transitions.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100445"},"PeriodicalIF":3.6,"publicationDate":"2025-07-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144865114","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
引用次数: 0
Impact of salt dome morphology on geological storage volumetric estimations: Implications for prospect-scale assessment 盐丘形态对地质储层体积估算的影响:对远景规模评估的影响
IF 3.6
Energy Geoscience Pub Date : 2025-07-17 DOI: 10.1016/j.engeos.2025.100443
C. Nur Schuba , Lorena G. Moscardelli , Jonathan P. Schuba
{"title":"Impact of salt dome morphology on geological storage volumetric estimations: Implications for prospect-scale assessment","authors":"C. Nur Schuba ,&nbsp;Lorena G. Moscardelli ,&nbsp;Jonathan P. Schuba","doi":"10.1016/j.engeos.2025.100443","DOIUrl":"10.1016/j.engeos.2025.100443","url":null,"abstract":"<div><div>Geological storage in salt caverns plays a critical role in managing energy resources, yet regional assessments often fall short in accounting for specific salt dome morphological variations that can significantly influence cavern engineering and storage capacity. To address this gap, we developed a refined approach to modeling salt domes, incorporating primary axis tilt, ellipticity, and conic taper. These geometric modifications are applied to a cylindrical baseline salt dome model to assess the effects on total salt volume, workable salt volume, and cavern storage potential. Case studies of four salt domes from the East Texas Salt Basin—Mount Sylvan, Boggy Creek, Steen, and Hainesville—validate the observed trends from the models. Our findings reveal that positive cone taper and primary axis tilt configurations enhance storage potential, leading to significant increases in potential cavern volume, while ellipticity and negative cone taper result in reduced storage capacities. The study underscores the importance of refining volumetric assessments by accounting for detailed morphologic variations, providing a more accurate framework for site-specific geological storage evaluations. Additionally, we discuss challenges related to intra-salt heterogeneities, including intra-salt deformation and mineralogical impurities, highlighting the need for improved site characterization to optimize the safety and efficiency of subsurface storage systems. This work contributes to the development of scalable and reliable geological storage infrastructure, essential for meeting future energy demands.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100443"},"PeriodicalIF":3.6,"publicationDate":"2025-07-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144721918","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
引用次数: 0
Characterizing stratigraphically complex deepwater slope channel reservoirs for production optimization and better field management – A brown field example, offshore West Africa 表征地层复杂的深水斜坡河道储层,以优化生产和更好地管理油田——以西非近海棕色油田为例
Energy Geoscience Pub Date : 2025-07-17 DOI: 10.1016/j.engeos.2025.100438
Ifeanyichukwu S. Obi , John A. Adegoke , Akinsanmi O. Ojo , Chidozie I.P. Dim , Goodluck E. Adagbasa
{"title":"Characterizing stratigraphically complex deepwater slope channel reservoirs for production optimization and better field management – A brown field example, offshore West Africa","authors":"Ifeanyichukwu S. Obi ,&nbsp;John A. Adegoke ,&nbsp;Akinsanmi O. Ojo ,&nbsp;Chidozie I.P. Dim ,&nbsp;Goodluck E. Adagbasa","doi":"10.1016/j.engeos.2025.100438","DOIUrl":"10.1016/j.engeos.2025.100438","url":null,"abstract":"<div><div>The dynamic relationship between field management and reservoir characterization has often been a puzzle, especially in complex deepwater channel systems. Reservoir management and infill drilling success cases were often due to improved understanding of deepwater depositional systems and geological controls on channel architecture and the general distribution of individual rock facies. For confined to weakly-confined slope channel complexes, some controls on the degree of channel avulsion and aggradation are the interplay between flow hydraulics, sediment calibre, depositional gradient, and the interaction of the flow with underlying substrate. This work aims at documenting the stratigraphic characterization of a Miocene deepwater channel system in a brownfield with focus on the historical evolution of the framework interpretation as well as applications of the recent updates in field management. The initial stratigraphic model (2005) was done using the layer cake concept with minimal incision, continuous shales and limited vertical connectivity based on observations from available seismic data (pre-baseline survey acquisition) and limited well control. This was modified in 2009 following acquisition of a 4D Monitor 1 seismic volume and 3 years production data from 20 wells to a more erosive model with compensationally stacked channel complexes of similar width. With new 4D Monitor 2 acquired in 2014, broadband processed seismic data in 2020, a total of 36 wells and 11 years of production, an updated framework has recently been built. In the new framework, two key fairways namely the Upper and the Lower Fairway were delineated, each comprising of 8 and 6 channel complexes, respectively. A conceptual basin-fill sequence was utilized, as well as a genetic classification of the channel complexes into erosional-confined systems, meandering systems, and levee-confined channel systems. The cut-and-fill behaviors of the individual complexes have been tied to changes in depositional gradient, sediment sand vs mud ratio, interaction of the flow with the substrate, and this has impacted the degree of channel amalgamation, avulsion and the degree of preservation of both internal and external levees. At flow unit scale, potential inter, and intra-reservoir connection pathways and compartments defined through integrated use of excess pressures, geobody attributes, well production and 4D data, have been very helpful in defining reservoir connection windows, injector – producer connectivity, and channel compartments. The implication is that this exercise or study has provided renewed insights into infill drill-well opportunities, well production performance as well as overall field management strategy.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100438"},"PeriodicalIF":0.0,"publicationDate":"2025-07-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144695322","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
引用次数: 0
Formation and evolution of thiadiamondoids in petroleum: Evidence from thermochemical sulfate reduction simulation experiments with 1,3-dimethyladamantane 石油中噻二胺类化合物的形成和演化:来自1,3-二甲基金刚烷热化学硫酸盐还原模拟实验的证据
IF 3.6
Energy Geoscience Pub Date : 2025-07-11 DOI: 10.1016/j.engeos.2025.100440
Anlai Ma , Zhaowen Zhan , Cuishan Zhu , Yunpeng Wang , Jinzhong Liu
{"title":"Formation and evolution of thiadiamondoids in petroleum: Evidence from thermochemical sulfate reduction simulation experiments with 1,3-dimethyladamantane","authors":"Anlai Ma ,&nbsp;Zhaowen Zhan ,&nbsp;Cuishan Zhu ,&nbsp;Yunpeng Wang ,&nbsp;Jinzhong Liu","doi":"10.1016/j.engeos.2025.100440","DOIUrl":"10.1016/j.engeos.2025.100440","url":null,"abstract":"<div><div>Thiadiamondoids (TDs) have recently attracted increasing attention as molecular proxies for thermochemical sulfate reduction (TSR) reactions in reservoirs. However, their formation mechanisms, as well as the generation and evolution processes, remain poorly understood. In this study, simulation experiments with a duration of 160 h were conducted on the model compound 1,3-dimethyladamantane (1,3-DMA) using the CaSO<sub>4</sub>, MgSO<sub>4</sub>, and elemental S systems, with measurements at the 10th, 20th, 40th, 80th and 160th hours during the simulation process being presented. The results indicate that at the end of simulation, the MgSO<sub>4</sub> system exhibited the lowest residual amounts of 1,3-DMA, suggesting the highest degree of TSR. Four types of non-hydrocarbon compounds with adamantane structures were detected in the liquid products in the three experiment systems: adamantanones, adamantanols, adamantanethiols (ATs), and thiaadamantanes (TAs). Among these, adamantanones exhibited the highest concentrations in the three simulation systems. In addition, TAs were dominated by C<sub>3</sub>-TAs in the CaSO<sub>4</sub> and MgSO<sub>4</sub> systems and by C<sub>2</sub>-TAs in the elemental S system. The simulation experiments revealed a strong correlation between the concentrations of TAs and adamantanones, suggesting that adamantanones might be the intermediates for TAs. Combined with the synthesis mechanism of TAs from thiaadamamantane-4,8-dione, TDs might have two different genetic mechanisms: (a) low temperature cationic carbon ion rearrangement from diagenesis to early catagenesis stage, and (b) a free sulfur radical mechanism in high-temperature TSR process during middle-late catagenesis. TAs exhibited different generation and evolution processes across different experiment systems. Notably, the MgSO<sub>4</sub> system revealed that TAs undergo generation, accumulation, and destruction process, corresponding to Easy%<em>R</em><sub>o</sub> values of 0.89 %–0.98 %, 0.98 %–1.21 %, and &gt;1.21 %, respectively. Among these three simulation systems, dibenzothiophenes (DBTs) concentrations consistently trended upwards, indicating TAs have lower thermal stability than DBTs.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 3","pages":"Article 100440"},"PeriodicalIF":3.6,"publicationDate":"2025-07-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144721501","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
引用次数: 0
Quantitative recognition and petroleum geological significance of interlayers in coastal sandstone reservoirs: A case study from the Donghe Sandstone in the Hade Oilfield, Tarim Basin, NW China 滨海砂岩储层间层定量识别及其石油地质意义——以塔里木盆地哈德油田东河砂岩为例
IF 3.6
Energy Geoscience Pub Date : 2025-07-10 DOI: 10.1016/j.engeos.2025.100439
Rui Yuan , Chenlong Lu , An Zhao , Wei Wang , Zhiwei Wu , Zijin Yan , Qi Sun
{"title":"Quantitative recognition and petroleum geological significance of interlayers in coastal sandstone reservoirs: A case study from the Donghe Sandstone in the Hade Oilfield, Tarim Basin, NW China","authors":"Rui Yuan ,&nbsp;Chenlong Lu ,&nbsp;An Zhao ,&nbsp;Wei Wang ,&nbsp;Zhiwei Wu ,&nbsp;Zijin Yan ,&nbsp;Qi Sun","doi":"10.1016/j.engeos.2025.100439","DOIUrl":"10.1016/j.engeos.2025.100439","url":null,"abstract":"<div><div>Buried coastal sandstones would be of high-quality hydrocarbon reservoirs. Controlled by deposition and diagenesis, coastal sandstones mixed with muddy and calcareous materials are usually low in porosity and permeability and small in layer thickness. These impermeable interlayers act as baffles and barriers between flow units and are crucial in hydrocarbon development. Donghe Sandstone in the Hade Oilfield of Tarim Basin, NW China, belongs to coastal clastic reservoirs of high oil productivity. Following nearly 30 years of development, the distribution of remaining hydrocarbon resources is affected by the muddy, calcareous, and marlaceous interlayers. Taking the Donghe Sandstone as an example, a quantitative recognition method of interlayers in coastal sandstone reservoirs is proposed in this paper. Based on cores from 26 wells, the sensitive conventional log curves of different interlayers, namely the natural gamma-ray (GR), density (DEN), compensated neutron (CNL), and acoustic (AC), are extracted by the Extreme Gradient Boosting (XGBoost). Multi-mineral model (MMM) is used to calculate continuous curves for muddy, sandy, and calcareous contents by the mentioned sensitive logs. A set of quantitative standard system is established for identifying muddy, calcareous, and marlaceous interlayers based on their respective contents. The types of interlayers are identified across all vertical wells. The interlayers exhibit lateral continuity at the top of each bed-set. Interlayers are currently more developed in the slope region than in the coastal region. Muddy and marlaceous interlayers are more developed at high relative sea-level, while calcareous interlayers are more developed at low relative sea-level. The extended interlayers at the top of BS6 lead to two different oil-water contacts in the Donghe Sandstone. The proposed quantitative recognition method for interlayers provides valuable insights into the exploitation potential of petroleum systems in the Donghe Sandstone of the Hade Oilfield. The flexible and easy-to-use method can be applied to other marine sandstone reservoirs or similar formations.</div></div>","PeriodicalId":100469,"journal":{"name":"Energy Geoscience","volume":"6 4","pages":"Article 100439"},"PeriodicalIF":3.6,"publicationDate":"2025-07-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145157947","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
引用次数: 0
Sequence stratigraphic and sedimentary evolution of the Cambrian Xiannüdong Formation in the north central Sichuan Basin, SW China 四川盆地中北部寒武系咸安<e:1>组层序地层及沉积演化
Energy Geoscience Pub Date : 2025-07-10 DOI: 10.1016/j.engeos.2025.100442
Zhuangzhuang Bai, Shuyuan Shi, Wei Yang, Wuren Xie, Shiyu Ma, Saijun Wu, Wenzheng Li, Wenliang Shang
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