Sebastian Amberg, Ralf Littke, Rüdiger Lutz, Peter Klitzke, Victoria Sachse
This study presents the results of a 2D numerical basin and petroleum systems model of the Olga Basin in the NW Barents Sea offshore northern Norway, a frontier exploration area in which there are abundant seafloor oil and gas seepages. The effects of Pleistocene ice sheet advances on rock properties and subsurface fluid migration in this area, and on seafloor hydrocarbon seepage, are not well understood. The 2D numerical model takes account of recurrent ice advances and retreats, together with related erosional and temperature effects, and investigates the influence of these parameters on fluid migration. Model results show that Pleistocene glaciations reduced the temperature in the sedimentary succession in the Olga Basin by up to 20 °C, for example in the uppermost Cretaceous and Jurassic sediments which underlie the seafloor down to a depth of 0.5 to 1 km. The decrease in temperature was in general predominantly related to the intensity of glacial erosion, which was set in this study to a depth of 600 m based on previous studies. Hydrocarbon fluids expelled from potential thermogenic source rocks of Carboniferous to Triassic ages on the SW margin of the Olga Basin migrated to the seafloor through permeable carrier beds. However, fluid migration to the surface in the NE of the study area took place along fault conduits. In a closed fault model scenario, only 0.3 Mt of hydrocarbons are modelled to have migrated along the 0.5 km wide model section; in a second scenario with partially open faults, about 22 Mt of hydrocarbons, representing about 11% of the total hydrocarbons generated by potential thermogenic source rocks in the study area, were lost to the surface during the Pleistocene. The potential for microbial methane generation in the Olga Basin was limited both during the Pleistocene and at the present day due to the significant reduction in temperature during glacial episodes, and due to the intense glacial-related erosion of the Mesozoic to Cenozoic stratigraphy. During glacial stages, the gas hydrate stability zone beneath the ice sheet is modelled to have extended to a depth of up to 900 m for a pure methane composition, and to a depth of up to 1100 m for a possible thermogenic-sourced mixed gas composition of 90% methane, 7% propane and 3% ethane. Gas hydrates with this mixed composition are modelled to have been stable in the Olga Basin during the last three glacial advances and into the present. These modelling results provide an insight into the key factors controlling the migration and surface leakage of hydrocarbon fluids in the Olga Basin region, and into the effects of glaciations on rock properties in a glaciated basin.
{"title":"INFLUENCE OF PLEISTOCENE GLACIATION ON PETROLEUM SYSTEMS AND GAS HYDRATE STABILITY IN THE OLGA BASIN REGION, BARENTS SEA","authors":"Sebastian Amberg, Ralf Littke, Rüdiger Lutz, Peter Klitzke, Victoria Sachse","doi":"10.1111/jpg.12856","DOIUrl":"https://doi.org/10.1111/jpg.12856","url":null,"abstract":"<div>\u0000 <p>This study presents the results of a 2D numerical basin and petroleum systems model of the Olga Basin in the NW Barents Sea offshore northern Norway, a frontier exploration area in which there are abundant seafloor oil and gas seepages. The effects of Pleistocene ice sheet advances on rock properties and subsurface fluid migration in this area, and on seafloor hydrocarbon seepage, are not well understood. The 2D numerical model takes account of recurrent ice advances and retreats, together with related erosional and temperature effects, and investigates the influence of these parameters on fluid migration. Model results show that Pleistocene glaciations reduced the temperature in the sedimentary succession in the Olga Basin by up to 20 °C, for example in the uppermost Cretaceous and Jurassic sediments which underlie the seafloor down to a depth of 0.5 to 1 km. The decrease in temperature was in general predominantly related to the intensity of glacial erosion, which was set in this study to a depth of 600 m based on previous studies. Hydrocarbon fluids expelled from potential thermogenic source rocks of Carboniferous to Triassic ages on the SW margin of the Olga Basin migrated to the seafloor through permeable carrier beds. However, fluid migration to the surface in the NE of the study area took place along fault conduits. In a closed fault model scenario, only 0.3 Mt of hydrocarbons are modelled to have migrated along the 0.5 km wide model section; in a second scenario with partially open faults, about 22 Mt of hydrocarbons, representing about 11% of the total hydrocarbons generated by potential thermogenic source rocks in the study area, were lost to the surface during the Pleistocene. The potential for microbial methane generation in the Olga Basin was limited both during the Pleistocene and at the present day due to the significant reduction in temperature during glacial episodes, and due to the intense glacial-related erosion of the Mesozoic to Cenozoic stratigraphy. During glacial stages, the gas hydrate stability zone beneath the ice sheet is modelled to have extended to a depth of up to 900 m for a pure methane composition, and to a depth of up to 1100 m for a possible thermogenic-sourced mixed gas composition of 90% methane, 7% propane and 3% ethane. Gas hydrates with this mixed composition are modelled to have been stable in the Olga Basin during the last three glacial advances and into the present. These modelling results provide an insight into the key factors controlling the migration and surface leakage of hydrocarbon fluids in the Olga Basin region, and into the effects of glaciations on rock properties in a glaciated basin.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 2","pages":"191-214"},"PeriodicalIF":1.8,"publicationDate":"2024-04-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://onlinelibrary.wiley.com/doi/epdf/10.1111/jpg.12856","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140556188","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Petroleum accumulations may coincide with either positive or negative temperature anomalies, which are conventionally detected using in situ temperature measurements made in shallow boreholes 1-3 m deep. Data gathered in this way, however, can be sparse and costly, and may require intensive fieldwork over a long time period. This article explores the possibility of detecting thermal anomalies associated with petroleum entrapment using satellite-derived land surface temperature data. For this aim, a robust correction scheme based on a physically-based land surface model was applied to night-time kinetic temperature data derived from NASA's ASTER instrument. The numerical model, known as SKinTES, attempts to simulate diurnal effects and to remove them from the measured temperature data to yield a residual temperature anomaly map. The performance of this methodology was tested over the Alborz oilfield located on an anticline of the same name in the Qom region of Central Iran. The study area has an arid to semi-arid climate and the surface geology is dominated by outcrops of the Lower Miocene Upper Red Formation. The modelling approach used successfully highlighted several negative temperature anomalies over the oil-bearing parts of the Alborz structure. In comparison to the uncorrected data, the anomalies were shown to be highly enhanced in both spatial and magnitude terms. In addition, time series analysis indicated that the temperature anomalies were consistent over time. The authenticity of the anomalies was confirmed by a suite of in situ temperature measurements made at shallow boreholes. In conclusion, a unifying framework is proposed to explain the occurrence of both negative and positive temperature anomalies over petroleum accumulations. The new modelling and correction scheme is expected to broaden the application of remote sensing land surface temperature data not only in petroleum exploration but also in other types of geothermic investigations including geothermal exploration.
石油积聚可能与正或负的温度异常现象相吻合，这种异常现象通常是通过在 1-3 米深的浅钻孔中进行现场温度测量来探测的。然而，这种方法收集的数据稀少且成本高昂，可能需要长时间密集的实地考察。本文探讨了利用卫星获得的地表温度数据探测与石油截留相关的热异常的可能性。为此，对 NASA 的 ASTER 仪器获取的夜间动能温度数据采用了基于物理地表模型的稳健校正方案。该数值模型被称为 SKinTES，试图模拟昼夜效应，并将其从测得的温度数据中去除，从而得出残余温度异常图。该方法的性能在位于伊朗中部库姆地区同名反斜线上的阿尔博兹油田进行了测试。研究区域属于干旱至半干旱气候，地表地质主要是下中新世上红岩层的露头。所使用的建模方法成功地突出了阿尔伯兹构造含油部分的几个负温度异常点。与未经校正的数据相比，这些异常现象在空间和幅度上都得到了极大的增强。此外，时间序列分析表明，温度异常在时间上是一致的。在浅层钻孔进行的一系列现场温度测量证实了异常的真实性。总之，提出了一个统一的框架来解释石油积聚区出现的正负温度异常。新的建模和校正方案有望拓宽遥感地表温度数据的应用范围，不仅用于石油勘探，还可用于其他类型的地热调查，包括地热勘探。
{"title":"REMOTE SENSING ANALYSIS AND NUMERICAL MODELLING OF SURFACE TEMPERATURE ANOMALIES OVER PETROLEUM ACCUMULATIONS: A CASE STUDY OF THE ALBORZ OILFIELD, CENTRAL IRAN","authors":"Saeid Asadzadeh, Carlos Roberto de Souza Filho","doi":"10.1111/jpg.12857","DOIUrl":"https://doi.org/10.1111/jpg.12857","url":null,"abstract":"<p>Petroleum accumulations may coincide with either positive or negative temperature anomalies, which are conventionally detected using in situ temperature measurements made in shallow boreholes 1-3 m deep. Data gathered in this way, however, can be sparse and costly, and may require intensive fieldwork over a long time period. This article explores the possibility of detecting thermal anomalies associated with petroleum entrapment using satellite-derived land surface temperature data. For this aim, a robust correction scheme based on a physically-based land surface model was applied to night-time kinetic temperature data derived from NASA's ASTER instrument. The numerical model, known as SKinTES, attempts to simulate diurnal effects and to remove them from the measured temperature data to yield a residual temperature anomaly map. The performance of this methodology was tested over the Alborz oilfield located on an anticline of the same name in the Qom region of Central Iran. The study area has an arid to semi-arid climate and the surface geology is dominated by outcrops of the Lower Miocene Upper Red Formation. The modelling approach used successfully highlighted several negative temperature anomalies over the oil-bearing parts of the Alborz structure. In comparison to the uncorrected data, the anomalies were shown to be highly enhanced in both spatial and magnitude terms. In addition, time series analysis indicated that the temperature anomalies were consistent over time. The authenticity of the anomalies was confirmed by a suite of in situ temperature measurements made at shallow boreholes. In conclusion, a unifying framework is proposed to explain the occurrence of both negative and positive temperature anomalies over petroleum accumulations. The new modelling and correction scheme is expected to broaden the application of remote sensing land surface temperature data not only in petroleum exploration but also in other types of geothermic investigations including geothermal exploration.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 2","pages":"215-230"},"PeriodicalIF":1.8,"publicationDate":"2024-04-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140556287","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Oilfield production is controlled by a wide range of geological and engineering parameters, many of which are at least partially interrelated. This paper uses multivariate statistical methods (principal component analysis, regression analysis and analysis of variance) to determine how these parameters are related, and which of them are most significant in controlling and predicting oilfield performance. The analysis is based on a database of publicly available oilfield data from the United Kingdom Continental Shelf (UKCS), from which a series of geological, engineering and fluid-related control variables from 136 fields were pre-processed and analyzed. This dataset is a subset of a much wider project database for UKCS oil, gas and condensate fields. For this study, the project database was divided into two datasets: a first dataset with 10 parameters from 136 fields, and a second, more detailed dataset with 27 parameters from 38 fields. Both datasets were analysed using principal component analysis in order to investigate possible correlations between numerically/statistically interrogable predictor variables such as porosity, permeability, number of production wells, gas-oil ratio and reservoir temperature. A regression analysis was then carried out on the predictor variables in order to obtain a ranking of predictability (i.e. how indicative a predictor is of a particular outcome) and sensitivity (how sensitive an outcome is to slight changes in a predictor) in relation to recovery factor based on R-squared and regression coefficient values. The results showed that key variables from the principal component analysis included field size, number of production wells, PVT, gross depositional environment and reservoir quality. High-ranking parameters of predictability and sensitivity from the regression analysis were found to include API, net-to-gross, porosity and reservoir depth. These results are consistent with previous studies and suggest that it should be possible to forecast oilfield recovery based on only a few selected input variables. As a preliminary test of forecasting ability of the variable permutations put forward, a best-subsets multiple regression was carried out using a statistical software package and yielded results which corroborated the main findings.
{"title":"A STATISTICAL ANALYSIS OF GEOLOGICAL AND ENGINEERING PREDICTORS OF OILFIELD PERFORMANCE RESPONSE: A CASE STUDY OF OILFIELDS ON THE UK CONTINENTAL SHELF","authors":"Ukari Osah, John Howell","doi":"10.1111/jpg.12855","DOIUrl":"https://doi.org/10.1111/jpg.12855","url":null,"abstract":"<div>\u0000 <p>Oilfield production is controlled by a wide range of geological and engineering parameters, many of which are at least partially interrelated. This paper uses multivariate statistical methods (principal component analysis, regression analysis and analysis of variance) to determine how these parameters are related, and which of them are most significant in controlling and predicting oilfield performance. The analysis is based on a database of publicly available oilfield data from the United Kingdom Continental Shelf (UKCS), from which a series of geological, engineering and fluid-related control variables from 136 fields were pre-processed and analyzed. This dataset is a subset of a much wider project database for UKCS oil, gas and condensate fields. For this study, the project database was divided into two datasets: a first dataset with 10 parameters from 136 fields, and a second, more detailed dataset with 27 parameters from 38 fields. Both datasets were analysed using principal component analysis in order to investigate possible correlations between numerically/statistically interrogable predictor variables such as porosity, permeability, number of production wells, gas-oil ratio and reservoir temperature. A regression analysis was then carried out on the predictor variables in order to obtain a ranking of predictability (i.e. how indicative a predictor is of a particular outcome) and sensitivity (how sensitive an outcome is to slight changes in a predictor) in relation to recovery factor based on R-squared and regression coefficient values. The results showed that key variables from the principal component analysis included field size, number of production wells, PVT, gross depositional environment and reservoir quality. High-ranking parameters of predictability and sensitivity from the regression analysis were found to include API, net-to-gross, porosity and reservoir depth. These results are consistent with previous studies and suggest that it should be possible to forecast oilfield recovery based on only a few selected input variables. As a preliminary test of forecasting ability of the variable permutations put forward, a best-subsets multiple regression was carried out using a statistical software package and yielded results which corroborated the main findings.</p></div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 2","pages":"173-190"},"PeriodicalIF":1.8,"publicationDate":"2024-04-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://onlinelibrary.wiley.com/doi/epdf/10.1111/jpg.12855","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140556311","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Juan A. Pineda, Marcos Comerio, Eduardo G. Ottone, Joaquín Salduondo, Gastón Otegui, Georgina Erra
This study presents an integrated investigation of the Upper Triassic Potrerillos – Cacheuta lacustrine source rock in the Cuyo Basin of western Argentina. Data came from palynofacies analyses, organic petrography, Rock-Eval pyrolysis and mineralogical studies based on X-ray diffraction analyses. An 80 m thick outcrop section was studied and is interpreted to represent the transition from shallow-lacustrine sediments influenced by fluvial discharges (uppermost Potrerillos Formation) to the deposits of a deep, permanent lake (Cacheuta Formation). Three palynofacies were defined. Palynofacies I is characterized by shallowing-upward cycles with abundant woody material, and was deposited under an oxic, disturbed water column. Palynofacies II and III occur in laminated shales rich in amorphous organic matter (AOM) and freshwater algal material (Botryococcus) respectively, which were deposited under oxygen-depleted conditions. In general, the detrital material present suggests an input derived from fluvial discharges; however, interbedded tuffs altered to analcime and smectite suggest the transformation of vitric material in pyroclastic ash under saline to alkaline water conditions. Kerogen Types II/III and III with high total organic carbon values indicate a moderate oil- and gas-prone source rock whose thermal maturity varies from immature to the early oil window (Tmax: 430-438 °C; vitrinite reflectance: 0.59-0.67 % VRo; and thermal alteration index: 2-2+).
This study demonstrates the importance of palynofacies analyses for the interpretation of depositional changes and associated controls in lacustrine shale successions. When integrated with data from organic geochemistry, palynofacies analysis is an important tool in the evaluation of a source rock's thermal maturity and hydrocarbon generation potential.
本研究介绍了对阿根廷西部库约盆地上三叠统波特里略斯-卡丘塔湖沼源岩的综合调查。数据来自于古生界分析、有机岩石学、Rock-Eval 热解和基于 X 射线衍射分析的矿物学研究。对一个 80 米厚的露头断面进行了研究，该断面被解释为代表从受河流排放影响的浅湖积沉积物（最上层的波特里略斯地层）向永久性深湖沉积物（卡丘塔地层）的过渡。共界定了三种古生界。第 I 组古生界的特点是由浅入深的上升循环，含有丰富的木质物质，沉积于缺氧、受干扰的水体中。第二和第三古生界分别出现在富含无定形有机质（AOM）和淡水藻类（Botryococcus）的层状页岩中，沉积于缺氧条件下。一般来说，存在的碎屑物质表明其来源于河水排放；然而，层间凝灰岩蚀变为安山岩和闪长岩表明，在盐碱水条件下，火山碎屑灰中的矾质物质发生了转变。具有高总有机碳值的Ⅱ/Ⅲ类和Ⅲ类岩浆源表明这是一种中等油气易生源岩，其热成熟度从未成熟到早期石油窗口不等（最高温度：430-438 °C；矾土反射率：0.59-0.67 % VR）：0.59-0.67%；热蚀变指数：2-2+）：2-2+).
{"title":"PALYNOFACIES AND ORGANIC GEOCHEMISTRY OF LACUSTRINE SOURCE ROCKS: THE POTRERILLOS – CACHEUTA SOURCE ROCK SYSTEM IN THE TRIASSIC CUYO BASIN, WEST-CENTRAL ARGENTINA","authors":"Juan A. Pineda, Marcos Comerio, Eduardo G. Ottone, Joaquín Salduondo, Gastón Otegui, Georgina Erra","doi":"10.1111/jpg.12851","DOIUrl":"10.1111/jpg.12851","url":null,"abstract":"<p>This study presents an integrated investigation of the Upper Triassic Potrerillos – Cacheuta lacustrine source rock in the Cuyo Basin of western Argentina. Data came from palynofacies analyses, organic petrography, Rock-Eval pyrolysis and mineralogical studies based on X-ray diffraction analyses. An 80 m thick outcrop section was studied and is interpreted to represent the transition from shallow-lacustrine sediments influenced by fluvial discharges (uppermost Potrerillos Formation) to the deposits of a deep, permanent lake (Cacheuta Formation). Three palynofacies were defined. Palynofacies I is characterized by shallowing-upward cycles with abundant woody material, and was deposited under an oxic, disturbed water column. Palynofacies II and III occur in laminated shales rich in amorphous organic matter (AOM) and freshwater algal material (Botryococcus) respectively, which were deposited under oxygen-depleted conditions. In general, the detrital material present suggests an input derived from fluvial discharges; however, interbedded tuffs altered to analcime and smectite suggest the transformation of vitric material in pyroclastic ash under saline to alkaline water conditions. Kerogen Types II/III and III with high total organic carbon values indicate a moderate oil- and gas-prone source rock whose thermal maturity varies from immature to the early oil window (T<sub>max</sub>: 430-438 °C; vitrinite reflectance: 0.59-0.67 % VR<sub>o</sub>; and thermal alteration index: 2-2<sup>+</sup>).</p><p>This study demonstrates the importance of palynofacies analyses for the interpretation of depositional changes and associated controls in lacustrine shale successions. When integrated with data from organic geochemistry, palynofacies analysis is an important tool in the evaluation of a source rock's thermal maturity and hydrocarbon generation potential.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 1","pages":"75-99"},"PeriodicalIF":1.8,"publicationDate":"2023-12-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139071976","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Jaume Vergés, Giulio Casini, Jonas Ruh, John Cosgrove, Shahram Sherkati, Mahdi Najafi, Emilio Casciello, Eduard Saura, Iraj Abdollahie Fard, Alireza Piryaei, Dominique Frizon de Lamotte, Jean Letouzey, Hasan Goodarzi, Bahman Soleimany, Salman Jahani
The Zagros foldbelt – foreland system in SW Iran is a prolific hydrocarbon province with known reserves of more than 90 billion brl of oil and 800 TCF of natural gas. Establishing the structural style of folding in the Zagros area presents a major challenge due both to the geographical extent of the foldbelt, which is some 1600 km long in total, and the presence of marked lateral variations in fold style related to the complex regional tectonic history. In addition, while numerous high-quality structural studies of the Zagros have been completed over the last 20 years, they support a variety of different interpretations and are therefore $$difficult to synthesize. In this paper, we review the general structural style of the Zagros fold-and-thrust belt in SW Iran, and in particular the style of folding in the Lurestan arc, Dezful embayment, Izeh Zone and Fars arc. We summarise relationships between folding in these areas and fracture development, and investigate the timing of folding and the interaction between NW-SE oriented “Zagros” folds and north-south oriented “Arabian” folds. Finally, we briefly assess the implications of fold style for petroleum systems in the Zagros area. Although no new data are presented in this paper, a series of unpublished maps are used to illustrate the main results and include: a map showing the extent of the main detachment levels across the Lurestan, Dezful and Fars structural domains; two palaeotectonic maps (for Late Cretaceous – Paleocene and Miocene – Pliocene times, respectively), showing the position of the deformation fronts of the Zagros and the North Oman thrust systems and their potential spatial and temporal relationship with folding; and a set of four maps showing the distribution of reservoir rocks which are grouped by age into the Permian – Triassic Dehram Group, the Late Jurassic – Early Cretaceous Khami Group, the Late Cretaceous Bangestan Group, and the Oligocene – Miocene Asmari Formation. In addition, for the Lurestan, Dezful and Fars structural domains, a series of regional cross-sections at the same scale are presented and discussed.
Most of the data in this review paper were acquired in order to gain an improved understanding of the petroleum systems in the Zagros area; however the data are used here to investigate a range of interacting processes including tectonics, sediment deposition and subsurface fluid flow in the development of the fold-and-thrust belt and its associated foreland basins. The resulting synthesis is intended to provice a starting point for future tectonostratigraphic and hydrocarbon-related studies which will make use of both existing and new multidisciplinary techniques to constrain the results. The knowledge acquired and the techniques used will be of benefit in future challenges including the identification of subsurface reservoirs suitable for the permanent storage of CO2 to mitigate the effects of climate change.
{"title":"STRUCTURAL STYLE AND TIMING OF NW-SE TRENDING ZAGROS FOLDS IN SW IRAN: INTERACTION WITH NORTH-SOUTH TRENDING ARABIAN FOLDS AND IMPLICATIONS FOR PETROLEUM GEOLOGY","authors":"Jaume Vergés, Giulio Casini, Jonas Ruh, John Cosgrove, Shahram Sherkati, Mahdi Najafi, Emilio Casciello, Eduard Saura, Iraj Abdollahie Fard, Alireza Piryaei, Dominique Frizon de Lamotte, Jean Letouzey, Hasan Goodarzi, Bahman Soleimany, Salman Jahani","doi":"10.1111/jpg.12850","DOIUrl":"10.1111/jpg.12850","url":null,"abstract":"<div>\u0000 <p>The Zagros foldbelt – foreland system in SW Iran is a prolific hydrocarbon province with known reserves of more than 90 billion brl of oil and 800 TCF of natural gas. Establishing the structural style of folding in the Zagros area presents a major challenge due both to the geographical extent of the foldbelt, which is some 1600 km long in total, and the presence of marked lateral variations in fold style related to the complex regional tectonic history. In addition, while numerous high-quality structural studies of the Zagros have been completed over the last 20 years, they support a variety of different interpretations and are therefore $$difficult to synthesize. In this paper, we review the general structural style of the Zagros fold-and-thrust belt in SW Iran, and in particular the style of folding in the Lurestan arc, Dezful embayment, Izeh Zone and Fars arc. We summarise relationships between folding in these areas and fracture development, and investigate the timing of folding and the interaction between NW-SE oriented “Zagros” folds and north-south oriented “Arabian” folds. Finally, we briefly assess the implications of fold style for petroleum systems in the Zagros area. Although no new data are presented in this paper, a series of unpublished maps are used to illustrate the main results and include: a map showing the extent of the main detachment levels across the Lurestan, Dezful and Fars structural domains; two palaeotectonic maps (for Late Cretaceous – Paleocene and Miocene – Pliocene times, respectively), showing the position of the deformation fronts of the Zagros and the North Oman thrust systems and their potential spatial and temporal relationship with folding; and a set of four maps showing the distribution of reservoir rocks which are grouped by age into the Permian – Triassic Dehram Group, the Late Jurassic – Early Cretaceous Khami Group, the Late Cretaceous Bangestan Group, and the Oligocene – Miocene Asmari Formation. In addition, for the Lurestan, Dezful and Fars structural domains, a series of regional cross-sections at the same scale are presented and discussed.</p>\u0000 <p>Most of the data in this review paper were acquired in order to gain an improved understanding of the petroleum systems in the Zagros area; however the data are used here to investigate a range of interacting processes including tectonics, sediment deposition and subsurface fluid flow in the development of the fold-and-thrust belt and its associated foreland basins. The resulting synthesis is intended to provice a starting point for future tectonostratigraphic and hydrocarbon-related studies which will make use of both existing and new multidisciplinary techniques to constrain the results. The knowledge acquired and the techniques used will be of benefit in future challenges including the identification of subsurface reservoirs suitable for the permanent storage of CO<sub>2</sub> to mitigate the effects of climate change.</p","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 1","pages":"3-74"},"PeriodicalIF":1.8,"publicationDate":"2023-12-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://onlinelibrary.wiley.com/doi/epdf/10.1111/jpg.12850","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139066722","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The production of petroleum substances has a long historical tradition in Iran. Glance (1970) reported that the “first man-made oil well was dug” in the ancient city of Susa (present-day Shush), about 40 km northwest of Ahwaz, in 500 BC during the reign of the Achaemenid emperor Darius I. Writing in the fifth century BC, Herodotus described petroleum production near a place called Ardericca, probably present-day Masjed Soleyman, located 210 furlongs from Susa (Lees, 1950). The petroleum substances produced included bitumen which was used in construction and the waterproofing of ships. Sorkhabi (2005) detailed the petroleum history in Iran during ancient and medieval times.
The modern quest for oil in Iran dates from the second half of the 19th century. From a historical perspective, this modern period can be divided into six distinct phases: (i) The early years, 1872–1900; (ii) The Anglo-Persian years, 1901–1932; (iii) The Anglo-Iranian Years and Nationalization, 1933–1953; (iv) The second Pahlavi years, 1954–1978 including the rise of OPEC; (v) The Islamic Revolution and Iran-Iraq War, 1979–1989; and (vi) Buyback Contracts and US Sanctions, 1990–Present. The search for oil was singularly unsuccessful during the first of these phases and the early years of the second phase. However, after a difficult six-year exploration campaign, oil in commercial quantities was struck in the early hours of 26 May, 1908 at Maidan-e Naftun, which in later years achieved world fame as the Masjed Soleyman oil field. Since then, more than 120 oil and gas field discoveries have been made in Iran's onshore areas and its territorial waters in the Persian Gulf.
The story of oil has always been an emotive and politically charged issue in Iran and has been the focus of great national interest and debate for over a century. Certainly, the discovery in 1908 marked a milestone in Iran's 20th century history: it ushered in a new era – an era not only of progress and prosperity, but also of social and political upheaval and turmoil that has not yet ended (Ala, 2007). In this paper, important events in each of the historical phases identified above are briefly reviewed. Emphasis is placed on the emergence of the modern petroleum industry in Iran, and the early phases are covered in particular detail.
{"title":"THE MODERN OIL INDUSTRY IN IRAN: A HISTORICAL PERSPECTIVE AND REVIEW","authors":"Mike Ala, Rasoul Sorkhabi","doi":"10.1111/jpg.12852","DOIUrl":"10.1111/jpg.12852","url":null,"abstract":"<p>The production of petroleum substances has a long historical tradition in Iran. Glance (1970) reported that the “first man-made oil well was dug” in the ancient city of Susa (present-day Shush), about 40 km northwest of Ahwaz, in 500 BC during the reign of the Achaemenid emperor Darius I. Writing in the fifth century BC, Herodotus described petroleum production near a place called Ardericca, probably present-day Masjed Soleyman, located 210 furlongs from Susa (Lees, 1950). The petroleum substances produced included bitumen which was used in construction and the waterproofing of ships. Sorkhabi (2005) detailed the petroleum history in Iran during ancient and medieval times.</p><p>The modern quest for oil in Iran dates from the second half of the 19th century. From a historical perspective, this modern period can be divided into six distinct phases: (i) The early years, 1872–1900; (ii) The Anglo-Persian years, 1901–1932; (iii) The Anglo-Iranian Years and Nationalization, 1933–1953; (iv) The second Pahlavi years, 1954–1978 including the rise of OPEC; (v) The Islamic Revolution and Iran-Iraq War, 1979–1989; and (vi) Buyback Contracts and US Sanctions, 1990–Present. The search for oil was singularly unsuccessful during the first of these phases and the early years of the second phase. However, after a difficult six-year exploration campaign, oil in commercial quantities was struck in the early hours of 26 May, 1908 at Maidan-e Naftun, which in later years achieved world fame as the Masjed Soleyman oil field. Since then, more than 120 oil and gas field discoveries have been made in Iran's onshore areas and its territorial waters in the Persian Gulf.</p><p>The story of oil has always been an emotive and politically charged issue in Iran and has been the focus of great national interest and debate for over a century. Certainly, the discovery in 1908 marked a milestone in Iran's 20th century history: it ushered in a new era – an era not only of progress and prosperity, but also of social and political upheaval and turmoil that has not yet ended (Ala, 2007). In this paper, important events in each of the historical phases identified above are briefly reviewed. Emphasis is placed on the emergence of the modern petroleum industry in Iran, and the early phases are covered in particular detail.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 1","pages":"101-119"},"PeriodicalIF":1.8,"publicationDate":"2023-12-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139067117","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Dominic P. Strogen, John E. A. Marshall, Andrew G. Whitham, Steven D. Andrews
A number of exhumed hydrocarbon traps have been described from the Traill Ø region of East Greenland. This study focuses on the Bjørnedal area where the distribution of bitumen has been mapped out. Bitumen staining clearly has a cross-cutting relationship to stratigraphic units and can be shown to form distinct palaeo-accumulations. Detailed petrographic studies show that bitumen occurs as late diagenetic phases in Middle to Late Jurassic sandstones, and is present both as both grain-coating and pore-filling phases. Geochemical analyses confirm that the bitumen is organic in composition and is composed largely of carbon and hydrogen. Both H/C ratios and bonds identified by FTIR behave as expected with increasing maturity measured using bitumen reflectance. Together, these results provide strong evidence that the material is pyrobitumen derived from the in situ thermal degradation of a liquid hydrocarbon precursor. On the basis of textures in transmitted and reflected light and quantitative bitumen reflectance distributions, two populations of pyrobitumen may be recognised in some samples.
Two phases of Paleogene magmatism occurred in the Traill Ø region. The first late Paleocene – early Eocene phase was related to the opening of the northern North Atlantic in the earliest Eocene, and was experienced throughout East Greenland and the northwest European margin. The later magmatic phase was related to the gradual separation of the Jan Mayen microcontinent from East Greenland through the late Eocene – early Oligocene. A single pyrobitumen phase is recognised in accumulations only affected by the early magmatism, and a second phase is only observed in areas affected by both the early and later magmatism. This relationship is interpreted as evidence for a direct relationship between magmatic phases and bitumen generation. The presence of bitumen formed by the thermal degradation of liquid hydrocarbons during the later magmatic event suggests that a viable petroleum system remained active following the early magmatic event.
{"title":"PETROGRAPHY OF PYROBITUMENS IN MIDDLE – LATE JURASSIC SANDSTONES FROM THERMALLY DEGRADED HYDROCARBON ACCUMULATIONS, EAST GREENLAND","authors":"Dominic P. Strogen, John E. A. Marshall, Andrew G. Whitham, Steven D. Andrews","doi":"10.1111/jpg.12845","DOIUrl":"https://doi.org/10.1111/jpg.12845","url":null,"abstract":"<p>A number of exhumed hydrocarbon traps have been described from the Traill Ø region of East Greenland. This study focuses on the Bjørnedal area where the distribution of bitumen has been mapped out. Bitumen staining clearly has a cross-cutting relationship to stratigraphic units and can be shown to form distinct palaeo-accumulations. Detailed petrographic studies show that bitumen occurs as late diagenetic phases in Middle to Late Jurassic sandstones, and is present both as both grain-coating and pore-filling phases. Geochemical analyses confirm that the bitumen is organic in composition and is composed largely of carbon and hydrogen. Both H/C ratios and bonds identified by FTIR behave as expected with increasing maturity measured using bitumen reflectance. Together, these results provide strong evidence that the material is pyrobitumen derived from the in situ thermal degradation of a liquid hydrocarbon precursor. On the basis of textures in transmitted and reflected light and quantitative bitumen reflectance distributions, two populations of pyrobitumen may be recognised in some samples.</p><p>Two phases of Paleogene magmatism occurred in the Traill Ø region. The first late Paleocene – early Eocene phase was related to the opening of the northern North Atlantic in the earliest Eocene, and was experienced throughout East Greenland and the northwest European margin. The later magmatic phase was related to the gradual separation of the Jan Mayen microcontinent from East Greenland through the late Eocene – early Oligocene. A single pyrobitumen phase is recognised in accumulations only affected by the early magmatism, and a second phase is only observed in areas affected by both the early and later magmatism. This relationship is interpreted as evidence for a direct relationship between magmatic phases and bitumen generation. The presence of bitumen formed by the thermal degradation of liquid hydrocarbons during the later magmatic event suggests that a viable petroleum system remained active following the early magmatic event.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 4","pages":"415-439"},"PeriodicalIF":1.8,"publicationDate":"2023-09-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"50146893","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Mohammad R. Ghassemi, Mark B. Allen, Hossein Motamedi
The South Caspian Basin, the northern Alborz Mountains, the Gorgan plain and the Moghan plain constitute the northernmost and youngest petroleum system in Iran. This region was part of the Paratethys realm from Oligocene to Pliocene time. The Oligocene – Miocene Maikop/Diatom Total Petroleum System of the South Caspian Basin produces major volumes of hydrocarbons in Azerbaijan and Turkmenistan, and the Iranian sector of the basin has consequently undergone exploration due to its generally similar geology. The 20 km thick, dominantly Cenozoic sedimentary cover in the basin is reduced to less than 3 km in the northern foothills of the Alborz Mountains, and scattered surface oil seepages in the latter region are believed to be generated by Cretaceous and Miocene source rocks. In the Moghan plain to the southwest of the South Caspian Basin, anticlinal folds of Oligo-Miocene Zivar Formation sandstones may be prospective for hydrocarbon exploration. Mud volcanoes in the Gorgan plain and in adjacent offshore regions at the SE margin of the South Caspian Basin are associated with hydrocarbon seepages, and appear to be sourced by Cretaceous and Cenozoic shales and mudstones. Major structural features in the southern part of the South Caspian Basin include Cenozoic mud diapirs, folds and gravity structures.
{"title":"A SYNTHESIS OF THE GEOLOGY AND PETROLEUM GEOLOGY OF THE IRANIAN PORTION OF THE SOUTH CASPIAN BASIN AND SURROUNDING AREAS","authors":"Mohammad R. Ghassemi, Mark B. Allen, Hossein Motamedi","doi":"10.1111/jpg.12848","DOIUrl":"https://doi.org/10.1111/jpg.12848","url":null,"abstract":"<p>The South Caspian Basin, the northern Alborz Mountains, the Gorgan plain and the Moghan plain constitute the northernmost and youngest petroleum system in Iran. This region was part of the Paratethys realm from Oligocene to Pliocene time. The Oligocene – Miocene Maikop/Diatom Total Petroleum System of the South Caspian Basin produces major volumes of hydrocarbons in Azerbaijan and Turkmenistan, and the Iranian sector of the basin has consequently undergone exploration due to its generally similar geology. The 20 km thick, dominantly Cenozoic sedimentary cover in the basin is reduced to less than 3 km in the northern foothills of the Alborz Mountains, and scattered surface oil seepages in the latter region are believed to be generated by Cretaceous and Miocene source rocks. In the Moghan plain to the southwest of the South Caspian Basin, anticlinal folds of Oligo-Miocene Zivar Formation sandstones may be prospective for hydrocarbon exploration. Mud volcanoes in the Gorgan plain and in adjacent offshore regions at the SE margin of the South Caspian Basin are associated with hydrocarbon seepages, and appear to be sourced by Cretaceous and Cenozoic shales and mudstones. Major structural features in the southern part of the South Caspian Basin include Cenozoic mud diapirs, folds and gravity structures.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 4","pages":"487-512"},"PeriodicalIF":1.8,"publicationDate":"2023-09-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"50146885","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Forooz Keyvani, Ihsan S. Al-Aasm, Howri Mansurbeg, Sadoon Morad
Lower Cretaceous carbonates of the Fahliyan Formation form prolific reservoir rocks at oilfields in the Dezful Embayment, central Zagros fold-thrust belt, SW Iran. The carbonates have undergone significant diagenetic alteration in phases which can in general be linked to the pre-, syn- and post-tectonic evolution of the fold-thrust belt. This paper investigates the impact of diagenetic processes on the reservoir quality of the carbonates using integrated petrographic, geochemical and sedimentological analyses of subsurface and outcrop samples of the formation. Diagenetic alterations include:
(i) pre-tectonic eogenesis in the marine and shallow-burial realm, which resulted in micritization of allochems and cementation by equant and isopachous calcite rims and framboidal pyrite together with limited dolomitization and dissolution of metastable bioclasts. The isotopic compositions of micrite and early calcite cement depart from postulated values of Lower Cretaceous marine carbonates, signifying early stabilization of precursor metastable carbonate minerals and the possible effects of the incursion of meteoric waters and/or increasing burial temperatures;
(ii) mesogenesis during the subsequent syn-tectonic phase, which included Late Cretaceous ophiolite obduction at the northern margin of the Arabian Plate and the later Zagros orogeny in the Miocene-Pliocene. Diagenetic modifications included the emplacement of hydrocarbons, the development of stylolites and fractures, and the precipitation of saddle dolomite, replacive rhombic dolomite, discrete pyrite, microcrystalline quartz, kaolin and anhydrite. The average stable isotope compositions of saddle dolomite (δ18O: -6.9 ‰ ± .9 and δ13C 0.5 ‰ ± 1.6, respectively) also reflects the influence of high temprature basinal fluids;
and (iii) “late” (telogenetic, post-tectonic) uplift-related modification starting in the Pliocene, when the incursion of meteoric waters resulted in the formation of vugs, the calcitization of dolomite, and cementation by fracture-filling blocky calcite. The negative δ18O and δ13C stable isotope values (average: -5.5 ‰ ± 1.5; and -3.6 ‰ ± 5.9, respectively) of late blocky calcite cement suggest the incursion of meteoric water into the system.
This study demonstrates that diagenetic processes in carbonates in the Fahliyan Formation, which exerted a significant control on the distribution of secondary porosity, can be related to the tectonic evolution of the central Zagros fold-thrust belt. Thus, constraining the diagenetic history of carbonate successions within the context of their wider tectonic evolution is important for the prediction of the spatial and temporal distribution of reservoir quality.
{"title":"PRE-, SYN- AND POST-TECTONIC DIAGENETIC EVOLUTION OF A CARBONATE RESERVOIR: A CASE STUDY OF THE LOWER CRETACEOUS FAHLIYAN FORMATION IN THE DEZFUL EMBAYMENT, ZAGROS FOLDBELT, SW IRAN","authors":"Forooz Keyvani, Ihsan S. Al-Aasm, Howri Mansurbeg, Sadoon Morad","doi":"10.1111/jpg.12846","DOIUrl":"https://doi.org/10.1111/jpg.12846","url":null,"abstract":"<div>\u0000 <p>Lower Cretaceous carbonates of the Fahliyan Formation form prolific reservoir rocks at oilfields in the Dezful Embayment, central Zagros fold-thrust belt, SW Iran. The carbonates have undergone significant diagenetic alteration in phases which can in general be linked to the pre-, syn- and post-tectonic evolution of the fold-thrust belt. This paper investigates the impact of diagenetic processes on the reservoir quality of the carbonates using integrated petrographic, geochemical and sedimentological analyses of subsurface and outcrop samples of the formation. Diagenetic alterations include:</p>\u0000 <p>(i) pre-tectonic eogenesis in the marine and shallow-burial realm, which resulted in micritization of allochems and cementation by equant and isopachous calcite rims and framboidal pyrite together with limited dolomitization and dissolution of metastable bioclasts. The isotopic compositions of micrite and early calcite cement depart from postulated values of Lower Cretaceous marine carbonates, signifying early stabilization of precursor metastable carbonate minerals and the possible effects of the incursion of meteoric waters and/or increasing burial temperatures;</p>\u0000 <p>(ii) mesogenesis during the subsequent syn-tectonic phase, which included Late Cretaceous ophiolite obduction at the northern margin of the Arabian Plate and the later Zagros orogeny in the Miocene-Pliocene. Diagenetic modifications included the emplacement of hydrocarbons, the development of stylolites and fractures, and the precipitation of saddle dolomite, replacive rhombic dolomite, discrete pyrite, microcrystalline quartz, kaolin and anhydrite. The average stable isotope compositions of saddle dolomite (δ<sup>18</sup>O: -6.9 ‰ ± .9 and δ<sup>13</sup>C 0.5 ‰ ± 1.6, respectively) also reflects the influence of high temprature basinal fluids;</p>\u0000 <p>and (iii) “late” (telogenetic, post-tectonic) uplift-related modification starting in the Pliocene, when the incursion of meteoric waters resulted in the formation of vugs, the calcitization of dolomite, and cementation by fracture-filling blocky calcite. The negative δ<sup>18</sup>O and δ<sup>13</sup>C stable isotope values (average: -5.5 ‰ ± 1.5; and -3.6 ‰ ± 5.9, respectively) of late blocky calcite cement suggest the incursion of meteoric water into the system.</p>\u0000 <p>This study demonstrates that diagenetic processes in carbonates in the Fahliyan Formation, which exerted a significant control on the distribution of secondary porosity, can be related to the tectonic evolution of the central Zagros fold-thrust belt. Thus, constraining the diagenetic history of carbonate successions within the context of their wider tectonic evolution is important for the prediction of the spatial and temporal distribution of reservoir quality.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 4","pages":"441-462"},"PeriodicalIF":1.8,"publicationDate":"2023-09-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://onlinelibrary.wiley.com/doi/epdf/10.1111/jpg.12846","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"50146894","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Marco Brito, René Rodrigues, Rui Baptista, Luís V. Duarte, Ana C. Azerêdo, Cleveland M. Jones
New stable carbon isotope and biomarker data for oils and source rock extracts from the Lusitanian Basin, Portugal, were studied in order to investigate the petroleum systems which are present there. The new analytical data was combined with data presented in previous publications, and oil-oil and oil- source rock correlations were carried out. Three genetic groups of oils (Groups 1, 2 and 3), belonging to three different petroleum systems, were identified:
Group 1 oils occur in the northern sector of the Lusitanian Basin and were generated by the Coimbra Formation (Sinemurian) source rock. Reservoir rocks for oils in this group are the Coimbra, Água de Madeiros (upper Sinemurian – lower Pliensbachian), Boa Viagem (Kimmeridgian –Tithonian) and Figueira da Foz (upper Aptian – Cenomanian) Formations. Other potential source rocks in the northern sector of the basin, such as the Polvoeira Member of the Água de Madeiros Formation and the Marly Limestones with Organic Facies (MLOF) Member of the Vale das Fontes Formation (Pliensbachian), had biomarker characteristics which differed from those of the Group 1 oils and did not therefore generate them.
Group 2 oils occur in the central and southern sectors of the basin. The source rock is the Cabaços Formation (middle Oxfordian), and reservoir rocks are the Montejunto (middle-upper Oxfordian) and Abadia (Kimmeridgian) Formations.
Group 3 is represented by an oil sample from the central sector of the Lusitanian Basin. Both the source rock and the reservoir rock for the oil are the Montejunto Formation.
Geochemical data combined with the regional tectono-stratigraphic history suggest that the generation-migration-accumulation of most of the oil (critical moment) in the Coimbra – Coimbra - Água de Madeiros - Boa Viagem - Figueira da Foz (!) petroleum system occurred in the early Campanian. For the Cabaços – Montejunto - Abadia (!) and Montejunto – Montejunto (!) petroleum systems, the critical moment occurred in the late Cenomanian.
研究了葡萄牙卢西塔尼亚盆地石油和烃源岩提取物的新的稳定碳同位素和生物标志物数据，以研究那里存在的石油系统。将新的分析数据与以往出版物中的数据相结合，进行了油气和油源岩对比。确定了属于三个不同石油系统的三个油成因组（第1、2和3组）：第1组油产于卢西塔阶盆地北部，由Coimbra组（Sinemurian）烃源岩生成。该组油的储层岩石为Coimbra、Água de Madeiros（上Sinemurian-下Pliensbachian）、Boa Viagem（Kimmeridian-Tithonian）和Figueira da Foz（上Aptian-Cenomanian）地层。盆地北部的其他潜在烃源岩，如Água de Madeiros组的Polvoeira段和Vale das Fontes组（Pliensbachian）的Marly Limestones with Organic Facies（MLOF）段，具有与第1组油不同的生物标志物特征，因此没有产生这些特征。第2组油产于盆地的中部和南部。烃源岩为Cabaços组（中牛津阶），储集岩为Montejunto组（中上牛津阶）和Abadia组（Kimmeridian阶）。第3组由Lusitanian盆地中部的石油样品代表。油的烃源岩和储集岩均为Montejunto组。地球化学数据结合区域构造-地层史表明，Coimbra-Coimbra-Água de Madeiros-Boa Viagem-Figueira da Foz（！）油气系统中大部分油（关键时刻）的生成-运移-聚集发生在坎帕尼亚早期。对于Cabaços-Montejunto-Abadia（！）和Montejunto–Montejunto（！）石油系统来说，关键时刻发生在晚塞诺曼时期。
{"title":"JURASSIC PETROLEUM SYSTEMS IN THE LUSITANIAN BASIN, PORTUGAL: NEW INSIGHTS BASED ON OIL – SOURCE ROCK CORRELATIONS","authors":"Marco Brito, René Rodrigues, Rui Baptista, Luís V. Duarte, Ana C. Azerêdo, Cleveland M. Jones","doi":"10.1111/jpg.12847","DOIUrl":"https://doi.org/10.1111/jpg.12847","url":null,"abstract":"<p>New stable carbon isotope and biomarker data for oils and source rock extracts from the Lusitanian Basin, Portugal, were studied in order to investigate the petroleum systems which are present there. The new analytical data was combined with data presented in previous publications, and oil-oil and oil- source rock correlations were carried out. Three genetic groups of oils (Groups 1, 2 and 3), belonging to three different petroleum systems, were identified:</p><p>Group 1 oils occur in the northern sector of the Lusitanian Basin and were generated by the Coimbra Formation (Sinemurian) source rock. Reservoir rocks for oils in this group are the Coimbra, Água de Madeiros (upper Sinemurian – lower Pliensbachian), Boa Viagem (Kimmeridgian –Tithonian) and Figueira da Foz (upper Aptian – Cenomanian) Formations. Other potential source rocks in the northern sector of the basin, such as the Polvoeira Member of the Água de Madeiros Formation and the Marly Limestones with Organic Facies (MLOF) Member of the Vale das Fontes Formation (Pliensbachian), had biomarker characteristics which differed from those of the Group 1 oils and did not therefore generate them.</p><p>Group 2 oils occur in the central and southern sectors of the basin. The source rock is the Cabaços Formation (middle Oxfordian), and reservoir rocks are the Montejunto (middle-upper Oxfordian) and Abadia (Kimmeridgian) Formations.</p><p>Group 3 is represented by an oil sample from the central sector of the Lusitanian Basin. Both the source rock and the reservoir rock for the oil are the Montejunto Formation.</p><p>Geochemical data combined with the regional tectono-stratigraphic history suggest that the generation-migration-accumulation of most of the oil (critical moment) in the Coimbra – Coimbra - Água de Madeiros - Boa Viagem - Figueira da Foz (!) petroleum system occurred in the early Campanian. For the Cabaços – Montejunto - Abadia (!) and Montejunto – Montejunto (!) petroleum systems, the critical moment occurred in the late Cenomanian.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 4","pages":"463-485"},"PeriodicalIF":1.8,"publicationDate":"2023-09-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"50146888","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"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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