Journal of Petroleum Geology最新文献

{"title":"Index of editorial contents, JPG vol. 47, 2024","authors":"","doi":"10.1111/jpg.12875","DOIUrl":"https://doi.org/10.1111/jpg.12875","url":null,"abstract":"","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 4","pages":"456-459"},"PeriodicalIF":1.8,"publicationDate":"2024-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142313294","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}

{"title":"GEOCHEMISTRY OF OILS AND GASES FROM THE VERKHNECHONSKOYE FIELD, EAST SIBERIAN BASIN: APPLICATION OF ANALYTICAL RESULTS TO RESERVOIR CHARACTERISATION","authors":"N. V. Oblasov,&nbsp;I. V. Goncharov,&nbsp;I. V. Eftor,&nbsp;G. W. van Graas,&nbsp;M. A. Veklich,&nbsp;A. T. Akhmadishin,&nbsp;D. A. Lokshin","doi":"10.1111/jpg.12865","DOIUrl":"https://doi.org/10.1111/jpg.12865","url":null,"abstract":"<p>A geochemical study was carried out on oil and gas samples from the Verkhnechonskoye field, located on the Nepa-Botuoba Anteclise in the central-southern part of the Siberian Platform. The goal of the study was to distinguish between fluids derived from the V_10-13 and B₁₂ reservoir units in the Vendian (Neoproterozoic) Katanga and Nepa Formations and to identify the producing reservoir using geochemical data. The results of analyses of 12 oil and 13 associated gas samples from the two reservoirs showed that all the fluids have similar geochemical properties including: low Pr/Ph ratios (0.78-1.00); a predominance of C₂₉ over C₂₇ and C₂₈ steranes; a predominance of odd-numbered C₂₁-C₂₅ n-alkylbenzenes over their even-numbered homologues; the presence of 12- and 13-methylalkanes; and a high relative abundance of tricyclic terpanes (cheilantanes). All these properties are consistent with those of the properties of petroleum from other fields on the Siberian Platform. The molecular and stable carbon isotope compositions of the oils and gases suggest that they were derived from marine organic matter with a high algal input deposited under reducing conditions. To date, specific source rocks which generated the oil and gas present at fields on the Nepa-Botuaoba Anteclise have not conclusively been identified, but potential candidates include the Upper Riphean Iremeken and Ayan Formations and more probably the Vendian Zherbinskaya, Seralakh, Vanavara and Nepa Formations.</p><p>The second part of the study demonstrates the application to reservoir geochemistry of C_3- and C_4- alkylbenzene compounds together with more conventional biomarkers. Key parameters were selected using statistical processing and displayed in graphic profiles. These profiles allowed the oil and gas samples to be classified according to the reservoir from which they were derived based on their geochemical properties. Parameters based on C_3- and C_4- alkylbenzene compounds were most effective in discriminating between oils from the two reservoirs. In addition, a new parameter is proposed based on the contents of 1-methyl-3-isopropylbenzene, 1-methyl-2-isopropylbenzene and 1-methyl-2-propylbenzene; this parameter correlates closely with the pristane/phytane ratio and can be used as an additional indicator of the level of oxicity in the source rock depositional environment.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 3","pages":"291-316"},"PeriodicalIF":1.8,"publicationDate":"2024-06-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141488721","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}

{"title":"Stratigraphic framework for Zechstein Carbonates on the Utsira High, Norwegian North Sea","authors":"Lars Stemmerik,&nbsp;Kasper H. Blinkenberg,&nbsp;Ingrid P. Gianotten,&nbsp;Malcolm S.W. Hodgskiss,&nbsp;Aivo Lepland,&nbsp;Päärn Paiste,&nbsp;Israel Polonio,&nbsp;Nicholas M.W. Roberts,&nbsp;Niels Rameil","doi":"10.1111/jpg.12867","DOIUrl":"https://doi.org/10.1111/jpg.12867","url":null,"abstract":"","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 3","pages":"341-343"},"PeriodicalIF":1.8,"publicationDate":"2024-06-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://onlinelibrary.wiley.com/doi/epdf/10.1111/jpg.12867","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141488444","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}

{"title":"PETROLEUM GEOLOGY OF THE CENOZOIC SUCCESSION IN THE ZAGROS OF SW IRAN: A SEQUENCE STRATIGRAPHIC APPROACH","authors":"Alireza Piryaei,&nbsp;Roger B. Davies","doi":"10.1111/jpg.12864","DOIUrl":"https://doi.org/10.1111/jpg.12864","url":null,"abstract":"<p>The Cenozoic stratigraphy of the Zagros records the ongoing collision between the Arabian and Eurasian Plates and the closure of NeoTethys. A Paleogene NW-SE trending foreland basin was inherited from a Late Cretaceous precursor. Widespread progradation into the foredeep was a feature of both margins which, allied to ongoing tectonism, had by the late Eocene led to the narrowing and subsequent division of the foredeep into the Lurestan – Khuzestan and Lengeh Troughs, separated by the northward continuation of the rejuvenated Qatar-Fars Arch. This sub-division strongly influenced subsequent deposition and the petroleum geology of the area. In addition, the diachronous nature of the Arabian – Eurasian collision led to strong diachroneity in lithostratigraphic units along the length of the Zagros. Hence its petroleum geology is best understood within a regional sequence stratigraphic framework. This study identifies three tectono-megasequences (TMS 10, TMS 11a, TMS 11b) and multiple depositional sequences.</p><p>The Cenozoic contains a world class hydrocarbon province with prolific oil reservoirs in the Oligo-Miocene Asmari Formation sealed by the evaporite-dominated Gachsaran Formation, mostly contained within giant NW-SE trending “whaleback” anticlines concentrated in the Dezful Embayment. Reservoirs in the SW are dominantly siliciclastic or comprise mixed siliciclastics and carbonates, whereas those to the east and NE are dominated by fractured carbonates. There remains untested potential in stratigraphic traps, especially in deeperwater sandstone reservoirs deposited along the SW margin of the foredeep.</p><p>Late Miocene to Pliocene charge to the Asmari reservoirs was mostly from Aptian – Albian Kazhdumi Formation source rocks. In some fields, an additional component was from organic-rich late Eocene to earliest Oligocene Pabdeh Formation source rocks confined to the narrowing Lurestan – Khuzestan Trough. Where mature, the latter source rock is also a potential unconventional reservoir target, although the prospective area is limited due to recent uplift and erosion. Deeper Jurassic source rocks contributed to the Cheshmeh Khush field in Dezful North. Silurian source rocks charged gas-bearing structures in the Bandar Abbas region.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 3","pages":"235-290"},"PeriodicalIF":1.8,"publicationDate":"2024-06-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141488460","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}

{"title":"OIL FAMILIES AND GEOCHEMICAL COMPOSITION OF DEVONIAN OILS AT THE RECHITSA FIELD, PRIPYAT BASIN, BELARUS","authors":"Evgenia Leushina,&nbsp;Timur Bulatov,&nbsp;Yauheni Kaleichyk,&nbsp;Arina Goncharova,&nbsp;Elena Kozlova,&nbsp;Lyudmila Torshina,&nbsp;Alina Bazhanova,&nbsp;Anna Eroshenko,&nbsp;Andrei Khaletski,&nbsp;Mikhail Spasennykh","doi":"10.1111/jpg.12866","DOIUrl":"https://doi.org/10.1111/jpg.12866","url":null,"abstract":"<p>The sedimentary column at the Rechitsa oilfield in the Pripyat rift basin, Belarus, is dominated by an Upper Devonian synrift succession. The succession includes uppermost Frasnian and mid-Famennian salt units which are about 1000 m and 2000 m thick respectively. Reservoir rocks consist of sandstones and carbonates in the intra-, inter- and sub-salt successions. In this paper, the geochemical analysis of 15 oil samples from different stratigraphic intervals at the Rechitsa field is used as a basis for reservoir characterisation. Geochemical studies included biomarker and stable C, N and S isotope analyses.</p><p>Four genetic oil groups were identified and are referred to as Groups A to D. Oils in Group A came from upper intra- and inter-salt reservoir rocks; the oils are early mature, enriched in heavy (C₃₆₊) hydrocarbons, heteroatoms, aryl-isoprenoids and gammacerane, with low Pr/Ph = 0.6 and a sulphur isotope composition averaging 22.7‰ CDT. Oils in Group B were from sub-salt reservoirs and are at peak maturity with Pr/Ph = 1, an increased proportion of C₂₇ regular steranes, and a sulphur isotope composition of 8.1‰ CDT. The single oil sample in Group C was from a Proterozoic reservoir. The oil was overmature with a low content of heavy fractions, heteroatoms and steranes; its hopanes composition indicated that it was generated by the same source rock as the oils in Group B. Oils in Group D came from inter-salt reservoir rocks and were composed of a mixture of Groups A and B oils in roughly equal proportions, as indicated by their average isotope, molecular and biomarker compositions.</p><p>Observed differences in oil composition were explained in terms of contributions from at least two different source rocks together with variations in source rock maturity. Group A oils were interpreted to have been generated by Famennian carbonate-rich source rocks containing dominantly marine and bacterial organic matter deposited in an anoxic evaporitic setting. Source rocks for Groups B and C oils were suggested to be composed of OM-rich marine shales of Frasnian age or older.</p><p>The geochemical characteristics of the Devonian oils from Rechitsa field, and the oil-oil and oil- source rock correlations reported, will contribute to a better understanding of the petroleum system in the Pripyat Basin although direct oil- source rock correlations are not yet available. The presence of at least two source rocks for the Rechitsa oils has been suggested, respectively comprising carbonates in the inter-salt succession and marine shales and/or carbonates in the sub-salt succession. The main controls on oil composition in the Devonian reservoir units were the varying contributions from the different source rocks and differences in source rock thermal maturity associated with variations in burial depth and tectonics, together with the stratigraphic distribution of reservoir units which was in turn controlled by the presence of the thick Fr","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 3","pages":"317-340"},"PeriodicalIF":1.8,"publicationDate":"2024-06-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141488722","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}

{"title":"THE ARABIA – EURASIA COLLISION ZONE IN IRAN: TECTONOSTRATIGRAPHIC AND STRUCTURAL SYNTHESIS","authors":"Saeed Madanipour,&nbsp;Mahdi Najafi,&nbsp;Reza Nozaem,&nbsp;Jaume Vergés,&nbsp;Ali Yassaghi,&nbsp;Iraj Heydari,&nbsp;Sedigheh Khodaparast,&nbsp;Zahra Soudmand,&nbsp;Lotfollah Aghajari","doi":"10.1111/jpg.12854","DOIUrl":"https://doi.org/10.1111/jpg.12854","url":null,"abstract":"<p>The Arabia – Eurasia collision zone in the central part of the Alpine – Himalayan orogenic system has had a complex deformation history since the Palaeozoic. In Iran, the collision zone consists of the Alborz-Talesh, Kopeh Dagh and Zagros foldbelts and the intervening Central Iran area. In this review paper, we summarize the structural architecture and tectonostratigraphic characteristics of these domains and attempt to correlate regional deformation events between them. The results show that six regional-scale deformation phases can be recognized and correlated in Iran over a time interval extending from the Late Palaeozoic to the Late Cenozoic.</p><p>Late Palaeozoic rifting in northern Gondwana and subsequent oceanic spreading resulted in the separation of the Central and North Iran blocks from the Arabian Platform. These blocks later converged and collided with the southern margin of Eurasia due to the subduction of the intervening PalaeoTethys lithosphere (“Cimmerian orogeny”: Late Triassic). The convergent setting resulted in the initial development of the Alborz-Talesh foldbelt in present-day northern Iran, while extensional basins developed in the forebulge area in Central Iran. Continuing northward subduction of NeoTethyan oceanic lithosphere at the southern Eurasia margin produced Early Cretaceous back-arc extension and associated volcanism in Central Iran and the Alborz-Talesh area to the north. A phase of compressional deformation in the Late Cretaceous was related to the collision of a series of microcontinents derived from Northern Gondwana, including the Ercinjan and Bitlis massifs, with the Central Iran block, and is recorded in the Alborz-Talesh foldbelt and in Central Iran. Further back-arc extension in the late Paleocene – Eocene was accompanied by pervasive volcanism and volcaniclastic sedimentation throughout northern and Central Iran. The final closure of NeoTethys and convergence between the Arabian and Eurasian Plates evolved through phases of early Oligocene “soft” collision and middle Miocene “hard” collision. This was accompanied by thrusting in the internal parts of the Zagros foldbelt and by folding and subordinate thrusting in the more external parts, with related development of the flexural Mesopotamian Basin in the foreland to the SW.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 2","pages":"123-171"},"PeriodicalIF":1.8,"publicationDate":"2024-04-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140556309","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}

{"title":"INFLUENCE OF PLEISTOCENE GLACIATION ON PETROLEUM SYSTEMS AND GAS HYDRATE STABILITY IN THE OLGA BASIN REGION, BARENTS SEA","authors":"Sebastian Amberg,&nbsp;Ralf Littke,&nbsp;Rüdiger Lutz,&nbsp;Peter Klitzke,&nbsp;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}

{"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,&nbsp;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}

{"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,&nbsp;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}

{"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,&nbsp;Marcos Comerio,&nbsp;Eduardo G. Ottone,&nbsp;Joaquín Salduondo,&nbsp;Gastón Otegui,&nbsp;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_max: 430-438 °C; vitrinite reflectance: 0.59-0.67 % VR_o; and thermal alteration index: 2-2⁺).</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}