Journal of Petroleum Geology最新文献

{"title":"ORGANIC AND INORGANIC GEOCHEMICAL AND MINERALOGICAL ASSESSMENTS OF THE SILURIAN AKKAS FORMATION, WESTERN IRAQ","authors":"A. I. Al-Juboury,&nbsp;F. M. Qader,&nbsp;J. Howard,&nbsp;S. J. Vincent,&nbsp;A. Al-Hadidy,&nbsp;B. Thusu,&nbsp;M. N.D. Kaye,&nbsp;B. Vautravers","doi":"10.1111/jpg.12779","DOIUrl":"10.1111/jpg.12779","url":null,"abstract":"<p>The Silurian Akkas Formation has been reported and described only in the subsurface of western Iraq. The formation is divided into the lower Hoseiba Member, which contains two high-TOC “hot” shale intervals that together are around 60 m thick, and the overlying Qaim Member that is composed of lower-TOC “cold” shales. This study investigates the source rock potential of Akkas Formation shales from the Akkas-1and Akkas-3 wells in western Iraq and assesses the relationship between their mineral and elemental contents and their redox depositional conditions and thermal maturity. Twenty-six shale samples from both members of the Akkas Formation from the Akkas-1and Akkas-3 wells were analysed. The results showed that the upper, ~20 m thick“hot” shale interval in the lower Hoseiba Member has good source rock characteristics with an average TOC content of 5.5 wt% and a mean Rock-Eval S₂ of 10 kg/tonne. Taken together, the two “hot” shale intervals and the intervening “cold” shale of the Hoseiba Member are ~125-150 m thick and have an average TOC of 3.3 wt% and mean S₂ of 6.2 kg/tonne. The samples from the Hoseiba Member contain mixed Type II / III or Type III kerogen with an HI of up to 296 mgS₂/gTOC. Visual organic-matter analysis showed that the samples contain dark brown, opaque amorphous organic matter with minor amounts of vitrinite-like and algal (Tasmanites) material. Pyrolysis – gas chromatography undertaken on a single sample indicated a mature (or higher) algal-dominated Type II kerogen. High spore and acritarch colour index values and weak or absent fluorescence similarly suggest that the lower part of the Akkas Formation is late mature to early post-mature for oil generation. “Cold” shales from the Qaim Member in the Akkas-3 well may locally have good source rock potential, while samples from the upper part of the Qaim Member from the Akkas-1 well have little source rock potential. Varied results from this interval may reflect source rock heterogeneity and limited sample coverage.</p><p>Mineralogically, all the shale samples studied were dominated by clay minerals – illite and kaolinite with minor amounts of chlorite and illite mixed layers. Non-clay minerals included quartz, carbonates, feldspars and pyrite along with rare apatite and anatase. Palaeoredox proxies confirmed the general link between anoxia and “hot” shale deposition; however, there was no clear relationship between TOC and U suggesting that another carrier of U could be present. Rare Earth Element (REE) contents suggested a slight change in sediment provenance during the deposition of the Akkas Formation. The presence of common micropores and fractures identified under SEM indicates that these shales could become potential unconventional reservoirs following hydraulic fracturing. Evidence for the dissolution of carbonate minerals was present along fractures, suggesting the possible passage of diagenetic fluids.</p><p>Palynological analysis c","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":1.8,"publicationDate":"2020-12-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12779","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44975055","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":"Homayoun Motiei, 1947-2020","authors":"","doi":"10.1111/jpg.12781","DOIUrl":"10.1111/jpg.12781","url":null,"abstract":"","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":1.8,"publicationDate":"2020-12-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12781","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49209674","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":"MINERALOGICAL, BIB-SEM AND PETROPHYSICAL DATA IN SEAL ROCK ANALYSIS: A CASE STUDY FROM THE VIENNA BASIN, AUSTRIA","authors":"D. Misch,&nbsp;W. Siedl,&nbsp;M. Drews,&nbsp;B. Liu,&nbsp;J. Klaver,&nbsp;M. Pupp,&nbsp;R.F. Sachsenhofer","doi":"10.1111/jpg.12777","DOIUrl":"10.1111/jpg.12777","url":null,"abstract":"<p>The Vienna Basin is a major hydrocarbon province with a long exploration history. Within the basin, secondary migration from Upper Jurassic source rocks into stacked Middle Miocene (Badenian) sandstone reservoirs was formerly considered to have occurred almost entirely along major fault zones. However recent exploration data has suggested that in areas where no major faults are present, oil may have migrated vertically through the sandy mudstone intervals separating individual reservoir units, which are therefore imperfectly sealed. In order to investigate possible secondary migration through the semi-permeable mudstones, this study links variations in gross depositional environment (GDE) to variations in mudstone properties (e.g. mineralogy and pore size distribution). The study focussed on the mudstones which seal reservoir sandstones referred to locally as the “8.TH” and “16.TH” units. The bulk mineralogical composition of 56 mudstone and sandy mudstone (and minor intercalated muddy sandstone) samples from seal layers in 22 wells was studied by X-ray diffraction analysis, broad ion beam – scanning electron microscopy (BIB-SEM), mercury intrusion porosimetry (MICP) and N₂ adsorption. These data are interpreted in the context of GDE maps of the Vienna Basin which were previously established using seismic and well log data.</p><p>Results indicate that the gross depositional environment strongly controlled the pore space characteristics of the mudstones. The sandy mudstones in the NW part of the study area were influenced by a complex eastward-prograding deltaic system which deposited coarse detritus into a major palaeo depression (“Zistersdorf Depression”) located in the centre of the basin. Higher overall porosity and a dominance of larger pore size classes, probably resulting in reduced seal quality, were observed for sandy mudstones from well locations within feeder channels and also from within the Zistersdorf Depression. Similarly, sandy mudstones from locations associated with the long-term input of coarser sediments in shoreline, coastal and proximal offshore settings in the NW and central parts of the study area are considered to be of lower sealing quality compared to fine-grained mudstones deposited in distal, open-marine settings which prevailed in the SE part of the study area throughout the Middle Miocene.</p><p>In general, pore geometries were influenced by mineralogical composition; quartz- and detrital carbonate-rich samples show equidimensional pores, while more elongated pores (with a higher average aspect ratio) characterize clay-rich samples. Furthermore, matrix mesopores (2-50 nm) determined by N₂ sorption are more abundant in clay-rich versus quartz-rich samples, and show a pronounced positive trend with increasing percentage of illite-smectite mixed-layer clay minerals.</p><p>This study shows that regional-scale mudstone seals in the Vienna Basin have been influenced by variations in sedimentation a","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":1.8,"publicationDate":"2020-12-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12777","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49212214","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":"SOURCE ROCK POTENTIAL AND DEPOSITIONAL ENVIRONMENT OF MIDDLE – UPPER JURASSIC SEDIMENTARY ROCKS, BLUE NILE BASIN, ETHIOPIA","authors":"M. S. Mohammedyasin,&nbsp;R. Littke,&nbsp;G. Wudie,&nbsp;L. Zieger","doi":"10.1111/jpg.12772","DOIUrl":"10.1111/jpg.12772","url":null,"abstract":"<p>This study investigates the hydrocarbon generation potential, kerogen quality, thermal maturity and depositional environment of Middle – Upper Jurassic sedimentary rocks in the Blue Nile Basin, Ethiopia, using organic petrography, Rock-Eval pyrolysis and molecular organic geochemistry. Thirty-seven outcrop samples were analysed for their total organic carbon (TOC) and inorganic carbon (TIC) contents. The samples came from a Toarcian – Bathonian transitional glauconitic shale-mudstone unit, the overlying Upper Bathonian Gohatsion Formation, and the Lower Callovian – Upper Tithonian Antalo Limestone Formation. Thirteen samples with sufficient TOC contents for further analysis of the organic matter, eight from the Antalo Limestone Formation and five from the glauconitic shale-mudstone unit, were selected and analysed using Rock-Eval pyrolysis. Vitrinite reflectance (VR_r) was measured on random particles, and qualitative maceral analysis was performed under normal incident and UV light. Nine samples were selected for molecular organic-geochemical analyses. All the samples originating from the Gohatsion Formation showed TOC values which were too low for further analyses of the organic matter.</p><p>The TOC contents of shales and limestones from the Antalo Limestone Formation and and of shales from the glauconitic shale-mudstone unit were 3.43-6.43% (average 4.85%) and 0.76-3.15% (average 1.72%), respectively, and two coaly shale samples from the latter unit have average TOC values of 18.48%. HI values are very high for shales in the Antalo Limestone Formation (average 575 mg HC/g TOC) but lower for the shales in the glauconitic shale-mudstone unit. The vitrinite reflectance of shales from the Antalo Limestone Formation ranged between 0.21% and 0.47%; coaly shales from the glauconitic shale-mudstone unit have VR_r% of between 0.29% and 0.35%. Pr/Ph ratios for samples of the Antalo Limestone Formation shales ranged from 0.8 to 1.1, indicating anoxic to suboxic depositional conditions; while shales in the glauconitic shale-mudstone unit show higher values of up to 4.9.</p><p>In terms of organic petrography, the Antalo Limestone Formation samples are dominated by finely dispersed liptinite particles and alginite; the organic material in the glauconitic shale-mudstone unit is of higher land plant origin, with abundant vitrinite and inertinite. Sterane and hopane biomarker ratios suggest an anoxic/suboxic depositional environment for the Antalo Limestone Formation shales and limestones. These values together with Rock-Eval Tmax (average 414 °C), the high ratio of pristane and phytane over the n-alkanes C₁₇ and C₁₈, and hopane biomarker ratios indicate that the Middle – Upper Jurassic succession is of low thermal maturity in the central parts of the Blue Nile Basin. The Antalo Limestone Formation shales have a high petroleum generation potential, making them a viable target for future exploration activities.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":1.8,"publicationDate":"2020-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12772","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45167416","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":"FORECASTING ABILITIES OF INDIVIDUAL PETROLEUM EXPLORERS: PRELIMINARY FINDINGS FROM CROWDSOURCED PROSPECT ASSESSMENTS","authors":"A. V. Milkov","doi":"10.1111/jpg.12771","DOIUrl":"10.1111/jpg.12771","url":null,"abstract":"<p>Petroleum explorers regularly make numerous forecasts for prospects and wells, but the quality of their predictions has inadequate documentation. Here I discuss the forecasting abilities of individual explorers inferred from a survey about future exploration wells, some of which were drilled in late 2018 and 2019. A total of 104 petroleum explorers provided 7,068 answers about eleven wells and about themselves, and subsets from this dataset were used to study their predictions. The survey participants were diverse, and most had M.Sc. or Ph.D. degrees with &gt;16 years of industry experience working as individual contributors and/or middle managers for oil companies. Assessments of the geological probability of success (PoS) by different explorers for the same well were highly variable, and average assessments poorly discriminated between future discoveries and dry holes. Point (binary or multiple choice) forecasts by explorers participating in the survey were, on average, only slightly better than random guessing. The participants' highest academic degree had little apparent influence on the quality of the point forecasts. Years of experience resulted in only slightly better correlation with increasing quality of forecasts. Survey participants more familiar with the prospects (those who generated them or evaluated proprietary company data) made, on average, worse exploration forecasts than those who studied only the limited publicly available information provided with the survey. The duration of time spent on the survey did not affect the quality of forecasts. The aggregated opinion of all explorers (wisdom of the crowd) may be beneficial in assessments of the geological PoS, but perhaps not so when forecasted outcomes have binary or multiple possibilities. The generally poor forecasting abilities of individual petroleum explorers may surprise some decision-makers and investors. However, many of the study results are based on relatively small datasets and should be treated as preliminary. Further research with larger datasets is necessary to replicate, validate and explain the findings of this study.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":1.8,"publicationDate":"2020-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12771","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45586948","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":"GEOPHYSICAL CHARACTERIZATION OF THE SANGU GAS FIELD, OFFSHORE, BANGLADESH: CONSTRAINTS ON RESERVOIRS","authors":"Md. Upal Shahriar,&nbsp;Delwar Hossain,&nbsp;Md. Sakawat Hossain,&nbsp;M. Julleh Jalalur Rahman,&nbsp; Kamruzzaman","doi":"10.1111/jpg.12770","DOIUrl":"10.1111/jpg.12770","url":null,"abstract":"<p>The only produced offshore gas field in Bangladesh, known as the Sangu field, is located in the Hatiya Trough in the east of the Bay of Bengal, and has estimated total reserves of about 1055 BCF GIIP. The early shut-down of the field in October 2013 may have resulted in significant volumes of recoverable gas being left in the subsurface over a depth range of 1893 m to 3640 m. In this paper, seismic and well log data were analyzed and interpreted in order to investigate the structure and stratigraphy of the Sangu field, together with the lithology, extent and petrophysical properties of the reservoir. The general lithostratigraphy at Sangu has some similarity to that of the Surma Basin of the Bengal Foredeep. Reservoir rocks consist of Miocene and Pliocene deltaic sandstones and deep-water clastics. The source rock is the Miocene Bhuban Shale which is mature for gas generation in the Hatiya Trough.</p><p>Three Neogene seismic stratigraphic megasequences were recognised at Sangu and are interpreted to have been deposited respectively in fluvial, delta front and shelf slope or marginal marine settings. Based on an analysis of wireline logs from wells Sangu-1 and Sangu-5 and on seismic-to-well ties, a series of reservoir units referred to (from the base up) as the T1 (E, D, C, A&amp;B), Supra-T1, T2 and T3 have been identified. Petrophysical analyses showed that the average total porosity of these reservoir units is &gt;13%, the permeability is in general less than10 mD, and the gas saturation ranges from 24% to 80%. Mapping of the reservoirs shows that the structure at Sangu is an asymmetric anticline with a NNW-SSE axial trend. Amplitude data have allowed the delineation of two other potential reservoir zones in the field at depths of 2900-3000 m and 3550-3750 m. The study will contribute to future offshore gas exploration and development in the Bay of Bengal region based on the geological and geophysical characteristics of the reservoirs delineated.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":1.8,"publicationDate":"2020-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12770","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42130042","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":"HIGHER LANDPLANT –DERIVED BIOMARKERS IN LIGHT OILS AND CONDENSATES FROM THE COAL-BEARING EOCENE PINGHU FORMATION, XIHU SAG, EAST CHINA SEA SHELF BASIN","authors":"X. Cheng,&nbsp;D. J. Hou,&nbsp;Z. Zhao,&nbsp;Y. H. Jiang,&nbsp;X. H. Zhou,&nbsp;H. Diao","doi":"10.1111/jpg.12774","DOIUrl":"10.1111/jpg.12774","url":null,"abstract":"<p>The Cenozoic Xihu Sag in the East China Sea Shelf Basin contains large reserves of coals together with liquid petroleum derived from coal-associated sediments. However, the origin of the petroleum is not well understood. In this study, biomarker assemblages in a suite of recently discovered light oils and condensates from the Paleogene succession in the western margin of in the Xihu Sag were investigated using gas chromatography – mass spectrometry. The objectives were to investigate the samples' thermal maturity and the depositional environment of the precursor source rocks which generated the oils. The light oils are believed to have been derived from coaly source rocks in the Eocene Pinghu Formation.</p><p>Assessment of thermal maturity based on CPI, pristane/n-C₁₇ ratio and isomerisation ratios of C₂₉ steranes and C₃₁ homohopanes suggest that the hydrocarbons have a relatively low maturity in the early to mid oil generation window. The distribution of isoprenoids relative to n-alkanes, the high pristane/phytane ratios (5.1–10.7), the almost complete absence of gammacerane and C₃₃₊ homohopanes, and the low dibenzothiophene/phenanthrene ratios indicate that the source rocks of the hydrocarbons were deposited in a relatively oxic and sulphate-poor fluvio-deltaic environment which was favourable for coal measure development.</p><p>Abnormally abundant gymnosperm-derived diterpanes including labdane, 19-norisopimarane, fichtelite, rimuane, pimarane, isopimarane, 17-nortetracyclic diterpene, phyllocladanes and abietane were detected in the samples analysed. 16<i>a</i>(H)-Phyllocladane was identified unambiguously and kauranes were confirmed to be absent. In addition, three 19-norisopimarane isomers, 13<i>β</i>(H)-atisane, and 20-normethylatisane were tentatively identified in the studied samples. The distributions of n-alkanes, isoprenoids and regular steranes, the presence of 4<i>β</i>(H)-eudesmane and oleanane, high Pr/Ph ratios and the abundant diterpanes together suggest that the hydrocarbons were derived from a coaly source rock. Gymnosperms of the conifer families Cupressaceae (especially the former Taxodiaceae) and Pinaceae are interpreted to be the major source of the diterpanes and to have made a significant contribution to the coaly source rock. However, the low abundance of oleanane relative to diterpanes may underestimate the contribution from angiosperms relative to gymnosperms. This could be due to differential preservation and alteration of the di- and triterpenoid precursors during diagenesis and the occurrence of non-specific precursors in higher land plants.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":1.8,"publicationDate":"2020-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12774","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47151705","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":"NUMERICAL MODELLING OF THE AUSTRALIA – ANTARCTICA CONJUGATE MARGINS USING THE GALO SYSTEM: PART 2. THERMAL AND MATURATION HISTORY OF THE MAWSON SEA BASIN, EAST ANTARCTICA","authors":"Y.I. Galushkin,&nbsp;G.L. Leitchenkov,&nbsp;E.P. Dubinin","doi":"10.1111/jpg.12773","DOIUrl":"10.1111/jpg.12773","url":null,"abstract":"<p>The thermal evolution of the Mawson Sea Basin, offshore East Antarctic, was modelled using the GALO basin modelling programme. As there exist no deep temperature or vitrinite reflectance data for the Mawson Sea Basin, the simulation was based on a limited nonthermal database. This includes the present-day sedimentary section along a multichannel seismic profile which crosses the western part of the Mawson Sea along with geophysical assessments of the depth of the Moho. An analysis of the variations in tectonic subsidence was used to estimate the duration and magnitude of thermal activation or stretching of the lithosphere. This analysis suggested that a proportion of the lithospheric stretching took place before the start of synrift sediment deposition at about 160 Ma (Late Jurassic). This pre-sedimentation lithospheric stretching has been ignored in previous studies, resulting in significant underestimation of the total stretching which has occurred. The analysis also suggests that the thermal maturity of Lower Jurassic potential source rocks along the profile may reach and even exceed the onset of the oil generation window, whereas source rocks in less deeply buried parts of the profile are less mature. In general, the results of the modelling indicate that the Mawson Sea Basin is a promising area for future oil and gas exploration.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":1.8,"publicationDate":"2020-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12773","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47173397","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":"Index of editorial contents, JPG vol. 43, 2020","authors":"","doi":"10.1111/jpg.12775","DOIUrl":"10.1111/jpg.12775","url":null,"abstract":"","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":1.8,"publicationDate":"2020-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12775","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48584297","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":"HYDROCARBON MIGRATION AND CHARGE HISTORY IN THE KARANJ, PARANJ AND PARSI OILFIELDS, SOUTHERN DEZFUL EMBAYMENT, ZAGROS FOLD-AND-THRUST BELT, SW IRAN","authors":"M. Vatandoust,&nbsp;A. Faghih,&nbsp;S. Asadi,&nbsp;A. M. Azimzadeh,&nbsp;B. Soleimany","doi":"10.1111/jpg.12769","DOIUrl":"10.1111/jpg.12769","url":null,"abstract":"<p>This study investigates the charge history of the Oligocene – Lower Miocene Asmari Formation reservoir at three oilfields (Karanj, Paranj and Parsi) in the southern Dezful Embayment, SW Iran, from microthermometric analyses of hydrocarbon-bearing fluid inclusions. The Asmari Formation reservoir was sampled in seven wells at depths of between 1671.5 and 3248.5 m; samples from three of the wells were found to be suitable for fluid inclusion analyses. The samples were analyzed using an integrated workflow including petrography, fluorescence spectroscopy, Raman microspectroscopy and microthermometry. Abundant oil inclusions with a range of fluorescence colours from near-yellow to near-blue were observed. Based on the fluid inclusion petrography, fluorescence and microthermometry data, two episodes of oil charging into the reservoir were identified: 7 to 3.5 Ma, and 3.5 to 2 Ma, respectively. Fluid inclusions in general homogenized at temperatures between 112 and 398°C and with salinities of 14 to 23 wt.% NaCl equivalent. Based on the burial history, the Albian Kazhdumi and Paleogene Pabdeh Formation source rocks in the study area have not reached the gas generation window. The abundant fluid inclusions containing gas-liquid phase observed in the Asmari samples studied are therefore inferred to have been derived from secondary oil-to-gas cracking which resulted from Late Pliocene uplift.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":1.8,"publicationDate":"2020-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12769","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44162165","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}