Journal of Petroleum Geology最新文献

{"title":"Geochemical Characteristics of Oils from the Orenburg Field in the SE Volga-Ural Basin, Russia: Implications for the Molecular Structure of a Marine Type II Kerogen","authors":"Mohammed Hail Hakimi,&nbsp;Muneer A. Suwaid,&nbsp;Shadi A. Saeed,&nbsp;Ameen A. Al-Muntaser,&nbsp;Mikhail A. Varfolomeev,&nbsp;Aliia N. Khamieva,&nbsp;Danis K. Nurgaliev,&nbsp;Mohammed A. Abdullah,&nbsp;Aref Lashin,&nbsp;Evgeniya V. Morozova,&nbsp;Bulat I. Gareev,&nbsp;Vitaly V. Andriyashin,&nbsp;Igor Ognev,&nbsp;Fatma Tahhan","doi":"10.1111/jpg.12877","DOIUrl":"https://doi.org/10.1111/jpg.12877","url":null,"abstract":"<div>\u0000 \u0000 <p>Six oil samples from an Upper Devonian carbonate reservoir in the Orenburg field in the SE Volga-Ural Basin (Russia) were analyzed geochemically, together with extracts of five core samples of the Domanik Formation source rock (Frasnian-Tournaisian) from a well located in the south of the basin. Biomarker analyses of saturated and aromatic oil fractions were combined with new data on the molecular structure of asphaltene in order to investigate source rock organic matter input, depositional environment, and thermal maturity. The studied oil samples have high API values (31°–37°) and saturated hydrocarbon contents up to 66%, suggesting that they were generated by a thermally mature source rock and consistent with high contents of С₆–С₁₄ <i>n-</i>alkanes relative to C₁₅₊ of the oil-asphaltene fraction. The molecular structure of asphaltene derived from pyrolysis-gas chromatograpy-mass spectrometry (Py-GC-Ms) analyses also suggests that the oils were generated by a source rock containing marine Type II kerogen, consistent with the H/C atomic ratio up to 1.25. Bulk kinetic analyses of the asphaltene showed a relatively broad range of activation energies between 40 and 58 kcal/mol and a frequency factor (A) of 12E+14/1 s. The biomarker characteristics of aliphatic and aromatic fractions in the studied oils suggest that they were generated by carbonate-rich source rocks containing organic matter of marine algal origin deposited under anoxic conditions. Furthermore, maturity-sensitive biomarker parameters show that the oils were generated at peak oil window maturities. Oil-source rock correlations of biomarker proxies indicated that the analyzed oils from the Orenburg field were mainly generated by carbonate-rich shaley source rocks in the Domanik Formation.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 1","pages":"58-81"},"PeriodicalIF":1.8,"publicationDate":"2025-01-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143121334","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":"Bulk Organic Matter Characteristics and Hydrocarbon Generation–Expulsion Modeling of Middle Jurassic–Lower Cretaceous Source Rocks in the Abadan Plain, Southern Mesopotamian Basin, SW Iran","authors":"Buyuk Ghorbani,&nbsp;Hossain Rahimpour-Bonab,&nbsp;Vahid Tavakoli,&nbsp;Navid Vahidimotlagh,&nbsp;Hojjat Kazemi","doi":"10.1111/jpg.12878","DOIUrl":"https://doi.org/10.1111/jpg.12878","url":null,"abstract":"<div>\u0000 \u0000 <p>This study examines the bulk organic geochemical properties, the burial and thermal history reconstruction, and timing of hydrocarbon generation of Jurassic and Cretaceous source rocks in the Abadan Plain, within the western Zagros fold-and-thrust belt in SW Iran. Three source rock units were evaluated: the Middle Jurassic (Bajocian–Callovian) Sargelu Formation, the Lower Cretaceous (Neocomian) Garau Formation, and the Lower Cretaceous (Aptian–Albian) Kazhdumi Formation. Rock-Eval pyrolysis and organic petrography analyses revealed that the Sargelu Formation is overmature, with abundant solid bitumen and pyrobitumen, indicating depleted hydrocarbon generation potential. Total organic carbon (TOC) values range from 0.46 to 14.8 wt% with low hydrogen index (HI) values, suggesting no further liquid hydrocarbon generation is possible. The Garau Formation is highly mature with TOC values of 0.44–9.4 wt% and HI values below 400 mg HC/g TOC, confirming that hydrocarbon generation has occurred. While the advanced maturity of both formations prevents direct kerogen-type identification through Rock-Eval results, petrography indicates the Sargelu and Garau formations are indicative of Type II kerogen. The Kazhdumi Formation shows varied maturity levels, ranging from immature to marginally mature, with TOC values between 0.16 and 6.33 wt% and HI values from 72 to 626 mg HC/g TOC, reflecting a mix of Types II and III kerogen.</p>\u0000 <p>The one-/two-dimensional basin modeling conducted across the Azadegan, Yadavaran, Darquain, and Mahshahr fields reveals significant variations in burial depth, thermal history, and hydrocarbon generation potential. Thermal modeling indicates maximum burial temperatures were reached in the late Neogene, with the basal heat flow value of 45 mW/m² for most fields, except in Darquain, where an elevated basal heat flow of 62 mW/m², potentially linked to detachment thrusting within the Hormuz salt caused by the reactivation of basement faults, accelerated thermal maturation of the Sargelu and Garau source rocks. In Darquain, the Sargelu Formation has entered the wet gas window (VRo% ∼1.9), and the Garau Formation. has reached late oil to wet gas maturity (VRo% ∼1.5), while in Azadegan both remain in the late oil window. The Kazhdumi Formation remains immature to marginally mature across all fields. The calculated transformation ratio (TR) shows that the Sargelu and Garau Formation. Source rocks in Darquain have surpassed 90% TR, fully exhausting their liquid hydrocarbon generation potential. These findings offer critical insights into the petroleum system of the Abadan Plain, highlighting areas like Darquain, where hydrocarbons have already been expelled and zones such as Azadegan and Mahshahr, with further oil generation potential.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 1","pages":"29-57"},"PeriodicalIF":1.8,"publicationDate":"2025-01-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143112590","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":"Comparison between Core- and Well Log-Based Identification of Flow Units in the Mid-Cretaceous Bangestan Group Reservoir, Mansuri Field, SW Iran: Implications for Regional Characterization","authors":"Mehdi Daraei,&nbsp;Saeed Afrazi,&nbsp;Mahdi Vasighi,&nbsp;Zohreh Masoumi","doi":"10.1111/jpg.12876","DOIUrl":"https://doi.org/10.1111/jpg.12876","url":null,"abstract":"<div>\u0000 \u0000 <p>Core- and well log-based techniques of reservoir characterization were used to independently assess mid-Cretaceous (Albian–Santonian) flow units in the Bangestan Group reservoir of the Mansuri oilfield, located in the Dezful Embayment of SW Iran. The outcomes of the two techniques were compared to assess their utility in flow unit determination. Core-based reservoir classification using the “Flow Zone Indicator” and “Stratigraphic Modified Lorenz Plot” approaches defined 15 flow units in the Mansuri reservoir, including three speed zones. Well log-based (“K-means” and “linkage clustering”) methodologies provided broadly consistent results with 16 flow units defined in the same reservoir sequence. The log-based reservoir zonation gave a better vertical and laterally continuous representation of the reservoir geometry, while the core-based zonation provided more information about reservoir quality and ranking of the flow units identified. To assess its regional significance, a reservoir zonation combining both techniques was then compared with Bangestan Group reservoirs across SW Iran. The analysis highlighted the influence of regional unconformities and associated subaerial exposure upon reservoir quality and flow unit geometries within the Bangestan reservoir. These exposure surfaces had distinct well log signatures, which could be traced across the region and used to define the regional configuration of the Bangestan Group reservoir in the absence of core data.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 1","pages":"3-28"},"PeriodicalIF":1.8,"publicationDate":"2025-01-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143110971","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":"APPLICATION OF BENZOCARBAZOLE MOLECULAR MIGRATION MARKERS IN RECONSTRUCTING RESERVOIR FILLING AT THE SOLVEIG FIELD, NORWEGIAN NORTH SEA","authors":"Thorsten Uwe Garlichs,&nbsp;Rolando di Primio,&nbsp;Lorenz Schwark","doi":"10.1111/jpg.12870","DOIUrl":"https://doi.org/10.1111/jpg.12870","url":null,"abstract":"<div>\u0000 <p>Benzocarbazole (BC) migration tracers were used to investigate the complex filling of reservoir segments at the Solveig field in the Norwegian North Sea. The study suggests that the benzocarbazole ratio [a]/([a]+[c]) of crude oils and extracts decreases with inferred increasing migration distance. The complex filling history of the Solveig field is evident from the observation of variable degrees of palaeo biodegradation associated with two palaeo oil-water contacts in residual oil zones below non- to moderately biodegraded live oil columns. Live oil properties also vary significantly across the field. Benzocarbazole ratios (BCRs) obtained from oils and reservoir core extracts appear not to be affected by biodegradation and indicate a migration and filling trend from NW to SE. The BCR values were set by the initial phase of filling and do not show any overprint effects as a result of later and more mature oil charges.</p>\u0000 <p>BCRs from both oils and extracts of reservoir cores, particularly those composed of clean sands, helped to reconstruct migration processes in the Solveig field. Migration is construed to have first filled reservoir segment D in the NW of the field and to have continued further east towards segment C, and then via segment B and finally into segment A. Migration then continued along the southern margin of the Haugaland High to a well location to the east of the Solveig field. A fractionation effect for benzocarbazoles derived from oils versus those from extracts was noted and was attributed to differential partitioning behavior. Nevertheless, spatial trends for oil- and extract-derived BCRs were congruent. This allowed the generation of spatially more highly-resolved benzocarbazole datasets for migration assessment by combining data from both samples types (oil and reservoir extracts) if partitioning is accounted for.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 4","pages":"373-394"},"PeriodicalIF":1.8,"publicationDate":"2024-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://onlinelibrary.wiley.com/doi/epdf/10.1111/jpg.12870","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142313292","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":"FACIES PARTITIONING AT REGIONAL AND FIELD SCALES IN THE BARREMIAN KHARAIB-2 CARBONATES, UAE","authors":"Pierre Gatel,&nbsp;Jean Borgomano,&nbsp;Jeroen Kenter,&nbsp;Tarek Mecheri","doi":"10.1111/jpg.12869","DOIUrl":"https://doi.org/10.1111/jpg.12869","url":null,"abstract":"<p>Carbonates in the Lower Cretaceous (Barremian to early Aptian) Kharaib Formation are reservoir rocks at giant oil fields in the UAE and Qatar. The Barremian Kharaib-2 member (K60), the focus of this study, is in general composed of a regionally continuous succession of high-energy, shallow-water limestones bounded above and below by “dense” low-energy mud-rich strata. Despite several decades of research, conventional carbonate facies classification schemes and resulting facies groupings for the Kharaib-2 member have failed to show a statistically acceptable correlation with core- and log-derived petrophysical data. Moreover, sedimentary bodies potentially responsible for dynamic reservoir heterogeneities have not clearly been identified. This paper proposes a standardized facies classification scheme for the Kharaib-2 carbonates based on vertical facies proportion curves (VPCs) and variogram analyses of core data to construct stratigraphic correlations at both field and regional scales. Data came from 295 cored wells penetrating the Kharaib-2 member at ten fields in the on- and offshore UAE. Thin, dense intervals separating reservoir units were adopted as fourth-order transgressive units and were used for stratigraphic correlation. Field-scale probability maps were used to identify sedimentary bodies such as shallow-water rudistid shoals.</p><p>Regional stratigraphic correlations of the Kharaib-2 member carbonates based on the VPCs identified variations in depositional environments, especially for the lower part of the reservoir unit; depositional facies at fields in the SE of the UAE were interpreted to be more distal compared to those at offshore fields to the NW. At a field scale, the VPCs failed to identify significant lateral variations in the carbonates. However, variogram analyses of cored wells showed spatial concentrations of specific facies in the inner ramp domain which could be correlated with high-energy depositional bodies such as shoals dominated by rudist debris. The bodies were sinusoidal in plan view with lengths of up to 8 km and widths of ca. 1 km. Although similar-shaped bodies with these dimensions have been reported from other carbonate depositional systems, they have not previously been reported in the Kharaib Formation. At a regional (inter-field) scale, the stratigraphic correlation of standardized sedimentary facies remains problematic; however, mapping of facies associations and their relative proportions relative to their environments of deposition demonstrated new patterns for the stratigraphic architecture of the Kharaib-2 member in the UAE.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 4","pages":"347-372"},"PeriodicalIF":1.8,"publicationDate":"2024-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142313405","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":"STRATIGRAPHY AND DIAGENESIS OF THE THAMAMA-B RESERVOIR ZONE AND ITS SURROUNDING DENSE ZONES IN ABU DHABI OILFIELDS AND EQUIVALENT OMAN OUTCROPS","authors":"S. N. Ehrenberg,&nbsp;J. E. Neilson,&nbsp;E. Gomez-Rivas,&nbsp;N. H. Oxtoby,&nbsp;I.S.A.J. Jayachandran,&nbsp;Q. Adlan,&nbsp;V. C. Vahrenkamp","doi":"10.1111/jpg.12871","DOIUrl":"https://doi.org/10.1111/jpg.12871","url":null,"abstract":"<p>We review published studies characterizing the Thamama-B reservoir zone in the upper Kharaib Formation (late Barremian) in Abu Dhabi oilfields and at outcrops in Oman. Available data for oxygen and carbon isotope compositions, fluid inclusion measurements, cement abundance and formation water composition are interpreted in terms of a paragenetic model for the Thamama-B in field F in Abu Dhabi where the interval is deeply buried. The present synthesis provides a useful basis for understanding and predicting reservoir quality in static models and undrilled prospects, as well as for planning promising directions for further research. The goals of this study were to summarize the geologic setting and petrology of the Thamama-B reservoir and its surrounding dense zones, and to examine how sedimentology, stratigraphy and diagenesis have interacted to control porosity and permeability. Results that may have useful applications for similar microporous limestone reservoirs in general include:</p><p>\u0000 </p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 4","pages":"395-430"},"PeriodicalIF":1.8,"publicationDate":"2024-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142313404","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":"GEOCHEMICAL ANALYSES OF EOCENE OILS IN DEEPLY BURIED SANDSTONE RESERVOIRS IN THE DONGYING DEPRESSION, BOHAI BAY BASIN, NE CHINA","authors":"Xiaoxiao Zhou,&nbsp;Xiaojun Li,&nbsp;Xu Song,&nbsp;Yuzhi Li,&nbsp;Xuejun Wang,&nbsp;Ke Han,&nbsp;Haiqing Yan","doi":"10.1111/jpg.12872","DOIUrl":"https://doi.org/10.1111/jpg.12872","url":null,"abstract":"<p>We report the results of organic geochemical analyses of 19 crude oil samples from reservoir sandstones in the 4th Member of the Eocene Shahejie Formation from wells in the Minfeng Sag, Dongying Depression, Bohai Bay Basin (NE China). In addition, 42 Shahejie Formation core samples of dark-coloured mudstones, including 28 extracts, were analysed. Geochemical data included Rock-Eval measurements, gas chromatography, GC-MS and diamondoid analyses.</p><p>Maceral analyses showed that mudstones in the 4th Member of the Shahejie Formation (“Es₄”) contain Types I and II₁ kerogen. The member can be divided into upper (Es₄s) and lower (Es₄x) intervals. Oil-prone Es₄s rock samples have good to excellent hydrocarbon-generating potential based on calculated initial TOC values; Rock-Eval T_max values indicate that they are sufficiently mature for hydrocarbon generation. Analytical results suggest that both Es₄s and Es₄x mudrocks are potential source rocks for oils produced at fields in the Minfeng Sag.</p><p>Analysed crude oils from the Minfeng Sag were classified into three genetic groups. Group I oils are mature to highly mature and have undergone a moderate degree of thermal cracking. They are characterized by a low <i>β</i>-carotane/nC₂₅ ratio and C₃₀ 4-methylsterane index (4MI); high values of oleanane index (oleanane /C₃₀-hopane), C₂₇ diasterane/C₂₇ regular sterane (C₂₇Dia/C₂₇), regular sterane/17<i>α</i> hopane and gammacerane/C₃₀ hopane (G/H); and medium pristane/phytane ratios (Pr/Ph). This suggests that Group I oils are mostly derived from source rocks in the upper part of the Es₄x unit which are interbedded with evaporites. Group II oils are mature and have high 4MI and Pr/Ph ratios, low oleanane index, regular sterane/17<i>α</i> hopane and C₂₇Dia/C₂₇ ratios, and medium<i>β</i>-carotane/nC₂₅ and G/H. These features are similar to those of Es₄s source rocks, indicating their genetic correlation. Group III oils show the lowest maturity and high<i>β</i>-carotane/nC₂₅ and regular sterane/17<i>α</i> hopane, and low oleanane index, Pr/Ph and 4MI. Previously-published data indicates that oils similar to those in Group III were mainly sourced by Es₄s mudstones.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"47 4","pages":"431-454"},"PeriodicalIF":1.8,"publicationDate":"2024-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142313293","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. 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}