Journal of Petroleum Geology最新文献

{"title":"Thermal History and Source Rock Maturity Modeling of the Akri-Bijeel Area, NW Zagros Fold Belt, Kurdistan Region, Northern Iraq","authors":"Ayad N. F. Edilbi,&nbsp;Stephen A. Bowden,&nbsp;Abdalla Y. Mohamed,&nbsp;David Muirhead","doi":"10.1111/jpg.12883","DOIUrl":"https://doi.org/10.1111/jpg.12883","url":null,"abstract":"<div>\u0000 \u0000 <p>The Akri-Bijeel area in the NW Zagros fold-and-thrust belt (Kurdistan region of northern Iraq) has been the focus of petroleum exploration, and its subsurface has been drilled extensively. This makes it possible to combine outcrop studies of this mountainous region with subsurface data. The region has five potential or regionally proven source rock units: the Ora Formation (Devonian–Carboniferous), the Baluti Formation (Upper Triassic), the Sargelu and Naokelekan Formations (Middle–Upper Jurassic), and the Chia Gara Formation (Upper Jurassic–Early Cretaceous). The area has a complex tectonic history, and it is therefore not necessarily clear when source rocks may have been active or inactive and therefore their generative potential. This makes basin modeling particularly useful as a tool to evaluate source rock thermal maturity and the timing of hydrocarbon generation and the amounts expelled. PetroMod version 2017 was used to reconstruct 1D burial and thermal history for four wells. The reconstructed burial and thermal history models were then calibrated against porosity, pressure, temperature, and vitrinite reflectance data. The results of constrained models show significant variations in heat flow through time, with high heat flows during Mesozoic rifting followed by low values, with sharp decreases in heat flow since the end of the Miocene. The present-day average geothermal gradient at Akri-Bijeel is low (18°C/km), with an average heat flow of 32 mW/m². The low heat flow can best be explained by the rapid deposition of a thick, cold Cenozoic sedimentary section, Zagros thrusting and accompanying uplift and exhumation, and the ongoing circulation of cold meteoric waters under hydrodynamic conditions. Thermal maturity modeling reveals that the present-day oil window extends from a depth of 860 m in well Bakrman-1 down to 5090 m in well Bijeel-1. The generation of hydrocarbons in the modeled source rocks (except for the Ora Formation) continued until it was halted by Zagros folding and thrusting in the Miocene, after which generation ceased or became negligible. Models predict that the majority of the oil discovered at Akri-Bijeel was generated by the Sargelu, Naokelekan, and Chia Gara Formations. On the basis of 1D basin modeling, the Paleozoic Ora Formation generated oil during the Early Triassic and is now in the gas window, and Jurassic source rocks generated oil during the Cretaceous. Volumetric calculations for the five source rock formations modeled in the area suggest that around 4.94 billion tons (or 36 billion barrels [bbl]) of petroleum have been expelled and charged to the reservoirs, indicating significant remaining potential for undiscovered resources.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 2","pages":"134-155"},"PeriodicalIF":1.8,"publicationDate":"2025-04-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143809482","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":"Evaporite Collapse, Karst and Detrital Carbonate Breccias in the Zechstein Reservoir of the Alma Field, Central North Sea: Characterisation, Controls and Implications for Reservoir Quality","authors":"Peter Gutteridge","doi":"10.1111/jpg.12882","DOIUrl":"https://doi.org/10.1111/jpg.12882","url":null,"abstract":"<p>The Zechstein reservoir of the Alma field (originally Argyll, formerly Ardmore) comprises at least four Zechstein carbonate and evaporite sequences, the latter dissolved during Jurassic exposure, forming a series of collapse breccias that were modified by karst, erosion and faulting. It is essential to identify the different origins of these breccia bodies because these processes produce zones of excess permeability with contrasting stratiform and cross-cutting geometry. In core, these breccia bodies are distinguished by their clast assemblage and fabric, the relationship of clasts and matrix, the presence of sedimentary structures and the nature of their upper and lower boundaries. Predicting the distribution, architecture and reservoir quality of these geobodies is key to managing reservoir development programmes in similar carbonate fields affected by karst, collapse brecciation, reworking and faulting. It requires an understanding of the stratigraphy of the reservoir, particularly that of any internal aquicludes, mapping the palaeogeology of the top reservoir and understanding the onlap history of the exposure surface. The Alma reservoir contains a field-wide impermeable layer, the Sapropelic Dolomite deposited in a basinal setting that controlled the influx of meteoric water during exposure. The lower dolomite breccia, which underlies the Sapropelic Dolomite, represents a stratiform evaporite collapse breccia formed by dissolution in meteoric water that was introduced down-dip beneath the Sapropelic Dolomite. The upper dolomite breccia formed by dissolution of one or more evaporite units by direct infiltration of meteoric water from the top Zechstein surface. During the Jurassic, the top Zechstein surface was modified by karst, apart from the SW part of the Alma field, where the Zechstein was buried by the onlapping impermeable Triassic Smith Bank Formation. Core also shows that there is limited karst development over the sub-crop of the Sapropelic Dolomite. The Zechstein is partly onlapped by Jurassic detrital conglomerates reworked from the brecciated Zechstein and deposited in alluvial fan, shore face and low-energy subtidal settings along the western margin of the field. A well-preserved matrix pore system can be expected within collapse breccias and karst cavities where the Zechstein is overlain by Jurassic detrital sandstone and carbonate breccias. However, in areas onlapped by impermeable sediment, the karst and collapse breccias are likely to contain much poorer reservoir quality.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 2","pages":"111-133"},"PeriodicalIF":1.8,"publicationDate":"2025-03-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://onlinelibrary.wiley.com/doi/epdf/10.1111/jpg.12882","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143809944","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":"Source Rock Properties, Depositional Environment and Kerogen Degradation Kinetics of Lower Permian Shales from the Ib River Sub-Basin, Mahanadi Basin, Eastern India","authors":"Nihar Ranjan Kar,&nbsp;Devleena Mani Tiwari,&nbsp;John Buragohain,&nbsp;Bodhisatwa Hazra,&nbsp;E. V. S. S. K. Babu,&nbsp;Bala Subrahanyam Seetha,&nbsp;Mohana Krishna Reddy Mudiam,&nbsp;Abhayanand S. Maurya","doi":"10.1111/jpg.12881","DOIUrl":"https://doi.org/10.1111/jpg.12881","url":null,"abstract":"<div>\u0000 \u0000 <p>Lower Permian organic-rich shales and coals from the Ib River sub-Basin, part of the Mahanadi Basin in Eastern India, were studied using Rock-Eval pyrolysis, kerogen kinetics, biomarker, and organic carbon isotopic analyses to investigate the source rock characteristics, depositional environment, and thermal degradation kinetics of the sedimentary organic matter (OM). The samples are organically rich (&gt;5 wt% total organic carbon [TOC]) and possess higher hydrocarbon generation potential (&gt;54 mgHC/g rock). The primary contributors to the OM supply were identified as terrestrial plants, supplemented by emergent aquatic plants, resulting in a Type II–III kerogen. The broader activation energy indicates OM input from heterogeneous sources, whereas the earlier and faster kerogen transformation ratio (TR), along with a high hydrocarbon generation rate (HGR), suggests excellent kerogen quality. Despite the samples’ favorable source rock characteristics, their relatively low <i>T</i>_max values (&lt;435°C) indicate immaturity, limiting their potential for natural hydrocarbon production. Marine incursions have been identified in the Barakar Formation of the Ib River sub-Basin, accompanied by climatic fluctuations (inferred from <i>P</i>_aq, average chain length [ACL], and <i>δ</i>¹³C) that correspond to alternating dry and wet periods during the deposition of various lithotypes. The samples exhibit an abundance of even lower <i>n-</i>alkanes, indicating that the OM inputs are derived from aquatic vegetation rather than microbial activity. The gammacerane index (GI) averages ∼0.29 for the Barakar Formation and ∼0.24 for the Karharbari Formation, indicating greater water stratification and higher salinity in the Barakar Formation compared to the Karharbari Formation. Likewise, other key parameters such as tricyclic terpanes (TTs) and polyaromatic hydrocarbons (fluorenes [FLs], dibenzothiophenes [DBTs], and DBFs) differentiate certain Barakar samples as being deposited in a saline lacustrine environment, whereas the other Barakar samples and all Karharbari samples indicate a swampy, oxic environment. The pristane (Pr)/phytane (Ph) ratio supports this conclusion, indicating a reducing to oxidizing depositional setting for the Barakar Formation, while suggesting an oxic environment for the Karharbari Formation. Integrating all parameters, we conclude that the Barakar Formation was influenced by marine activities during Permian Period. Drawing on our research and prior studies, we propose two scenarios for marine interaction in the Ib River sub-Basin during the Permian Period: Either the region was covered by an extended marine embayment or marine influence extended to the NW-SE slope of the basin, notably affecting the Rewa region in the northwest.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 2","pages":"85-110"},"PeriodicalIF":1.8,"publicationDate":"2025-03-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143809836","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 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}