Journal of Petroleum Geology最新文献

{"title":"HYDROCARBON GENERATION AND MIGRATION FROM BARREMIAN – APTIAN SOURCE ROCKS, NORTHERN ORANGE BASIN, OFFSHORE WESTERN SOUTH AFRICA: A 3D NUMERICAL MODELLING STUDY","authors":"C. A. Samakinde,&nbsp;J. M. van Bever Donker,&nbsp;R. Durrheim,&nbsp;M. Manzi","doi":"10.1111/jpg.12785","DOIUrl":"10.1111/jpg.12785","url":null,"abstract":"<p>A 3D numerical modelling workflow was applied to the Barremian—Aptian source rock interval in a shelfal to lower slope area of the northern Orange Basin, offshore western South Africa. The main objective was to investigate the timing of hydrocarbon generation and migration. Hydrocarbon migration has previously been investigated in the south of the basin by relating gas escape features with structural elements as seen on seismic sections, but migration pathways are still poorly understood. The modelling study was based on data from three exploration wells (AO-1, AE-1 and AF-1) together with 42 2D seismic sections totalling 3537 km in length, and a 3D seismic cube covering an area of 750 sq. km.</p><p>Modelled formation temperatures increase from north to south in the study area and were consistent with downhole temperatures at well locations. However, there is variation between measured and modelled values of vitrinite reflectance (VR), especially in the Turonian and Cenomanian intervals. The measured VR is lower than the modelled VR within the Turonian section in the north of the study area, suggesting that erosion has affected the thermal maturity of the sediments. However, in the Cenomanian interval, the measured VR is higher than the modelled VR. Uplift, increased erosion in the hinterland and sediment transport to the coastal areas resulted in Cenomanian progradation of the Orange Basin fill. This together with a heat flow pulse resulted in increased thermal maturities in the study area.</p><p>Modelling results show that hydrocarbon generation began in the central part of the study area by 116 Ma and reached a peak in the Late Cretaceous (65 Ma). Hydrocarbon migration began at about 110 Ma with an expulsion efficiency of 0.77. At the present day, ∼100% transformation of reactive kerogen into hydrocarbons has taken place in the central part of the study area, with random gas migration within Cenomanian and Albian reservoirs. Modelled oil migration likely influenced by hydrodynamic factors is down-dip (westwards), towards deeper-water, more distal parts of the basin.</p><p>Gas saturation on a reactivated listric fault, which was ∼100% saturated at 93 Ma, declined to ∼15% by 65 Ma. This decrease in gas saturation is linked to uplift of the African margin in the Late Cretaceous which resulted in fault reactivation and re-migration of gas.</p><p>Despite the uncertainties which are associated with petroleum systems modelling, the study provides an insight into hydrocarbon migration in the northern part of the Orange Basin and contributes to the de-risking of future oil and gas exploration in this area.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"44 2","pages":"187-208"},"PeriodicalIF":1.8,"publicationDate":"2021-03-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12785","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47191450","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":"RESERVOIR PROPERTIES OF BARREMIAN–APTIAN URGONIAN LIMESTONES, SE FRANCE, PART 2: INFLUENCE OF DIAGENESIS AND FRACTURING","authors":"J. Cochard,&nbsp;P. Léonide,&nbsp;J. Borgomano,&nbsp;Y. Guglielmi,&nbsp;G. Massonnat,&nbsp;J-P. Rolando,&nbsp;L. Marie,&nbsp;A. Pasquier","doi":"10.1111/jpg.12780","DOIUrl":"10.1111/jpg.12780","url":null,"abstract":"<p>Integrated sedimentological, diagenetic and structural analyses have been carried out on microporous and tight Urgonian (Barremian – Aptian) limestones in a study area in SE France in order to understand the influence of diagenetic changes and structural deformation on the spatial distribution of reservoir properties. A diagenetic history for the carbonates was established and was divided into phases which correspond to episodes of regional geodynamic activity. Petrographic (optical, SEM and cathodoluminescence microscopy), structural and geochemical (δ¹⁸O, δ¹³C) studies were carried out to characterize the cement phases in the carbonates, especially micrite and blocky calcite, and to investigate their relationship with episodes of fracturing.</p><p>Eleven calcite cement phases and four micritic cement phases were identified in relation to the two main phases of structural deformation which affected the Urgonian limestones. A first phase of micrite cementation occurred early in the diagenetic history and was linked to early marine cementation at the tops and bases of depositional cycles during the Barremian. A major phase of micrite recrystallization, which generated microporosity in carbonates that had previously been preserved from early cementation, was followed by a first phase of blocky calcite which occluded intergranular pore spaces. The blocky cement formed in a shallow burial meteoric environment and contributed to the preservation of microporosity during late Durancian tectonism (Albian – Cenomanian). A second phase of blocky calcite is associated with fracture activation during latest Eocene (Priabonian) – Oligo-Miocene extension.</p><p>Reservoir rock-types (RRTs) proposed in a previous study were consistent with the diagenetic characteristics and the results of δ¹³C / δ¹⁸O analyses. Microporous RRTs formed as a result of early to late shallow burial processes and display low δ¹³C values; whereas cemented RRTs developed both due to early marine cementation (with high δ¹³C values) and/or as a result of cementation related to fluid flow linked to the reactivation of faults and fractures. This suggests that some late diagenetic and microstructural processes were pre-determined by early diagenetic changes in the carbonates. The resulting stratigraphic architecture consists of a vertical stacking of weakly fractured microporous limestone intervals alternating with highly fractured, cemented limestone units.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"44 1","pages":"97-114"},"PeriodicalIF":1.8,"publicationDate":"2020-12-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12780","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46336891","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 PROSPECT AREA YIELD (PAY) METHOD: A REMEDY FOR OVER-OPTIMISTIC VOLUMETRIC ESTIMATIONS IN CONVENTIONAL PETROLEUM EXPLORATION","authors":"D. G. Quirk,&nbsp;D. W. Schmid","doi":"10.1111/jpg.12778","DOIUrl":"10.1111/jpg.12778","url":null,"abstract":"<p>The frequently stated problem of under-delivery in oil and gas exploration is largely due to overprediction in the volumetric size of prospects rather than to the misinterpretation of risk. In an effort to deal with the significant degree of uncertainty inherent in sub-surface evaluations, the standard method involves building a stochastic volumetric model of the potential container by choosing distributions and probabilities of the gross rock volume, the simulated column height, and the average 3D net/gross, as well as of other reservoir and fluid parameters. Unfortunately, prior to drilling, the three main inputs to the model are difficult to constrain as they are closely tied to the seismic interpretation rather than to historical information. By contrast, a source of hard data is available from existing discoveries and wells in the form of statistics for the play or analogue play, the most useful of which are: (i) the footprint area of the discoveries; (ii) the properties of net reservoir, encapsulated in an area yield parameter MMboe/km²; and (iii) the downside size of the discoveries, specifically the inferred P99 recoverable resource. In this paper, we propose a method called Prospect Area Yield (PAY) to assess the potential size of an exploration prospect which simply integrates these statistical data with the most reliable information from seismic mapping. The main step involves calculating an upside volume by multiplying a mid-case MMboe/km² yield with a mapped reasonable closure area for the prospect. This upside volume is assigned a probability which is currently assumed to be P10, implying that 90% of discovery outcomes will be smaller. A probabilistic distribution of the recoverable resource for the prospect is then produced by using the upside volume (P10) and the inferred P99 to construct a lognormal trend. The method can be tested by companies using lookbacks to fine-tune the probability of the upside volume to ensure that exploration predictions effectively match historical reality. In the meantime, it is recommended that the PAY method, which is available as a free online tool, is used as a check on the results of stochastic models.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"44 1","pages":"47-68"},"PeriodicalIF":1.8,"publicationDate":"2020-12-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12778","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45264984","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":"TEMPORAL AND SPATIAL DISTRIBUTION OF ORIGINAL SOURCE ROCK POTENTIAL IN UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SHALES, DANISH CENTRAL GRABEN, NORTH SEA","authors":"Henrik I. Petersen,&nbsp;Michael Hertle","doi":"10.1111/jpg.12776","DOIUrl":"10.1111/jpg.12776","url":null,"abstract":"<p>The Danish Central Graben, North Sea, is a mature oil- and gas-producing basin in which the principal source rocks are the Upper Jurassic – lowermost Cretaceous marine shales of the Farsund Formation (Kimmeridge Clay Formation equivalent), with possible additional potential in the directly underlying Lola Formation. This study investigates the initial source rock potential of the basin by evaluating the original (back-calculated) source rock properties (TOCo, S2o, HIo) of the shales in the Farsund and Lola Formations within a temporal and spatial framework. About 4800 samples from 81 wells regionally distributed in the Danish Central Graben were included in the study. Samples for source rock analysis were in general collected with varying sampling density from the entire shale section. The shale section has been divided into seven units (referred to as pre-FSU1 to FSU6; FSU: Farsund Seismic Unit) which are delineated by mappable, regional-scale seismic markers. For the pre-FSU1 and FSU2–FSU6 units, the number of available samples ranged from 608 to 1145, while 433 samples were available for FSU1. Good source rock quality varies through space and time and reflects both the structural development of the basin and the effects of the Late Jurassic transgression, with primary kitchen areas developing in the Tail End Graben, Feda Graben, Gertrud Graben and the Rosa Basin. The source rock quality of the shales increases gradually through time and reaches a maximum in FSU6 which includes the “hot shales” of the Bo Member. The maximum source rock quality appears to correspond to an original Hydrogen Index (HIo) of approximately 675 mg HC/g TOC. The proportion of oil-prone samples per unit (with HIo &gt;350 mg HC/g TOC) ranges from 7 to 11% in the pre-FSU1 to FSU2 units (Lower Kimmeridgian – Lower Volgian), increasing to 18 – 22% in FSU3 and FSU4/FSU5 (Lower Volgian – Middle Volgian), and reaching a maximum of 53% in FSU6 (Upper Volgian – Ryazanian). FSU6 is the most prolific oil-prone source rock interval, but the presence of oil-prone intervals in older and deeper parts of the shale succession is important for assessing the generation potential of the Upper Jurassic petroleum system. The breakdown of the Upper Jurassic – lowermost Cretaceous shale section into mappable seismic units with assigned original source rock properties will contribute to a considerably improved understanding of the temporal and spatial distributions of source rock quality in the Danish Central Graben.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"44 1","pages":"5-24"},"PeriodicalIF":1.8,"publicationDate":"2020-12-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1111/jpg.12776","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43768547","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":"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":"44 1","pages":"69-96"},"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":"44 1","pages":"115-116"},"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":"44 1","pages":"25-46"},"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":"43 4","pages":"401-417"},"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":"43 4","pages":"383-400"},"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":"43 4","pages":"363-382"},"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}