The Experts below are selected from a list of 234 Experts worldwide ranked by ideXlab platform

Sadegh Elyasi - One of the best experts on this subject based on the ideXlab platform.

  • Petroleum Source Rock potential of the piranj oil field zagros basin
    Marine and Petroleum Geology, 2016
    Co-Authors: Sadegh Elyasi
    Abstract:

    Abstract Zagros basin constitutes one of the most prolific hydrocarbon producing habitats and the second largest basin in the Middle East. The Piranj oil field is part of The Middle Cretaceous–Early Miocene Petroleum System in Zagros basin and southwest of Iran. This study mainly focuses on organic matter characterization and thermal history of two potential Source Rock's name Gurpi and Pabdeh formations. To evaluate the candidate Source Rocks, 50 cuttings and core samples of these Rock units from well M-11 (the only well drilled up to the probable Source Rocks) were analysed, using Rock-Eval pyrolysis and organic petrography. In addition, 1D basin modelling and reconstruction of burial history were applied to analyse the thermal history of these Source Rocks. The green shale, limestone and marls of Pabdeh formation with average 2.52%wt Total Organic Matter (TOC) and Hydrogen Index (HI) higher than 250 is more favourite Source Rock in comparison with dark shale and limestone of Gurpi formation by 1.8%wt and HI  R ) (from 0.44% to 1.23%) indicate that samples from the well M-11 have reached maturities corresponding to early to peak oil generation. Reconstruction of the thermal history suggests various steady heat flow values (53–91 mW/m 2 ) resulted in the best fit between the observed and the calculated bottom hole temperatures (BHT) and Vitrinite reflectance (V R ) in the model. Rock-Eval pyrolysis results and Vitrinite reflectance (V R ) suggest that the most of samples are in the early mature to mature stage of hydrocarbon generation. Furthermore, according to the modelling results, Petroleum generation from the studied Source Rocks has began after deposition of related seal-Rocks and formation of traps which ensures entrapment and preservation of migrated hydrocarbon.

  • Petroleum Source-Rock potential of the Piranj oil field, Zagros basin
    Marine and Petroleum Geology, 2016
    Co-Authors: Sadegh Elyasi
    Abstract:

    Zagros basin constitutes one of the most prolific hydrocarbon producing habitats and the second largest basin in the Middle East. The Piranj oil field is part of The Middle Cretaceous–Early Miocene Petroleum System in Zagros basin and southwest of Iran. This study mainly focuses on organic matter characterization and thermal history of two potential Source Rock's name Gurpi and Pabdeh formations. To evaluate the candidate Source Rocks, 50 cuttings and core samples of these Rock units from well M-11 (the only well drilled up to the probable Source Rocks) were analysed, using Rock-Eval pyrolysis and organic petrography. In addition, 1D basin modelling and reconstruction of burial history were applied to analyse the thermal history of these Source Rocks. The green shale, limestone and marls of Pabdeh formation with average 2.52%wt Total Organic Matter (TOC) and Hydrogen Index (HI) higher than 250 is more favourite Source Rock in comparison with dark shale and limestone of Gurpi formation by 1.8%wt and HI 

F Zamani - One of the best experts on this subject based on the ideXlab platform.

  • preliminary Petroleum Source Rock evaluation of the asmari pabdeh reservoirs karanj and parsi oil fields zagros iran
    Journal of Petroleum Science and Engineering, 2015
    Co-Authors: Bahman Soleimani, F Zamani
    Abstract:

    Abstract Petroleum Source Rock evaluation is formed a main part in the oil field study. The present work is focused on the Dezful Embayment, the Karanj and Parsi oil fields, Zagros. To evaluate the Source Rocks, oil–oil and oil–Rock correlation, multidisciplinary methods were used. Rock-Eval pyrolysis data and Illite Crystallinity Index indicated that the Pabdeh Formation is in beginning of oil generation. The kerogen is principally type II. The Gurpi Formation is in the same maturity level as well. Different parameters such as normal alkanes ratios, CPI, Pri/Phy, Pri/n-C17, Phy/n-C18 were determined. These reservoirs seem to be charged partially by the Pabdeh Formation itself. To make the reservoir oils correlation with the possible Source Rocks, 6 samples were selected and analysed using GC–MS procedure. Ts/Ts+Tm ratio and C29bb/(bb+aa) sterane to C2920S/(20S+20R) sterane variation are showing high maturity of the Asmari oils in these fields. C29/ (C27+C28+C29) diasterane to C29/C30 hopane ratio are the same in all analysed samples. Carbon isotope data (δ13C) are −26.3, −26.7 and −26.7‰ for saturated and −25.6, −25.8, and −26.1‰ for aromatic fractions of Karanj–Parsi oils and Pabdeh bituminous shale, respectively. All geochemical and isotopic data demonstrated that the oil of Pabdeh and Asmari reservoirs in the Karanj and Parsi oil fields have the same Source and are belong to paraphinic oils family.

  • Preliminary Petroleum Source Rock evaluation of the Asmari–Pabdeh reservoirs, Karanj and Parsi oil fields, Zagros, Iran
    Journal of Petroleum Science and Engineering, 2015
    Co-Authors: Bahman Soleimani, F Zamani
    Abstract:

    Abstract Petroleum Source Rock evaluation is formed a main part in the oil field study. The present work is focused on the Dezful Embayment, the Karanj and Parsi oil fields, Zagros. To evaluate the Source Rocks, oil–oil and oil–Rock correlation, multidisciplinary methods were used. Rock-Eval pyrolysis data and Illite Crystallinity Index indicated that the Pabdeh Formation is in beginning of oil generation. The kerogen is principally type II. The Gurpi Formation is in the same maturity level as well. Different parameters such as normal alkanes ratios, CPI, Pri/Phy, Pri/n-C17, Phy/n-C18 were determined. These reservoirs seem to be charged partially by the Pabdeh Formation itself. To make the reservoir oils correlation with the possible Source Rocks, 6 samples were selected and analysed using GC–MS procedure. Ts/Ts+Tm ratio and C29bb/(bb+aa) sterane to C2920S/(20S+20R) sterane variation are showing high maturity of the Asmari oils in these fields. C29/ (C27+C28+C29) diasterane to C29/C30 hopane ratio are the same in all analysed samples. Carbon isotope data (δ13C) are −26.3, −26.7 and −26.7‰ for saturated and −25.6, −25.8, and −26.1‰ for aromatic fractions of Karanj–Parsi oils and Pabdeh bituminous shale, respectively. All geochemical and isotopic data demonstrated that the oil of Pabdeh and Asmari reservoirs in the Karanj and Parsi oil fields have the same Source and are belong to paraphinic oils family.

Donald A. Goddard - One of the best experts on this subject based on the ideXlab platform.

  • ReSource Assessment of the In-Place and Potentially Recoverable Deep Natural Gas ReSource of the Onshore Interior Salt Basins, North Central and Northeastern Gulf of Mexico
    2005
    Co-Authors: Ernest A. Mancini, Paul Aharon, Donald A. Goddard, Roger Barnaby
    Abstract:

    The principal research effort for Year 2 of the project has been Petroleum system characterization and modeling. Understanding the burial, thermal maturation, and hydrocarbon expulsion histories of the strata in the onshore interior salt basins of the North Central and Northeastern Gulf of Mexico areas is important in hydrocarbon reSource assessment. The underburden and overburden Rocks in these basins and subbasins are a product of their rift-related geohistory. Petroleum Source Rock analysis and initial thermal maturation and hydrocarbon expulsion modeling indicated that an effective regional Petroleum Source Rock in the onshore interior salt basins and subbasins, the North Louisiana Salt Basin, Mississippi Interior Salt Basin, Manila Subbasin and Conecuh Subbasin, was Upper Jurassic Smackover lime mudstone. The initial modeling also indicated that hydrocarbon generation and expulsion were initiated in the Early Cretaceous and continued into the Tertiary in the North Louisiana Salt Basin and the Mississippi Interior Salt Basin and that hydrocarbon generation and expulsion were initiated in the Late Cretaceous and continued into the Tertiary in the Manila Subbasin and Conecuh Subbasin. Refined thermal maturation and hydrocarbon expulsion modeling and additional Petroleum Source Rock analysis have confirmed that the major Source Rock in the onshore interior salt basins and subbasins is Upper Jurassic Smackover lime mudstone. Hydrocarbon generation and expulsion were initiated in the Early to Late Cretaceous and continued into the Tertiary

  • ReSource Assessment of the In-Place and Potentially Recoverable Deep Natural Gas ReSource of the Onshore Interior Salt Basins, North Central and Northeastern Gulf of Mexico
    2005
    Co-Authors: Ernest A. Mancini, Donald A. Goddard
    Abstract:

    The principal research effort for the first six months of Year 2 of the project has been Petroleum system characterization. Understanding the burial and thermal maturation histories of the strata in the onshore interior salt basins of the North Central and Northeastern Gulf of Mexico areas is important in Petroleum system characterization. The underburden and overburden Rocks in these basins and subbasins are a product of their rift-related geohistory. Petroleum Source Rock analysis and thermal maturation and hydrocarbon expulsion modeling indicate that an effective regional Petroleum Source Rock in the onshore interior salt basins, the North Louisiana Salt Basin, Mississippi Interior Salt Basin, Manila Subbasin and Conecuh Subbasin, was the Upper Jurassic Smackover lime mudstone. The Upper Cretaceous Tuscaloosa shale was an effective local Petroleum Source Rock in the Mississippi Interior Salt Basin and a possible local Source bed in the North Louisiana Salt Basin. Hydrocarbon generation and expulsion was initiated in the Early Cretaceous and continued into the Tertiary in the North Louisiana Salt Basin and the Mississippi Interior Salt Basin. Hydrocarbon generation and expulsion was initiated in the Late Cretaceous and continued into the Tertiary in the Manila Subbasin and Conecuh Subbasin. Reservoir Rocks include Jurassic, Cretaceous and Tertiary siliciclastic and carbonate strata. Seal Rocks include Jurassic, Cretaceous and Tertiary anhydrite and shale beds. Petroleum traps include structural and combination traps

Wan Hasiah Abdullah - One of the best experts on this subject based on the ideXlab platform.

  • Petroleum Source Rock properties of the neogene bhuban shales bengal basin bangladesh
    2015
    Co-Authors: Md Farhaduzzaman, Wan Hasiah Abdullah, Md Aminul Islam
    Abstract:

    The present study evaluates the Petroleum Source Rock generation potential of the Neogene Bhuban shales from Bangladesh. Organic geochemical and organic petrological methods were used for analyzing 11 drill core samples from 4 gas fields in the basin. Source Rock potential, maceral composition, organic matter abundance, biomarker distribution, thermal maturity, hydrocarbon generation and depositional environment were evaluated. Kerogen in the studied shale samples is classified mainly as Type III with lesser amounts of Type II. Vitrinite is the dominant maceral group observed in the analyzed Bhuban samples followed by liptinite and inertinite. Vitrinite reflectance, T max and biomarker parameters indicate the thermal maturity ranges from just pre-oil window to mid-oil window. Based on its total organic carbon (TOC), extractable organic matter (EOM) and hydrogen index (HI), the analyzed Bhuban shales are ranked as mainly poor to fair Source Rocks but with good gas generation potential. The dominant terrestrial environment prevailed during the deposition of the studied Bhuban shales while the condition was sub-oxic as indicated by cross-plots of pristane versus phytane and sterane versus pristane/phytane ratios.

  • Petroleum Source Rock evaluation of the sebahat and ganduman formations dent peninsula eastern sabah malaysia
    Journal of Asian Earth Sciences, 2013
    Co-Authors: Khairul Azlan Mustapha, Wan Hasiah Abdullah
    Abstract:

    The Sebahat (Middle Miocene to Early Pliocene) and Ganduman (Early Pliocene to Late Pliocene) Formations comprise part of the Dent Group. The onshore Sebahat and Ganduman Formations form part of the sedimentary sequence within the Sandakan sub-basin which continues offshore in the southern portion of the Sulu Sea off Eastern Sabah. The Ganduman Formation lies conformably on the Sebahat Formation. The shaly Sebahat Formation represents a distal holomarine facies while the sandy Ganduman Formation represents the proximal unit of a fluvial–deltaic system. Based on organic geochemical and petrological analyses, both formations posses very variable TOC content in the range of 0.7–48 wt% for Sebahat Formation and 1–57 wt% for Ganduman Formation. Both formations are dominated by Type III kerogen, and are thus considered to be gas-prone based on HI vs. Tmax plots. Although the HI–Tmax diagram indicates a Type III kerogen, petrographic observations indicate a significant amount of oil-prone liptinite macerals. Petrographically, it was observed that significant amounts (1–17% by volume) of liptinite macerals are present in the Ganduman Formation with lesser amounts in the Sebahat Formation. Both formations are thermally immature with vitrinite reflectance values in the range of 0.20–0.35%Ro for Ganduman Formation and 0.25–0.44%Ro for Sebahat Formation. Although these onshore sediments are thermally immature for Petroleum generation, the stratigraphic equivalent of these sediments offshore are known to have been buried to deeper depth and could therefore act as potential Source Rocks for gas with minor amounts of oil.

  • A geochemical overview of selected Palaeozoic and Mesozoic Petroleum Source Rock analogues from outcrop studies, Peninsular Malaysia.
    2011
    Co-Authors: Meor Hakif Amir Hassan, Wan Hasiah Abdullah, Lee Chai Peng
    Abstract:

    With Petroleum reSources on the decline, oil and gas companies worldwide including Malaysia are on the lookout for unconventional Petroleum accumulations. Part of this effort includes looking at older and deeper Petroleum Source Rock intervals that could have generated hydrocarbons earlier that subsequently accumulated in older and deeper reservoir intervals. In Peninsular Malaysia, two main Tertiary Petroleum systems exist (Madon et al., 2006; Tan, 2009). Madon et al. (1999) identified the Groups L and K lacustrine shales (Upper Oligocene-Lower Miocene), and Groups I and H fluvio-deltaic shales and carbonaceous/coaly shales (Lower-Middle Miocene) as the main Petroleum Source Rock intervals for the Malay Basin. Deeper units such as sediments from Group M and pre-Group M (syn-rift) sediments are also believed to contribute to the Petroleum system. The 2005 discovery in the south western part of the Malay Basin by the exploration well Anding Utara-1 penetrated a 220 m oil column in metamorphic Rocks (Shahar, 2005). This is significant as it indicates the possibility of having hydrocarbon accumulations in older Rocks. Such play is commonly referred to as the fractured basement play. It is believed that the Penyu Basin, which lies to the south of the Malay Basin, could potentially have similar plays as the basement there mainly consists of metamorphosed basalts and weathered tuffs (Fanani et al., 2006). However, the hydrocarbons for these fractured reservoirs, which are on basement highs are thought to be Sourced from younger sedimentary Rocks that are positioned lower/deeper in grabens. This study will evaluate the potential of older (i.e. Mesozoic and Palaeozoic) Petroleum Source Rocks based on geochemical analysis of outcrop samples from Peninsular Malaysia. As the fractured basement play involves reservoir Rocks that are of Cretaceous age or older, it is interesting to see if any organic-rich intervals from the Palaeozoic or Lower Mesozoic in Peninsular Malaysia could have contributed to earlier hydrocarbon generation.

Ernest A. Mancini - One of the best experts on this subject based on the ideXlab platform.

  • ReSource Assessment of the In-Place and Potentially Recoverable Deep Natural Gas ReSource of the Onshore Interior Salt Basins, North Central and Northeastern Gulf of Mexico
    2005
    Co-Authors: Ernest A. Mancini, Paul Aharon, Donald A. Goddard, Roger Barnaby
    Abstract:

    The principal research effort for Year 2 of the project has been Petroleum system characterization and modeling. Understanding the burial, thermal maturation, and hydrocarbon expulsion histories of the strata in the onshore interior salt basins of the North Central and Northeastern Gulf of Mexico areas is important in hydrocarbon reSource assessment. The underburden and overburden Rocks in these basins and subbasins are a product of their rift-related geohistory. Petroleum Source Rock analysis and initial thermal maturation and hydrocarbon expulsion modeling indicated that an effective regional Petroleum Source Rock in the onshore interior salt basins and subbasins, the North Louisiana Salt Basin, Mississippi Interior Salt Basin, Manila Subbasin and Conecuh Subbasin, was Upper Jurassic Smackover lime mudstone. The initial modeling also indicated that hydrocarbon generation and expulsion were initiated in the Early Cretaceous and continued into the Tertiary in the North Louisiana Salt Basin and the Mississippi Interior Salt Basin and that hydrocarbon generation and expulsion were initiated in the Late Cretaceous and continued into the Tertiary in the Manila Subbasin and Conecuh Subbasin. Refined thermal maturation and hydrocarbon expulsion modeling and additional Petroleum Source Rock analysis have confirmed that the major Source Rock in the onshore interior salt basins and subbasins is Upper Jurassic Smackover lime mudstone. Hydrocarbon generation and expulsion were initiated in the Early to Late Cretaceous and continued into the Tertiary

  • ReSource Assessment of the In-Place and Potentially Recoverable Deep Natural Gas ReSource of the Onshore Interior Salt Basins, North Central and Northeastern Gulf of Mexico
    2005
    Co-Authors: Ernest A. Mancini, Donald A. Goddard
    Abstract:

    The principal research effort for the first six months of Year 2 of the project has been Petroleum system characterization. Understanding the burial and thermal maturation histories of the strata in the onshore interior salt basins of the North Central and Northeastern Gulf of Mexico areas is important in Petroleum system characterization. The underburden and overburden Rocks in these basins and subbasins are a product of their rift-related geohistory. Petroleum Source Rock analysis and thermal maturation and hydrocarbon expulsion modeling indicate that an effective regional Petroleum Source Rock in the onshore interior salt basins, the North Louisiana Salt Basin, Mississippi Interior Salt Basin, Manila Subbasin and Conecuh Subbasin, was the Upper Jurassic Smackover lime mudstone. The Upper Cretaceous Tuscaloosa shale was an effective local Petroleum Source Rock in the Mississippi Interior Salt Basin and a possible local Source bed in the North Louisiana Salt Basin. Hydrocarbon generation and expulsion was initiated in the Early Cretaceous and continued into the Tertiary in the North Louisiana Salt Basin and the Mississippi Interior Salt Basin. Hydrocarbon generation and expulsion was initiated in the Late Cretaceous and continued into the Tertiary in the Manila Subbasin and Conecuh Subbasin. Reservoir Rocks include Jurassic, Cretaceous and Tertiary siliciclastic and carbonate strata. Seal Rocks include Jurassic, Cretaceous and Tertiary anhydrite and shale beds. Petroleum traps include structural and combination traps