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Bo Qiao - One of the best experts on this subject based on the ideXlab platform.
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Experimental investigation of Oil Generation, retention, and expulsion within Type II kerogen-dominated marine shales: Insights from gold-tube nonhydrous pyrolysis of Barnett and Woodford Shales using miniature core plugs
International Journal of Coal Geology, 2020Co-Authors: Deyong Shao, Tongwei Zhang, Jianping Yan, Liuliu Zhang, Huan Luo, Bo QiaoAbstract:Abstract Although Oil retention has recently emerged as a key topic of unconventional-shale resource assessment, Oil-retention and expulsion controls in organic-rich shales during thermal maturation remain poorly constrained. This study presents an experimental comparison of Oil Generation, retention, and expulsion in two immature, Type II kerogen-dominated marine shales, the Mississippian Barnett Shale and the Upper Devonian-Lower Mississippian Woodford Shale, mainly with respect to the combined effects of the organic macerals and rock fabric involved. In both cases, miniature core plugs drilled from the given samples were isothermally pyrolyzed at 130 to 425 °C for 72 h under a confining pressure of 68 MPa during gold-tube nonhydrous pyrolysis, corresponding to the thermally immature, early stage of the Oil window, the main stage of the Oil window, the late stage of the Oil window, the main stage of Oil cracking to wet gas, and the late stage of Oil cracking. Yields of generated Oil, retained Oil, and expelled Oil for the two studied samples were systematically quantified on the basis of mass-balance calculation of measured Oil and gas yields, as well as Rock-Eval analyses on pyrolyzed subsamples. Through the six stages of petroleum formation investigated, the principal difference in Oil Generation was observed in the two studied samples, with approximately 38 to 68% greater yields of generated Oil (equivalent to ~130 mg Oil/g TOCo) for the Woodford Shale when it evolved into the main and late stages of the Oil window. These elevated yields of generated Oil for the Woodford Shale were compensated for by additional Oil Generation resulting from conversion of abundant Type I kerogen-like algae such as Tasmanites and Leiosphaeridia, which lag in onset and have a shorter period of petroleum Generation upon maturation. As a response to the difference in Oil Generation, Oil retention was found to be significantly enhanced for the Woodford Shale at equivalent stages, with 0.2 to 1.7 times more free Oil (equivalent to 24–105 mg Oil/g TOCo) and 0.7 to 3.9 times more sorbed Oil (equivalent to 58–76 mg Oil/g TOCo) being retained than that of the Barnett Shale, although this effect was not pronounced for Oil expulsion. In contrast to the Barnett Shale, relatively low expelled Oil yields and expulsion efficiencies both indicate highly limited Oil expulsion in the Woodford Shale, implying that the Woodford Shale, whose mineral composition and lithofacies are similar to those of the Barnett Shale, may have a relatively low permeability rock fabric to prevent Oil from being expelled. Furthermore, not only significantly higher Oil-saturation index (OSI) values but also a wider range of maturity at which the Oil crossover effect (OSI > 100 mg/g TOC) occurs is expected for the Woodford Shale when extrapolation to a geological setting occurs. These data suggest that the presence of abundant Type I kerogen-like algae and relatively low permeability rock fabric in the Woodford Shale are critical to significant Oil retention during Oil Generation and expulsion, which jointly raise the possibility of potential commercial shale Oil within Type II kerogen-dominated marine shales.
Mohammed Hail Hakimi - One of the best experts on this subject based on the ideXlab platform.
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Organic geochemistry characterization of Late Jurassic bituminous shales and their organofacies and Oil Generation potential in the Shabwah depression, southeast Sabatayn, Yemen
Journal of Petroleum Science and Engineering, 2020Co-Authors: Mohammed Hail Hakimi, Adel M. Al-matary, Osama Elmahdy, Baleid Ali Hatem, Ali Y. Kahal, Aref LashinAbstract:Abstract Bituminous shales of the Late Jurassic Madbi Formation from Shabwah depression in the south-eastern Sabatayn Basin has been collected and analyzed. The organofacies, paleo-sedimentary environmental conditions and Oil Generation potential are discussed based on combined geochemistry and petrology investigations. Biomarkers indicate that the bituminous-analyzed shales contain mainly marine phytoplankton algae and minor land plants and deposited under reducing environmental conditions. The rich in lipids from phytoplankton algae and land plants suggest high Type II to mixtures of Types II and Type III kerogen as the original organic facies during deposition. This is consistent with significant amounts of alginite and amorphous organic matter, with minor vitrinite land plants observed under microscope and hydrogen index (HI) values of 210–679 mg HC per g TOC and indicated good to excellent Oil-source rocks. The presence of the reducing conditions during deposition consequently enhanced the preservation and subsequently gave rise to enrichment of organic matter in the analyzed bituminous shale as indicated by the relatively high TOC values between 1 and 14 wt%. The geochemical maturity indicators show that the analyzed bituminous shales have reached a low maturity stage, and commercial Oils have not yet generated. Therefore, the results presented and discussed in this study suggest that the low maturity bituminous shales can be heated to crack the kerogens and subsequently significant amount of Oil can be generated. This will lead to a huge alternative potential of unconventional resources and provide a sense of extending the exploration activities for both unconventional and conventional petroleum resources in the whole Basin.
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The petroleum Generation modeling of prospective affinities of Jurassic–Cretaceous source rocks in Tut Oilfield, north Western Desert, Egypt: an integrated bulk pyrolysis and 1D-basin modeling
Arabian Journal of Geosciences, 2016Co-Authors: Mohamed M. Nady, Mohammed Hail HakimiAbstract:Total organic carbon (TOC) and Rock-Eval pyrolysis for 27 rock samples and geochemical model of Alam El Bueib, Masajid, Khatatba, and Ras Qattara Formations from Tut-1x well in the Tut Oilfield, North Western Desert, Egypt, were used to determine the source rock characteristics and petroleum generative potentials of prospective source rocks, including quantity, type of organic matter, and their thermal maturity level. The results were then incorporated into basin modeling in order to improve our understanding of burial/thermal histories and hydrocarbon Generation and extraction from Jurassic–Cretaceous source rocks. The bulk geochemical results showed that Alam El Bueib and Ras Qattara formations contain type-III kerogen, while the Masajid and Khatatba formations displaying generally contain mixed kerogen types II–III, which have the ability to generate mixed Oil and gas accumulations under thermal maturation level. Vitrinite reflectance values of the Jurassic–Cretacouse source rocks range from 0.42 to 0.86 % R, indicating sufficient thermal maturity for Oil Generation. Meanwhile, the burial/thermal history models indicate that the Alam El Bueib and Masajid formations initiated the early-mature stage of Oil Generation during the Late Cretaceous till the present day and the peak Oil Generation has not been reached yet. The source rock of the Khatatba and Ras Qattara formations reached to the peak Oil Generation at vitrinite reflectance values of 0.76 Ro% between 110 and 77 million years before present (mybp), and maximum rates of Oil have been generated during late Cretaceous–early Tertiary (100–58 mybp). The transformation ratio of the main phase of Oil Generation varied from 25 to 65 %. The modeled hydrocarbon Generation evolution suggests that the timing of hydrocarbon extraction from the Khatatba and Ras Qattara source rocks began in the early Tertiary (58 mybp) and persisted to the present day. This indicates that Khatatba and Ras Qattara formations can be consider as generative potentials of prospective source rock horizons in Tut Oilfield.
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Organic geochemical and petrographic characteristics of the Miocene Salif organic-rich shales in the Tihama Basin, Red Sea of Yemen: Implications for paleoenvironmental conditions and Oil-Generation potential
International Journal of Coal Geology, 2016Co-Authors: Mohammed Hail Hakimi, Abdulghani F. Ahmed, Wan Hasiah AbdullahAbstract:Abstract This study is the first investigation which provides information regarding the organic geochemical and petrographic characteristics of Miocene Salif organic-rich shales from Tihama Basin in the Red Sea, Yemen. We evaluate organic matter content, type, maturity, and Oil-Generation potential as well as depositional environmental conditions. The total organic carbon (TOC) contents of the Miocene Salif shales vary between 0.59% and 5.40%, indicating fair to very good source rock potential. The Salif shales have hydrogen index values in the range of 64–576 mg HC/g TOC. The organic matter in the Salif shales are dominated by Type II kerogen and mixed II–III kerogens with a minor contribution of Type III kerogen, as supported by kerogen microscopy. This is also confirmed by their biomarker and carbon isotope results, which indicate that the Salif shales were deposited in highly reducing marine conditions and received high contributions of aquatic organic matter (e.g., algal and microbial) and terrigenous organic matter. Consequently, the Salif Formation is likely to be an Oil-source rock. Maturity indicators such as vitrinite reflectance and pyrolysis data (i.e., Tmax and PI) indicate that most of the Salif shale samples are generally thermally mature, at the early-mature to peak Oil window stage. The new data presented in this paper suggest that early-mature Oil has been generated from Miocene Salif organic-rich shales, so exploration strategies should focus on the known location of Miocene Salif organic-rich shales for predicting the location of the source kitchen.
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geochemistry and organic petrology study of kimmeridgian organic rich shales in the marib shabowah basin yemen origin and implication for depositional environments and Oil Generation potential
Marine and Petroleum Geology, 2014Co-Authors: Mohammed Hail Hakimi, Wan Hasiah Abdullah, Mohamed Ragab Shalaby, Gamal A AlramisyAbstract:Kimmeridgian organic-rich shales of the Madbi Formation from the Marib-Shabowah Basin in western Yemen were analysed to evaluate the type of organic matter, origin and depositional environments as well as their Oil-Generation potential. Results of the current study establishes the organic geochemical characteristics of the Kimmeridgian organic-rich shales and identifies the kerogen type based on their organic petrographic characteristics as observed under reflected white light and blue light excitation. Kerogen microscopy shows that the Kimmeridgian organic-rich shales contain a large amount of organic matter, consisting predominantly of yellow fluorescing alginite and amorphous organic matter with marine-microfossils (e.g., dinoflagellate cysts and micro-foraminiferal linings). Terrigenous organic matters (e.g., vitrinite, spores and pollen) are also present in low quantities. The high contributions of marine organic matter with minor terrigenous organic matter are also confirmed by carbon isotopic values. The organic richness of the Kimmeridgian shales is mainly due to good preservation under suboxic to relatively anoxic conditions, as indicated by the percent of numerous pyritized fragments associated with the organic matter. The biomarker parameters obtained from mass spectrometer data on m/z 191 and m/z 217 also indicate that these organic-rich shales contain mixed organic matter that were deposited in a marine environment and preserved under suboxic to relatively anoxic conditions. The Kimmeridgian organic-rich shales thus have high Oil and low gas-Generation potential due to Oil window maturities and the nature of the organic matter, with high content of hydrogen-rich Type II and mixed Type II-III kerogens with minor contributions of Type III kerogen.
Michael D. Lewan - One of the best experts on this subject based on the ideXlab platform.
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Comparison of Oil Generation Kinetics Derived from Hydrous Pyrolysis and Rock-eval in Four-dimensional Models of the Western Canada Sedimentary Basin and Its Northern Alberta Oil Sands
2013Co-Authors: Debra K. Higley, Michael D. LewanAbstract:Four-dimensional petroleum system models within the Western Canada sedimentary basin were constructed using hydrous pyrolysis (HP) and Rock-Eval (RE) kinetic parameters for six of the major Oil-prone source rocks in the basin. These source rocks include the Devonian Duvernay Member of the Woodbend Group; Devonian-Mississippian Exshaw Formation; Triassic Doig Formation; Gordondale Member; Poker Chip A shale, both of the Jurassic Fernie Group; and Ostracod Zone of the Lower Cretaceous Mannville Group. The Mannville Group coals also contributed Oil to the Oil sands (Higley et al., 2009) but are excluded herein because HP kinetics were used for both models with identical results. The locations of Oil migration flowpaths are identical for the HP and RE models, with the exception of an earlier onset of Generation and migration shown with the HP model. Both models show that the Oil sands are located at focal points of the petroleum migration pathways. The principal differences between the models are the onset and extent of Oil Generation from the Jurassic Fernie source rocks (Gordondale Member and Poker Chip A shale) at about 85 Ma with the HP model and 65 Ma with the RE model. Earlier Oil Generation in the HP model is caused by the high sulfur content of the type IIS kerogen in the Jurassic source rocks. The influence of organic sulfur is accounted for in the HP kinetic parameters, but not the RE kinetic parameters. The cumulative volume of Oil generated from the source rocks is 678 billion m3 for the HP model and 444 billion m3 for the RE model, or 65% of the HP volume. This difference is attributed to early Generation from type IIS kerogen that resulted in much larger volumes of thermally mature source rocks for the Jurassic Fernie Group and consequently larger volumes of generated Oil. The Gordondale Member in the HP model generated more than 550 times the volume of Oil generated by the Gordondale Member in the RE model. The timing and generated volumes are comparable in the RE and HP models for source rocks that contain normal levels of organic sulfur (type II kerogen). The Duvernay is an exception because of the very low sulfur content of its type II kerogen. The result is higher HP kinetic than RE kinetic parameters, with associated greater thermal maturities required for HP than for RE Oil Generation. Consequently, there is less mature Duvernay source rock in the HP model than the RE model.
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Estimation of hydrous-pyrolysis kinetic parameters for Oil Generation from Baltic Cambrian and Tremadocian source rocks with Type-II kerogen
Geological Quarterly, 2010Co-Authors: Dariusz Więcław, Maciej J. Kotarba, Michael D. LewanAbstract:Determining kinetic parameters for Oil Generation from a source rock by hydrous pyrolysis requires a considerable amount of sample (kilograms) and laboratory time (several weeks). In an effort to circumvent these requirements, hydrous-pyrolysis (HP) kinetic parameters for Oil Generation from Upper Cambrian and Tremadocian source rocks of the Baltic region are estimated by two methods: (1) organic sulfur content in kerogen and (2) HP experiments conducted at 330 and 355°C for 72 h. Estimates for the Upper Cambrian source rocks based on organic sulfur contents gave activation energies from 47 to 56 kcal/mole and frequency factors from 1.156 ´ 1025 to 1.078 ´ 1028 m.y.-1 . Tremadocian source rocks based on organic sulfur content gave estimated activation energies from 60 to 62 kcal/mole and frequency factors from 1.790 ´ 1029 to 1.104 ´ 1030 m.y.-1 . The estimates for the Tremadocian source rocks were less affected by thermal maturation because their low kerogen S/(S + C) mole fractions ( >gt; 0.018) of the Upper Cambrian source rocks decreased with thermal maturation and resulted in overestimation of the kinetic parameters. The second method was designed to estimate kinetic parameters based on two HP experiments. The assumption that the maximum yield in calculating the rate constant at 330°C (k330°C) could be determined by a second hydrous pyrolysis experiment at 355°C for 72 h proved not to be valid. Instead, a previously established relationship between Rock-Eval hydrogen index and maximum HP yield for Type-II kerogen was used to calculate k330°C from Oil yields generated by the HP experiment at 330°C for 72 h assuming a first-order reaction. HP kinetic parameters were determined from relationships between k330°C and the HP kinetic parameters previously reported. These estimated HP kinetic parameters were in agreement with those obtained by the first method for immature samples, but underestimated the kinetic parameters for samples at higher thermal maturities. Applying these estimated HP kinetic parameters to geological heating rates of 1 and 10°C/m.y. indicated that the Upper Cambrian source rocks would generate Oil notably earlier than the overlying Tremadocian source rocks. This was confirmed in part by available data from two neighboring boreholes in the Polish sector of the Baltic.
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Oil-Generation kinetics for organic facies with Type-II and -IIS kerogen in the Menilite Shales of the Polish Carpathians
Geochimica et Cosmochimica Acta, 2006Co-Authors: Michael D. Lewan, Maciej J. Kotarba, John B. Curtis, Dariusz Więcław, Paweł KosakowskiAbstract:The Menilite Shales (Oligocene) of the Polish Carpathians are the source of low-sulfur Oils in the thrust belt and some high-sulfur Oils in the Carpathian Foredeep. These Oil occurrences indicate that the high-sulfur Oils in the Foredeep were generated and expelled before major thrusting and the low-sulfur Oils in the thrust belt were generated and expelled during or after major thrusting. Two distinct organic facies have been observed in the Menilite Shales. One organic facies has a high clastic sediment input and contains Type-II kerogen. The other organic facies has a lower clastic sediment input and contains Type-IIS kerogen. Representative samples of both organic facies were used to determine kinetic parameters for immiscible Oil Generation by isothermal hydrous pyrolysis and S2 Generation by non-isothermal open-system pyrolysis. The derived kinetic parameters showed that timing of S2 Generation was not as different between the Type-IIS and -II kerogen based on open-system pyrolysis as compared with immiscible Oil Generation based on hydrous pyrolysis. Applying these kinetic parameters to a burial history in the Skole unit showed that some expelled Oil would have been generated from the organic facies with Type-IIS kerogen before major thrusting with the hydrous-pyrolysis kinetic parameters but not with the open-system pyrolysis kinetic parameters. The inability of open-system pyrolysis to determine earlier petroleum Generation from Type-IIS kerogen is attributed to the large polar-rich bitumen component in S2 Generation, rapid loss of sulfur free-radical initiators in the open system, and diminished radical selectivity and rate constant differences at higher temperatures. Hydrous-pyrolysis kinetic parameters are determined in the presence of water at lower temperatures in a closed system, which allows differentiation of bitumen and Oil Generation, interaction of free-radical initiators, greater radical selectivity, and more distinguishable rate constants as would occur during natural maturation. Kinetic parameters derived from hydrous pyrolysis show good correlations with one another (compensation effect) and kerogen organic-sulfur contents. These correlations allow for indirect determination of hydrous-pyrolysis kinetic parameters on the basis of the organic-sulfur mole fraction of an immature Type-II or -IIS kerogen.
Paweł Kosakowski - One of the best experts on this subject based on the ideXlab platform.
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Oil-Generation kinetics for organic facies with Type-II and -IIS kerogen in the Menilite Shales of the Polish Carpathians
Geochimica et Cosmochimica Acta, 2006Co-Authors: Michael D. Lewan, Maciej J. Kotarba, John B. Curtis, Dariusz Więcław, Paweł KosakowskiAbstract:The Menilite Shales (Oligocene) of the Polish Carpathians are the source of low-sulfur Oils in the thrust belt and some high-sulfur Oils in the Carpathian Foredeep. These Oil occurrences indicate that the high-sulfur Oils in the Foredeep were generated and expelled before major thrusting and the low-sulfur Oils in the thrust belt were generated and expelled during or after major thrusting. Two distinct organic facies have been observed in the Menilite Shales. One organic facies has a high clastic sediment input and contains Type-II kerogen. The other organic facies has a lower clastic sediment input and contains Type-IIS kerogen. Representative samples of both organic facies were used to determine kinetic parameters for immiscible Oil Generation by isothermal hydrous pyrolysis and S2 Generation by non-isothermal open-system pyrolysis. The derived kinetic parameters showed that timing of S2 Generation was not as different between the Type-IIS and -II kerogen based on open-system pyrolysis as compared with immiscible Oil Generation based on hydrous pyrolysis. Applying these kinetic parameters to a burial history in the Skole unit showed that some expelled Oil would have been generated from the organic facies with Type-IIS kerogen before major thrusting with the hydrous-pyrolysis kinetic parameters but not with the open-system pyrolysis kinetic parameters. The inability of open-system pyrolysis to determine earlier petroleum Generation from Type-IIS kerogen is attributed to the large polar-rich bitumen component in S2 Generation, rapid loss of sulfur free-radical initiators in the open system, and diminished radical selectivity and rate constant differences at higher temperatures. Hydrous-pyrolysis kinetic parameters are determined in the presence of water at lower temperatures in a closed system, which allows differentiation of bitumen and Oil Generation, interaction of free-radical initiators, greater radical selectivity, and more distinguishable rate constants as would occur during natural maturation. Kinetic parameters derived from hydrous pyrolysis show good correlations with one another (compensation effect) and kerogen organic-sulfur contents. These correlations allow for indirect determination of hydrous-pyrolysis kinetic parameters on the basis of the organic-sulfur mole fraction of an immature Type-II or -IIS kerogen.
T.c. Hester - One of the best experts on this subject based on the ideXlab platform.
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ABSTRACT: Formation Resistivity as an Indicator of Oil Generation — Bakken Formation of North Dakota and Woodford Shale of Oklahoma*
The Log Analyst, 1991Co-Authors: J.w. Schmoker, T.c. HesterAbstract:ABSTRACT With the onset of Oil Generation in organic-rich, low porosity shales, nonconductive hydrocarbons begin to displace conductive pore water. As this process continues, formation resistivity increases from the low levels typical of water saturated shales and can reach hundreds of ohm-m if sufficient Oil is generated. In this study, formation resistivity of selected organic-rich shales is compared with geochemical indicators of hydrocarbon Generation and thermal maturity in order to quantify relationships between resistivity and Oil Generation. The upper and lower shale members of the Bakken Formation (Upper Devonian and Lower Mississip-pian) of the Williston Basin, North Dakota, and the Woodford Shale (Upper Devonian and Lower Missis-sippian) of the Anadarko Basin, Oklahoma are used here as illustrative examples. An increase of volatile hydrocarbons (Si) in core samples indicates that a resistivity of about 35 ohm-m marks the onset of observable Oil Generation in these three organic rich shales. This resistivity value is used to map regions of the study areas where the Woodford Shale and the Bakken Formation have generated Oil and where free Oil might possibly be produced from fracture systems. Crossplots of formation resistivity versus vitrinite reflectance (Ro) indicate that the level of thermal maturation required for Oil Generation is about Ro = 0.44% in the upper Bakken Formation, Ro = 0.50% in the lower member of the Bakken Formation, and Ro = 0.57% in the Woodford Shale of the study area. Crossplots of formation resistivity versus Lopatin's time-temperature index of thermal maturity (TTI) indicate that the level of time-temperature exposure required for Oil Generation is about TTI = 11 in the upper Bakken Formation, TTI = 23 in the lower member of the Bakken Formation, and TTI = 33-48 in the Woodford Shale of the study area. Such crossplots provide a direct empirical link between initiation of Oil Generation and mathematical measures of time-temperature exposure, thereby circumventing problems of indirect calibrations.
