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Hongwei Ping - One of the best experts on this subject based on the ideXlab platform.
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petroleum accumulation in the deeply buried reservoirs in the northern dongying depression bohai bay basin china new insights from fluid inclusions natural gas geochemistry and 1 d basin modeling
Marine and Petroleum Geology, 2017Co-Authors: Hongwei Ping, Honghan ChenAbstract:Abstract The deeply buried reservoirs (DBRs) from the Lijin, Shengtuo and Minfeng areas in the northern Dongying Depression of the Bohai Bay Basin, China exhibit various petroleum types (black Oil-gas Condensates) and pressure systems (normal pressure-overpressure) with high reservoir temperatures (154–185 °C). The pressure-volume-temperature-composition (PVTX) evolution of petroleum and the processes of petroleum accumulation were reconstructed using integrated data from fluid inclusions, stable carbon isotope data of natural gas and one-dimensional basin modeling to trace the petroleum accumulation histories. The results suggest that (1) the gas Condensates in the Lijin area originated from the thermal cracking of highly mature kerogen in deeper formations. Two episodes of gas Condensate charging, which were evidenced by the trapping of non-fluorescent gas Condensate inclusions, occurred between 29-25.5 Ma and 8.6–5.0 Ma with strong overpressure (pressure coefficient, Pc = 1.68–1.70), resulting in the greatest contribution to the present-day gas Condensate accumulation; (2) the early yellow fluorescent Oil charge was responsible for the present-day black Oil accumulation in well T764, while the late blue-white Oil charge together with the latest kerogen cracked gas injection resulted in the present-day volatile Oil accumulation in well T765; and (3) the various fluorescent colors (yellow, blue-white and blue) and the degree of bubble filling (Fv) (2.3–72.5%) of the Oil inclusions in the Minfeng area show a wide range of thermal maturity (API gravity ranges from 30 to 50°), representing the charging of black Oil to gas Condensates. The presence of abundant blue-white fluorescent Oil inclusions with high Grain-obtaining Oil Inclusion (GOI) values (35.8%, usually >5% in Oil reservoirs) indicate that a paleo-Oil accumulation with an approximate API gravity of 39–40° could have occurred before 25 Ma, and gas from Oil cracking in deeper formations was injected into the paleo-Oil reservoir from 2.8 Ma to 0 Ma, resulting in the present-day gas Condensate Oil accumulation. This Oil and gas accumulation model results in three Oil and gas distribution zones: 1) normal Oil reservoirs at relatively shallow depth; 2) gas Condensate reservoirs that originated from the mixture of Oil cracking gas with a paleo-Oil reservoir at intermediate depth; and 3) Oil-cracked gas reservoirs at deeper depth. The retardation of organic matter maturation and Oil cracking by high overpressure could have played an important role in the distribution of different origins of gas Condensate accumulations in the Lijin and Minfeng areas. The application of Oil and gas accumulation models in this study is not limited to the Dongying Depression and can be applied to other overpressured rift basins.
Guangjin Chen - One of the best experts on this subject based on the ideXlab platform.
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flow characteristics and morphology of hydrate slurry formed from natural gas diesel Oil Condensate Oil water system containing anti agglomerant
Chemical Engineering Science, 2012Co-Authors: Baozi Peng, Jun Chen, Abhijit Dandekar, Liang Mu, Lanying Yang, Wenzhi Li, Guangjin ChenAbstract:Abstract The performance of a new kind of anti-agglomerant was evaluated on preventing hydrate plug in Oil and gas pipelines using a flow loop device where hydrate slurries were formed from (diesel Oil/Condensate Oil+water) dispersed system. The flow characteristics, shut down/restart behavior, and morphology of hydrate slurries were investigated experimentally at different water cut. The experimental results show that the adopted anti-agglomerant can disperse hydrate particles in fluid phase apparently. The formed hydrate slurries can safely flow and be easily restarted even though the initial water cut is upto 30.0 vol%. The rheology of hydrate slurries was analyzed based on the power-law fluid assumption and the rheology parameters and apparent viscosity were determined at different hydrate volume fraction. The analyzed results show that hydrate slurry exhibits shear-thinning behavior and belongs to pseudoplastic fluid. Its non-Newtonian behavior becomes more obvious with increasing hydrate volume fraction in fluid phase. The authors believe that the results presented in this paper are of key significance from flow assurance standpoint.
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an inward and outward natural gas hydrates growth shell model considering intrinsic kinetics mass and heat transfer
Chemical Engineering Journal, 2011Co-Authors: Jing Gong, Jiankui Zhao, Yao Ding, Guangjin ChenAbstract:Abstract The natural gas hydrates formation and growth at 2 MPa and 277.15 K were studied at different water cuts for water-in-Condensate Oil emulsions in the flow loop unit. The variations of gas consumption with time at different water cuts were obtained. The experimental results showed that the gas consumption value increased with the rise of water cut. The total water conversion rates not only depended on the water cuts, but also related to several other factors, two of which were the amount of the dissolved gas and the surface/volume ratio of the particles. No more natural gas transformed into hydrates after 3 h, which was likely caused by intrinsic kinetics, mass transfer and heat transfer limitations. An inward and outward natural gas hydrates growth shell model was proposed considering all the three limitations to simulate the gas and water consumptions to form natural gas hydrates.
Honghan Chen - One of the best experts on this subject based on the ideXlab platform.
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petroleum accumulation in the deeply buried reservoirs in the northern dongying depression bohai bay basin china new insights from fluid inclusions natural gas geochemistry and 1 d basin modeling
Marine and Petroleum Geology, 2017Co-Authors: Hongwei Ping, Honghan ChenAbstract:Abstract The deeply buried reservoirs (DBRs) from the Lijin, Shengtuo and Minfeng areas in the northern Dongying Depression of the Bohai Bay Basin, China exhibit various petroleum types (black Oil-gas Condensates) and pressure systems (normal pressure-overpressure) with high reservoir temperatures (154–185 °C). The pressure-volume-temperature-composition (PVTX) evolution of petroleum and the processes of petroleum accumulation were reconstructed using integrated data from fluid inclusions, stable carbon isotope data of natural gas and one-dimensional basin modeling to trace the petroleum accumulation histories. The results suggest that (1) the gas Condensates in the Lijin area originated from the thermal cracking of highly mature kerogen in deeper formations. Two episodes of gas Condensate charging, which were evidenced by the trapping of non-fluorescent gas Condensate inclusions, occurred between 29-25.5 Ma and 8.6–5.0 Ma with strong overpressure (pressure coefficient, Pc = 1.68–1.70), resulting in the greatest contribution to the present-day gas Condensate accumulation; (2) the early yellow fluorescent Oil charge was responsible for the present-day black Oil accumulation in well T764, while the late blue-white Oil charge together with the latest kerogen cracked gas injection resulted in the present-day volatile Oil accumulation in well T765; and (3) the various fluorescent colors (yellow, blue-white and blue) and the degree of bubble filling (Fv) (2.3–72.5%) of the Oil inclusions in the Minfeng area show a wide range of thermal maturity (API gravity ranges from 30 to 50°), representing the charging of black Oil to gas Condensates. The presence of abundant blue-white fluorescent Oil inclusions with high Grain-obtaining Oil Inclusion (GOI) values (35.8%, usually >5% in Oil reservoirs) indicate that a paleo-Oil accumulation with an approximate API gravity of 39–40° could have occurred before 25 Ma, and gas from Oil cracking in deeper formations was injected into the paleo-Oil reservoir from 2.8 Ma to 0 Ma, resulting in the present-day gas Condensate Oil accumulation. This Oil and gas accumulation model results in three Oil and gas distribution zones: 1) normal Oil reservoirs at relatively shallow depth; 2) gas Condensate reservoirs that originated from the mixture of Oil cracking gas with a paleo-Oil reservoir at intermediate depth; and 3) Oil-cracked gas reservoirs at deeper depth. The retardation of organic matter maturation and Oil cracking by high overpressure could have played an important role in the distribution of different origins of gas Condensate accumulations in the Lijin and Minfeng areas. The application of Oil and gas accumulation models in this study is not limited to the Dongying Depression and can be applied to other overpressured rift basins.
Jianping Chen - One of the best experts on this subject based on the ideXlab platform.
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source of Condensate Oil in the middle of southern margin junggar basin nw china
Petroleum Exploration and Development, 2016Co-Authors: Jianping Chen, Chunping Deng, Xulong Wang, Yongge Sun, Zhe Zhao, N I Yunyan, Peirong WangAbstract:Abstract Through detailed geochemical analysis of over 40 crude Oil, Condensate Oil and heavy Oil samples in the southern margin of Junggar Basin, and based on the hydrocarbon generation condition of five sets of source rocks, with the combination between compositions of carbon isotopes of whole Oil, light hydrocarbon, n-alkanes isoprenoids and biomarker composition characteristics, a detailed discussion on the source of the Condensate Oil in anticlines in the central part of the southern margin was carried out. Condensate Oils from the central part of the southern margin have abundant isoprenoids, Pr/Ph 13 C value between −27‰ and −28‰. The δ 13 C value of alkanes with carbon number smaller than 9 ranges from −26‰ to −24‰, carbon isotopes of C 9+ n-alkanes decrease remarkably with increasing carbon number, and the δ 13 C value of C 19+ n-alkanes is lower than −30‰. The δ 13 C value of pristane and phytane is lower than −29‰. The biomarker components contain abundant C 27 steranes and C 30 methyl steranes, “V” shape distribution of C 27 , C 28 and C 29 20R sterane, abundant tricyclic terpanes with dominance of C 21 , and relatively high content of gammacerane with two isomers. The 20 S /(20 S +20 R ) ratio of C 29 steranes is between 0.40 and 0.50, and the maturity calculated by the methylphenanthrene index and distribution fraction ( R c ) ranges from 0.70% to 1.1%. These geochemical characteristics of the Condensate Oils are very similar to those mature crude Oils from the typical Cretaceous lacustrine source rocks in the central part of southern margin, but are greatly different from those of typical Jurassic crude Oils, implying that these Condensate Oils are derived from mature Cretaceous lacustrine source rocks instead of highly mature Jurassic coal-measures source rocks.
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Source of Condensate Oil in the middle of southern margin, Junggar Basin, NW China
KeAi Communications Co. Ltd., 2016Co-Authors: Jianping Chen, Chunping Deng, Xulong Wang, Yongge Sun, Zhe Zhao, Peirong Wang, Jiande Liao, Dijia Zhang, Digang LiangAbstract:Through detailed geochemical analysis of over 40 crude Oil, Condensate Oil and heavy Oil samples in the southern margin of Junggar Basin, and based on the hydrocarbon generation condition of five sets of source rocks, with the combination between compositions of carbon isotopes of whole Oil, light hydrocarbon, n-alkanes isoprenoids and biomarker composition characteristics, a detailed discussion on the source of the Condensate Oil in anticlines in the central part of the southern margin was carried out. Condensate Oils from the central part of the southern margin have abundant isoprenoids, Pr/Ph
Peirong Wang - One of the best experts on this subject based on the ideXlab platform.
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source of Condensate Oil in the middle of southern margin junggar basin nw china
Petroleum Exploration and Development, 2016Co-Authors: Jianping Chen, Chunping Deng, Xulong Wang, Yongge Sun, Zhe Zhao, N I Yunyan, Peirong WangAbstract:Abstract Through detailed geochemical analysis of over 40 crude Oil, Condensate Oil and heavy Oil samples in the southern margin of Junggar Basin, and based on the hydrocarbon generation condition of five sets of source rocks, with the combination between compositions of carbon isotopes of whole Oil, light hydrocarbon, n-alkanes isoprenoids and biomarker composition characteristics, a detailed discussion on the source of the Condensate Oil in anticlines in the central part of the southern margin was carried out. Condensate Oils from the central part of the southern margin have abundant isoprenoids, Pr/Ph 13 C value between −27‰ and −28‰. The δ 13 C value of alkanes with carbon number smaller than 9 ranges from −26‰ to −24‰, carbon isotopes of C 9+ n-alkanes decrease remarkably with increasing carbon number, and the δ 13 C value of C 19+ n-alkanes is lower than −30‰. The δ 13 C value of pristane and phytane is lower than −29‰. The biomarker components contain abundant C 27 steranes and C 30 methyl steranes, “V” shape distribution of C 27 , C 28 and C 29 20R sterane, abundant tricyclic terpanes with dominance of C 21 , and relatively high content of gammacerane with two isomers. The 20 S /(20 S +20 R ) ratio of C 29 steranes is between 0.40 and 0.50, and the maturity calculated by the methylphenanthrene index and distribution fraction ( R c ) ranges from 0.70% to 1.1%. These geochemical characteristics of the Condensate Oils are very similar to those mature crude Oils from the typical Cretaceous lacustrine source rocks in the central part of southern margin, but are greatly different from those of typical Jurassic crude Oils, implying that these Condensate Oils are derived from mature Cretaceous lacustrine source rocks instead of highly mature Jurassic coal-measures source rocks.
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Source of Condensate Oil in the middle of southern margin, Junggar Basin, NW China
KeAi Communications Co. Ltd., 2016Co-Authors: Jianping Chen, Chunping Deng, Xulong Wang, Yongge Sun, Zhe Zhao, Peirong Wang, Jiande Liao, Dijia Zhang, Digang LiangAbstract:Through detailed geochemical analysis of over 40 crude Oil, Condensate Oil and heavy Oil samples in the southern margin of Junggar Basin, and based on the hydrocarbon generation condition of five sets of source rocks, with the combination between compositions of carbon isotopes of whole Oil, light hydrocarbon, n-alkanes isoprenoids and biomarker composition characteristics, a detailed discussion on the source of the Condensate Oil in anticlines in the central part of the southern margin was carried out. Condensate Oils from the central part of the southern margin have abundant isoprenoids, Pr/Ph