It is difficult to identify the source（s） of mixed oils from multiple source rocks, and in particular the relative contribution of each source rock. Artificial mixing experiments using typical crude oils and ratios ...It is difficult to identify the source（s） of mixed oils from multiple source rocks, and in particular the relative contribution of each source rock. Artificial mixing experiments using typical crude oils and ratios of different biomarkers show that the relative contribution changes are non-linear when two oils with different concentrations of biomarkers mix with each other. This may result in an incorrect conclusion if ratios of biomarkers and a simple binary linear equation are used to calculate the contribution proportion of each end-member to the mixed oil. The changes of biomarker ratios with the mixing proportion of end-member oils in the trinal mixing model are more complex than in the binary mixing model. When four or more oils mix, the contribution proportion of each end-member oil to the mixed oil cannot be calculated using biomarker ratios and a simple formula. Artificial mixing experiments on typical oils reveal that the absolute concentrations of biomarkers in the mixed oil cause a linear change with mixing proportion of each end-member. Mathematical inferences verify such linear changes. Some of the mathematical calculation methods using the absolute concentrations or ratios of biomarkers to quantitatively determine the proportion of each end-member in the mixed oils are deduced from the results of artificial experiments and by theoretical inference. Ratio of two biomarker compounds changes as a hyperbola with the mixing proportion in the binary mixing model, as a hyperboloid in the trinal mixing model, and as a hypersurface when mixing more than three end- members. The mixing proportion of each end-member can be quantitatively determined with these mathematical models, using the absolute concentrations and the ratios of biomarkers. The mathematical calculation model is more economical, convenient, accurate and reliable than conventional artificial mixing methods.展开更多
The experimental data yielded by Rock-Eval pyrolysis, kerogen atomic H/C, Py-GC and gold-tube sealing thermal simulation on the marine Cambrian-Ordovician source rock from the Tarim Basin revealed that the upper limit...The experimental data yielded by Rock-Eval pyrolysis, kerogen atomic H/C, Py-GC and gold-tube sealing thermal simulation on the marine Cambrian-Ordovician source rock from the Tarim Basin revealed that the upper limit of maturity for natural gas generation or the "deadline of gas generation" for marine types I and II kerogens is equal to 3.0% of vitrinite reflectance (Ro); while the "deadline of gas generation" for type III kerogens typically like coals is as high as 10% Ro. Thus, different organic matter has obviously different utmost maturities for gas generation. The mass-balance calculation by kerogen elements showed that when Ro>1.5%, the utmost amount of gas generation for the marine type II kerogen is less than 185 m3/t TOC, accounting for less than 30% of its total hydrocarbon generative potential; when Ro>2.0%, it becomes 110 m3/t TOC, less than 20% of the total hydrocarbon generative potential. The amount of the gas generative potential obtained by Rock-Eval is only around one tenth of the calculated value by the mass balance of kerogen elements at the same thermal evolutionary stage, while those by Py-GC and gold-tube sealing simulation are intervenient between the above two. The utmost of gas generative potential at the over 1.3% Ro stage is around 60―90 m3/t TOC, therefore, the amount of gas generation obtained by Rock-Eval is the minimum of gas generative potential, while that by the mass-balance calculation of kerogen elements is the maximum that the actual amount of gas generation should not exceed.展开更多
It is a challenge to determine the source and genetic relationship of condensate, waxy and heavy oils in one given complicated petroliferous area, where developed multiple sets of source rocks with different maturity ...It is a challenge to determine the source and genetic relationship of condensate, waxy and heavy oils in one given complicated petroliferous area, where developed multiple sets of source rocks with different maturity and various chemical features.The central part of southern margin of Junggar Basin, NW China is such an example where there are condensates, light oils, normal density oils, heavy crude oils and natural gases. The formation mechanism of condensates has been seriously debated for long time;however, no study has integrated it with genetic types of waxy and heavy oils. Taking the central part of southern margin of Junggar Basin as a case, this study employs geological and geochemical methods to determine the formation mechanism of condensates,waxy and heavy oils in a complicated petroliferous area, and reveals the causes and geochemical processes of the co-occurrence of different types of crude oils in this region. Based on detailed geochemical analyses of more than 40 normal crude oils, light oils,condensates and heavy oils, it is found that the condensates are dominated by low carbon number n-alkanes and enriched in light naphthenics and aromatic hydrocarbons. Heptane values of these condensates range from 19% to 21%, isoheptane values from1.9 to 2.1, and toluene/n-heptane ratios from 1.5 to 2.0. The distribution of n-alkanes in the condensates presents a mirror image with high density waxy crude oils and heavy oils. Combined with the oil and gas-source correlations of the crude oils, condensates and natural gas, it is found that the condensates are product of evaporative fractionation and/or phase-controlled fractionation of reservoir crude oils which were derived from mature Cretaceous lacustrine source rocks in the relatively early stage. The waxy oils are the intermediate products of evaporative fractionation and/or phase-controlled fractionation of reservoir crude oils, while the heavy oils are in-situ residuals. Therefore, evaporative fractionation and/or phase-controlled fractionation would account for the formation of the condensate, light oil, waxy oil and heavy oil in the central part of southern margin of Junggar Basin, resulting in a great change of the content in terms of light alkanes, naphthenics and aromatics in condensates, followed by great uncertainties of toluene/n-heptane ratios due to migration and re-accumulation. The results suggest that the origin of the condensate cannot be simply concluded by its ratios of toluene/n-heptane and n-heptane/methylcyclohexane on the Thompson's cross-plot, it should be comprehensively determined by the aspects of geological background, thermal history of source rocks and petroleum generation,physical and chemical features of various crude oils and natural gas, vertical and lateral distribution of various crude oils in the study area.展开更多
The semi-closed pyrolysis simulation system under constant pressure was conducted to explore the characteristics and mechanisms of hydrocarbon generation from Xiamaling Formation shale in Xiahuayuan,North China.The ex...The semi-closed pyrolysis simulation system under constant pressure was conducted to explore the characteristics and mechanisms of hydrocarbon generation from Xiamaling Formation shale in Xiahuayuan,North China.The experiment results indicate the oil generated by the Xiamaling Formation shale in oil window should be classified as "aromatic-intermediate" type,whereas the decreasing of dry coefficient can be ascribed to the cracking of residual bitumen in source rock in the stage of high to post maturity.The amount of hydrocarbon gas generated from residual bitumen can be up to 1-2 m3 per ton rock in high to post mature stage by calculating hydrogen contents in the kerogen,the expelled hydrocarbon,and the residual hydrocarbon.This reveals the importance of residual bitumen as a gas source during high to post mature stage of the kerogen evolution,and also as the broad exploration prospect of these gases.This research highlights the attention should be paid to oil/gas reservoirs sourced from residual bitumen of organic-rich source rock in high mature stage,even the primary oil/gas reservoirs considered as the main exploration targets in middle-upper Proterozoic sediments of North China.展开更多
文摘It is difficult to identify the source（s） of mixed oils from multiple source rocks, and in particular the relative contribution of each source rock. Artificial mixing experiments using typical crude oils and ratios of different biomarkers show that the relative contribution changes are non-linear when two oils with different concentrations of biomarkers mix with each other. This may result in an incorrect conclusion if ratios of biomarkers and a simple binary linear equation are used to calculate the contribution proportion of each end-member to the mixed oil. The changes of biomarker ratios with the mixing proportion of end-member oils in the trinal mixing model are more complex than in the binary mixing model. When four or more oils mix, the contribution proportion of each end-member oil to the mixed oil cannot be calculated using biomarker ratios and a simple formula. Artificial mixing experiments on typical oils reveal that the absolute concentrations of biomarkers in the mixed oil cause a linear change with mixing proportion of each end-member. Mathematical inferences verify such linear changes. Some of the mathematical calculation methods using the absolute concentrations or ratios of biomarkers to quantitatively determine the proportion of each end-member in the mixed oils are deduced from the results of artificial experiments and by theoretical inference. Ratio of two biomarker compounds changes as a hyperbola with the mixing proportion in the binary mixing model, as a hyperboloid in the trinal mixing model, and as a hypersurface when mixing more than three end- members. The mixing proportion of each end-member can be quantitatively determined with these mathematical models, using the absolute concentrations and the ratios of biomarkers. The mathematical calculation model is more economical, convenient, accurate and reliable than conventional artificial mixing methods.
基金the Natural Gas Project of the National "973" Basic Research Devel-opment Planning (Grant No. 2001CB209100)"the Tenth Five-Year Plan" Na-tional Scientific & Technological Programs (Grant No. 2004BA616A020-01-01)
文摘The experimental data yielded by Rock-Eval pyrolysis, kerogen atomic H/C, Py-GC and gold-tube sealing thermal simulation on the marine Cambrian-Ordovician source rock from the Tarim Basin revealed that the upper limit of maturity for natural gas generation or the "deadline of gas generation" for marine types I and II kerogens is equal to 3.0% of vitrinite reflectance (Ro); while the "deadline of gas generation" for type III kerogens typically like coals is as high as 10% Ro. Thus, different organic matter has obviously different utmost maturities for gas generation. The mass-balance calculation by kerogen elements showed that when Ro>1.5%, the utmost amount of gas generation for the marine type II kerogen is less than 185 m3/t TOC, accounting for less than 30% of its total hydrocarbon generative potential; when Ro>2.0%, it becomes 110 m3/t TOC, less than 20% of the total hydrocarbon generative potential. The amount of the gas generative potential obtained by Rock-Eval is only around one tenth of the calculated value by the mass balance of kerogen elements at the same thermal evolutionary stage, while those by Py-GC and gold-tube sealing simulation are intervenient between the above two. The utmost of gas generative potential at the over 1.3% Ro stage is around 60―90 m3/t TOC, therefore, the amount of gas generation obtained by Rock-Eval is the minimum of gas generative potential, while that by the mass-balance calculation of kerogen elements is the maximum that the actual amount of gas generation should not exceed.
基金supported by the PetroChina Science and Technology Special Projects (Grant Nos. 06-10A-01-02, 2011A-0201, 2014A-0211 and 2016A-0202)
文摘It is a challenge to determine the source and genetic relationship of condensate, waxy and heavy oils in one given complicated petroliferous area, where developed multiple sets of source rocks with different maturity and various chemical features.The central part of southern margin of Junggar Basin, NW China is such an example where there are condensates, light oils, normal density oils, heavy crude oils and natural gases. The formation mechanism of condensates has been seriously debated for long time;however, no study has integrated it with genetic types of waxy and heavy oils. Taking the central part of southern margin of Junggar Basin as a case, this study employs geological and geochemical methods to determine the formation mechanism of condensates,waxy and heavy oils in a complicated petroliferous area, and reveals the causes and geochemical processes of the co-occurrence of different types of crude oils in this region. Based on detailed geochemical analyses of more than 40 normal crude oils, light oils,condensates and heavy oils, it is found that the condensates are dominated by low carbon number n-alkanes and enriched in light naphthenics and aromatic hydrocarbons. Heptane values of these condensates range from 19% to 21%, isoheptane values from1.9 to 2.1, and toluene/n-heptane ratios from 1.5 to 2.0. The distribution of n-alkanes in the condensates presents a mirror image with high density waxy crude oils and heavy oils. Combined with the oil and gas-source correlations of the crude oils, condensates and natural gas, it is found that the condensates are product of evaporative fractionation and/or phase-controlled fractionation of reservoir crude oils which were derived from mature Cretaceous lacustrine source rocks in the relatively early stage. The waxy oils are the intermediate products of evaporative fractionation and/or phase-controlled fractionation of reservoir crude oils, while the heavy oils are in-situ residuals. Therefore, evaporative fractionation and/or phase-controlled fractionation would account for the formation of the condensate, light oil, waxy oil and heavy oil in the central part of southern margin of Junggar Basin, resulting in a great change of the content in terms of light alkanes, naphthenics and aromatics in condensates, followed by great uncertainties of toluene/n-heptane ratios due to migration and re-accumulation. The results suggest that the origin of the condensate cannot be simply concluded by its ratios of toluene/n-heptane and n-heptane/methylcyclohexane on the Thompson's cross-plot, it should be comprehensively determined by the aspects of geological background, thermal history of source rocks and petroleum generation,physical and chemical features of various crude oils and natural gas, vertical and lateral distribution of various crude oils in the study area.
基金supported by National Natural Science Foundation of China(Grant Nos.40972093 and 41172112)Natural Science Foundation of Zhejiang Province(Grant No.R5080124)+1 种基金Foundation of State Key Laboratory of Enhanced Oil Recoverythe Foundation of State Key Laboratory of Petroleum Resource and Prospecting(Grant No.2009001)
文摘The semi-closed pyrolysis simulation system under constant pressure was conducted to explore the characteristics and mechanisms of hydrocarbon generation from Xiamaling Formation shale in Xiahuayuan,North China.The experiment results indicate the oil generated by the Xiamaling Formation shale in oil window should be classified as "aromatic-intermediate" type,whereas the decreasing of dry coefficient can be ascribed to the cracking of residual bitumen in source rock in the stage of high to post maturity.The amount of hydrocarbon gas generated from residual bitumen can be up to 1-2 m3 per ton rock in high to post mature stage by calculating hydrogen contents in the kerogen,the expelled hydrocarbon,and the residual hydrocarbon.This reveals the importance of residual bitumen as a gas source during high to post mature stage of the kerogen evolution,and also as the broad exploration prospect of these gases.This research highlights the attention should be paid to oil/gas reservoirs sourced from residual bitumen of organic-rich source rock in high mature stage,even the primary oil/gas reservoirs considered as the main exploration targets in middle-upper Proterozoic sediments of North China.
