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2. Improved VGG-16 Neural Network for Parameter Reduction

Author

Jiang, Zheng, Zou, Kaiwen, Yao, Jiangyuan, Li, Deshun, Cao, Xingcan, Filipe, Joaquim, Editorial Board Member, Ghosh, Ashish, Editorial Board Member, Prates, Raquel Oliveira, Editorial Board Member, Zhou, Lizhu, Editorial Board Member, Sun, Xingming, editor, Zhang, Xiaorui, editor, Xia, Zhihua, editor, and Bertino, Elisa, editor

Published
2022
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4. Design and Testing of Source Address Validation Protocols: A Survey

Author

Li, Deshun, Xiao, Lu, Cao, Ganghua, Yao, Jiangyuan, Cao, Xingcan, Filipe, Joaquim, Editorial Board Member, Ghosh, Ashish, Editorial Board Member, Prates, Raquel Oliveira, Editorial Board Member, Zhou, Lizhu, Editorial Board Member, Sun, Xingming, editor, Zhang, Xiaorui, editor, Xia, Zhihua, editor, and Bertino, Elisa, editor

Published
2022
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6. Autoperman: Automatic Network Traffic Anomaly Detection with Ensemble Learning

Author

Han, Shangbin, Wu, Qianhong, Zhang, Han, Qin, Bo, Yao, Jiangyuan, Susilo, Willy, Filipe, Joaquim, Editorial Board Member, Ghosh, Ashish, Editorial Board Member, Prates, Raquel Oliveira, Editorial Board Member, Zhou, Lizhu, Editorial Board Member, Sun, Xingming, editor, Zhang, Xiaorui, editor, Xia, Zhihua, editor, and Bertino, Elisa, editor

Published
2022
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9. Review of Detection and Avoidance of Interference Among Multiple Applications in Software-Defined Networks

Author

Yao, Jiangyuan, Lin, Shengjun, Xu, Chunxiang, Jing, Min, Li, Deshun, Wang, Minrui, Cao, Xingcan, Goos, Gerhard, Founding Editor, Hartmanis, Juris, Founding Editor, Bertino, Elisa, Editorial Board Member, Gao, Wen, Editorial Board Member, Steffen, Bernhard, Editorial Board Member, Yung, Moti, Editorial Board Member, Sun, Xingming, editor, Zhang, Xiaorui, editor, and Xia, Zhihua, editor

Published
2022
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10. Formal Verification of Security Protocols: ProVerif and Extensions

Author

Yao, Jiangyuan, Xu, Chunxiang, Li, Deshun, Lin, Shengjun, Cao, Xingcan, Goos, Gerhard, Founding Editor, Hartmanis, Juris, Founding Editor, Bertino, Elisa, Editorial Board Member, Gao, Wen, Editorial Board Member, Steffen, Bernhard, Editorial Board Member, Yung, Moti, Editorial Board Member, Sun, Xingming, editor, Zhang, Xiaorui, editor, and Xia, Zhihua, editor

Published
2022
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11. Test Traffic Control Based on REST API for Software-Defined Networking

Author

Yao, Jiangyuan, Wang, Minrui, Yang, Weiping, Weng, Shuhua, Jiang, Zheng, Jing, Min, Li, Deshun, Cao, Xingcan, Goos, Gerhard, Founding Editor, Hartmanis, Juris, Founding Editor, Bertino, Elisa, Editorial Board Member, Gao, Wen, Editorial Board Member, Steffen, Bernhard, Editorial Board Member, Yung, Moti, Editorial Board Member, Sun, Xingming, editor, Zhang, Xiaorui, editor, and Xia, Zhihua, editor

Published
2022
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13. Real-Time Self-defense Approach Based on Customized Netlink Connection for Industrial Linux-Based Devices

Author

Wan, Ming, Li, Jiawei, Yao, Jiangyuan, Akan, Ozgur, Editorial Board Member, Bellavista, Paolo, Editorial Board Member, Cao, Jiannong, Editorial Board Member, Coulson, Geoffrey, Editorial Board Member, Dressler, Falko, Editorial Board Member, Ferrari, Domenico, Editorial Board Member, Gerla, Mario, Editorial Board Member, Kobayashi, Hisashi, Editorial Board Member, Palazzo, Sergio, Editorial Board Member, Sahni, Sartaj, Editorial Board Member, Shen, Xuemin (Sherman), Editorial Board Member, Stan, Mircea, Editorial Board Member, Jia, Xiaohua, Editorial Board Member, Zomaya, Albert Y., Editorial Board Member, Gao, Honghao, editor, Wang, Xinheng, editor, Iqbal, Muddesar, editor, Yin, Yuyu, editor, Yin, Jianwei, editor, and Gu, Ning, editor

Published
2021
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15. An Integrated Numerical Study of CO 2 Storage in Carbonate Gas Reservoirs with Chemical Interaction between CO 2 , Brine, and Carbonate Rock Matrix.

Author

Yao, Jiangyuan, Chen, Zhuoheng, Jiang, Chunqing, and Peng, Xiaolong

Subjects
CARBONATE reservoirs, CARBONATE rocks, GAS reservoirs, CARBON sequestration, RESERVOIR rocks, CALCITE, LIMESTONE
Abstract

In light of the burgeoning interest in mitigating anthropogenic CO2 emissions, carbonate reservoirs have emerged as promising sequestration sites due to their substantial storage potentials. However, the complexity of CO2 storage in carbonate reservoirs exceeds that in conventional sandstone reservoirs, predominantly due to the rapid interactions occurring between the injected CO2, brine, and carbonate rock matrix. In this study, a numerical model integrated with the chemical CO2–brine–rock matrix interaction was developed to analyze the carbonate rock dissolution process and the physical property variations of different carbonate gas reservoirs during the CO2 injection and sequestration process. More specifically, a total of twenty scenarios were simulated to examine the effects of lithology, pore size, pore–throat structures, and CO2 injection rate on carbonate rock matrix dissolution and reservoir property variation. Calcite is significantly easier and quicker to react with CO2-solvated brine than dolomite; as a result, limestones exhibit an expedited rock dissolution and pore volume increase, along with a slower pressure buildup in comparison to dolomites. Also, the carbonate reservoir with a smaller pore size has a higher rock dissolution rate than one with a larger pore size. Furthermore, the simulation results show injected CO2 can modify the pore-dominant carbonate reservoir to a more pronounced extent than the fracture-dominant carbonate reservoir. Lastly, the carbonate rock dissolution is more obvious at a lower CO2 injection rate. The insights derived from this research aid evaluations related to CO2 injectivity, storage capacity, and reservoir integrity, thereby paving the way for environmentally and structurally sound carbon sequestration strategies. [ABSTRACT FROM AUTHOR]

Published
2024
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23. Placement and Routing Optimization Problem for Service Function Chain: State of Art and Future Opportunities

Author

Chen, Weihan, Yin, Xia, Wang, Zhiliang, Shi, Xingang, Yao, Jiangyuan, Filipe, Joaquim, Editorial Board Member, Ghosh, Ashish, Editorial Board Member, Kotenko, Igor, Editorial Board Member, Prates, Raquel Oliveira, Editorial Board Member, Zhou, Lizhu, Editorial Board Member, Sun, Xingming, editor, Wang, Jinwei, editor, and Bertino, Elisa, editor

Published
2020
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26. A Secure Blind Watermarking Scheme Based on Dual Frequency Domains and Ergodic Matrix

Author

Zhao, Minjun, Liu, Shiqin, Cao, Chunjie, Yao, Jiangyuan, Zhou, Xiaoyi, Hutchison, David, Series Editor, Kanade, Takeo, Series Editor, Kittler, Josef, Series Editor, Kleinberg, Jon M., Series Editor, Mattern, Friedemann, Series Editor, Mitchell, John C., Series Editor, Naor, Moni, Series Editor, Pandu Rangan, C., Series Editor, Steffen, Bernhard, Series Editor, Terzopoulos, Demetri, Series Editor, Tygar, Doug, Series Editor, Weikum, Gerhard, Series Editor, Sun, Xingming, editor, Pan, Zhaoqing, editor, and Bertino, Elisa, editor

Published
2018
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27. A Novel Watermarking Technology Based on Posterior Probability SVM and Improved GA

Author

Liu, Shiqin, Zhao, Minjun, Ma, Jixin, Yao, Jiangyuan, Duan, Yucong, Zhou, Xiaoyi, Hutchison, David, Series Editor, Kanade, Takeo, Series Editor, Kittler, Josef, Series Editor, Kleinberg, Jon M., Series Editor, Mattern, Friedemann, Series Editor, Mitchell, John C., Series Editor, Naor, Moni, Series Editor, Pandu Rangan, C., Series Editor, Steffen, Bernhard, Series Editor, Terzopoulos, Demetri, Series Editor, Tygar, Doug, Series Editor, Weikum, Gerhard, Series Editor, Sun, Xingming, editor, Pan, Zhaoqing, editor, and Bertino, Elisa, editor

Published
2018
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28. Fast Detection of Heavy Hitters in Software Defined Networking Using an Adaptive and Learning Method

Author

Wang, Zhiliang, Zhou, Changping, Yu, Yang, Shi, Xingang, Yin, Xia, Yao, Jiangyuan, Hutchison, David, Series Editor, Kanade, Takeo, Series Editor, Kittler, Josef, Series Editor, Kleinberg, Jon M., Series Editor, Mattern, Friedemann, Series Editor, Mitchell, John C., Series Editor, Naor, Moni, Series Editor, Pandu Rangan, C., Series Editor, Steffen, Bernhard, Series Editor, Terzopoulos, Demetri, Series Editor, Tygar, Doug, Series Editor, Weikum, Gerhard, Series Editor, Sun, Xingming, editor, Pan, Zhaoqing, editor, and Bertino, Elisa, editor

Published
2018
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41. A Novel Multi-Phase Strategy for Optimizing CO 2 Utilization and Storage in an Oil Reservoir.

Author

Yao, Jiangyuan, Yuan, Wanju, Peng, Xiaolong, Chen, Zhuoheng, and Gu, Yongan

Subjects
*PETROLEUM reservoirs, *GEOLOGICAL carbon sequestration, *CARBON dioxide, *GEOTHERMAL resources, *INJECTION wells, *POWER resources
Abstract

In this paper, an innovative multi-phase strategy is developed and numerically tested to optimize CO2 utilization and storage in an oil reservoir to support low carbon transition. In the first phase, the water-alternating-gas (WAG) injection is conducted to simultaneously store CO2 and produce crude oil in the reservoir from the respective injection and production wells. In the second phase, the injection and production wells are both shut in for some time to allow CO2 and water to be stratigraphically separated. In the third phase, CO2 is injected from the upper part of the reservoir above the separated water layer to displace water downwards, while fluids continue to be produced in the water-dominated zone from the lower part of the production well. Lastly, the production well is finally shut in when the produced gas–water ratio (GWR) reaches 95%, but CO2 injection is kept until the reservoir pressure is close to the fracture pressure of its caprocks. The numerical simulations show that implementing the proposed multi-phase strategy doubles CO2 storage in comparison to applying the WAG injection alone. In particular, 80% of the increased CO2 is stored in the third phase due to the optimized perforation. In addition, the CO2 injection rate in the last phase does not appear to affect the amount of CO2 storage, while a higher CO2 injection rate can reduce the CO2 injection time and accelerate the CO2 storage process. In the proposed strategy, we assume that the geothermal energy resources from the produced fluids can be utilized to offset some energy needs for the operation. The analysis of energy gain and consumption from the simulation found that at the early stage of the CO2-WAG phase, the energy gain mostly comes from the produced oil. At the late stage of the CO2-WAG phase and the subsequent phases, there is very little or even no energy gain from the produced oil. However, the geothermal energy of the produced water and CO2 substantially compensate for the energy loss due to decreasing oil production. As a result, a net energy gain can be achieved from the proposed multi-phase strategy when geothermal energy extraction is incorporated. The new multi-phase strategy and numerical simulation provide insights for practical energy transition and CO2 storage by converting a "to be depleted" oil reservoir to a CO2 storage site and a geothermal energy producer while enhancing oil recovery. [ABSTRACT FROM AUTHOR]

Published
2023
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48. A New Dynamic Fluid Flow Method for Studying the Phase Changes of the Light/Heavy Crude Oil-Solvent Systems

Author

Yao, Jiangyuan, Gu, Yongan, Zeng, Fanhua, Jia, Na, Henni, Amr, Veawab, Amornvadee, Qing, Hairuo, and Trivedi, Japan

Abstract

A Thesis Submitted to the Faculty of Graduate Studies and Research In Partial Fulfillment of the Requirements for the Degree of Doctor of Philosophy in Petroleum Systems Engineering, University of Regina. xxxii, 197 p. In this thesis, a novel experimental method, namely, the dynamic fluid flow (DFF) method, was developed to study the phase changes of various light/heavy crude oil‒solvent systems. First, two series of constant-composition-expansion (CCE) tests and constant-composition-expansion and compression (CCEC) tests were conducted by using a pressure‒volume‒temperature (PVT) system. Second, a series of the DFF tests were undertaken to measure the pressure gradients along a long micro-tubing at different outlet pressures when a given light/heavy crude oil‒solvent mixture flowed at a constant volume flow rate. For the light crude oil‒CO2 systems, it was found that the pressure gradient remained low and almost constant as long as the outlet pressure was above the bubble-point pressure of the light crude oil‒CO2 system. However, the pressure gradient was suddenly increased once the outlet pressure was below the bubble-point pressure because the light crude oil‒CO2 system changed from one liquid phase into liquid‒gas two phases. The linear regression was applied to obtain the measured pressure gradient versus outlet pressure line in each case. The outlet pressure at the intersection point of the two lines, where a sudden slope change occurred, was determined to be the bubble-point pressure. It was also found that for the same light crude oil‒CO2 system, the measured bubble-point pressures from the DFF tests were close to but slightly lower than those measured from the CCE tests due to the micro-tubing confinement and gas bubble re-entrainment. Furthermore, a mathematical formula was derived to predict the length of the two-phase flow region at a different outlet pressure below the bubble-point pressure. For the heavy crude oil‒solvent systems, it was found from the CCE tests that the measured Pcell‒νmix data could be divided into two or three regions, depending on the solvent concentration. For the heavy crude oil-solvent system with a low solvent concentration, its measured Pcell‒νmix data had three different regions (I, II, and III). The higher pressure at the intersection point of Regions I and II was referred to as the bubble-point pressure and the lower pressure at the intersection point of Regions II and III was referred to as the pseudo bubble-point pressure. For the heavy crude oil-solvent system with a high solvent concentration, its measured Pcell‒νmix data had two regions (I and II) only. The pressure at the intersection point of the two regions was referred to as the bubble-point pressure. In this case, the pseudo bubble-point pressure could not be obtained. It was found that the heavy crude oil-CH4 system had not only the highest bubble-point pressure and pseudo bubble-point pressure but also the largest difference between these two threshold pressures, in comparison with the heavy crude oil-CO2 system and the heavy crude oil-C3H8 system at the same solvent concentration. These facts indicate that CH4 not only is the most volatile solvent but also can be dispersed as gas bubbles to induce a stable foamy oil in the largest pressure range, in comparison with CO2 and C3H8. In each DFF test of the heavy crude oil‒solvent system, the measured pressure gradient vs. outlet pressure data could be divided into three regions (I, II and III). For all the heavy crude oilsolvent systems tested except the heavy crude oil-C3H8 systems with high C3H8 concentrations, the higher outlet pressure at the intersection point of Regions I and II was determined to be the bubble-point pressure. The lower outlet pressure at the intersection point of Regions II and III was referred to as the pseudo bubble-point pressure. For the heavy crude oil-C3H8 systems with high C3H8 concentrations, however, the higher outlet pressure at the intersection of Regions I and II represented a phase-change pressure, at which a two-liquid phase flow occurred in the micro-tubing. The lower outlet pressure at the intersection point of Regions II and III was determined as the bubble-point pressure. A mathematical model based on the CCE test results was derived to study the gas bubble nucleation processes in different heavy crude oilsolvent systems. A newly defined quantity called the bubble nucleation index (BNI) was used to represent the strength of bubble nucleation. The ratio of the solvent concentration at each pressure step in the CCE test to that at the equilibrium state, c_CCE/c_eq, was used to represent the degree of supersaturation. It was found from the BNI vs. c_CCE/c_eq data that there was a threshold degree of supersaturation for gas bubble nucleation to take place for the heavy crude oil-CH4 system and heavy crude oil-C3H8 system. However, there was no such threshold degree of supersaturation for the heavy crude oil-CO2 system. By comparing the degrees of supersaturation of different heavy crude oil-solvent systems, it can be concluded that in comparison with CO2 and C3H8, CH4 is the easiest solvent that can be nucleated from the heavy oil and the heavy crude oil-CH4 system has the lowest degree of supersaturation in comparison with the other two heavy crude oil-solvent systems. Three CCEC tests of three different heavy crude oil-solvent systems were conducted and another mathematical model was formulated based on the CCEC test results to study bubble liberation. Another new quantity, namely, the bubble liberation index (BLI), was defined to denote the strength of bubble liberation. By comparing the BLIs of different heavy crude oil-solvent systems, it was found that CH4 was the most difficult solvent to be liberated from the heavy oil in comparison with CO2 and C3H8. Also, the heavy crude oil could hold and contain more bubbles of CH4 than the other two solvents. Therefore, CH4 can induce the strongest and most stable foamy oil in comparison with CO2 and C3H8. Student yes

Published
2021

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